PIPESIM

Version 2014.1

User Guide
PIPESIM User Guide

Copyright 2014 Schlumberger. All rights reserved.

No part of this manual may be reproduced, stored in a retrieval system, or translated in any form or
by any means, electronic or mechanical, including photocopying and recording, without the prior
written permission of Schlumberger Information Solutions, 5599 San Felipe, Suite 1700, Houston,
TX 77056-2722, USA.

Use of this product is governed by the License Agreement. Schlumberger makes no warranties,
express, implied, or statutory, with respect to the product described herein and disclaims without
limitation any warranties of merchantability or fitness for a particular purpose. Schlumberger
reserves the right to revise the information in this manual at any time without notice.
PIPESIM User Guide

Table of Contents
1 Navigating the Interface ............................................................................................. 1
1.1 Workspace Tab Options ................................................................................................................ 2
1.2 Workspace Types .......................................................................................................................... 3
1.2.1 Network-Centric Workspace ............................................................................................... 4
1.2.2 Well-Centric Workspace ...................................................................................................... 5
1.3 Workspace Options ....................................................................................................................... 6
1.3.1 Units .................................................................................................................................... 7
Selecting a Standard Unit System ................................................................................... 7
Creating a Custom Unit System ...................................................................................... 8
Importing or Exporting a Custom Unit System ................................................................ 8
1.3.2 Plugins ................................................................................................................................ 9
User defined flow correlations ......................................................................................... 9
User defined equipment .................................................................................................. 9
1.3.3 Advanced options ................................................................................................................ 9
Resolving Intel MPI incompatibility ................................................................................ 12
1.3.4 Catalog .............................................................................................................................. 13
1.3.5 GIS Map options ............................................................................................................... 13
1.4 Tour of the Ribbon ....................................................................................................................... 15
1.5 Changing the Main Window Layout ........................................................................................... 16
1.6 Managing Floating Panes ........................................................................................................... 16
1.6.1 Inputs Pane ....................................................................................................................... 18
1.6.2 Tasks Pane ....................................................................................................................... 18
1.6.3 Information Area Overview ................................................................................................ 19
Message Center Pane ................................................................................................... 19
Validation Pane ............................................................................................................. 20

2 Building Physical Models ......................................................................................... 22

2.1 Creating or Editing a Well Model ................................................................................................ 23
2.1.1 Adding Tubular Data ......................................................................................................... 25
Adding Casing and Tubing to a Simple Wellbore Schematic ........................................ 25
Adding Casing and Tubing to a Detailed Wellbore Schematic ...................................... 27
2.1.2 Adding a Deviation Survey ................................................................................................ 29
Azimuth .......................................................................................................................... 31
Measured Depth and True Vertical Depth ..................................................................... 31

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2.1.3 Adding Downhole Equipment ............................................................................................ 32

Choke Properties ........................................................................................................... 33
Packer ........................................................................................................................... 36
Separator (Downhole) ................................................................................................... 36
Sliding Sleeve ................................................................................................................ 37
Sub-Surface Safety Valve ............................................................................................. 38
Tubing Plug ................................................................................................................... 38
User defined equipment .................................................................................................. 9
Engine Keywords ........................................................................................................... 40
2.1.4 Adding Artificial Lift ............................................................................................................ 41
Adding a Gas Lift Injection Point ................................................................................... 41
User defined equipment .................................................................................................. 9
Adding an ESP .............................................................................................................. 12
Adding a Progressive Cavity Pump (PCP) .................................................................... 46
Adding a Rod Pump ...................................................................................................... 48
2.1.5 Adding Heat Transfer Data ............................................................................................... 49
Measured Depth and True Vertical Depth ..................................................................... 31
2.1.6 Adding Completions .......................................................................................................... 51
IPR Options and Applicability Table .............................................................................. 53
Multilayer Completions .................................................................................................. 87
Associating Zones with Completions ............................................................................. 90
2.1.7 Adding Surface Equipment using the Well Editor ............................................................. 91
2.1.8 Working with Well Tabs and Ribbons ............................................................................... 92
2.1.9 Interactive Wellbore Schematic ......................................................................................... 93
2.2 Creating or Editing a Network Model ......................................................................................... 96
2.2.1 Navigating in the Network Diagram ................................................................................... 97
Panning and Zooming in the Network Diagram ............................................................. 97
Bringing Objects into View ............................................................................................. 98
Changing the Model Display Properties ........................................................................ 98
Printing the Model from the Network Diagram ............................................................... 99
2.2.2 Adding Wells ..................................................................................................................... 99
2.2.3 Adding Sources and Sinks .............................................................................................. 101
Sink Properties ............................................................................................................ 101

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2.2.4 Adding Surface Equipment using the Network Diagram ................................................. 102
Choke Properties ........................................................................................................... 33
Check Valves ................................................................................................................. 33
Compressor Properties ................................................................................................ 105
Expander Properties .................................................................................................... 108
Flowline - Simple Model Properties ............................................................................. 109
Flowline - Detailed Model Properties - General Tab .................................................... 112
Flowline - Detailed Model Properties - Heat Transfer Tab .......................................... 115
Pipeline Comparison: Land, Subsea, and Riser .......................................................... 116
Generic Equipment Properties .................................................................................... 117
Generic Pump Properties ............................................................................................ 119
Heat Exchanger Properties ......................................................................................... 121
Injection Point Properties ............................................................................................. 122
Source and Junctions Treated as Source Properties .................................................. 123
User defined equipment .................................................................................................. 9
Multiphase Booster Properties .................................................................................... 127
Multiplier/Adder Properties .......................................................................................... 128
Riser - Simple Model Properties .................................................................................. 128
Riser - Detailed Model Properties - General Tab ........................................................ 131
Riser - Detailed Model Properties - Heat Transfer Tab ............................................... 133
Three Phase Separator ............................................................................................... 135
Two Phase Separator .................................................................................................. 137
Configuring Wellstream Outlet or Inlet Conditions ....................................................... 138
Viewing Surface Equipment Properties ....................................................................... 142
Engine Keywords ........................................................................................................... 40
2.2.5 Creating a Network Model from a GIS Shapefile Automatically ........................................ 23
2.2.6 Adding Connections ........................................................................................................ 144

3 Creating or Editing Fluid Models ........................................................................... 146

3.1 Defining Black Oil Fluids .......................................................................................................... 147
3.1.1 Properties Tab ................................................................................................................... 87
3.1.2 Viscosity Properties ......................................................................................................... 150
3.1.3 Calibration Properties ...................................................................................................... 154
3.1.4 Thermal Properties .......................................................................................................... 156
3.2 Defining Compositional Fluids ................................................................................................. 156
3.2.1 Viscosity Properties ......................................................................................................... 150
3.2.2 Salinity Models ................................................................................................................ 150
3.2.3 Binary Interaction Parameter (BIP) Sets ........................................................................... 57
3.3 Multiflash in the Compositional Fluid mode (native) vs. Multiflash MFL files ..................... 146
3.4 Ensuring consistency among multiple fluid files in a PIPESIM network model .................. 164
3.5 Creating/Defining a new MFL fluid ........................................................................................... 156
3.5.1 Importing existing MFL fluid files ..................................................................................... 156
3.5.2 Viewing Wax or Asphaltene Curves on Phase Envelopes ................................................ 57
3.5.3 Editing an MFL fluid file ................................................................................................... 156
3.5.4 Availability of Multiflash models in PIPESIM using the MFL file fluid mode option ......... 164

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3.5.5 Multiflash phases supported in PIPESIM ........................................................................ 164

3.6 Displaying Phase Envelopes for Compositional fluid or MFL file ........................................ 172
3.7 Overriding Fluid Phase Ratios ................................................................................................. 174
3.8 Importing a PVT File .................................................................................................................. 176

4 Running Simulations .............................................................................................. 177

4.1 Configuring Simulation Settings .............................................................................................. 177
4.1.1 Flow Correlation Properties ............................................................................................. 178
4.1.2 Heat Transfer Properties ................................................................................................. 181
4.1.3 Erosion/Corrosion Properties .......................................................................................... 181
4.1.4 Environmental Properties ................................................................................................ 183
4.1.5 Output Variables Properties ............................................................................................ 184
Managing Output Variable Report Templates ............................................................. 185
4.1.6 Advanced Properties ........................................................................................................... 9
4.1.7 Overriding the Default Value in Specific Rows ................................................................ 190
4.2 Running a P/T Profile ................................................................................................................ 191
4.2.1 P/T Profile Parameters Tab ............................................................................................. 191
4.2.2 System Results Tab Properties - P/T Profile ................................................................... 195
4.2.3 Profile Results Tab Properties - P/T Profile .................................................................... 195
4.3 Running a Nodal Analysis ........................................................................................................ 197
4.3.1 Nodal Analysis Properties ............................................................................................... 198
4.3.2 Adding a Nodal Point ...................................................................................................... 201
4.3.3 Nodal Analysis Results Tab Properties ........................................................................... 203
4.4 Creating a VFP Table ................................................................................................................. 204
4.4.1 VFP Table Properties ...................................................................................................... 206
4.4.2 Saving a VFP Table to a File .......................................................................................... 207
4.5 Running a Network Simulation ................................................................................................. 208
4.5.1 Boundary Conditions ....................................................................................................... 209
4.5.2 Rate Constraints ............................................................................................................. 209
4.5.3 Node/Branch Results Tab Properties - Network Simulation ........................................... 213
4.5.4 Profile Results Tab Properties - Network Simulation ...................................................... 214
4.5.5 Improving Network Simulation Performance ................................................................... 215
Restart Simulation ....................................................................................................... 221
PIPESIM Differences from other Simulators ............................................................... 222
Reversing the changes made to PIPESIM models to optimize their simulation
performance ................................................................................................................ 223
4.6 Running a System Analysis ...................................................................................................... 223
4.6.1 System Analysis Properties ............................................................................................ 224
4.6.2 System Results Tab Properties - System Analysis ......................................................... 227
4.6.3 Profile Results Tab Properties - System Analysis ........................................................... 195
4.7 Designing an ESP ...................................................................................................................... 229
4.7.1 ESP Design Task Parameters ........................................................................................ 232

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4.7.2 Tapered ESP Design ........................................................................................................ 51

4.8 Managing Results ...................................................................................................................... 236
4.8.1 Launching the Results Viewer ......................................................................................... 238

5 Managing Model Data ............................................................................................. 240

5.1 Managing the Catalogs ............................................................................................................. 240
5.1.1 Filtering Catalog Views ................................................................................................... 241
Casing Catalog Properties ........................................................................................... 242
Tubing Catalog Properties ........................................................................................... 243
Flowline/Riser Catalog Properties ............................................................................... 243
5.1.2 Adding Items to the Compressor Catalog ....................................................................... 244
Compressor Catalog Properties .................................................................................. 244
5.1.3 Adding Items to the Pump Catalog ................................................................................. 246
Pump Catalog Properties ............................................................................................ 246
5.1.4 Managing the Fluid Templates Catalog .......................................................................... 247
Viewing a Built-in Fluid Template ................................................................................ 248
Creating a Custom Fluid Template .............................................................................. 248
Viewing or Editing a Custom Fluid Template ............................................................... 249
5.1.5 Managing the Well Templates Catalog ........................................................................... 249
Viewing a Built-in Well Template ................................................................................. 249
Creating a Custom Well Template ............................................................................... 250
Viewing or Editing a Custom Well Template ............................................................... 250
5.2 Managing Flowlines and Risers ............................................................................................... 251
5.3 Managing Fluids .......................................................................................................................... 13
5.4 Managing Zones ........................................................................................................................ 253

6 Working with the GIS Map ...................................................................................... 255

6.1 Choosing a Basemap ................................................................................................................ 255
6.1.1 Adding Bing Basemaps ................................................................................................... 256
6.2 Navigating the GIS Map ............................................................................................................. 257
6.2.1 Panning and Zooming to Your Map Area ........................................................................ 257
6.2.2 Zooming to a Geographic Location or Address ............................................................... 258
6.3 Zooming to Bookmarks ............................................................................................................. 259
6.3.1 Importing a Bookmark File .............................................................................................. 260
Creating a Custom Bookmark File ............................................................................... 260
6.4 Working with Layers .................................................................................................................. 261
6.4.1 GIS Shapefile Basics ...................................................................................................... 262
6.4.2 Using Shapefiles ............................................................................................................. 263
6.4.3 Using Map Services ........................................................................................................ 264
Network Prerequisites ................................................................................................. 265
Obtaining WMS Parameters ........................................................................................ 266
6.4.4 Using a Map Cache ......................................................................................................... 268
6.4.5 Changing the Display Options ......................................................................................... 269
6.5 Using the GIS Map ..................................................................................................................... 270

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6.5.1 Creating a New Network Model on the GIS Map Manually ............................................. 271
6.5.2 Locating a Previously Built Schematic Network on the GIS Map .................................... 271
6.5.3 Moving the Entire Network to a New Map Location ........................................................ 272
6.5.4 Displaying Object Clusters .............................................................................................. 272
6.5.5 ASTER and SRTM Elevation Data Sources ..................................................................... 22
6.5.6 Changing the PIPESIM Data Source for GIS Elevation Data Capture .............................. 22
6.5.7 Capturing Elevations ....................................................................................................... 276
6.5.8 Viewing Profile Direction ................................................................................................. 276
6.5.9 Editing Equipment Locations ........................................................................................... 277
6.5.10 Creating a Network Model from a GIS Shapefile Automatically ........................................ 23
6.5.11 Using Additional Functions within the GIS Map .............................................................. 279
Showing the Map Legend ............................................................................................ 279
Measuring Distance and Area ..................................................................................... 279
Printing the Map .......................................................................................................... 280

7 Technical Description ............................................................................................. 281

7.1 Flow Models ............................................................................................................................... 281
7.1.1 Flow Regimes ................................................................................................................. 281
Flow Regimes Classification for Vertical Two Phase Flow .......................................... 281
Flow Regimes Classification for Horizontal Two Phase Flow ...................................... 282
7.1.2 Horizontal Multiphase Flow Correlations ......................................................................... 283
Baker Jardine (BJA) Correlation .................................................................................. 283
Beggs and Brill Original ............................................................................................... 283
Beggs and Brill Revised .............................................................................................. 284
Dukler (AGA) and Flanigan ......................................................................................... 284
Eaton-Oliemans ........................................................................................................... 284
Hughmark-Dukler ........................................................................................................ 284
LEDA ........................................................................................................................... 285
Minami and Brill ........................................................................................................... 285
Mukherjee and Brill ...................................................................................................... 285
NOSLIP Correlation ..................................................................................................... 286
OLGAS 2-phase / OLGAS 2000 3-phase .................................................................... 286
Oliemans ..................................................................................................................... 286
TUFFP Unified Mechanistic Model (2-phase and 3-phase) ......................................... 287
Xiao ............................................................................................................................. 287
Xiao (film modified) ...................................................................................................... 288

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7.1.3 Vertical Multiphase Flow Correlations ............................................................................. 288

Ansari .......................................................................................................................... 288
Aziz Govier Fogarasi ................................................................................................... 288
Beggs and Brill Original ............................................................................................... 289
Beggs and Brill Revised .............................................................................................. 289
Duns and Ros .............................................................................................................. 289
Gomez ......................................................................................................................... 290
Gomez enhanced ........................................................................................................ 290
Govier and Aziz ........................................................................................................... 290
Gray ............................................................................................................................. 290
Gray Modified .............................................................................................................. 290
Gregory ........................................................................................................................ 291
Hagedorn and Brown ................................................................................................... 292
Mukherjee and Brill ...................................................................................................... 292
NOSLIP Correlation ..................................................................................................... 292
OLGAS 2-phase/ OLGAS ............................................................................................ 292
LEDA ........................................................................................................................... 293
Orkiszewski ................................................................................................................. 293
TUFFP Unified Mechanistic Model (2-phase and 3-phase) ......................................... 287
7.1.4 Suggested correlations ................................................................................................... 294
7.1.5 Friction and Holdup factors ............................................................................................. 296
7.1.6 Single Phase Flow Correlations ...................................................................................... 296
Moody (default for liquid or gas) .................................................................................. 297
AGA (for gas) ............................................................................................................... 298
Cullender and Smith (for gas) ...................................................................................... 299
Other friction pressure drops for gas ........................................................................... 299
Hazen-Williams (for liquid water) ................................................................................. 300
7.1.7 Swap Angle ..................................................................................................................... 301
7.1.8 deWaard (1995) Corrosion Model ................................................................................... 301
7.1.9 Cunliffe's Method for Ramp Up Surge ............................................................................ 303
7.1.10 Liquid by Sphere ............................................................................................................. 304
PI-SS (Severe-Slugging Group) .................................................................................. 305
7.1.11 Liquid Loading ................................................................................................................. 307
Critical Unloading Velocity ........................................................................................... 307
Critical Gas Rate ......................................................................................................... 308
7.2 Completion (IPR) Models .......................................................................................................... 308

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7.2.1 Inflow Performance Relationships for Vertical Completions ........................................... 308

Productivity Index (PI) ................................................................................................. 309
Vogel's Equation .......................................................................................................... 310
Fetkovich's Equation ................................................................................................... 311
Jones' Equation ........................................................................................................... 312
Forchheimer Equation ................................................................................................. 313
Back Pressure Equation .............................................................................................. 313
Pseudo Steady State Equation / Darcy Equation ........................................................ 314
Transient IPR ............................................................................................................... 319
Data File ...................................................................................................................... 324
Bubble Point Correction ............................................................................................... 325
Vertical Well Skin Factor ............................................................................................. 326
7.2.2 Inflow Performance Relationships for Horizontal Completions ....................................... 338
Theory ......................................................................................................................... 338
Pressure Drop ............................................................................................................. 338
Inflow Production Profiles ............................................................................................ 342
Steady-State Productivity ............................................................................................ 343
Pseudo-Steady State Productivity ............................................................................... 346
Solution Gas-Drive IPR ............................................................................................... 349
Horizontal Gas Wells ................................................................................................... 349
Distributed Productivity Index Method ......................................................................... 352
7.2.3 Oil / Water Relative Permeability tables .......................................................................... 352
Keywords ..................................................................................................................... 353
7.2.4 Coning ............................................................................................................................. 353
7.3 Equipment .................................................................................................................................. 354
7.3.1 Chokes, Valves and Fittings ............................................................................................ 354
Choke .......................................................................................................................... 354
Choke Subcritical Flow Correlations ............................................................................ 357
Choke Critical Pressure Ratio ..................................................................................... 360
Choke Critical Flow Correlations ................................................................................. 361
Flow Control Valves Mechanistic Theory .................................................................... 362
Fittings ......................................................................................................................... 363
7.3.2 Compressors, Pumps, and Expanders ........................................................................... 366
Centrifugal Pumps and Compressors .......................................................................... 366
Reciprocating Compressor Operation ......................................................................... 369
Expanders ................................................................................................................... 370
7.3.3 Multiphase Boosting Technology .................................................................................... 372
Guide to Multiphase Booster Efficiencies .................................................................... 386
7.3.4 Artificial Lift ...................................................................................................................... 387
Progressive Cavity Pump (PCP) ................................................................................. 387
Electrical Submersible Pumps (ESP) .......................................................................... 390
Assumptions of the Alhanati model ............................................................................. 397
7.4 Heat Transfer Models ................................................................................................................ 398
7.4.1 Energy Equation for Steady-State Flow .......................................................................... 398
7.4.2 Overall Heat Transfer Coefficient .................................................................................... 399

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7.4.3 Inside Fluid Film Heat Transfer Coefficient ..................................................................... 402

Inside Forced Convection ............................................................................................ 402
Inside Natural Convection ........................................................................................... 407
7.4.4 Conductive Heat Transfer Coefficients ........................................................................... 408
7.4.5 Annulus and Outside Convective Heat Transfer Coefficients ......................................... 410
7.4.6 Heat Transfer Between a Horizontal Flowline and the Ground Surface ......................... 412
Fully Buried Ground Heat Transfer Coefficient ............................................................ 412
Partially Buried Ground Heat Transfer Coefficient ...................................................... 413
7.4.7 Heat Transfer Between a Vertical Well and the Surrounding Rock ................................ 416
Ramey Model .............................................................................................................. 416
7.5 Fluid Models ............................................................................................................................... 417
7.5.1 Steam Modelling ............................................................................................................. 418
Single branch steam .................................................................................................... 418
Network model steam .................................................................................................. 419
7.5.2 Black Oil Fluid Modeling .................................................................................................. 419
Black oil Correlations ................................................................................................... 421
Solution Gas-oil Ratio .................................................................................................. 422
Oil Formation Volume Factor ....................................................................................... 427
Oil Viscosity ................................................................................................................. 429
Gas Compressibility ..................................................................................................... 436
Gas Viscosity ............................................................................................................... 439
Surface Tension .......................................................................................................... 440
Black Oil Enthalpy ....................................................................................................... 441
Black Oil Mixing ........................................................................................................... 442
7.5.3 Compositional Fluid Modeling ......................................................................................... 449
Cubic Equations of State ............................................................................................. 450
Non-cubic Equations of State ...................................................................................... 454
Components for Cubic Equations of State .................................................................. 459
Components for Non-Cubic Equations of State ........................................................... 464
Viscosity Models for Compositional Fluids .................................................................. 429
Solid Precipitation ........................................................................................................ 466
7.5.4 Fluid Property Table Files ............................................................................................... 469
Internal fluid property tables ........................................................................................ 470
7.5.5 Liquid mixture properties ................................................................................................. 470
Liquid Viscosity and Oil/Water Emulsions ................................................................... 470
Liquid-gas Surface Tension ......................................................................................... 477
7.6 Typical and Default Data ........................................................................................................... 477
7.6.1 Limits ............................................................................................................................... 477
General ........................................................................................................................ 477
Pipeline and facilities ................................................................................................... 477
Well Performance ........................................................................................................ 477
Network ....................................................................................................................... 478
7.6.2 Tubing and Pipeline Tables ............................................................................................. 478
Tubing/Casing Tables .................................................................................................. 478
Pipeline tables ............................................................................................................. 483

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7.6.3 Typical Values ................................................................................................................. 487

Fluid Properties ........................................................................................................... 487
Roughness .................................................................................................................. 488
Thermal Conductivities ................................................................................................ 488
Permeability ................................................................................................................. 490
Drainage Radius .......................................................................................................... 490
Fittings ......................................................................................................................... 490
7.7 Glossary ..................................................................................................................................... 492
7.7.1 Roman Letters ................................................................................................................. 492
7.7.2 Greek Letters .................................................................................................................. 495
7.7.3 Subscripts ....................................................................................................................... 496
7.8 Conversion Factors ................................................................................................................... 497
7.8.1 Length ............................................................................................................................. 497
7.8.2 Volume ............................................................................................................................ 497
7.8.3 Mass ................................................................................................................................ 497
7.8.4 Time ................................................................................................................................ 498
7.8.5 Gravity ............................................................................................................................. 498
7.8.6 Pressure .......................................................................................................................... 498
7.8.7 Energy ............................................................................................................................. 498
7.8.8 Power .............................................................................................................................. 498
7.8.9 Dynamic viscosity ............................................................................................................ 498
7.8.10 Permeability .................................................................................................................... 499
7.9 References ................................................................................................................................. 499

8 Keyword Index ........................................................................................................ 511

8.1 Keyword List .............................................................................................................................. 511
8.1.1 A ...................................................................................................................................... 511
8.1.2 B ...................................................................................................................................... 511
8.1.3 C ...................................................................................................................................... 512
8.1.4 D E .................................................................................................................................. 512
8.1.5 F ...................................................................................................................................... 512
8.1.6 G ..................................................................................................................................... 512
8.1.7 H ...................................................................................................................................... 513
8.1.8 I ....................................................................................................................................... 513
8.1.9 J ...................................................................................................................................... 513
8.1.10 K ...................................................................................................................................... 513
8.1.11 L ...................................................................................................................................... 513
8.1.12 M ..................................................................................................................................... 513
8.1.13 N ...................................................................................................................................... 514
8.1.14 O ..................................................................................................................................... 514
8.1.15 P ...................................................................................................................................... 514
8.1.16 Q R .................................................................................................................................. 514
8.1.17 S ...................................................................................................................................... 514
8.1.18 T ...................................................................................................................................... 515
8.1.19 U ...................................................................................................................................... 515

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8.1.20 V ...................................................................................................................................... 515

8.1.21 W ..................................................................................................................................... 515
8.1.22 XYZ ................................................................................................................................. 515
8.2 Input Files and Input Data Conventions .................................................................................. 515
8.2.1 General ........................................................................................................................... 515
8.2.2 Statements ...................................................................................................................... 516
8.2.3 Delimiters ........................................................................................................................ 516
Examples ..................................................................................................................... 517
8.2.4 Abbreviations .................................................................................................................. 517
Example ....................................................................................................................... 517
8.2.5 Numeric data ................................................................................................................... 518
Example ....................................................................................................................... 518
8.2.6 Units Description ............................................................................................................. 518
8.2.7 Character Input ............................................................................................................... 518
Example ....................................................................................................................... 519
8.2.8 Comment Statements and Blank Lines ........................................................................... 519
Example ....................................................................................................................... 519
8.2.9 Multiple Value Data Sets ................................................................................................. 519
Examples ..................................................................................................................... 520
8.2.10 Input Files ........................................................................................................................ 520
General ........................................................................................................................ 520
The main input ('.PSM' or '.PST') file ........................................................................... 521
Included files and the INCLUDE statement ................................................................. 521
AUTOEXEC.PSM ........................................................................................................ 522
modelname.U2P or branchname.U2P ......................................................................... 522
8.3 General Data ............................................................................................................................... 522
8.3.1 Changing Parameters within the System Profile ............................................................. 522
Example ....................................................................................................................... 523
Multiple Cases ............................................................................................................. 523
8.3.2 HEADER - Job Accounting Header (Required) ............................................................... 523
Example ....................................................................................................................... 523
8.3.3 JOB - Job Title (Optional) ................................................................................................ 523
8.3.4 CASE - Case Title (Optional) .......................................................................................... 524
8.3.5 UNITS - Input and Output Units (Optional) ..................................................................... 524
Example ....................................................................................................................... 524
8.3.6 OPTIONS Calculation Procedure Options (Optional) ..................................................... 525
8.3.7 RATE: Fluid Flow Rate Data ........................................................................................... 535
8.3.8 ITERN Iteration Data (Optional) ...................................................................................... 537
8.3.9 INLET System Inlet Data ................................................................................................. 539
8.3.10 PRINT Output Printing Options (Optional) ...................................................................... 539
Per-case output page options ...................................................................................... 540
Attributes ..................................................................................................................... 543
Point report subcodes .................................................................................................. 544
One-off output pages ................................................................................................... 546
8.3.11 PLOT Output Plotting Options (Optional) ........................................................................ 547

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8.3.12 NOPRINT Output Print Suppression Options (Optional) ................................................. 550

8.3.13 BEGIN , END - Block delimiters ...................................................................................... 550
Example ....................................................................................................................... 551
8.3.14 PUSH - Remote Action Editing (optional) ....................................................................... 552
8.3.15 PLOTFILEDATA .............................................................................................................. 553
8.3.16 EXECUTE - deferred execution of a statement .............................................................. 553
8.3.17 USERDLL - Equipment ................................................................................................... 554
8.4 FLOW CORRELATION DATA .................................................................................................... 554
8.4.1 CORROSION .................................................................................................................. 555
8.4.2 EROSION Erosion Rate and Velocity (Optional) ............................................................ 555
8.4.3 SLUG Slug Calculation Options (Optional) ..................................................................... 556
Slug catcher size ......................................................................................................... 557
8.4.4 VCORR Vertical Flow Correlation Options ...................................................................... 557
Summary of Valid Vertical Flow Correlation Combinations ......................................... 558
Vertical Flow Correlations - Abbreviations ................................................................... 559
8.4.5 HCORR Horizontal Flow Correlation Options ................................................................. 561
Summary of Valid Horizontal Flow Correlation Combinations ..................................... 562
Horizontal Flow Correlations - Abbreviations .............................................................. 559
8.4.6 SPHASE Single Phase Flow Options (Optional) ............................................................. 564
8.4.7 USERDLL - Flow Correlations ........................................................................................ 566
8.5 WELL PERFORMANCE MODELING ......................................................................................... 566
8.5.1 INTRODUCTION ............................................................................................................. 567
8.5.2 COMPLETION Completion Profile Delimiter ................................................................... 567
Supercode ................................................................................................................... 568
8.5.3 WELLPI Well Productivity Index (Optional) ..................................................................... 569
Subcodes ..................................................................................................................... 569
8.5.4 WPCURVE (Optional) ..................................................................................................... 570
8.5.5 VOGEL Vogel Equation (Optional) .................................................................................. 570
Subcodes ..................................................................................................................... 570
8.5.6 FETKOVICH Fetkovich Equation (Optional) ................................................................... 570
Subcodes ..................................................................................................................... 570
8.5.7 JONES Jones Equation (Optional) .................................................................................. 571
Subcodes ..................................................................................................................... 571
8.5.8 IFPPSSE : Data for the Pseudo Steady State Equation (Optional) ................................ 571
8.5.9 WCOPTION Well Completion Data (Optional) ................................................................ 573
8.5.10 IPRCRV or IFPCRV: Inflow Performance Curve ............................................................. 576
Examples ..................................................................................................................... 577
8.5.11 IFPTAB Inflow Performance Tabulation (Optional) ......................................................... 578
Values .......................................................................................................................... 578
Example ....................................................................................................................... 579
8.5.12 CONETAB Coning Relationship Tabulation (Optional) ................................................... 579
Example ....................................................................................................................... 580
8.5.13 BACKPRES Back Pressure Equation (BPE) (Optional) .................................................. 580
Subcodes ..................................................................................................................... 580
8.5.14 HORWELL Horizontal Well Inflow Performance ............................................................. 580

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8.5.15 LAYER Reservoir Layer Properties ................................................................................. 582

Examples ..................................................................................................................... 583
8.5.16 RESERVOIR ................................................................................................................... 584
8.5.17 PERMCRV: Curves of Relative Permeability versus Saturation (Optional) .................... 584
Example ....................................................................................................................... 584
8.5.18 PERMTAB: Tabulation of Relative Permeability versus Saturation (Optional) ............... 585
Example ....................................................................................................................... 585
8.5.19 HVOGEL (Optional) ........................................................................................................ 586
8.5.20 FORCHHEIMER (Optional) ............................................................................................. 586
8.5.21 FRACTURE: Data for Hydraulic Fracture ....................................................................... 586
8.5.22 TRANSIENT: Data for the Transient Inflow equation (Optional) ..................................... 587
8.6 SYSTEM DATA ........................................................................................................................... 588
8.6.1 CHOKE (Optional) ........................................................................................................... 589
8.6.2 COMPCRV and PUMPCRV: Compressor and Pump performance curves .................... 593
Examples ..................................................................................................................... 594
8.6.3 COMPRESSOR Compressor (Optional) ......................................................................... 595
8.6.4 RODPUMP: Rod- or Beam-pump ................................................................................... 596
8.6.5 EQUIPMENT Generic Equipment ................................................................................... 354
Examples ..................................................................................................................... 599
8.6.6 EXPANDER Expander (Optional) ................................................................................... 599
8.6.7 FITTING : Valves and Fittings ......................................................................................... 600
EXAMPLES ................................................................................................................. 601
8.6.8 FMPUMP (Optional) ........................................................................................................ 602
8.6.9 FRAMO 2009 (Optional) ................................................................................................. 602
EXAMPLE .................................................................................................................... 603
8.6.10 HEATER Heater/Cooler (Optional) ................................................................................. 603
8.6.11 GASLIFT: Multiple Injection Ports in Gaslifted Wells ...................................................... 603
Main-code: GASLIFT ................................................................................................... 604
8.6.12 INJPORT Gas Lift Injection Valve ................................................................................... 607
8.6.13 INJGAS: Injection Gas (Optional) and INJFLUID: Fluid Injection ................................... 609
8.6.14 MPBOOSTER (Optional) ................................................................................................ 611
8.6.15 MPUMP Multiphase Pump (Optional) ............................................................................. 612
8.6.16 NODE System Profile Data (Required) ........................................................................... 614
8.6.17 PIPE: Pipe or Tubing cross-section dimensions (Required) ........................................... 615
8.6.18 PUMP Pump (Optional) ................................................................................................... 617
8.6.19 COMPCRV and PUMPCRV: Compressor and Pump performance curves .................... 593
Examples ..................................................................................................................... 594
8.6.20 REINJECTOR (Optional) ................................................................................................ 620
8.6.21 RODPUMP: Rod- or Beam-pump ................................................................................... 596
8.6.22 SEPARATOR Separator (Optional) ................................................................................ 621
8.6.23 WELLHEAD Wellhead Profile Delimiter .......................................................................... 622
8.7 HEAT TRANSFER DATA ........................................................................................................... 623
8.7.1 Notes on Heat Transfer Output Printing .......................................................................... 623
8.7.2 HEAT Heat Balance Options (Optional) .......................................................................... 623
Heat transfer mode ...................................................................................................... 626

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8.7.3 COAT Pipe Coat and Annular Space Medium Data (Optional) ....................................... 626
Example ....................................................................................................................... 627
8.7.4 TCOAT Pipe Coat Thickness Data (Optional) ................................................................. 627
8.7.5 KCOAT Pipe Coat Thermal Conductivity Data (Optional) ............................................... 628
Files ............................................................................................................................. 629
Example ....................................................................................................................... 629
8.7.6 FLUID Fluid Thermal Conductivity Data (Optional) ......................................................... 631
8.7.7 CONFIG: Pipe Heat Transfer Configuration Data (Optional) .......................................... 631
8.7.8 Pipeline burial depth examples ....................................................................................... 632
8.8 Fluid Models ............................................................................................................................... 633
8.8.1 BLACK OIL DATA ........................................................................................................... 633
BLACKOIL: Black Oil Fluid definitions ......................................................................... 633
PROP Fluid Property Data (Optional) .......................................................................... 635
LVIS: Liquid Viscosity Data (Optional) ......................................................................... 637
CPFLUID: Fluid Heat Capacity Data (Optional) .......................................................... 642
TPRINT Black Oil Table Printing (Optional) ................................................................ 642
CALIBRATE: Black Oil Property Calibration (Optional) ............................................... 643
CONTAMINANTS Gas phase contaminants data (optional) ....................................... 644
8.8.2 COMPOSITIONAL DATA ................................................................................................ 645
AQUEOUS: Aqueous Component Specification ......................................................... 645
CEMULSION Compositional Liquid Emulsion Data (Optional) .................................... 645
COMPOSITION: Compositional Fluid Specification .................................................... 648
LIBRARY: Library Component Specification ............................................................... 652
MODEL: Model Properties Specification ..................................................................... 652
PETROFRAC: Petroleum Fraction Specification ......................................................... 653
TPRINT Tabular Data Print Options (Optional) ........................................................... 654
8.9 PIPESIM OPERATIONS OPTIONS ............................................................................................ 654
8.9.1 NAPLOT: Nodal Analysis ................................................................................................ 655
8.9.2 NAPOINT System Analysis Point .................................................................................... 659
8.9.3 MULTICASE Introduction and Summary ........................................................................ 659
General Rules for use with MULTICASE ..................................................................... 660
8.9.4 Explicit Subcodes ............................................................................................................ 660
8.9.5 General Purpose Subcodes ............................................................................................ 663
Examples ..................................................................................................................... 663
8.9.6 Combining MULTICASE and CASE/ENDCASE ............................................................. 664
8.9.7 Multiple Case and PS-PLOT ........................................................................................... 665
8.9.8 Reservoir Simulator Tabular Data Interface .................................................................... 666
8.9.9 ASSIGN Changing Profile Data by Assignment .............................................................. 667
Example ....................................................................................................................... 668
8.9.10 OPTIMIZE ....................................................................................................................... 668
Examples ..................................................................................................................... 669

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8.9.11 Wax deposition and Time Stepping modeling options .................................................... 670
Time subcodes ............................................................................................................ 670
Termination subcodes ................................................................................................. 671
Wax subcodes ............................................................................................................. 672
BP, DBRS or DBRM method subcodes ....................................................................... 673
Shell subcodes ............................................................................................................ 674
8.10 PIPESIM-Net keywords .............................................................................................................. 675
8.10.1 SETUP .............................................................................................................................. 40
Subcodes ..................................................................................................................... 676
8.10.2 BRANCH ......................................................................................................................... 678
Subcodes ..................................................................................................................... 678
8.10.3 SOURCE ......................................................................................................................... 680
Subcodes ..................................................................................................................... 680
8.10.4 SINK ................................................................................................................................ 683
Subcodes ..................................................................................................................... 683
8.10.5 JUNCTION ...................................................................................................................... 685
Subcodes ..................................................................................................................... 685
8.10.6 NSEPARATOR ............................................................................................................... 685
Subcodes ..................................................................................................................... 685
8.11 Keyword Index ........................................................................................................................... 511
8.11.1 Keyword List .................................................................................................................... 511
A .................................................................................................................................. 511
B .................................................................................................................................. 511
C .................................................................................................................................. 512
D E ............................................................................................................................... 512
F .................................................................................................................................. 512
G .................................................................................................................................. 512
H .................................................................................................................................. 513
I .................................................................................................................................... 513
J ................................................................................................................................... 513
K .................................................................................................................................. 513
L ................................................................................................................................... 513
M .................................................................................................................................. 513
N .................................................................................................................................. 514
O .................................................................................................................................. 514
P .................................................................................................................................. 514
Q R .............................................................................................................................. 514
S .................................................................................................................................. 514
T .................................................................................................................................. 515
U .................................................................................................................................. 515
V .................................................................................................................................. 515
W ................................................................................................................................. 515
XYZ .............................................................................................................................. 515

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9 Tutorials ................................................................................................................... 692

9.1 Oil Well Performance Analysis ................................................................................................. 692
9.1.1 NODAL Analysis ............................................................................................................. 693
9.1.2 Task 1: Build the Well Model ........................................................................................... 693
9.1.3 Task 2: Perform a NODAL Analysis ................................................................................ 699
9.1.4 Task 3: Generate a Pressure/Temperature Profile ......................................................... 700
9.1.5 Fluid Calibration .............................................................................................................. 703
9.1.6 Single Point Calibration ................................................................................................... 703
9.1.7 Task 4: Calibrate PVT Data ............................................................................................ 704
9.1.8 Multiphase Flow Correlation Calibration ......................................................................... 705
9.1.9 Inflow Performance Matching .......................................................................................... 706
9.1.10 Task 5: Sensitizing on the Well PI to Match Well Performance ...................................... 706
9.1.11 Well Performance Analysis ............................................................................................. 707
9.1.12 Task 6: Analyze Water Cut Sensitivity ............................................................................ 707
9.1.13 Task 7: Evaluate Gas Lift Performance .......................................................................... 709
9.1.14 Task 8: Model Multiple Completions ............................................................................... 712
9.1.15 Task 9: Model a Downhole Choke .................................................................................. 714
9.2 Gas Well Performance ............................................................................................................... 716
9.2.1 Compositional Fluid Modeling ......................................................................................... 716
9.2.2 Task 1: Create a Compositional Fluid Model for a Gas Well .......................................... 720
9.2.3 Gas Well Deliverability .................................................................................................... 725
9.2.4 Task 2: Calculate Gas Well Deliverability ....................................................................... 726
9.2.5 Task 3: Calibrate the Inflow Model Using Multipoint Test Data ....................................... 727
9.2.6 Erosion Prediction ........................................................................................................... 728
9.2.7 Task 4: Select a Tubing Size .......................................................................................... 729
9.2.8 Choke Modeling .............................................................................................................. 730
9.2.9 Task 5: Model a Flowline and Choke .............................................................................. 731
9.2.10 Task 6: Predict Future Production Rates ........................................................................ 734
9.2.11 Liquid Loading ................................................................................................................. 735
9.2.12 Task 7: Determine a Critical Gas Rate to Prevent Well Loading .................................... 736
9.3 Subsea Tieback Design ............................................................................................................. 740
9.3.1 Flow Assurance Considerations ...................................................................................... 740
9.3.2 Task 1: Size the Subsea Tieback and Riser ................................................................... 740
9.3.3 Hydrates .......................................................................................................................... 750
9.3.4 Task 2: Select Tieback Insulation Thickness .................................................................. 752
9.3.5 Task 3: Determine the Methanol Requirement ............................................................... 756
9.3.6 Severe Riser Slugging .................................................................................................... 759
9.3.7 Task 4: Screen for Severe Riser Slugging ...................................................................... 760
9.3.8 Slug Catcher Sizing ......................................................................................................... 761
9.3.9 Task 5: Size a Slug Catcher ............................................................................................ 764
9.4 Looped Gas Gathering Network ............................................................................................... 766
9.4.1 Model a Gathering Network ............................................................................................ 767
9.4.2 Task 1: Model a Pipeline Network ................................................................................... 768

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9.4.3 Task 2: Screen the Network for Erosion Issues .............................................................. 777
9.5 Manual Creation of a Simple Network Model on the GIS Map ............................................... 778
9.5.1 Task 1: Build the Network Model on a Map .................................................................... 778
9.6 Automatic Creation of a Network Model on the GIS Map and Investigation of the
Use of Inline Heating for Wax Mitigation ................................................................................. 793

10 Support .................................................................................................................... 812

10.1 SIS web support ......................................................................................................................... 812
10.2 On-site support .......................................................................................................................... 812
10.3 SIS Education ............................................................................................................................. 812

Index .......................................................................................................................................................... 813

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1
Navigating the Interface
The user interface is similar in style to the Microsoft Office ribbon. At startup, the Workspace tab
appears.

Startup Options
Create a new network-centric or well-centric workspace.
Open an existing workspace (including PIPESIM* 2007-2012 single-branch and network
models).
Open a recent model from the Recent workspaces group, which displays the last 20
workspaces used.
Perform other activities, using the Workspace tab options on the left.

License Information
In the License information group, green icons indicate licensed features and red icons indicate
unlicensed features.
PIPESIM single-branch (wells & pipelines)
required to run single branch simulations
PIPESIM network modeling
required to run network simulations

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Related links:
Workspace Tab Options (p.2)
Workspace Types (p.3)
Workspace Options (p.6)
Tour of the Ribbon (p.15)
Changing the Main Window Layout (p.16)
Managing Floating Panes (p.16)

1.1 Workspace Tab Options

The Workspace tab provides options to manage your PIPESIM* workspace files and preferences.

Option Description
Save Saves the current workspace. If no workspace is open, this option is unavailable.
Save as Saves the current workspace to a different location in the file system. If no workspace is
open, this option is unavailable.
Open Opens an existing workspace. If a workspace containing unsaved changes is already
open, you are prompted to save it.
You can open the following types of models in a workspace:

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Option Description
PIPESIM 2013+ network or well model file (.pips*)
PIPESIM (2007-2012) single-branch model file (.bps)
PIPESIM (2007-2012) network model file (.bpn)
Close Closes an open workspace. If the workspace contains unsaved changes, you are
prompted to save it.
New Creates a new workspace, or opens an existing workspace. By default, the New option
is selected when you start the application.
Help Provides access to the online help, support portal, Schlumberger contact information,
demo videos, case studies (sample model files), and information about the application.
Options Opens the Options window where you can configure unit systems, manage installed
plug-ins, configure GIS map options, and select advanced simulation preferences..
Exit Quits the application. If the workspace contains unsaved changes, you are prompted to
save it.

Related links:
Navigating the Interface (p.1)

1.2 Workspace Types

A workspace contains all of the data for a model. There are two types of workspaces: network-
centric and well-centric. The well-centric workspace mode is essentially a subset of the network-
centric mode that simplifies the user interface by showing user interface elements relevant only to
well modeling applications. Both workspace types use the same model file format (.pips).
Well-centric workspace
Use this workspace type when your focus is specifically on modeling wells only. Some of
the options and viewers for network modeling and simulation are not offered in a well-
centric workspace. When you save the workspace, the mode is retained; the next time you
open the workspace, it will automatically open in well-centric mode.
Network-centric workspace
Use this workspace type when you want to construct a network model and run Network
Simulation tasks to optimize the model. Network-centric mode also includes all the
functionality of well-centric mode. When you save the workspace, the mode is retained;
the next time you open the workspace, it will automatically open in network-centric mode.
You can switch modes easily any time a workspace is open. This is useful, for example, when you
want to extend a single-well model to include other wells and build a production network. On the
Home tab, in the Perspective gallery, click Well or Network.

Related links:
Network-Centric Workspace (p.4)

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Well-Centric Workspace (p.5)

1.2.1 Network-Centric Workspace

A network-centric workspace consists of four main areas: ribbon and context tab, navigation
panes, network diagram, and information area.
Ribbon and contextual tool tab
The ribbon is located at the top of the window. The Network tools tab is contextual; its
content is determined by the core tab selected (Home, Insert, or Format).
Context bar
The context bar appears just below the ribbon and is always viewable. You may use the
context bar to create, edit, and select studies and wells.
Navigation panes
Use the Inputs pane to add and manage network objects in the diagram. Use the Tasks
pane to perform analysis and simulation tasks.

Note: By default, the Tasks pane is not visible. To show the pane, change the window
layout.

Network diagram
The network diagram serves as the canvas on which you build the surface network, using
objects located in the Insert tab. Equipment with missing values is outlined in red. On the
Format tab, you can access additional visualization options such as zoom, icon size, grid
size and style, and object labels.
Information area
Located at the bottom left of the window, this area contains the Message center and
Validation tabs. Each tab opens a dockable pane.

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Related links:
Workspace Types (p.3)

1.2.2 Well-Centric Workspace

A well-centric workspace consists of four main areas: the ribbon and context tab, the navigation
panes, the Well editor, and information area.
Ribbon and contextual tool tab
The ribbon is located at the top of the window. The Well tools tab is contextual; its content
is determined by the core tab selected (Home, Insert, or Format).
Context bar
The context bar appears just below the ribbon and is always viewable. You may use the
context bar to create, edit, and select studies and wells.
Navigation panes
Use the Inputs pane to add or manage wells. Use the Tasks pane to perform analysis
and simulation tasks.

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Note: By default, the Tasks pane is not visible. To show the pane, change the window
layout.

Well editor
This window contains the interactive wellbore schematic on the left and a well properties
area, organized into tabs, on the right.
Information area
Located at the bottom left of the window, this area contains the Message center and
Validation tabs. Each tab opens a dockable pane.

Related links:
Workspace Types (p.3)

1.3 Workspace Options

Use the Options dialog box to configure your workspace environment.

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Related links:
Units (p.7)
Plugins (p.9)
Advanced options (p.9)
Catalog (p.13)
GIS Map options (p.13)

1.3.1 Units
Use the Options dialog box to either select a standard unit system for data display or to create and
manage custom unit systems. You can also quickly select both default and customized unit
systems from the Home tab.

Related links:
Selecting a Standard Unit System (p.7)
Creating a Custom Unit System (p.8)
Importing or Exporting a Custom Unit System (p.8)

Selecting a Standard Unit System

You can select a standard unit system for data display.
1. On the Workspace tab, click Options.
2. In the left pane, click Units.
3. In the Default unit system list, click one of the following items:
Field

Metric
Uses a set of decimalized prefixes (in powers of ten). Although more consistent than
field units, there were still inconsistencies among disciplines. For example, scientists
preferred centimeter gram seconds (CGS), and engineers preferred meter kilogram
seconds (MKS), mainly because engineers were used to larger quantities. Both CGS
and MKS are metric units.
SI
Uses a set of base units that are all from the metric system, but are chosen to provide
consistency. Using SI units makes it easier to compare work done in different countries
and disciplines. Length is provided in meters, mass in kilograms, time in seconds, and
temperature in degrees Kelvin.

Note: The Description and Reference base name fields update based on your selection.

4. Click Close.

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Related links:
Units (p.7)

Creating a Custom Unit System

You can create a custom system of units of measurement for display of input data and results.
1. On the Workspace tab, click Options.
2. In the left pane, click Units.
3. In the Display unit system list, click a predefined unit system to use as a basis (preferably, the
one most similar to the system you want to create).
4. Click Clone.
5. Enter a name for the new unit system in the Name field, and click OK.
6. In the table, change the units of measurement as necessary.
7. Click Close.

Note: You can export, import, rename, or delete custom unit systems.

Related links:
Units (p.7)

Importing or Exporting a Custom Unit System

You can import a custom system of units of measurement for display of input data and results. You
can also save a custom unit system to a local or network drive.
1. On the Workspace tab, click Options.
2. In the Options dialog box left pane, click Units.
3. To select a custom unit system from a local or network drive, perform the following actions:
a. Click Import.
b. Browse to the location of the file, select it, and then click Open.
c. Close the Options dialog box.
4. To save a custom unit system to a local or network drive, perform the following actions:
a. Click Export.
b. Enter the file name, and then click Save.
c. Close the Options dialog box.

Note: You can create, export, rename, or delete custom unit systems. Custom unit systems are
saved in the .cus file format.

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Related links:
Units (p.7)

1.3.2 Plugins
Plugins allow you to extend the functionality of PIPESIM to enable custom modules that have been
developed externally.
User defined flow correlations
User defined equipment

Related links:
Workspace Options (p.6)

User defined flow correlations

Multiphase flow models are fundamental to PIPESIM and an area of ongoing research and
development. To facilitate the testing and use of proprietary models, PIPESIM supports user
defined multiphase flow correlations to calculate the flow pattern, liquid holdup, pressure gradient
and other characteristics of multiphase flow. Additionally, the ability to specify input switches and
report any output variable associated with the user flow correlation is available.
User defined multiphase flow correlations may be written in a variety of languages including c, c++,
Fortran, etc. Self-documenting code templates for two-phase and three-phase models written in c+
+ and Fortran are provided in ..\Program Files\Schlumberger\PIPESIM2014.1\Developer Tools\User Flow
Correlations directory created during the PIPESIM installation.

Related links:
Registering User Flow Correlations (p.7)
Using User defined flow correlations (p.7)

Registering User Flow Correlations

Use the Options dialog box to register a user defined flow correlation plug-in.
1. On the Workspace tab, click Options.
2. In the left pane, click Plugins.
3. Click Register.
4. Browse to and select the desired user flow correlation DLL.
5. Click Open.
The user flow correlation DLL with relevant information is added to the list of plugins.

Related links:
User defined flow correlations (p.9)

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Using User defined flow correlations

1. To define a user flow correlation, from the Home tab, select the Simulation Settings menu and
then the Flow Correlations tab.
2. From the vertical or horizontal flow correlations group, select the desired Source and
Correlation from the drop down menus.
3. For correlations defined with extra input options, a settings button will be displayed so you can
select the desired options.
The settings menu is only available when the Use Global option is selected. When using local
flow correlations, options defined in this settings menu will be applied for all local instances.

Related links:
User defined flow correlations (p.9)

User defined equipment

PIPESIM supports many types of equipment that can be inserted into a flow path to model devices
that affect the fluid (flowrate, pressure, temperature and enthalpy). Examples include pumps,
compressors, heaters, multipliers, chokes, etc.
If you want to model certain specialized or proprietary devices not currently supported by PIPESIM,
you can create a Dynamically Linked Library (DLL) to achieve this. Such devices may include jet
pumps, multiphase boosters, valves, etc.
Self-documenting code templates written in c++ and Fortran are provided in the .. \Program Files
\Schlumberger\PIPESIM2014.1\Developer Tools\User Equipment directory created during the PIPESIM
installation.

Related links:
Registering User Defined Equipment (p.10)
Using User defined equipment (p.9)

Registering User Defined Equipment

1. On the Workspace tab, click Options.

2. In the left pane, click Plugins.
3. Click Register.
4. Browse to and select the desired user equipment DLL.
5. Select a user equipment or flow correlations DLL.
6. Click Open.
The user equipment DLL with relevant information is added to the list of plugins.

Related links:
User defined equipment (p.9)

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Using User defined equipment

Depending on the type of user equipment created, you can add a user defined equipment to the
PIPESIM model from one of three possible locations:
Surface equipment (network or well editor)
Downhole equipment (well editor)
Artificial lift (well editor)
Depending on the specific configuration options defined for the user equipment, you can specify
settings and input variables in the properties editor of the user equipment. Additionally, you may
sensitize on numerical input parameters while running certain single branch tasks (such as PT
Profile, System Analysis, Nodal Analysis). Results may be viewed in both tabular and graphical
form by inspecting the System node result tables and System plots respectively.

Related links:
User defined equipment (p.9)

1.3.3 Advanced options

The Advanced options, under Workspace Options Advanced, allows you to configure
options settings for a faster network simulations.
The Advanced tab contains the following options:

Property Description
PORGRAM The Engine path is the directory where the PIPESIM engine resides. The
PATHS Performance curve import path contains the PIPESIM *.mdb file.
ENGINE Number of processes for Network engine
OPTIONS PIPESIM 2012 (and newer) introduced a parallelized network solver where
you can run network simulations with multiple processors to increase the
speed. The selection for this will be limited to the number of available
processors on your hardware as reported by Windows. The larger the
selected value the faster the network simulation. Set this to a smaller value of
you would like to limit the number of processes used for simulation due to
other running applications that may need processing resources. The
parallelized network solver requires the installation of a compatible version of
Intel MPI (the version in the PIPESIM install kit). Any issues with incompatible
Intel MPI versions (p.12) can be easily resolved by uninstalling the
incompatible version and installing the compatible one.
Network debug codes
For the advanced user and as directed by technical support to enable/disable
optional features deemed temporary or to provide additional specific console
output or problem workaround, these codes are only used during Network
simulation.

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Property Description
Network verbosity level
Indicates how much information is displayed in the engine console during
network simulation. 0 is minimal, 1 is default and higher generally increases
the amount of output.
Single branch debug codes
For the advanced user and as directed by technical support to enable/disable
optional features deemed temporary or to provide additional specific console
output or problem workaround, these codes are used for any operation other
than network simulation.
Single branch verbosity level
Indicates how much information is displayed in the engine console during any
operation. 0 is minimal, 1 is default and higher generally increases the
amount of output.
RESULTS Show engine console
DISPLAY When you run a simulation, the engine output is displayed in a tab called
OPTIONS Engine Console. If this option is not checked, you do not get that tab.
Show engine output files
If this option is checked, a tab will be added and the contents of the output
and summary file will be displayed.
Max. auto-selected case/case group results
Displays only the number of profile results returned and ignores subsequent
results.
This option controls the number of profile plots automatically selected for
initial display in the profile plot.
This option helps improve performance and legibility when several
sensitivities are run.

Related links:
Resolving Intel MPI incompatibility (p.12)

Resolving Intel MPI incompatibility

While multiple Intel MPI versions can be installed on a machine, if any of these versions are
incompatible with PIPESIM such as the Intel MPI version installed with Avocet IAM 2011 (and
older), and was installed last (for example, after a compatible Intel MPI version was already
installed), PIPESIM network simulations will be unable to run with multiple processors.

1. To resolve the MPI incompatibility issue, perform one of the following actions:
Uninstall all Intel MPI versions including the incompatible Intel MPI version (4.01.007 and
older) and any previously installed compatible versions. Then, re-install the compatible
version in the PIPESIM install kit.

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Uninstall Avocet IAM 2011 (which will also uninstall the incompatible Intel MPI version) and
all other Intel MPI versions and upgrade to Avocet IAM 2013 (or newer) which includes a
compatible Intel MPI version.
If you do not want to change the Intel MPI version, you still have the option of running the
network simulation with only one (1) processor by manually selecting this under
Workspace Options Advanced Number of processes for Network engine.
If you have only one (1) Intel MPI version installed and it is the incompatible version, the
PIPESIM network simulation will run, but will default to using only one (1) processor.

Related links:
Advanced options (p.9)

1.3.4 Catalog
Catalog data can be updated to include user defined performance curves that may exist in one of
the older versions of catalog. The import process does not affect standard catalog data of the
destination catalog; it only adds user defined data, if any from the source catalog and merge into
destination catalog.
If you install a newer version of PIPESIM and an older database is found, perform the following
steps:
1. On the Workspace tab, select Options.
2. Click Catalog on the left hand side.
3. Decide if you want to import or export catalog data.

Import You can import from a Previous version of catalog or From file (*.sdf) that you
Source may have exported earlier.
Previous Version:
When this option is selected, the drop down menu Version to import from
becomes active and displays all the previous versions of catalog listed
under the default catalog location. Clicking Import will import and merge
user data if it exists, otherwise, you will get a notification.
From File:
When this option is selected, the drop down menu File to import from
becomes active and allows you to browse to the location where you may
have the catalog file (*.sdf). The import will be successful if the selected file
is a previous version of the catalog and has some user data.
Import Duplicate options are Ignore and Overwrite.
Duplicates In case one of the imported user data has same name as one of the existing
data in destination catalog, the import will be ignored (with Ignore option) or
override the destination catalog with imported data (if overwrite option is
selected).
Export This option exports the current catalog as *.sdf file.

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Related links:
Workspace Options (p.6)

1.3.5 GIS Map options

You can add bookmarks and map services layers from the map options under Workspace
Options GIS map.

LICENSED Bing key

FEATURES If a user acquires a Bing Maps Key through the Bing Maps Account Center:
https://www.bingmapsportal.com/, the following features will be unlocked
(available for use) in PIPESIM:
Address Geocoding: Geocoding is the ability to translate an address
(whether street, ZIP code, city, country, etc.) into a corresponding
geographic location. If a valid Bing Maps Key has been provided,
geocoding can be performed by navigating to GIS map Format Go
location Address.
Additional Basemaps: If a valid Bing Maps Key has been provided,
three Bing Maps basemaps will be added to the top of the basemap
gallery under GIS map Format Basemaps which allow visualization
of imagery at a higher level of detail than what is supported by the default
Esri-provided basemaps.
See Adding Bing Basemaps (p.256) and Zooming to a Specific Map
Coordinate or Address (p.258) for additional information.
Elevation account
If you have your own Geonames account, you can provide the account
name (ID) here. This field should generally not be touched and only be
used in cases where you expect to make an extraordinarily large number of
elevation capture requests and have your own account name which may be
provided here. For more information, see Capturing Elevation (p.276).
ELEVATION Default elevation source
There are 2 sources available for elevation data capture in PIPESIM; SRTM
and ASTER services. Select your preferred option from the dropdown
menu. For more information, see ASTER and SRTM Elevation Data
Sources. (p.22)
BOOKMARKS Bookmarks file
Custom (user-defined) bookmarks may be added to the GIS map using an
XML configuration file. You can navigate to the file and access these
bookmarks by opening the GIS map from the Home tab and selecting them
from the Bookmarks option list. For more information, see Creating a
Custom Bookmark File (p.260).
MAP SERVICE Map services can be added by connecting to an internal GIS server or a service
LAYERS over the Internet. The speed depends on your bandwidth and the server that

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hosts the map layers. You can connect to a web map service or an ArcGIS
map. However, if you do not connect to your internal GIS server or the Internet,
the GIS map cannot display the layers from those sources. Supported map
service types are Web Map Service (WMS), ArcGIS, and Keyhole Markup
Language (KML).
For more information, see Using Map Services (p.264).

Related links:
Workspace Options (p.6)

1.4 Tour of the Ribbon

The ribbon is a command bar that organizes application features into a series of tabs at the top of
the main window. The ribbon replaces traditional menus and toolbars.

The ribbon consists of the following key components:

Quick Access Toolbar
This small toolbar provides quick access to the Save and Save as commands (also
located in the Workspace tab). Click the down arrow to access additional commands,
such as moving the Quick Access Toolbar below the ribbon and minimizing the ribbon.
Core tabs
The Workspace, Home, Insert, and Format tabs appear in both workspace modes.
Contextual tool tabs
These tabs appear under certain circumstances. For example, in network-centric mode,
the Network tools context tab appears above the core tabs.
Context bar
The context bar appears just below the ribbon and is always viewable. You may use the
context bar to create, edit, and select studies and wells.
Tab groups
Within each tab, related features are organized into named groups.

Related links:
Navigating the Interface (p.1)

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1.5 Changing the Main Window Layout

You can change the layout of the main window in network centric mode only. For example, you can
show or hide the Inputs and Tasks panes.
1. On the Home tab, in the Application options group, click Layout and then click a layout view.

2. To return to the default layout (showing the Inputs pane only, on the left), on the Home tab, in
the Application options group, click Return to default.

Related links:
Navigating the Interface (p.1)

1.6 Managing Floating Panes

You can dock, auto hide, and undock the following panes: Inputs, Tasks, Message center, and
Validation.
1. To dock a floating pane, perform the following actions:
a. Right-click the title bar, and then click Dockable.
b. Drag the title bar onto the arrow that represents the desired docked position.

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2. To auto hide a floating pane, perform one of the following actions:

Click Auto-hide (the pin-shaped button).

Note: When the pin is horizontal, auto-hide is active.

When the pin is vertical, auto-hide is inactive (the pane is pinned).

In the View position list, click Auto-hide.

3. To undock a floating pane, perform the following actions:

a. Right-click the title bar, and then turn off Auto hide, if necessary.
b. Right-click the title bar, and then click Float view always.
c. Drag the title bar to move the pane anywhere on the monitor screen.

Note: In well-centric mode, you cannot undock the Wellbore schematic.

Related links:
Inputs Pane (p.18)

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Tasks Pane (p.18)

Information Area Overview (p.19)

1.6.1 Inputs Pane

Use the Inputs pane to manage all equipment in the model. When an object is selected in the
pane, the object is automatically selected in the network diagram (network-centric mode) or
displayed in the Wellbore schematic (well-centric mode). In addition, any open properties pane
or tab automatically displays the properties of the selected object.
In network-centric mode, the pane appears on the left side of the window by default.
In well-centric mode, the pane is not visible since you are not generally dealing with a large
number of model objects. However, if the workspace contains multiple wells, you can quickly
select wells in the Well selector group under the ribbon.

Operation Instructions
Expand or collapse an Double-click the object category.
object tree In network-centric mode, the pane contains a tree for each type of
surface equipment.
In well-centric mode, the pane contains only one tree, and it is for
wells.
Display a command Right-click an object.
menu
Edit an object Double-click the object name, or right-click the object and then click
Edit.
Table 1.1: Pane Operations

Related links:
Managing Floating Panes (p.16)

1.6.2 Tasks Pane

Use the Tasks pane to display simulation tasks in network centric mode only.
Network-centric mode offers five tasks: Network simulation, P/T profile, Nodal analysis,
System analysis, VFP tables, and ESP design.
In a valid model, Network simulation is always available. When the selected object is a well,
source, or junction treated as source, the remaining tasks become available.
When a well is selected, all tasks become available.
By default, the Tasks pane is not visible. (These same tasks appear on the ribbon in the Home
tab.) To show or hide the pane, change the window layout.

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Related links:
Managing Floating Panes (p.16)

1.6.3 Information Area Overview

The information area, located at the bottom of the window, displays all messages related to
application operations.

Pane Description
Message center Displays messages related to application operations.
Validation Displays validation warnings and errors, along with recommendations for
resolution.

Related links:
Message Center Pane (p.19)
Validation Pane (p.20)

Message Center Pane

The Message center pane displays information related to operations performed in the
application. This pane features filtering and sorting.

There are three key types of messages:

Errors
problems that resulted in the termination of an operation
Warnings
problems that do not result in the termination of an operation, but may need attention
Information
information about operations and the status of the application

Operation Instructions
Filter messages by Click the appropriate filter button (Errors, Warnings, Information, or
type Current Study).

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Operation Instructions
You may select multiple filters.

Note: The Current Study filter show messages for the currently open
study only.

Search for a To find messages containing specific text, enter the text in the text box.
message
Delete a message Right-click the message, and then click Clear.
Sort the table To sort the table in ascending or descending order, double-click a column
header.
Copy table data 1. Drag the mouse pointer to select the desired table cells. To quickly
select all table data, click the top left cell.
2. Press CTRL+C.
3. Paste the table data into a document, such as an e-mail message or
spreadsheet.
Table 1.2: Pane Operations

Related links:
Information Area Overview (p.19)

Validation Pane
The Validation pane displays all known issues within the model, such as object properties that
are missing or out of range, sources not linked to fluids, or problems with connections. Clicking the
hypertext in the Context column opens the relevant editor so that you can correct the issue.

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Operation Instructions
Resolve an error 1. Click a message to select the invalid object in the Inputs pane and
network diagram, if visible.
2. Double-click a message to open the appropriate editor where you can
correct the problem.
Sort the table To sort the table in ascending or descending order, double-click a column
header.
Copy table data 1. Select a table row.
2. Press CTRL+C.
3. Paste the table data into a document, such as an e-mail message or
spreadsheet.
Table 1.3: Pane Operations

Related links:
Information Area Overview (p.19)

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2
Building Physical Models
A PIPESIM model is a representation of a flowing system that can be used to simulate fluid flow
through the system. A model can be a single well with or without connected surface piping and
equipment, a pipeline transporting fluid from one point to another, or multiple wells, pipeline, and
surface equipment connected together to represent a large and complex flow network.
PIPESIM modes for building a model include:
Well-centric mode
Network-centric mode
For building a single well with connected surface piping and equipment, well-centric mode is
recommended even though it can be modeled in either mode. On the other hand, building a
pipeline model that does not contain a well or building a network model that consists of multiple
wells and a piping system essentially requires that you use the network-centric mode.

Basic Model Building Workflow

Building a PIPESIM model and performing a simulation involves the following high-level steps:
1. Identify the flowing system to select the appropriate mode, well-centric or network-centric.
2. Select units system based on available data.
3. Select fluid mode (black oil, compositional, etc) and define fluid with or without calibration where
applicable.
4. Add physical elements of the model--such as wells, downhole equipment, and surface
equipment--and establish connections between them.
5. Specify basic minimum data for each model element and specify equations/correlations specific
to model element as required.
6. Apply general simulation settings by specifying your choice of flow correlations, heat transfer
options, environmental data, and other desired settings. These can be applied globally or locally
(to specific model elements).
7. Apply advance simulation settings to control calculations and reporting.
8. Select and define reporting templates based on types of models and/or intended analysis.

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9. Validate the model by addressing validation issues, if any are displayed under the Message
Center.
10.Save the model.
After you build models, you can run simulations.
11.Configure simulation tasks (your choice depends on the type of model and configuration) and
perform simulation.
12.Analyze graphical and tabular results.
For more information, see Running Simulations (p.177).
Well-centric model
In well-centric mode, you see only the wells. The Well editor consists of the Wellbore
schematic pane and the tabs that you use to configure details of the well. From the
Surface equipment tab in the Well editor, you can add and edit surface equipment.
Well-centric mode makes it easier to analyze and edit one or more wells. In well-centric
mode, you can run all PIPESIM single-branch operations such as Nodal Analysis, P/T
Profile, or VFP Tables for analysis.
Network-centric model
In network-centric mode, you can view your entire network including wells, flowlines,
risers, and surface equipment displayed over a network diagram. Network-centric mode
allows access to the full Well editor (available in a floating window). Network-centric
mode allows you to resolve issues for the entire network by running a network simulation.

Note: You can run single-branch operations in network-centric mode by selecting a particular
branch inlet such as a well, a source, or a junction source in the network diagram.
You can switch between well-centric and network-centric mode while a workspace is open. On the
Home tab, in the Perspective Gallery, select Well or Network.

Related links:
Creating or Editing a Well Model (p.23)
Creating or Editing a Network Model (p.96)

2.1 Creating or Editing a Well Model

Use the Well editor (which consists of the Wellbore schematic pane and the tabs that you
use to define the well properties) to create new wells and edit existing ones. A well is one of the
ways fluids can enter (via production well) or leave (via injection well) the network.
A well model is a schematic representation of a well. It contains complete information on the well
including wellbore construction, downhole equipment, artificial lift equipment, completion
information as well as surface equipment as applicable. A well can be created from scratch or
using a template well as starting point.

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Important: To avoid possible conflicts, assign a unique name to each piece of equipment within a
well or any branch. This practice also helps you to identify the object definitively while viewing or
analyzing results.

1. Perform one of the following actions:

To create a new well model, on the Workspace tab in the Well group, click New.
To edit an existing well model, on the Workspace tab in the Well group, click Existing.
To edit an existing well model, on the Workspace tab in the Recent workspaces group,
click an existing model name.
2. On the General tab, define the well type, its status, and the flow direction.

Field Action
Well name Change the name of the well, if necessary.
Active Indicates whether the well is active.

Note: Simulation tasks cannot be performed on an inactive well. If a network

contains an inactive well, that well and the equipment in its branch are ignored
during network simulation.

Well type Select Production or Injection, based on the intended flow direction. The final
solution depends on system hydraulics.
Check Models a check valve for the well and therefore controls the direction of the flow.
valve Block reverse
setting
The most common setting, Block reverse, ensures that flow is always as
intended; i.e., upward for a production well and downward for an injection well.
Block forward
Block forward blocks flow in the intended direction.
None
No flow block exists, so the flow can go in either direction based on system
hydraulics.
3. Add tubular data.
4. Add a deviation survey.
5. Add downhole equipment, if applicable.
6. Add artificial lift, if applicable.
7. Add heat transfer data.
8. Add completions.
9. Add surface equipment.
10.Create a meaningful title and click Save.

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The default title for new and imported models is New workspace.pips.
Each well model is stored in a single input file. (It is not necessary to store each model in a
separate directory.) The models are stored in binary data files with the .pips extension.

Related links:
Adding Tubular Data (p.25)
Adding a Deviation Survey (p.29)
Adding Downhole Equipment (p.32)
Adding Artificial Lift (p.41)
Adding Heat Transfer Data (p.49)
Adding Completions (p.51)
Adding Surface Equipment using the Well Editor (p.91)
Working with Well Tabs and Ribbons (p.92)
Interactive Wellbore Schematic (p.93)

2.1.1 Adding Tubular Data

When you create a new well without using a template, the welbore schematic appears blank
except for the wellhead. You can add casing and tubing to create a simple or detailed wellbore
schematic.
A simple wellbore schematic contains one casing and one tubing. In simple design mode, the
Tubular tab on the Well editor has one table, where you can add the first row for casing and
the second row for tubing detail.
In detailed wellbore schematic you can add multiple casings and tubings. In detailed design mode,
Well editor has two tables, Casing/Liner (which also supports the Openhole type) and
Tubings.

Note: You can add casing or tubing dimensions manually or populate the elements by selecting
from a list of available tubing or casing entries from the Casing catalog or Tubing catalog.

Related links:
Adding Casing and Tubing to a Simple Wellbore Schematic (p.25)
Adding Casing and Tubing to a Detailed Wellbore Schematic (p.27)

Adding Casing and Tubing to a Simple Wellbore Schematic

When you do create a new well without using a template, you typically add casing as the first
object and tubing as the second object to the wellbore schematic. Tubing and casing establish the
structure around which other downhole objects can be added.
1. To add casing in the Well editor, perform one of the following actions:

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On the Tubulars tab, click New (+) in the first row of the table. The casing object also
appears on the Wellbore schematic.
On the Insert tab in the Tubulars group, drag the Casing icon onto the Wellbore
schematic. Release the mouse button when the casing locks onto the wellhead. The
casing object also appears in the table.
2. To add tubing in the Well editor, perform one of the following actions:
On the Tubulars tab, click New (+) in the second row of the table. The tubing object also
appears on the Wellbore schematic.
On the Insert tab in the Tubulars group, drag the Tubing icon onto the Wellbore
schematic. Release the mouse button when the tubing locks into position. The tubing
object also appears in the table.
3. Click either Outside diameter or Wall thickness to display either the outside diameter or wall
thickness of the casing or the tubing in the table's variable column.
4. In the table, enter the remaining properties for the casing or the tubing.
You can use the default casing or tubing, design your own casing or tubing, or select a pre-
configured item from the Casing catalog or the Tubing catalog by clicking the browse
button in the Catalog column.

Field Description
Name Name of the casing or tubing object that will appear on the Wellbore
schematic.
Bottom MD The measured depth of the bottom of the casing or tubing.
ID The inside diameter of the casing or tubing.
Wall thickness The thickness of the casing or tubing wall. If wall thickness is entered, the
(variable column) outside diameter is calculated based on the inside diameter (ID) and wall
thickness.
OD (variable The outside diameter of the casing and tubing.
column)
Roughness The typical value for the absolute pipe roughness for casing or tubing wall
based on the pipe material and surface finish.
Catalog Opens either the Casing catalog or Tubing catalog from which you
can select a standard casing or tubing string. Selections from the catalog
are populated from the database.

Note: When starting from scratch, the tubular table has no data row but a New (+) sign at the
bottom left lets you add rows for casing and tubing. After you add one casing and one tubing, the
New (+) button is no longer displayed, thus preventing you from adding more rows. To add more
casings and tubings to a detailed wellbore schematic, select the Mode Detailed check box. You
also have the option of entering tubing dimensions manually or selecting a specific string from the
Casing catalog or Tubing catalog.

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For more information, see Typical Values (p.487).

Related links:
Casing Catalog Properties (p.242)
Tubing Catalog Properties (p.243)

Adding Casing and Tubing to a Detailed Wellbore Schematic

You can create a more detailed model with multiple tubings and casings. Detailed models are
typically used when the well contains tapered tubings, liners, and openhole sections.
To create a detailed wellbore:
1. In the Well editor on the Tubulars tab, select the Mode: Simple or Detailed option.
Casing and tubing are separated into two tables and each table allows multiple entries.
2. To add new casings, perform one of the following actions:
In the Casing/Liner table, click New (+). The casing string also appears on the Wellbore
schematic.
On the Insert tab in the Tubulars group, drag the Casing icon onto the Wellbore
schematic. Release the mouse button when the casing locks onto the wellhead.
3. To add new tubings, perform one of the following:
In the Tubings table, click New (+). The tubing string also appears on the Wellbore
schematic.
On the Insert tab in the Tubulars group, drag the Tubing icon onto the Wellbore
schematic. Release the mouse button when the tubing locks into position.
The tubing string also appears in the table.
4. In the Casing/Liner table, for each casing item, assign the Section type(Casing, Liner, or
Open hole), add a unique Name, and specify the measured depth (From MD, which is always
zero, and To MD)depending on the Section type.

Note: The casing table is governed by certain rules listed below. Deviating from these rules may
invalidate the model.
a. A new string when added is the default casing; however, you can change it to another type.
b. You can add multiple casings.
c. Casings always start from the wellhead; therefore, you cannot edit the From MD starting
depth.
d. You can add multiple liners.
e. A liner is always referenced to the innermost casing/liner as its parent if the starting depth
(From MD) of a liner has multiple casings/liners around it.
f. A liner must always fit inside its parent casing or liner.

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g. Liner starting depth (From MD) must also fall between the starting depth (From MD) and
bottom depth (To MD) of the parent casing/liner
h. Bottom depth (To MD) of a liner must be below the bottom depth of the parent casing/liner.
i. An openhole section cannot overlap any existing casing/liner. It must always start from the
bottom depth (To MD) of the previous casing/liner at the deepest depth.

5. In the respective tables, enter the remaining properties for either the casing or the tubing.
You can use the default casing or tubing, design your own casing or tubing , or select a pre-
configured item from the Casing catalog or the Tubing catalog by clicking the browse
button in the Catalog column.

Field Description
Section Type Applies to Casing/Liner table only. Available types are Casing, Liner, or
Openhole.
Name Name of the casing, liner, openhole, or tubing objects. The name is displayed
in the Wellbore Schematic.
From MD From measured depth (that is, the depth at the start of a casing or tubing
string). Applies to Casing/Liner table only.
To MD To measured depth (MD) is the bottom of a casing or tubing string.
ID The inside diameter of the casing or tubing.
Wall thickness The thickness of the casing or tubing wall. If wall thickness is entered, the
outside diameter is calculated based on (ID) and wall thickness.
OD (variable The outside diameter of the casing and tubing.
column)
Roughness The typical value for the absolute pipe roughness based on the pipe material
and surface finish. For openhole section, this is the formation wall in contact
with the well.
Catalog Opens either the Casing catalog or Tubing catalog from which you can
select a standard casing or tubing string stored in the Pipesim* database. For
an openhole section, no catalog option is available.

Note: If you are creating a detailed wellbore design and you change your Mode selection from
Detailed to Simple, all casing and tubing entries except the first casing and the first tubing will be
deleted.

Related links:
Casing Catalog Properties (p.242)
Tubing Catalog Properties (p.243)

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2.1.2 Adding a Deviation Survey

Deviation surveys record the trajectory of the wellbore as drilled.
Wells may be deviated for many different reasons, such as:
To increase exposure to producing zones
To intersect a larger number of fractures
To follow a complex geological structure
The directional change can be intentional, as part of a drilling plan; or the change can be a slight
divergence from the plan, in which case, the next tubing section added to the wellbore can begin to
correct the path.
1. In the Well editor, on the Deviation survey tab, enter the survey data, which are common
to all survey types:

Field Action
Survey Type Available options are: Vertical, 2D or 3D. If a well is vertical, no deviation survey is
required. Choice of 2D or 3D survey depends on available survey data.
Depth Enter the upper point in a well from which depth is measured (the selected
reference reference point represents zero depth).
Original RKB
rotary kelly bushing level during drilling
RKB
rotary kelly bushing level
GL
ground level
MSL
mean sea level
THF
tubing head flange level
Wellhead Enter the depth from the depth reference point.
depth For example: if the deviation survey is measured from a kelly bushing 16 ft above
the wellhead, defining a Wellhead depth of 16 ft will ensure that all
measurements relative to the Kelly bushing are correct. In other words, the 16-ft
section above the wellhead will not be included in the well profile used for
simulation.
Bottom The deepest point at which casing, liner, or openhole sections are defined in the
depth Tubulars tab. This is a read-only field.
2. If you selected 2D or 3D for the Survey type, the Deviation survey tab displays additional
properties and a table to define wellbore trajectory.
a. Define calculation options based on available data.

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Field Action
Dependent Available options are: MD, TVD or Angle
parameter The dependent parameter is one that is unknown and needs to be calculated
based on available values of others. A typical 2D survey has MD and TVD data
available making angle the dependent parameter.
Calculation Available options are: Tangential method or Minimum curvature method.
method When the Dependent parameter is MD or Angle, the Calculation method is
automatically set to Tangential method; however, with TVD as Dependent
parameter, both these methods are available to select.
Tangential method
Tubing/casing length is calculated, assuming straight pipe segments between
survey points.
Minimum curvature method
The two straight line segments of the tangential method are replaced with a
circular arc. This is accomplished by applying a ratio factor, based on the
amount of bend in the well path between the two points (the dogleg angle).
b. In the Deviation survey table, enter the new tubing segments that will divert the wellbore
trajectory from true vertical. Click New (+) to add additional rows as required.

Field Action
MD Enter the measured depth (MD) at any survey point in the well measured
relative to Depth reference.
If the well deviates from true vertical, MD will always be greater than TVD.
MD must be entered in the ascending order as you go down the table.
TVD Enter the true vertical depth (TVD), which is the actual vertical depth of the
tubing from the depth reference.
Horizontal Displays the calculated cumulative horizontal displacement of the well.
displacement
Angle Enter the angle deviation from true vertical.
Angle is usually the Dependent parameter in a 2D survey.
Azimuth (used in 3D surveys only)
Enter the angle of the wellbore direction relative to due north, as projected
perpendicular to a horizontal reference plane.
By definition, if the wellbore direction is due north, the azimuth is 0. From
there, East = 90, South = 180, and West = 270.
Max dogleg (used in 3D surveys only)
severity Enter the maximum change of direction allowed over a specified length.

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Note: By default, the data appears in tabular format. Each row in the table represents survey data
for a new wellbore section (indicating a change in borehole trajectory). Click the button below the
table to switch between tabular format and chart format.

c. Click New (+) in the Deviation survey table to add a row for each new wellbore section
(indicating a new borehole trajectory).

Related links:
Azimuth (p.31)
Measured Depth and True Vertical Depth (p.31)

Azimuth
This figure illustrates how azimuth is determined. For drilling purposes, azimuth refers to a point
below the horizon, projected upward.

Related links:
Adding a Deviation Survey (p.29)

Measured Depth and True Vertical Depth

This graphic shows the difference between Measured Depth (MD) and True Vertical Depth (TVD).
These are only equivalent when a well is completely vertical.

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Related links:
Adding a Deviation Survey (p.29)
Adding Heat Transfer Data (p.49)

2.1.3 Adding Downhole Equipment

You can drag downhole equipment directly onto the Wellbore schematic, or you can add
equipment using the table in the Downhole equipment tab.

Note: Certain types of equipment, such as chokes and separators, can be used both in the
wellbore and on the surface.

To add downhole equipment:

1. Open the Well editor, and then perform one of the following actions:
On the Insert tab in the Downhole equipment group, drag an equipment icon to the
appropriate position on the Wellbore schematic.
Downhole equipment appears under wellbore and at the same time it also gets added to the
equipment table under Downhole equipment tab.

Important: When you add specific downhole equipment like artificial lift equipment or a
completion, it is added to the respective tables under artificial lift tab or completions tab.

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Click the Downhole equipment tab, and click New (+) in the installed equipment table.
Equipment is added to the table and also displays in the Wellbore schematic.
2. In the table, complete the following fields for the newly added equipment.

Field Action
Equipment Select the equipment type. Available types of equipment are: Choke, Packer,
Separator, Sliding sleeve, SSSV, Tubing plug, User Equipment (available only after
User Equipment is created), and Engine Keyword Tool.
Name Enter a unique name for the equipment to avoid any conflict with other equipments
and make it easier to identify the equipment in result table.
Active Select this check box to activate the equipment.
In the Wellbore schematic, deactivated equipment is outlined in red. If the check
box is cleared, that equipment will be ignored during simulation.
MD Enter the measured depth at which the equipment is installed.
If you dragged the equipment icon onto the Wellbore schematic, MD is
approximated. Enter a more accurate value, if necessary.
3. Click a row in the installed equipment table to display specific properties for that equipment
type. This displays equipment editor for the selected equipment below the table.
4. In the properties editor section, enter any additional properties for the equipment.

Related links:
Choke Properties (p.33)
Packer (p.36)
Separator (Downhole) (p.36)
Sliding Sleeve (p.37)
Sub-Surface Safety Valve (p.38)
Tubing Plug (p.38)
User defined equipment (p.9)
Engine Keywords (p.40)

Choke Properties
A choke is a device that limits flow by mechanically constricting the cross-sectional area through
which fluid flows. The fluid velocity increases through the constriction and a pressure loss occurs.

Important: Downhole chokes and surface chokes use the same properties, although they are
created differently and appear differently in the Well schematic.

A surface choke is not part of wellbore schematic. It appears on surface schematic as below:

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Choke Properties

Property Description
Name Unique name of the choke.
Active Select this check box to activate the choke so that it will be used during simulation.
Clear the check box to deactivate and the choke will be bypassed during simulation.

General Choke Properties

Property Description
Subcritical Select a correlation from the list. (All correlations except Mechanistic and
Correlation API14B require hydrocarbon liquids at Stock tank conditions.)
Critical Select a correlation from the list. Can be used to set the critical flowrate. This
Correlation may not match the subcritical flow at the critical pressure ratio, so the
subcritical flow correlation is adjusted to ensure that the flow is correct at the
critical pressure.
Bean size Enter the diameter of the choke bean. The bean size represents the diameter
of the available flow area assuming that the constriction is circular.
Critical pressure Used to determine the downstream pressure when critical flow occurs in the
ratio choke. You can specify a value or have it calculated. If you select Calculate,
the calculations are performed using the Ashford-Pierce method.
Tolerance Tolerance for identification of critical flow conditions (given as a percentage or
fraction)
Upstream pipe ID Enter the inside diameter of the pipe upstream of the choke.
Measured depth Downhole location of the choke

Advanced Choke Properties

Property Description
Gas Phase flow (Used in the Mechanistic correlation) Flow coefficient for the gas
coefficient phase. For API14B compatibility, set this to 0.9.
Liquid Phase flow (Used in the Mechanistic correlation) Flow coefficient for the liquid
coefficient phase. For API14B compatibility, set this to 0.85.
Table 2.1: Flow coefficients

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Property Description
Discharge Used to calculate the flow coefficients.
coefficient
Fluid heat capacity Normally calculated, but can be specified. The valid range is 0.7 to 2.
ratio (Cp/Cv) Typically it is 1.26 for a natural gas, 1.4 for a diatomic gas. It is used to
calculate the Critical pressure ratio if that is set to 0.
Y at critical point Gas expansion factor at critical flow. Normally, it is calculated, but it can be
specified. The valid range is 0.5 to 1. It is used to modify the pressure drop
equation to allow for gas compressibility.
Table 2.2: Choke parameters

Property Description
Flowrate Flowrate to identify critical flow.
Pressure ratio Pressure ratio to identify critical flow.
Sonic upstream velocity Sonic upstream velocity to identify critical flow.
Sonic downstream velocity Sonic downstream velocity to identify critical flow.
Table 2.3: Identification of Critical and Supercritical Flow

The choke model calculates the pressure ratio across the choke for the current flowrate. The
pressure ratio calculated is then categorized as subcritical, critical, or supercritical based on criteria
defined by the user. Use the check boxes to define the criteria for identification of critical and
supercritical flow. Note the following behaviors:
Clearing all the check boxes prevents identification of critical and supercritical flow, so flow is
always subcritical. Do this for API14B compatibility.
If more than one check box is selected, critical flow will be identified by any of the selected
criteria that are met.

Property Description
Adjust sub-critical Adjust subcritical correlation to match flowrate predicted by critical
correlation correlation.
Print detailed calculations Detailed choke calculation output. It appears on your terminal
screen and on the primary output page.
Table 2.4: Miscellaneous options

For more information, see Choke (p.354).

Related links:
Adding Surface Equipment using the Well Editor (p.91)
Adding Downhole Equipment (p.32)
Adding Surface Equipment using the Network Diagram (p.102)

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Packer
A packer is a downhole device used in almost every well to isolate the annulus from the production
conduit, enabling controlled production, injection, or treatment. A typical packer assembly
incorporates a means of securing the packer against the casing or liner wall (such as a slip
arrangement), and a means of creating a reliable hydraulic seal to isolate the annulus (typically by
means of an expandable elastomeric element). A packer is generally placed close to the foot of the
tubing, shortly above the production zone.
The role of the packer in PIPESIM* is simply to define the flow path of the produced or injected
fluid. No simulation is performed on the packer itself.
On the Wellbore schematic, a packer appears as follows:

Property Description
Name Unique name for the packer
Active Status of the packer. If unchecked, the packer will be bypassed and cannot
block flow.
Measured depth Downhole location of the packer

Related links:
Adding Downhole Equipment (p.32)

Separator (Downhole)
Downhole separator discards the separated stream while allowing the primary fluid to pass through
it. Typically downhole separators are used upstream of certain equipment like ESP, Rod-pump,
and so forth.

Property Description
Name A unique name for the Separator
Active Status of the Separator. If unchecked, the separator will be bypassed and allow
fluid pass through it without separation.
Discarded Phase to be removed (Gas, Water, or Liquid)
stream
Efficiency Amount of material (measured in a percentage or fraction) removed from the
product stream at in stiu condition. For example, a water separator with 90%
efficiency removes 90% of the water. From the point downstream of the
separator, the flow model reflects only the remaining fluids.
MD Downhole location of the separator

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In the wellbore, you can use a separator to remove a single phase (gas, water, or liquid) from the
fluid stream. (On the surface, you can use a two-phase or three-phase separator.)
On the Wellbore schematic, a downhole separator appears as follows:

Related links:
Adding Downhole Equipment (p.32)

Sliding Sleeve
A sliding sleeve is a device that can be operated to provide a flow path between the production
conduit and the annulus. It uses a system of ports that can be opened or closed by a sliding
component that is generally controlled and operated by slickline tool string.
The role of the sliding sleeve in PIPESIM* is simply to define the flow path of the produced or
injected fluid. No simulation, for example as in pressure loss, is performed on the sliding sleeve
itself.
On the Wellbore schematic, an open sliding sleeve appears as follows:

On the Wellbore schematic, a closed sliding sleeve appears as follows:

Property Description
Name A unique name for the Sliding sleeve
Active/Open Status of the Sliding sleeve. If the sliding sleeve is open, fluid may flow from
the tubing to the annulus or vice versa. If closed, no fluid may flow between
the tubing an annulus.
Measured depth Downhole location of the sliding sleeve

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Note: For a sliding sleeve to convey fluids from a completion through the tubing, the sliding sleeve
must be positioned at the exact same depth as the completion.

For more information, see Multilayer Completions (p.87).

Related links:
Adding Downhole Equipment (p.32)

Sub-Surface Safety Valve

A sub-surface safety valve (SSSV) is a safety device installed in the upper wellbore to shut off
production in an emergency, particularly for offshore wells.
Pressure drop is calculated across the SSSV using the same equation used to model chokes, and
is generally sub-critical flow.
On the Wellbore schematic, a sub-surface safety valve appears as follows:

Property Description
Name A unique name for the SSSV
Active Status of the SSSV. If unchecked, the SSSV will be bypassed during
simulation.
Bean size Size of the passage available for flow
Measured depth Downhole location of the SSSV

For more information, see Choke Subcritical Flow Correlations. (p.357)

Related links:
Adding Downhole Equipment (p.32)

Tubing Plug
A tubing plug prevents flow through tubing in a wellbore.
The role of the tubing plug in PIPESIM* is simply to define the flow path of the produced or injected
fluid. No simulation is performed on the tubing plug itself.
On the Wellbore schematic, a tubing plug appears as follows:

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Property Description
Name A unique name for the tubing plug
Measured depth Downhole location of the top of tubing plug (especially when length is
provided)

Related links:
Adding Downhole Equipment (p.32)

User defined equipment

PIPESIM supports many types of equipment that can be inserted into a flow path to model devices
that affect the fluid (flowrate, pressure, temperature and enthalpy). Examples include pumps,
compressors, heaters, multipliers, chokes, etc.
If you want to model certain specialized or proprietary devices not currently supported by PIPESIM,
you can create a Dynamically Linked Library (DLL) to achieve this. Such devices may include jet
pumps, multiphase boosters, valves, etc.
Self-documenting code templates written in c++ and Fortran are provided in the .. \Program Files
\Schlumberger\PIPESIM2014.1\Developer Tools\User Equipment directory created during the PIPESIM
installation.

Related links:
Registering User Defined Equipment (p.10)
Using User defined equipment (p.9)

Registering User Defined Equipment

1. On the Workspace tab, click Options.

2. In the left pane, click Plugins.
3. Click Register.
4. Browse to and select the desired user equipment DLL.
5. Select a user equipment or flow correlations DLL.
6. Click Open.
The user equipment DLL with relevant information is added to the list of plugins.

Related links:
User defined equipment (p.9)

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Using User defined equipment

Depending on the type of user equipment created, you can add a user defined equipment to the
PIPESIM model from one of three possible locations:
Surface equipment (network or well editor)
Downhole equipment (well editor)
Artificial lift (well editor)
Depending on the specific configuration options defined for the user equipment, you can specify
settings and input variables in the properties editor of the user equipment. Additionally, you may
sensitize on numerical input parameters while running certain single branch tasks (such as PT
Profile, System Analysis, Nodal Analysis). Results may be viewed in both tabular and graphical
form by inspecting the System node result tables and System plots respectively.

Related links:
User defined equipment (p.9)

Engine Keywords
You can insert this tool in a well or as a surface equipment. The Engine Keyword Equipment writes
to the engine input file the keywords inline and entered by you.
To use the Engine keywords tool, perform the following steps:
1. Double click a well to open the Well Editor.
2. Drag and drop the Engine keywords equipment on the well.
The Downhole equipment tab is active to include the engine keywords parameters.
3. Click the Downhole equipment tab and update (if necessary) the engine keywords
parameters:

Name: Name of the engine surface equipment.

Active You can specify if the unit is active or not.
Measured depth The depth of the equipment in the well.

Note: The Measured depth parameter is only available in the Well Editor.

Engine keywords Enter the keyword used by the engine

For more information, see Keyword Reference (p.511).

Related links:
Adding Downhole Equipment (p.32)
Adding Surface Equipment using the Network Diagram (p.102)

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2.1.4 Adding Artificial Lift

Artificial lift refers to the use of artificial means to increase the flow of liquids, such as crude oil or
water, from a production well.
Generally this is achieved by the use of a mechanical device inside the well or by decreasing the
weight of the hydrostatic column by injecting gas into the liquid some distance down the well.
Artificial lift is needed in the well when there is insufficient pressure in the reservoir to lift the
produced fluid to the surface, but often used in naturally flowing wells to boost flowrate. PIPESIM
provides options to model several types of artificial lift equipments as indicated below:
Gas Lift
ESP (Electrical Submersible Pump)
PCP (Progressive Cavity Pump)
Rod Pump
You can model any one of these artificial lift systems in a PIPESIM well or combine two or more of
these systems to create a composite lift well.

Related links:
Adding a Gas Lift Injection Point (p.41)
User defined equipment (p.9)
Adding an ESP (p.12)
Adding a Progressive Cavity Pump (PCP) (p.46)
Adding a Rod Pump (p.48)

Adding a Gas Lift Injection Point

PIPESIM* allows definition of gas lift injection points for modeling gas lift systems. Gas lift is the
process of raising or lifting fluid from a well by injecting gas down the well through the tubing,
casing, annulus, or riser. Injected gas aerates the wellbore fluid making it lighter and thus
significantly reduces back pressure to the producing reservoir.
PIPESIM models simplified form of Gas Lift using single or multiple gas lift injection ports installed
at known locations in the wellbore and each injection port is assigned with a fixed quantity of
injection gas. This simplified method assumes that sufficient injection pressure is available and
also the port size is suitable to fully inject the quantity of lift gas specified at each port.

Note: PIPESIM only models the continuous injection process.

1. In the Well editor, click the Artificial lift tab,

2. Perform one of the following steps to add a gas lift injection point:
Click New (+) at the bottom of the table and select Gas lift injection as the equipment.
Drag the Gas lift injection icon in the artificial lift group to the well tubing in the schematic.
3. Click the row for the equipment added above to display the properties.

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4. Enter the Gas lift injection properties as described in the table.

Field Action
Name Enter the name of the gas lift injection point. A unique name for each gas lift
injection point is required.
Active Select this checkbox to indicate the injection point is in operation. If unchecked, no
lift gas will be injected through the port.
Measured Depth (MD) of the specified gas lift injection port
depth
Injection gas Quantity of injection gas through an injection port can be specified in one of the
rate following ways:
Injection gas rate
Actual (fixed) amount of lift gas to be injected. PIPESIM always injects this
amount of gas at the specified depth, assuming that the port size and injection
pressure is suitable to inject the specified quantity.
Set GLR to
Injection rate that is calculated to ensure that the stock tank gas lift ratio of the
tubing fluid downstream of the injection point is equal to this value. If this
value is less than the gas lift ratio of the tubing fluid upstream of the injection,
PIPESIM removes the gas.
Increase GLR by
Injection rate that is calculated where the stock tank gas lift ratio of the tubing
fluid is increased by an amount equal to this value.
5. Specify properties of the injected gas in one of the following ways:
To enter a specific gravity associated with a fluid, click Specify gas specific gravity and
enter the value.
To specify a fluid model, click Use fluid model and select a fluid from the of available pre-
defined fluids list.

Note: If a fluid model is selected, gas specific gravity with be used from the specified fluid model.
You can also create a new fluid by clicking New (+) or edit an existing fluid by clicking Edit.

6. Enter the Optional data information.

Field Action
Valve port diameter Enter the diameter of the operating gas lift valve port (orifice).
Surface injection pressure Enter the gas lift injection surface pressure (upstream of the
surface injection choke).
Surface injection Enter the surface temperature of the injection gas.
temperature

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Note: If you enter the optional information, it does not affect the amount of gas that is passed
through the gas lift point. However, PIPESIM* uses this data for additional calculations. For
example, if you enter the Valve port diameter, PIPESIM calculates the pressure drop across the
valve and the Joule-Thomson temperature change. If you require the Alhanati instability check,
PIPESIM uses this data in the calculations. To set this, write the information as Single branch
keywords in the Advanced tab of Simulation settings.

7. To add multiple injection points, repeat the preceding steps.

Related links:
Creating or Editing Fluid Models (p.146)

User defined equipment

PIPESIM supports many types of equipment that can be inserted into a flow path to model devices
that affect the fluid (flowrate, pressure, temperature and enthalpy). Examples include pumps,
compressors, heaters, multipliers, chokes, etc.
If you want to model certain specialized or proprietary devices not currently supported by PIPESIM,
you can create a Dynamically Linked Library (DLL) to achieve this. Such devices may include jet
pumps, multiphase boosters, valves, etc.
Self-documenting code templates written in c++ and Fortran are provided in the .. \Program Files
\Schlumberger\PIPESIM2014.1\Developer Tools\User Equipment directory created during the PIPESIM
installation.

Related links:
Registering User Defined Equipment (p.10)
Using User defined equipment (p.9)

Registering User Defined Equipment

1. On the Workspace tab, click Options.

2. In the left pane, click Plugins.
3. Click Register.
4. Browse to and select the desired user equipment DLL.
5. Select a user equipment or flow correlations DLL.
6. Click Open.
The user equipment DLL with relevant information is added to the list of plugins.

Related links:
User defined equipment (p.9)

Using User defined equipment

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Depending on the type of user equipment created, you can add a user defined equipment to the
PIPESIM model from one of three possible locations:
Surface equipment (network or well editor)
Downhole equipment (well editor)
Artificial lift (well editor)
Depending on the specific configuration options defined for the user equipment, you can specify
settings and input variables in the properties editor of the user equipment. Additionally, you may
sensitize on numerical input parameters while running certain single branch tasks (such as PT
Profile, System Analysis, Nodal Analysis). Results may be viewed in both tabular and graphical
form by inspecting the System node result tables and System plots respectively.

Related links:
User defined equipment (p.9)

Adding an ESP
The electric submersible pump (ESP) is perhaps the most versatile of the artificial lift methods. The
ESP comprises a downhole pump, electric power cable, motor, and surface controls. In a typical
application, the downhole pump is suspended on a tubing string hung on the wellhead and is
submerged in the well fluid. The pump is close-coupled to a submersible electric motor that
receives power through the power cable and surface controls. The ESP has the broadest
producing range of any artificial lift methods.
To simulate an ESP, PIPESIM* maintains a database of manufacturers and models from which
you can select. For each model the diameter, minimum and maximum flow rate, and base speed
are provided. A performance plot of the ESP is also available.
1. In the Well editor, click the Artificial lift tab.
2. Perform one of the following actions:
Click New (+) at the bottom of the table and then click ESP as the Equipment to be used for
the artificial lift.
Drag the ESP icon in the Artificial lift group to the well tubing in the schematic.
3. Click the row in the table for the equipment added above to display the properties for that
equipment.
4. Configure the appropriate properties.
For more information, see Electric Submersible Pumps (ESP) (p.390).

Related links:
ESP Properties (p.44)

ESP Properties
The following tables explain the different ESP properties.

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General Properties

Property Description
Name Name of the Electrical Submersible Pump. A unique name is required.
Active Specifies whether the pump is in operation. If inactive, the pump is bypassed
during simulation.
Measured depth Depth of the specified ESP (MD)

Performance Data Properties

Property Description
Manufacturer Pump manufacturer (from catalog).
Model Model name or number of the pump (from catalog).

Note: To select an ESP from the catalog, select the catalog button and
choose the appropriate manufacturer and model. List of pump displayed is
automatically filtered based on casing inside diameter at pump location and
also the operating flowrate and operating frequency you specified.

Diameter Diameter of the pump for the model selected from catalog
Min flowrate Minimum recommended flowrate for pump selected from catalog
Max flowrate Maximum recommended flowrate for the pump selected
Base frequency The frequency used for the base performance curve (generally 60 Hz for
ESPs).
Operating The frequency at which the pump motor is expected to run.
frequency
Operating speed The actual operating speed of the pump in RPM or cycles per minute. For
both Operating frequency and Operating speed, if one is specified, the
other is calculated.

Note: The operating speed is adjusted to the operating frequency based on

the Pump speed factor defined in Simulation Settings in the Advanced tab
under Miscellaneous options.

Stages The actual number of stages of the ESP. This can be selected from a drop-
down list of available stages (stored in catalog) or entered manually.
Head factor Allows the pump head to be adjusted (default = 1).
Flowrate factor Allows the pump flowrate to be adjusted.
Power factor Allows the pump power requirement to be adjusted.

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Calculation Options Properties

Property Description
Viscosity All pump performance curves are based on water systems. This option
correction corrects for oil viscosity.
Gas separator Indicates whether a gas separator is installed. If checked, a gas separator
present will be installed upstream of ESP. Separated gas will be discarded.
Separator The efficiency of the gas separator. This indicates the amount of free gas that
efficiency is removed. For example, a 90% efficiency indicates 90% of free gas at pump
intake condition will be discarded.
Stage by stage Stage by stage calculation is more rigorous that takes into account losses
calculation between stages of ESP and therefore gives realistic results across the pump

Performance Curve and Variable Speed Curve Tabs

To change the data format from a chart to a table, click the table-shaped View data in a table
button beneath the plot, or right-click the chart and click View table.
To change the data format from a table to a chart, click the chart-shaped View data in a chart
button beneath the table, or right-click the table and click View chart.

Related links:
Adding an ESP (p.12)

Adding a Progressive Cavity Pump (PCP)

A PCP is a special type of rotary positive displacement pump sometimes referred to as a single-
screw pump. PCP performance is based on the volume of fluid displaced through the pump.
1. In the Well editor, click the Artificial lift tab.
2. Perform one of the following actions:
Click New (+) at the bottom of the table and then click PCP as the Equipment to be used
for the artificial lift.
Drag the PCP icon in the Artificial lift group to the well tubing in the schematic.
3. Click the row in the table for the artificial lift added in step 2 to display the properties for that
equipment.
4. Configure the appropriate properties on each tab.

Related links:
PCP Properties (p.46)

PCP Properties
The following tables describe the different PCP properties.

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General Properties

Property Description
Name Name of the PCP. A unique name is required.
Active Specifies whether the pump is in operation. If unchecked, the pump is
bypassed during simulation.
Measured depth Depth of the PCP in the wellbore (MD)

Performance Data Properties

Property Description
Manufacturer Manufacturer of the pump (from catalog).
Model Model of the pump (from catalog)
Diameter Diameter of the pump for the model selected (from catalog).
Nominal rate The actual volumetric flowrate that the pump would produce, if it were pumping
with no back-pressure at its discharge (m3/sec or ft3/min).
Base speed The frequency at which the performance curve is defined.
Operating speed The actual operating speed of the pump in RPM or cycles per minute. For both
Operating frequency and Operating speed, if one is specified, the other is
calculated.

Note: The operating speed is adjusted to the operating frequency based on the
Pump speed factor defined in Simulation Settings in the Advanced tab under
Miscellaneous options.

Top Drive Specifies whether the drive is a top-drive or a bottom-drive. This is used for
torque calculations.
Rod Diameter Specifies the rod diameter (top drive only).
Head factor Allows the pump head to be adjusted to better match field performance data or
account for wear (default = 1).
Flowrate factor Allows the pump flowrate to be adjusted.
Power factor Allows the pump power requirement to be adjusted.

Calculation Options Properties

Property Description
Viscosity correction Allows a viscosity correction factor to be applied to account for reduced
slippage.
Gas separator present Allows a gas separator to be modeled.
Separator efficiency Specifies efficiency of the gas separator (default = 100%).

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Performance Curve and Variable Speed Curve Tabs

To change the data format from a chart to a table, click the table-shaped View data in a table
button beneath the plot, or right-click the chart and click View table.
To change the data format from a table to a chart, click the chart-shaped View data in a chart
button beneath the table, or right-click the table and click View chart.

Related links:
Adding a Progressive Cavity Pump (PCP) (p.46)

Adding a Rod Pump

The rod pump uses a surface power source to drive a downhole pump assembly. The beam pump
is the most popular rod pump system because of its simple structure, flexibility, and longevity. The
system consists of the pumping unit, sucker rod, and pump. The pump unit is the main surface
equipment of the rod pump system. The beam-balanced pumping unit transforms the circular
movement of the crank to the up and down swing of the horse head using the connection rod
between the beam and crank.
1. In the Well editor, click the Artificial lift tab.
2. Perform one of the following actions:
Click New (+) at the bottom of the table and then click Rod pump as the Equipment to be
used for the artificial lift.
Drag the Rod pump icon in the Artificial lift group to the well tubing in the schematic.
3. Click the row in the table for the artificial lift added in step 2 to display the properties for that
equipment.
4. Configure the appropriate properties on each tab.

Related links:
Rod Pump Properties (p.48)

Rod Pump Properties

The following tables explain the different rod pump properties.

General Properties

Property Description
Name Name of the rod pump.
Active Specifies whether the pump is in operation.
Measured depth Measured depth to the bottom of the rod pump.
This is a required value. The value cannot be less than zero.

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Performance Data Properties

Property Description
Nominal rate The actual volumetric flowrate that the pump would produce, if it were
pumping with no back-pressure at its discharge.
Maximum DP The maximum pressure rise the device is allowed to exhibit (psi or bar). This
property is used to prevent excess rod loading.
Maximum power The maximum power the device is allowed to draw (hp or kw). This property is
used to prevent excess rod loading.
Drive rod This property allows the pipe cross-section area to be reduced, to account for
diameter the presence of a drive rod for a pump.

Calculation Options Properties

Property Description
Gas separator If checked, a gas separator is installed to remove free gas before the
present produced fluid enters the pump. Separated gas will be discarded to annulus
between tubing and casing strings.
Separator efficiency The efficiency of the gas separator if installed. A 90% separation efficiency
indicates that 90% of free gas available at pump intake condition will be
removed.
Recombine gas at If checked, the separated gas recombines with the produced fluid at the
wellhead wellhead.

Related links:
Adding a Rod Pump (p.48)

2.1.5 Adding Heat Transfer Data

Heat transfer can be modeled by entering the single heat transfer coefficient (U value) or by
entering multiple values in a table.
1. To define the heat transfer data, in the Well editor, click the Heat transfer tab.

Note: The information in the Heat transfer tab changes based on the selected U Value input
method and the Ambient temperature input method.

2. Select the U Value input method and Ambient temperature input method.

Field Action
U Value input Perform one of the following actions:
method Click Single, enter the value and select the appropriate units.

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Field Action
Click Multiple, select the appropriate Depth option (MD or TVD) and
enter U Value at given depths. The U values at all other depths will be
interpolated based on measured depth (MD).
U Value U value or heat transfer coefficient
Ambient Perform one of the following actions:
temperature Click Single, enter the soil temperature at wellhead with the appropriate
input method unit. The Ambient temperature (surrounding formation temperature) at
any point in the wellbore will be interpolated between the entered Soil
Temperature at wellhead and the known Reservoir temperature
specified in the Completions tab of Well editor based on depth (TVD).
Click Multiple, select the appropriate Depth option (MD or TVD) and
enter Ambient temperature at given depths. The Ambient temperature at
all other depths will be interpolated based on true vertical depth (TVD) .
3. To add more rows to the table, click New (+).

Note: By default, the data appears in a plot. Click the button below the plot to switch between plot
format and tabular format.

For more information, see Overall Heat Transfer Coefficient (p.399).

Related links:
Measured Depth and True Vertical Depth (p.31)

Measured Depth and True Vertical Depth

This graphic shows the difference between Measured Depth (MD) and True Vertical Depth (TVD).
These are only equivalent when a well is completely vertical.

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Related links:
Adding a Deviation Survey (p.29)
Adding Heat Transfer Data (p.49)

2.1.6 Adding Completions

In PIPESIM*, a completion refers to the point or interval of contact(s) between wellbore and the
reservoir. A completion includes a definition of an Inflow Performance Relationship (IPR) and the
fluid that is associated with the producing reservoir as well as some of the mechanical wellbore
configuration (for example: gravel pack, etc.) to account for pressure drop between the reservoir
and the wellbore. Completion characteristics such as fracture geometry, gravel packing, perforation
parameters and so on, may be described as part of the IPR. A completion may contain perforations
(with casing) or be openhole (no casing). Only one set of perforations are allowed per completion.

Note: Any completion changes that you make while interacting with the Wellbore schematic will
be reflected in the Completions table, such as adding a completion or changing the depth of a
completion. Likewise, any changes that you make on the Completions tab appear in the
Wellbore schematic.

1. Add a completion to the Wellbore schematic by performing one of the following actions:
On the Insert tab in the Downhole equipment group, drag the Completion icon to the
appropriate position on the Wellbore schematic.

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On the Completions tab, click New (+) at the bottom of the table and select whether the
Geometry profile is a vertical or horizontal completion.

Note: By default, if the completion is created in a wellbore section within 10 degrees from
horizontal, PIPESIM creates a horizontal completion; otherwise, PIPESIM creates a vertical
completion. You can override this designation. Based on the designated completion (horizontal or
vertical), the list of selectable IPR models changes.

2. To reposition the Completion object, perform one of the following actions:

On the Wellbore schematic, drag the Completion object to another location.
On the Completions tab, define the completion depth.
For Single point completions, enter the Middle MD.
For Distributed completions, enter the Top MD and Bottom MD.

Note: The Type property displays the completion type (Perforated or Openhole). You
cannot change this value in the Completions tab.

3. On the Completions tab, define the completion.

To select the completion that you want to define, either click the completion on the Wellbore
schematic, or click the appropriate row in the Completions table.

Note: When defining completions, the selections available in the Completions tab change based
on whether the well completion is vertical or horizontal, and whether the fluid entry is single point or
distributed.

a. If the completion is active, ensure that the Active check box is selected.
An inactive completion will ignore the completion and there will be no contribution.
b. Select the IPR model.
The IPR models available for selection change based on the selection made for the Fluid
entry and the Geometry profile.
c. Define the completion properties, reservoir conditions, and fluid model associated with the
completion.
You define these properties on the tabs displayed beneath the Completions table.

Related links:
IPR Options and Applicability Table (p.53)
Multilayer Completions (p.87)
Associating Zones with Completions (p.90)
Creating or Editing Fluid Models (p.146)

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IPR Options and Applicability Table

The IPR models that are available are based on the Geometry profile and the Fluid entry
selected.

Geometry Profile Fluid Entry IPR Model

Vertical Single Point Well PI (gas, liquid)
Vogel (liquid)
Fetkovich (liquid)
Jones (liquid, gas)
Backpressure (gas)
Darcy (gas, liquid)
Forchheimer (gas)
Hydraulic Fracture (liquid, gas)
Horizontal Single Point Joshi (liquid, gas)
Babu & Odeh (liquid, gas)
Horizontal Distributed Distributed PI (liquid, gas)
Joshi (liquid, gas)
Babu & Odeh (liquid, gas)

Related links:
Vertical Completions Overview (p.53)
Horizontal Completions Overview (p.60)
Defining the Skin (p.65)
Multi-rate Well Test Data (p.87)

Vertical Completions Overview

The vertical completion models flow between the reservoir and bottomhole using an Inflow
Performance Relationship (IPR).
The following wellbore schematic shows a vertical completion named VertComp.

Related links:
Inflow Performance Relationships for Vertical Completions (p.308)
Vertical Completion Options (p.54)

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Well Productivity Index (PI) Reservoir Properties (p.54)

Vogel's Reservoir Properties (p.55)
Fetkovich's Reservoir Properties (p.56)
Jones' Reservoir Properties (p.56)
Backpressure's Reservoir Properties (p.57)
Darcy's Reservoir Properties (p.57)
Forchheimer's Equation (p.58)
Hydraulic Fracture Reservoir Properties (p.59)

Vertical Completion Options

When the selected IPR model is Darcy and one of the Skin options is set to calculate, the following
vertical completion options are available:

Completion Type Description

OpenHole Does not have casing or liner cemented in place across the production zone.
Produced fluids flow directly into the wellbore. In some cases, the zone is left
entirely bare, but usually some sort of sand-control or flow-control method is
used.
Openhole with An openhole completion in which a slotted or perforated liner, often wire-
gravel pack wrapped and placed in the well, is surrounded by gravel. Gravel packs are
most commonly used for mitigating sand production.
Perforated Has a production casing or liner perforated to allow fluids to pass between
the wellbore and the producing formation.
Perforated with Uses a combination of gravel pack and perforation in cased-holes. The
gravel pack perforations allow passage of fluids between the wellbore and the producing
formation. Gravel packing the annulus and perforations prevents sand
production.
Frac Pack Process of creating a propped hydraulic fracture and an annular gravel pack
to increase well productivity and control sand production.

Related links:
Vertical Completion Skin Table (p.68)

Well Productivity Index (PI) Reservoir Properties

This topic describes the reservoir data to enter when you use the well PI equation for vertical
completions.

Property Description
Reservoir pressure Static reservoir pressure
Reservoir Reservoir temperature
temperature

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Property Description
IPR basis Basis for IPR calculation (liquid or gas)
Productivity Index Productivity Index
Use Vogel below Available for Liquid PI for reservoirs where bottomhole pressure may be
bubble point below the bubble point.

Note: The Well PI option is intended for use when the reservoir pressure is
above the bubble point. The Vogel correction below the bubble point
accounts for presence of 2-phase as gas comes out of solution. An
alternate option is to use an IPR model that is intended for two-phase
fluids, such as Vogel or Fetkovich.

Use test data Input rate versus pressure data available from standard multipoint tests or
isochronal test. PIPESIM adjusts the IPR automatically to match the test
data and computes the resultant productivity index (PI).

For more information, see Productivity Index (PI) (p.309).

Related links:
Multi-rate Well Test Data (p.87)

Vogel's Reservoir Properties

This topic describes the reservoir data to enter when you use Vogel's equation for vertical
completions.

Property Description
Reservoir pressure Static reservoir pressure
Reservoir Reservoir temperature
temperature
IPR basis Basis for IPR calculation. Liquid is the only option for Vogel IPR model.
AOFP Absolute Open Flow Potential - the maximum liquid flowrate the well could
deliver if the bottomhole flowing pressure were set to 0.
Vogel coefficient Coefficient used in Vogel's equation to adjust the degree of curvature of
the inflow performance curve. Curvature increases with an increasing
coefficient. A straight line is produced when the PI-coefficient is 0 (default
value = 0.8).
Use test data Input rate versus pressure data for a well test. PIPESIM* adjusts the IPR
automatically to match the test data.

Related links:
Vogel's Equation (p.310)

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Multi-rate Well Test Data (p.87)

Fetkovich's Reservoir Properties

This topic describes the reservoir data to enter when you use Fetkovich's equation for vertical
completions.

Property Description
Reservoir Static reservoir pressure
pressure
Reservoir Reservoir temperature
temperature
IPR basis Basis for IPR calculation (liquid is the only option for Fetkovich IPR model).
AOFP Absolute Open Flow Potential - the maximum liquid flowrate the well could
deliver if the bottomhole flowing pressure were set to 0.
n exponent Exponent used in the Fetkovich equation to adjust the degree of curvature
of the inflow performance curve. Unlike the Vogel equation it is not possible
to produce a linear well inflow characteristic as a special case of the
Fetkovich equation. The default value is 1.0.
Use test data Input rate versus pressure data available from standard multipoint tests or
isochronal test. PIPESIM adjusts the IPR automatically to match the test
data and computes the resultant AOFP and n exponent.

Related links:
Fetkovich's Equation (p.311)
Multi-rate Well Test Data (p.87)

Jones' Reservoir Properties

This topic describes the reservoir data to enter when you use the Jones' equation for vertical
completions.

Property Description
Reservoir pressure Static reservoir pressure
Reservoir temperature Reservoir temperature
IPR basis Basis for IPR calculation (liquid or gas)
A (turb) Turbulent flow coefficient. This value must be 0.
B (lam) Laminar coefficient. This value must be 0.
Use test data Input rate versus pressure data available from standard multipoint tests
or isochronal test. PIPESIM adjusts the IPR automatically to match the
test data and computes parameters A and B.

For more information, see Jones' Equation (p.312).

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Related links:
Multi-rate Well Test Data (p.87)

Backpressure's Reservoir Properties

This topic describes the reservoir data to enter when you use the backpressure equation vertical
completions.

Property Description
Reservoir pressure Static reservoir pressure
Reservoir Reservoir temperature
temperature
IPR basis Basis for IPR calculation (gas is the only option for Backpressure IPR
model).
Constant C C is the coefficient to pressure square differential term in back pressure
equation. C is influenced by reservoir and fluid parameters.
Slope n Slope n is the exponent to pressure square differential term in the
backpressure equation representing flow characteristics. Its value ranges
between 0.5 (for completely turbulent flow) to 1.0 (for pure laminar flow).
Use test data Input rate versus pressure data from a typical backpressure test. PIPESIM
adjusts the IPR automatically to match the test data and computes values
for C and n.

Related links:
Back Pressure Equation (p.313)
Multi-rate Well Test Data (p.87)

Darcy's Reservoir Properties

This topic describes the reservoir data to enter when you use the Darcy equation for vertical
completions.
For more information, see Pseudo Steady State Equation / Darcy Equation (p.314).

Property Description
Reservoir pressure Static reservoir pressure
Reservoir temperature Reservoir temperature
IPR basis Basis for IPR calculation (liquid or gas)
Use Vogel below This option is available for liquid-based IPR only. Use the Vogel equation
bubble point to calculate the IPR curve below the bubble point.
Reservoir thickness Average formation thickness
Borehole diameter Diameter of the wellbore (drilled hole) outside of the casing and cement.
The default value is 6 inches.

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Property Description
Reservoir permeability Average permeability of the formation.
Use relative This option is available for liquid-based IPR only. Select This checkbox
permeability data to specify a relative permeability table.
Reservoir shape Specify either a drainage radius or a shape factor.
option
Drainage radius Radius of external boundary of drainage area
Shape factor Identifies the physical location of a well with respect to reservoir
boundaries. The typical value for a circular reservoir is 31.62.
Reservoir area Area of the reservoir.
Use transient model Select the Transient model check box to model a well that has not
reached pseudo steady-state condition. This displays following additional
parameters
Time
Time well has been producing
Porosity
Pore volume/bulk volume
Compressibility
Total compressibility of the reservoir rock

Related links:
Vertical Completions Overview (p.53)

Forchheimer's Equation
This topic describes the reservoir data to enter when you use the Forchheimer equation for vertical
completions.

Property Description
Reservoir pressure Static reservoir pressure
Reservoir temperature Reservoir temperature
IPR basis Basis for IPR calculation (gas is the only option for Forchheimer IPR
model).
F (turb) Turbulent coefficient. This value must be 0.
B (lam) Laminar coefficient. This value must be 0.
Use test data Input rate versus pressure data available from standard multipoint tests
or isochronal test. PIPESIM adjusts the IPR automatically to match the
test data and computes parameters F and B.

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Related links:
Forchheimer Equation (p.313)
Multi-rate Well Test Data (p.87)

Hydraulic Fracture Reservoir Properties

This topic describes the reservoir data to enter when you use the hydraulic fracture equation for
vertical completions.

Note: The Fractured Well IPR type uses a digitized, constant rate, finite-conductivity, closed
square, fractured well type-curve to calculate the effect of a vertically drilled well that has been
hydraulically fractured. This is the same method used in the Schlumberger FracCADE software.

The well is assumed to be in the center of a square reservoir with an aspect ratio of 1:1.
The type curves used in the calculation are taken from Reservoir Stimulation 2nd Edition by
Econimides and Nolte, Chapter 8 by Hai-Zui Meng and SPE paper 16435 and are best suited
for tight gas wells. Type curves are generated using single-phase, two-dimensional finite
difference simulators for ranges of system properties (permeability, porosity, fluid viscosity, total
system compressibility) and the characteristic length of the system, fracture half-length. These
are then used to compute Dimensionless time (valid range: 10e-5 - 10e3), Dimensionless
wellbore pressure, and Dimensionless fracture conductivity (valid range 0.1 - 500).

Property Description
Reservoir pressure Static reservoir pressure
Reservoir Reservoir temperature
temperature
IPR basis Basis for IPR calculation (liquid or gas)
Use Vogel below (Available for liquid-based IPR only) Uses a type-curve equation for
bubble point calculating the productivity above the bubble point, and the Vogel
relationship to calculate the IPR curve below the bubble point. If the
watercut exceeds 60%, using Vogel's equation is not recommended.
Reservoir thickness Average formation thickness.
Reservoir Average formation permeability. For a gas well, this is gas permeability. For
permeability an oil well, this is total liquid permeability.
Reservoir radius Radius of external boundary of drainage area. The default value is 2,000
feet.
Borehole diameter Diameter of the wellbore (drilled hole) outside of the casing and cement.
The default value is 6 inches.
Fracture half length The length of the fracture extending out in one direction from the wellbore,
which is half of the total fracture length.
Fracture The effective permeability to the primary fluid of the fracture proppant under
permeability reservoir conditions.
Fracture width Average width of the fractures in a hydraulically fractured reservoir.

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Property Description
Use transient model Select the Transient model check box to model a well when the well has
not reached pseudo-steady-state conditions. When selected, the following
properties appear:
Time
Time well has been producing
Porosity
Pore volume/bulk volume
Compressibility
Total compressibility of the reservoir

Related links:
Vertical Completions Overview (p.53)

Horizontal Completions Overview

PIPESIM* uses the reservoir inflow and wellbore pressure drop equations to calculate the
production rate along the well length. PIPESIM supports the following completion types:
Single point (infinite conductivity)
Distributed (finite conductivity)

Single Point Completions

For single point completions, inflow is assumed to occur at the heel of the well only (no pressure
drop is calculated along the horizontal completion). The following IPRs are available:
Pseudo-steady-state (oil reservoirs)
Pseudo-steady-state (gas reservoirs)
Steady-state (oil reservoirs)
Steady-state (gas reservoirs)

Distributed Completions
For distributed completions, the inflow performance is expressed as a Productivity Index (PI) per
unit length that can be assigned explicitly (Distributive PI) or calculated using the following
equations:
Steady-state (oil reservoirs)
Steady-state (gas reservoirs)
Pseudo-steady-state (oil reservoirs)
Pseudo-steady-state (gas reservoirs) productivity equations.
In this mode, PIPESIM calculates the pressure drop along the horizontal completion.
These equations take account of the effect of the vertical/horizontal permeability ratio, completion
skin, and reservoir thickness.

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Related links:
Joshi (Steady State) (p.61)
Distributed Productivity Index (PI) Reservoir Properties (p.64)
Babu and Odeh (Pseudo-Steady State) (p.62)

Joshi (Steady State)

This topic describes the reservoir data to enter when you use the Joshi equation for oil and gas
horizontal completions.
The following reservoir data in the table is shared for Distributed and Single point.

For more information, see Pseudo-Steady State Productivity (p.346).

Property Description
Reservoir pressure Static reservoir pressure
Reservoir temperature Reservoir temperature
IPR basis Basis for IPR calculation (liquid or gas)
Radius of reservoir extent External boundary radius of the drainage area
Reservoir thickness Reservoir thickness
Permeability perpendicular to well Permeability in the x-direction (perpendicular to the well)
Permeability parallel to well Permeability in the y-direction (parallel to the well)
Vertical permeability Permeability in the z-direction (Kv)
Well Radius Sandface radius (drilled-hole radius)
Well Eccentricity Offset of the well from the center of the pay zone

Note: These properties are only applicable to Joshi (Steady State) - Single point model.

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Property Description
Productivity Index Computed single point PI values from the data supplied
Horizontal section Effective length of the horizontal completion
length
Fluid OFVF or Gas Z Option changes based on selected IPR basis. For liquids, the Fluid OFVF
(Oil Formation Volume Factor value) field appears. For gas, the Gas Z
field appears.

Note: This fluid property will replace the values defined in the fluid model
for the completion calculations only.

Fluid viscosity Fluid viscosity.

Note: This fluid property will replace the values defined in the fluid model
for the completion calculations only.

Related links:
Horizontal Completions Overview (p.60)

Babu and Odeh (Pseudo-Steady State)

This topic describes the reservoir data to enter when you use the Babu and Odeh equation for oil
and gas horizontal completions.
The following reservoir data in the table is shared for Distributed and Single point.
For more information, see Pseudo-Steady State Productivity (p.346).

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Property Description
Reservoir pressure static reservoir pressure
Reservoir temperature Reservoir temperature
IPR basis Basis for IPR calculation (liquid or gas)
Reservoir X dim Drainage width perpendicular to the well
Reservoir Y dim Drainage width parallel to the well
Reservoir thickness Reservoir thickness
Permeability X (perpendicular to well) Permeability in the x-direction (perpendicular to the well)
Permeability Y (parallel to well) Permeability in the y-direction (parallel to the well)

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Property Description
Permeability Z (Vertical) Permeability in the z-direction (vertical permeability)
Heel location (X position) x coordinate of the horizontal well trajectory
Heel location (Y position) y coordinate of the horizontal well trajectory
Heel location (Z position) z coordinate of the horizontal well trajectory
Horizontal section length Effective length of the horizontal completion.
Well Radius Sandface radius (drilled-hole radius).

Note: These properties are only applicable to Babu and Odeh (Pseudo-Steady State) - Single
point model.

Property Description
Productivity Index Computes the single point PI values from the data supplied
Fluid OFVF or Gas Optional changes based on selected IPR basis. For liquids, the Fluid OFVF
Z (Oil Formation Volume Factor value) field appears. For gas, the Gas Z
(compressibility factor) field appears.

Note: This fluid property will replace the volumes defined in the fluid model
for the completion calculations only.

Fluid viscosity Fluid viscosity.

Note: This fluid property will replace the volumes defined in the fluid model
for the completion calculations only.

Related links:
Horizontal Completions Overview (p.60)

Distributed Productivity Index (PI) Reservoir Properties

This topic describes the reservoir data to enter when you use the Distributed PI for oil and gas
horizontal completions.

Note: Distributed PI is the flowrate divided by drawdown divided by the unit wellbore length.

Property Description
Reservoir pressure Static reservoir pressure
Reservoir temperature Reservoir temperature
IPR basis Basis for IPR calculation (liquid or gas)

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Property Description
Productivity Index Distributed Productivity Index

Related links:
Horizontal Completions Overview (p.60)

Defining the Skin

The Skin tab is used to specify the completion properties used to calculate the skin factor. It can
be negative (enhanced inflow) or positive (reduced inflow).
In certain cases, especially the low permeability reservoir, well stimulation jobs like matrix
acidizing, hydraulic fracturing, etc may improve the near wellbore flow performance. Skin is
therefore the measure of damage/improvement from the original behavior and can have a positive
or negative value.
A positive skin indicates damage to the near wellbore region.
A negative skin indicates improved near wellbore flow performance.
A zero skin indicates no damage or improvement.
Sometimes, especially in high-rate gas wells, another skin term is introduced due to turbulence
known as rate dependent skin.
These two terms are added to get the overall skin factor. For example, if the rate is 20 mmscf/d,
the constant skin is 3, and the rate dependent skin is 0.1/mmscf/d, then the total skin is 5. Both
mechanical and rate dependent skin terms can be entered or calculated. Horizontal completion has
only one skin type.
You can model skin for both vertical and horizontal wells when appropriate IPR models and
completion methods are selected. The skin option is available only for the models shown in the
table.

Geometry Profile Fluid Entry IPR Model

Vertical Single Point Darcy (gas, liquid)
Horizontal Single Point Joshi (liquid, gas)
Babu & Odeh (liquid, gas)
Distributed Joshi (liquid, gas)
Babu & Odeh (liquid, gas)

When the appropriate IPR model is selected, the Skin tab appears under property for the selected
completion.
1. Click the Skin tab.
You will notice applicable skin terms depending on geometry profile of the well.
Horizontal geometry profile has a single term called Skin.
Vertical geometry profile has a Mechanical skin term and a rate-dependent skin term.
2. Click Specify (to enter a value) or Calculate (to have PIPESIM* calculate the values).

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If you selected Specify for the Mechanical skin or Rate dependent skin, enter the value.
If you selected Calculate, complete the remaining steps.

Note: When the Calculate option is selected for any of the skin terms for vertical geometry profile
(mechanical or rate dependent terms) or horizontal geometry profile (a single skin term), you will
need to select an appropriate Completion method to display various skin component associated
with it.

3. Select the appropriate Completion method that is available depending on well geometry and
interval type.

Geometry Profile Interval type Completion method

Vertical Cased hole Perforated
Perforated and gravel packed
Frac packed
Open hole Open hole
Open hole gravel packed
Horizontal Cased hole Perforated
Perforated and gravel packed
Open hole Open hole
Open hole gravel packed
4. Enter the required data for skin components exposed for the selected geometry profile and
interval type.

Related links:
Skin Compacted/Crushed Zone Properties
Darcy's Skin Properties - OpenHole (p.70)
Darcy's Skin Properties - OpenHole Gravel Packed (p.72)
Darcy's Skin Properties - Perforated (p.74)
Darcy's Skin Properties - Perforated and Gravel Packed (p.74)
Darcy's Skin Properties - Frac packed (p.78)
Joshi/Babu and Odeh Skin Properties - Perforated (p.70)
Joshi/Babu and Odeh Skin Properties - Perforated and Gravel Packed (p.70)
Joshi/Babu and Odeh Skin Properties - OpenHole (p.84)
Joshi/Babu and Odeh Skin Properties - OpenHole Gravel Packed (p.72)

Skin Components
The total skin is calculated by summing contributions from different components. The Skin factor
can be either negative (enhanced inflow) or positive (reduced inflow).

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The components comprising the skin factor depend on the completion type selected. The following
tables display skin components associated with various completion methods for horizontal and
vertical geometry profiles

Type Description
Openhole The skin factor calculation assumes the well is not cemented (no casing or
liner set across the reservoir formation). Openhole completions allow
produced fluids to flow directly into the wellbore.
Completion
vertical permeability, deviation
Damaged zone
diameter, permeability
Openhole Gravel Completion
Pack vertical permeability, deviation
Damaged zone
diameter, permeability
Perforated The skin factor calculation uses the McLeod or Karakas/Tariq model.
Completion
vertical permeability, deviation
Damaged zone
diameter, permeability
Compacted zone
diameter, permeability
Perforated with Completion
Gravel Pack vertical permeability, deviation
Damaged zone
diameter, permeability
Compacted zone
diameter, permeability
Frac Pack (a gravel Completion
packed hydraulic vertical permeability, deviation
fracture model)
Fracture
half length, width, proppant permeability
Fracture face skin and choke fracture skin options are available.

For more information, see Vertical Well Skin Factor (p.326), Gravel Pack Skin (p.330), Perforated
Well Skin (p.331), and Frac Pack Skin (p.335).

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Related links:
Vertical Completion Skin Table (p.68)
Horizontal Completion Skin Table (p.69)
Partial Penetration Skin (p.329)

Vertical Completion Skin Table

A vertical completion might be comprised of any of the following completion models. Based on the
information that you entered, skin components appropriate to each completion model are
calculated.

Completion Model Damaged Partial Gravel Perforated Compacted Frac

Model Assumptions Zone Penetration / Pack Skin Zone Skin Pack
Skin Deviation Skin Skin
Skin
Openhole The well is not X X
(p.70) lined or
cemented.
Openhole The wellbore X X X
Gravel Pack is openhole
(p.72) and has a
gravel pack.
Perforated The well is X X X X
(p.74) lined or
cemented and
is perforated.
Gravel The well is X X X X X
Packed and lined or
Perforated cemented, is
(p.74) perforated,
and has a
gravel pack.
Frac Pack The well is X X X X
(p.78) lined or
cemented, is
perforated,
and has been
fractured.

Based on the completion type, data is passed to the engines to calculate the IPR during simulation.

Related links:
Vertical Completion Options (p.54)
Skin Components (p.66)

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Horizontal Completion Skin Table

A horizontal completion can use any of the following completion models. Based on the information
that you entered, skin components appropriate to each completion model are calculated.

Completion Model Assumptions Damaged Gravel Perforated Compacted

Model Zone Skin Packed Skin Zone Skin
Skin
Open hole The well is not lined or X
(p.84) cemented.
Openhole The wellbore is openhole X X
Gravel Pack and has a gravel pack.
(p.72)
Perforated The well is lined or X X X
(p.70) cemented and is
perforated.
Gravel Packed The well is lined or X X X X
and Perforated cemented, is perforated
(p.70) and has a gravel pack

Based on the completion type, data is passed to the engines to calculate the IPR during simulation.

Related links:
Skin Components (p.66)

Skin Options Properties

The skin value has two components, a mechanical (constant) term and a rate dependent term. (For
example, if the rate is 20 mmscf/d, the constant skin is 3, and the rate dependent skin is 0.1/
mmscf/d, then the total skin is 5). Both mechanical and rate dependent skin terms can be entered
or calculated.

Property Description
Mechanical Used to represent friction terms arising from any departure from this idealized
skin model.
Specify
Enter the dimensionless constant skin factor.
Calculate
Model the completion and computes the skin factor using completion
options. If the skin is computed, sensitivity cannot be performed directly on
the skin value; however, sensitivities can be performed on any completion
description parameter (such as shots per foot or perforation depth).
Rate Flowrate dependent.
dependent skin Specify
Enter the dimensionless rate dependent skin factor.

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Property Description
Calculate
Calculate the rate dependent skin terms for all the components specified in
the completion options description.

Skin Options Properties - Distributed

The skin terms can be entered or calculated.

Property Description
Skin Used to represent friction terms arising from any departure from this idealized model.
Specify
Enter the dimensionless constant skin factor.
Calculate
Model the completion and computes the skin factor using completion options. If
the skin is computed, sensitivity cannot be performed directly on the skin value;
however, sensitivities can be performed on any completion description parameter
(such as shots per foot or perforation depth).

Darcy's Skin Properties - OpenHole

This skin models geometric effects, such as partial penetration of the reservoir layer and deviation
of the well from vertical. If the open interval is equal to the reservoir thickness and the well is
vertical (0 degrees deviation), then the partial penetration/deviation skin will be zero. Also, this skin
factor component considers the effect of reduced (or improved) permeability in a zone around the
well. The diameter and permeability of the damaged zone must be supplied, otherwise the default
values (wellbore diameter and the formation permeability) will be used, and the damaged zone skin
will be zero.

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Property Description
PARTIAL PENETRATION
Length of interval open to flow Open interval or perforated interval of the completion.
Vertical permeability Vertical permeability of the completion.
Well deviation Deviation from vertical, in degrees.
DAMAGED ZONE
Permeability Permeability of the damaged zone around the wellbore.
Diameter Diameter of the damaged zone around the wellbore.

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Related links:
Defining the Skin (p.65)

Darcy's Skin Properties - OpenHole Gravel Packed

This skin models geometric effects, such as partial penetration of the reservoir layer and deviation
of the well from vertical. If the open interval is equal to the reservoir thickness and the well is
vertical (0 degrees deviation), then the partial penetration/deviation skin will be zero. Also, this skin
factor component considers the effect of reduced (or improved) permeability in a zone around the
well. The diameter and permeability of the damaged zone must be supplied, otherwise the default
values (wellbore diameter and the formation permeability) will be used, and the damaged zone skin
will be zero. The effect of a gravel pack in the wellbore, between a screen and the reservoir.
PIPESIM* explicitly calculates the pressure drop contribution across the gravel pack.

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Property Description
PARTIAL PENETRATION
Length of interval open to flow The length of the reservoir in contact with the well through which
fluids are able to flow into the well.
Vertical permeability Vertical permeability of the completion.
Well deviation Deviation from vertical, in degrees.
DAMAGED ZONE
Permeability Permeability of the damaged zone around the wellbore.
Diameter Diameter of the damaged zone around the wellbore.

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Property Description
GRAVEL PACK
Permeability Permeability of the gravel pack.
Screen diameter Average screen diameter of the gravel pack used.

Related links:
Defining the Skin (p.65)

Darcy's Skin Properties - Perforated

This skin models the effects of perforations. A compacted zone around the perforations is included.
The rubblized or damaged zone surrounding a perforation tunnel where the action of the
perforating charge has altered the formation structure and permeability. The severity or extent of
the crushed zone depends on the characteristics of the formation, the perforating charge and the
underbalance or overbalance conditions at time of perforating. This skin models geometric effects,
such as partial penetration of the reservoir layer and deviation of the well from vertical. If the open
interval is equal to the reservoir thickness and the well is vertical (0 degrees deviation), then the
partial penetration/deviation skin will be zero. Also, this skin factor component considers the effect
of reduced (or improved) permeability in a zone around the well. The diameter and permeability of
the damaged zone must be supplied, otherwise the default values (wellbore diameter and the
formation permeability) will be used, and the damaged zone skin will be zero. The effect of a gravel
pack in the wellbore, between a screen and the reservoir. PIPESIM* explicitly calculates the
pressure drop contribution across the gravel pack.

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Property Description
PERFORATION
Skin method Available methods are:
McLeod
Karakas/Tariq
Perforation density Number of perforations per unit length.
Diameter Diameter of the perforation into the formation.
Length/Depth Length or Depth of the perforation into the formation.
Phase angle The angle of the completion.

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Property Description

Note: This option is only available if Karakas/Tariq option is

selected.

COMPACTED/CRUSHED
ZONE
Permeability Permeability of the compacted zone (or crushed zone) around
the perforation.
Diameter Diameter of the compacted zone (or crushed zone) around the
perforation.
PARTIAL PENETRATION
Length of perforated interval Open interval or perforated interval of the completion.
Vertical permeability Vertical permeability of the completion.
Well deviation Deviation from vertical, in degrees.
DAMAGED ZONE
Permeability Permeability of the damaged zone around the wellbore.
Diameter Diameter of the damaged zone around the wellbore.

For more information, see Perforated Well Skin (p.331).

Related links:
Defining the Skin (p.65)

Darcy's Skin Properties - Perforated and Gravel Packed

This skin models the effects of perforations. A compacted zone around the perforations is included.
The rubblized or damaged zone surrounding a perforation tunnel where the action of the
perforating charge has altered the formation structure and permeability. The severity or extent of
the crushed zone depends on the characteristics of the formation, the perforating charge and the
underbalance or overbalance conditions at time of perforating. This skin models geometric effects,
such as partial penetration of the reservoir layer and deviation of the well from vertical. If the open
interval is equal to the reservoir thickness and the well is vertical (0 degrees deviation), then the
partial penetration/deviation skin will be zero. Also, this skin factor component considers the effect
of reduced (or improved) permeability in a zone around the well. The diameter and permeability of
the damaged zone must be supplied, otherwise the default values (wellbore diameter and the
formation permeability) will be used, and the damaged zone skin will be zero. The effect of a gravel
pack in the wellbore, between a screen and the reservoir. PIPESIM* explicitly calculates the
pressure drop contribution across the gravel pack.

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Property Description
PERFORATION
Skin method Available methods are:
McLeod
Karakas/Tariq
Perforation density Perforation shot density.
Diameter Diameter of the perforation into the formation.
Length/Depth Length or Depth of the perforation into the formation.
Phase angle The angle of the completion.

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Property Description

Note: This option is only available if Karakas/Tariq option is

selected.

COMPACTED/CRUSHED
ZONE
Permeability Permeability of the compacted zone (or crushed zone) around the
perforation.
Diameter Diameter of the compacted zone (or crushed zone) around the
perforation.
PARTIAL PENETRATION
Length of perforated interval Open interval or perforated interval of the completion.
Vertical permeability Vertical permeability of the completion.
Well deviation Deviation from vertical, in degrees.
DAMAGED ZONE
Permeability Permeability of the damaged zone around the wellbore.
Diameter Diameter of the damaged zone around the wellbore.
GRAVEL PACK
Permeability Permeability of the gravel pack.
Screen diameter Average screen diameter of the gravel pack used.
Tunnel length Length of the tunnel. This value is usually the sum of the
thickness of cement, casing, and annulus.
Casing ID Inside diameter of the casing string which is gravel packed. This
value is taken automatically from the Tubulars tab.

For more information, see Perforated Well Skin (p.331).

Related links:
Defining the Skin (p.65)

Darcy's Skin Properties - Frac packed

A hydraulic fracture is characterized by its length, conductivity, and related equivalent skin effect.
The Frac Pack skin is calculated only in association with a cased hole gravel pack. If the gravel
pack is not defined, the Frac Pack Skin is 0.

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Property Description
Perforation density Perforation shot density.
Diameter Diameter of the perforation into the formation.
Length of perforated Open interval or perforated interval of the completion.
interval
Vertical permeability Vertical permeability of the completion.
Well deviation Deviation from vertical, in degrees.
Permeability Permeability of the gravel pack.
Screen diameter Average screen diameter of the gravel pack used.

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Property Description
Tunnel length Length of the tunnel. This value is usually the sum of the thickness of
cement, casing, and annulus.
Casing ID Inside diameter of the casing string which is gravel packed. This value is
taken automatically from the Tubulars tab.
Fracture A hydraulic fracture in the rock next to the wellbore
Half length (fracture) Length of the fracture extending out in one direction from the wellbore, or
half the total fracture length
Width (fracture) Average fracture width
Proppant permeability Effective permeability of the propped fracture
(fracture)
Choke Damage at the connection between the fracture and a well.
A choke fracture skin represents the choking effect caused by near
wellbore narrowing of the fracture due to tortuosity or other effects.
Check to include this component.
Permeability (choke) Permeability of frac choke
Length (choke) Length of damage at the connection between the fracture and a well is
referred to as a choke length.
Damage zone Damage left on the fracture face during the fracturing treatment,
expressed as a skin effect. Check to include skin associated with frac
face damage and specify required data.
Permeability (damage Permeability of the damaged zone around the wellbore. The default
zone) value is the formation permeability.
Thickness (Damage Depth of damage (normal to the fracture face). It is generally very thin
zone) (0.2 ft or less).

Related links:
Defining the Skin (p.65)

Joshi/Babu and Odeh Skin Properties - Perforated

This skin models the effects of perforations. A compacted zone around the perforations is included.
The Joshi (Steady State) and Babu and Odeh IPR models have the same parameters.

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Property Description
PERFORATION
Perforation density Perforation shot density.
Diameter Diameter of the perforation into the formation.
Length Length of the perforation into the formation.
COMPACTED/CRUSHED
ZONE
Permeability Permeability of the compacted zone (or crushed zone) around
the perforation.

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Property Description
Diameter Diameter of the compacted zone (or crushed zone) around the
perforation.
DAMAGED ZONE
Permeability Permeability of the damaged zone around the wellbore.
Diameter Diameter of the damaged zone around the wellbore.

Related links:
Defining the Skin (p.65)

Joshi/Babu and Odeh Skin Properties - Perforated and Gravel Packed

This skin models the effects of perforations. A compacted zone around the perforations is included.
The rubblized or damaged zone surrounding a perforation tunnel where the action of the
perforating charge has altered the formation structure and permeability. The severity or extent of
the crushed zone depends on the characteristics of the formation, the perforating charge and the
underbalance or overbalance conditions at time of perforating. This skin models geometric effects,
such as partial penetration of the reservoir layer and deviation of the well from vertical.
The Joshi (Steady State) and Babu and Odeh IPR models have the same parameters.

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Property Description
PERFORATION
Perforation density Perforation shot density.
Diameter Diameter of the perforation into the formation.
Length Length of the perforation into the formation.
COMPACTED/CRUSHED
ZONE
Permeability Permeability of the compacted zone (or crushed zone) around the
perforation.

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Property Description
Diameter Diameter of the compacted zone (or crushed zone) around the
perforation.
DAMAGED ZONE
Permeability Permeability of the damaged zone around the wellbore.
Diameter Diameter of the damaged zone around the wellbore.
GRAVEL PACK
Permeability Permeability of the gravel pack.
Tunnel length Length of the tunnel. This value is usually the sum of the
thickness of cement, casing, and annulus.

Related links:
Defining the Skin (p.65)

Joshi/Babu and Odeh Skin Properties - OpenHole

The diameter and permeability of the damaged zone must be supplied, otherwise the default
values (wellbore diameter and the formation permeability) will be used, and the damaged zone skin
will be zero. The effect of a gravel pack in the wellbore, between a screen and the reservoir.
PIPESIM* explicitly calculates the pressure drop contribution across the gravel pack.

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Property Description
DAMAGED ZONE
Permeability Permeability of the damaged zone around the wellbore.
Diameter Diameter of the damaged zone around the wellbore.

Related links:
Defining the Skin (p.65)

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Joshi/Babu and Odeh Skin Properties - OpenHole Gravel Packed

The diameter and permeability of the damaged zone must be supplied, otherwise the default
values (wellbore diameter and the formation permeability) will be used, and the damaged zone skin
will be zero. The effect of a gravel pack in the wellbore, between a screen and the reservoir.
PIPESIM* explicitly calculates the pressure drop contribution across the gravel pack.

Property Description
DAMAGED ZONE
Permeability Permeability of the damaged zone around the wellbore.
Diameter Diameter of the damaged zone around the wellbore.
GRAVEL PACK

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Property Description
Permeability Permeability of the gravel pack.

Related links:
Defining the Skin (p.65)

Multi-rate Well Test Data

In addition to the standard IPR equations, test data can be utilized so that the inflow can be
matched to actual measured data. A minimum of three data points is required. Two types of multi-
rate test are available:
Multipoint (default)
A flow-after-flow test sequence. Static pressure is taken as a constant throughout the test
period. The flowrate (Q) and corresponding flowing bottom hole pressure (Pwf) are
required. These are entered into the spreadsheet.
Isochronal
This type of test is normally performed in reservoirs with low permeability where the time
taken to reach stabilized flow conditions is unacceptably long (such as low permeability
sands). Isochronal testing is performed by periods of flowing followed by shutting-in of a
well (normally with increasing rate). The wellbore flowing pressure is recorded during each
flow period at a specific time (for example if the time is 4 hours, then the test is referred to
as a 4-hour isochronal test). Due to the long stabilization time normally associated with the
isochronal test, reservoir conditions need not return to the original static pressure. Hence a
different static reservoir pressure is recorded. The flowrate (Q), flowing bottom hole
pressure (Pwf) and static reservoir pressure (Pws) are required. These are entered into
the spreadsheet.
Once the test data has been entered, the IPR constants (for example PI, A and B, C and n, and so
on) will be computed and displayed.

Related links:
IPR Options and Applicability Table (p.53)
Well Productivity Index (PI) Reservoir Properties (p.54)
Vogel's Reservoir Properties (p.55)
Fetkovich's Reservoir Properties (p.56)
Jones' Reservoir Properties (p.56)
Backpressure's Reservoir Properties (p.57)
Forchheimer's Equation (p.58)

Multilayer Completions
A multilayer reservoir model is easy to construct in PIPESIM by adding multiple layers to the
wellbore and specifying necessary data and inflow performance for each layer. These layers may

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be connected to the same reservoir drawing same fluid with or without variation in phase ratios or
may be connected to separate reservoirs drawing different fluids. Constructing a multilayer well in
PIPESIM requires all these layers connected to the well and configured in such a way that a single
flow path is maintained and the fluids are commingled. Specific validation in PIPESIM will ensure
that single flow path is maintained in a multilayer well.

Figure 1: Valid well with a linear flowpath and point connection at each intermediate layer and
commingled fluids.
Figure 2: Invalid well as top layer follows a separate flowpath; fluids are not comingled.
If the fluids from different layers are not commingled, the individual layers should be treated as part
of separate wells and be modeled as a network with the two wells connected at a common junction
representing the wellhead.
There is no limit to the number of layers/reservoirs that can be added in a well can be added to the
model. These layers can be either vertical completions, horizontal completions or a combination
and the flow path is controlled using downhole tools like packers, sliding sleeves and/or tubing
plugs.

Layers
A completion represents each layer. Each layer is independent with respect to the layer properties,
Inflow Performance Relationship (IPR) and fluid model and are treated as separate source/
boundary for operations like Nodal Analysis and Network Simulation.

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Note: Typical single branch operations like PT Profile and System Analysis treat the bottommost
layer as the inlet boundary for the well.

Crossflow
PIPESIM can model both Production and Injection wells. In a typical production well, all the layers
are intended to contribute fluid into the wellbore and the commingled fluid is expected to flow
upward in the wellbore towards the wellhead. On the other hand, a typical injection well expects
injected fluid coming from the wellhead to flow downward with each layer receiving part of the
injected fluid.

Figure 3: Crossflow scenarios indicating cases that can be modeled using PIPESIM as Valid
cases.
However, the exact flow profile depends on the wellbore hydraulics and therefore crossflow may
exist in one of more layers. As shown above in Figure 3 (cases a, b, d and e), PIPESIM allows
crossflow as long as intended flow path in the wellbore (upward for a Production well and
downward for an Injection well) in all sections of wellbore. Cases c) and f) are in breach of intended
flow path in the wellbore and cannot be modeled.

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For more information, see Associating Zones with Completions (p.90).

Related links:
Adding Completions (p.51)

Associating Zones with Completions

Associating zones is optional; however, it is useful for aggregating reservoir and fluid properties
shared by completions across a large number of wells that draw fluid from a common zone.
1. Select the Use zones check box.
The Zones table appears below the check box.
2. In the row below the headings, click New (+).
3. In the Zone column, select the zone name from the dropdown list. If the zone name does not
appear in the list, use the Zone manager on the Home tab to create it.

Note: To change the values for pressure, temperature, and fluid, use the zone manager on the
Home tab.

4. Enter the depth of the well that intersects zone depth information.
Top MD
Measured depth of the well where the top intersects the zone
Bottom MD
Measured depth of the well where the bottom intersects the zone
5. Ensure the selected zone displays remaining data: pressure, temperature and a fluid model
mapped to the zone.

Note: To add/edit the values for Pressure, Temperature, and Fluid, use the Zone manager on
the Home tab.

6. Repeat the previous steps to add more zones.

7. To remove a zone from a completion, click the row number of the zone that you want to delete
and press DELETE.

Note: To remove all zones from the Completions tab, clear the Use zones check box. The Zones
section is no longer visible.

Related links:
Adding Completions (p.51)
Managing Zones (p.253)

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2.1.7 Adding Surface Equipment using the Well Editor

When working with individual wells in Well-Centric Mode, you can add surface equipment on the
Surface equipment tab in the Well editor.

Note: To add subsurface equipment, use the Downhole equipment tab in the Well editor.

1. On the Surface equipment tab, select an equipment object from available internal node
objects.
2. Move the cursor to the schematic area of the surface equipment tab to a location where you
want to place the equipment.
The cursor will show the selected equipment with an add (+) sign over it.
3. Click the Add equipment arrow pointing to the right to place the equipment.
The equipment appears in the preview pane at the top.
4. To add a connection between the well and an equipment object or between 2 equipment
objects:
Select one of the connections (connector, flowline or riser) and move to the schematic area.
The cursor will show a connection symbol and a sign (right or wrong) indicating validity of
the connection.
Move the cursor to the first equipment object (with a connection port available) that you want
to connect and click. One end of the connector gets connected to the first equipment. The
cursor still shows the connection symbol.
Click on the second equipment object (with a connection port available) that you want to
connect.
5. Repeat the steps above to add multiple equipment objects and connect them together.

Note: In the well-centric mode, well and surface equipment connections strictly maintain a linear
flow path by restricting every internal node object to two connection ports (inlet and outlet) only.
Additional ports for multi-outlet ports equipments such as 2-phase and 3-phase separators are
ignored.

Not all the equipment and connections added above form part of the well's surface equipment. The
end (or start in case of an injection well) of the well branch is controlled by the well stream outlet
(or inlet for an injection well), which by default is at the wellhead. However, you can set any of the
above equipment or connection as a well stream outlet (or inlet for an injection well).
6. Define the properties for the equipments and connections added:
a. Select any equipment or connection on the surface equipment schematic (or from the list of
surface equipment objects and connections displayed at the top of well or from the property
pane schematic)
The property pane for the selected equipment or connection appears under the surface
equipment schematic.
b. Complete the required data for the selected equipment or connection.

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c. Repeat this step for all equipment objects and connections.

Note: If you click the well instead of a surface equipment or connection, it will show the property
editor for the wellstream outlet (or inlet for an injection well) under the surface equipment
schematic.
See Configuring Wellstream Outlet or Inlet Conditions (p.138) for more detail on these.

Related links:
Choke Properties (p.33)
Compressor Properties (p.105)
Expander Properties (p.108)
Flowline - Simple Model Properties (p.109)
Generic Equipment Properties (p.117)
Generic Pump Properties (p.119)
Heat Exchanger Properties (p.121)
Injection Point Properties (p.122)
Source and Junctions Properties (p.123)
Multiphase Booster Properties (p.127)
Multiplier/Adder Properties (p.128)
Riser - Simple Model Properties (p.128)
Three Phase Separator (p.135)
Two Phase Separator (p.137)
Configuring Wellstream Outlet or Inlet Conditions (p.138)
Viewing Surface Equipment Properties (p.142)

2.1.8 Working with Well Tabs and Ribbons

Use the well-centric mode or the Well editor to configure all properties for a well. The Well
tools context tab appears when a well-centric model is open. The well core tabs group related
features together within the Ribbon. The core tabs are Home, Insert, and Format.

Well Core Tabs

Tab Description
Workspace A common tab that appears in both Well-centric mode or Network-centric mode
where you can access high level controls (for example, open, close, save, etc.). You
can also access various Help resources.
Home Select well tasks (for example, selecting well-centric or single branch tasks) and
views, and access the well selector, manage Data (Catalogs, flowline, fluid and/or

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Tab Description
zone), select Fluid mode, access to simulation settings, or configure layout options
including switching between well-centric and network-centric modes.
Insert By default, the Insert tab groups tubular, downhole equipment and artificial
equipment for inserting these and creating a well interactively on Well schematic.
However, the content of the tab changes to display surface equipment when you are
in Surface equipment tab of the well editor.
Format View the wellbore in 1D or 2D style and control the sectional view of the wellbore;
show or hide wellbore flow paths, schematic labels, and depth references. You can
also print, preview, or save the well as a template.

Well Insert Tab

Ribbon group Description

Tubulars Add tubing and casing to a wellbore schematic.
Downhole equipment Access the necessary equipment required to build a new wellbore
schematic.
Auxiliary Add a nodal point to the well.
Artificial lift Add a method to raise, or lift, fluid from a well.

Related links:
Creating or Editing a Well Model (p.23)

2.1.9 Interactive Wellbore Schematic

The Wellbore schematic, located in the Well editor, displays the well components - tubular,
downhole equipment and artificial lift equipment in a schematic view.
Well geometry display : You can view a well in 1D (linear mode appropriate for a vertical well)
or 2D mode (to display well deviation from vertical to properly display a deviated well.
High resolution sectional display: You can visualize a well as built in various high resolution
sectional views.

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Figure 2.1. Full sectional 2D view (left) and quarter sectional 1D view (right)
Interactive Well Building: With drag and drop support, you can build the entire well (tubular,
downhole equipment including completions and artificial lift equipment). This is a quick and
easy way of building the well visually and interactively. You can right click any object to delete.
Flow path indication: One of the significant features that allows you to visualize and model
simple to complex flow paths in the wellbore. The schematic visually indicates a valid flow path
(green) or an invalid flow path (red). An invalid flow path cannot be simulated.

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Figure 2.2. Valid flow path (left) and invalid flow path (right)
Interaction with well editor tabs: You can select any object (tubular, downhole equipments,
artificial lift equipments) on the Well schematic to open property editors for the selected object.
Data sync between a Well Schematic and the Well Editor tabs: All relevant data (name, status,
location, etc.) are synchronized between the well schematic and well editor tabs. Any object
added to/deleted from a well schematic gets updated to the well editor tab and vice versa.
Surface equipment display: If a well has attached surface equipment objects (flowline, pump,
etc), they get listed at the top of well schematic. You can click any of the objects on the surface
equipment list to get to the property editor of selected surface equipment.

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Figure 2.3. Surface equipment listed on the well schematic

Depth reference display: Locations of all equipment displayed on well schematic are referenced
to a reference depth that you set. However, the positioning of wellbore equipments are off scale
for better visualization. You can show/hide depth the reference display.
Object label display: All equipment objects displayed on a well schematic also display the name
of the equipment that you set under the well editor tabs. You can move the position of
equipment labels (up/down) or show/hide the object labels for a cleaner display.

Related links:
Creating or Editing a Well Model (p.23)

2.2 Creating or Editing a Network Model

A network model is a diagrammatic representation of the pipeline network, showing all the nodes
and the connections between them. The model is displayed as a diagram on the Network viewer
tab. Each node or connection added to the network diagram also appears in the Inputs pane.
1. Perform one of the following actions:
To create a new network model, on the Workspace tab in the Network group, click New.
To edit a network model, on the Workspace tab in the Network group, click Existing.
To edit a network model, on the Workspace tab in the Recent workspaces group, click an
existing model name.
2. Select units.
3. Add wells and/or sources.
4. Add pipeline components and field equipment.
5. Create a meaningful title, and then click Save. The default title for new and imported models is
New workspace.pips.
Each network model is stored in a single input file. (It is not necessary to store each model in a
separate directory.) The models are stored in binary data files with the .pips extension.

Related links:
Navigating in the Network Diagram (p.97)
Units (p.7)

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Adding Wells (p.99)

Adding Sources and Sinks (p.101)
Adding Sources and Sinks (p.101)
Creating a Network Model from a GIS Shapefile Automatically (p.23)
Adding Connections (p.144)
Improving Network Simulation Performance (p.215)

2.2.1 Navigating in the Network Diagram

You can specify the viewable area of your network diagram by
Panning and zooming to an area
Centering the network around an object
You can change the appearance of the labels for objects on the network diagram by changing
display properties such as nodes labels and connections. You can also display flow and profile
direction. You can print the model from the network diagram.

Related links:
Panning and Zooming in the Network Diagram (p.97)
Bringing Objects into View (p.98)
Changing the Model Display Properties (p.98)
Printing the Model from the Network Diagram (p.99)

Panning and Zooming in the Network Diagram

There are several ways to move from one area to another on the network diagram and to change
the viewing area.
1. To open the network diagram for a well or network, on the Home tab, in the Viewers group,
click Network.
2. To change the zoom level incrementally, on the Format tab, in the Zoom group, click Zoom in
or Zoom out.
3. To zoom to an area of the network, on the Format tab, in the Zoom group, click Zoom area,
left-click a start point on the network diagram, and drag the box to encompass the area that you
want.
4. To zoom into the smallest area that will show all your defined objects, on the Format tab, in the
Zoom group, click Zoom to fit.
Both Zoom area and Zoom to fit are actions that allow you to navigate very quickly to specific
areas of the model.
Tip: Select F4 to zoom to fit.
5. To pan across the network diagram, press CTRL, left-click the network diagram, and drag
across the network.

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6. To use the Overview inset window to adjust the center of the map view, perform the
following actions:
a. On the Format tab, in the Show/hide group, select Overview.
The Overview inset window displays in the upper-right corner of the network diagram. A
box marks the area of the network diagram that you are viewing.
b. In the Overview inset window, left-click the mouse button and drag across the network
diagram before releasing.
A blue box marks the area of the network diagram that you selected. The map is re-centered
at that location.
c. To close the inset window: On the Format tab, in the Show/hide group, clear the Overview
check box.

Related links:
Navigating in the Network Diagram (p.97)

Bringing Objects into View

Selecting from the list of equipment for your model in the Inputs pane can change the view.
1. On the Home tab, in the Application options group, click a Layout that displays the Inputs
pane.
2. Select an object in the Inputs pane.
If the object was not already in view, the network diagram pans so that the view of the model is
centered at the selected object.

Related links:
Navigating in the Network Diagram (p.97)

Changing the Model Display Properties

You can change the appearance of the labels for objects on the network diagram by changing
display properties such as nodes labels and connections. You can also display flow and profile
direction.
1. To open the network diagram for a well or network, on the Home tab, in the Viewers group,
click Network.
2. On the Home tab, in the Show/hide group, select the properties you want displayed for the
objects in your model.

Label or action Description

Flow direction Select or clear this check box to show or hide flow direction labels.
Annotations Select or clear this check box to show or hide annotation labels, and then click
which annotations you want for the objects in your model.
Hide results Hide flow direction and annotation labels.

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3. On the Format tab, in the Show/hide group, select the properties you want displayed for
labels.

Label Description
Node labels Select or clear this check box to show or hide the node labels.
Connection labels Select or clear this check box to show or hide labels for connectors, flowlines,
and risers.
Profile direction Select or clear this check box to show or hide profile direction labels.

Related links:
Navigating in the Network Diagram (p.97)

Printing the Model from the Network Diagram

You can print the model from the network diagram.
1. To open the network diagram for a well or network, on the Home tab, in the Viewers group,
click Network.
2. To print the model, perform one of the following actions:
On the Format tab, in the Print group, click Print.
Right-click the network diagram, and then click Print.
3. Select print options, and then click OK.

Note: Labels, icon size changes, and annotations are displayed in the printed copy. However, grid
lines and the Overview inset window are not displayed.

Related links:
Navigating in the Network Diagram (p.97)

2.2.2 Adding Wells

Use the Well editor (which consists of the Wellbore schematic pane and the tabs that you
use to define the well properties) to create new wells and edit existing ones. A well is one of the
ways fluids can enter (via production well) or leave (via injection well) the network.
A well model is a schematic representation of a well. It contains complete information on the well
including wellbore construction, downhole equipment, artificial lift equipment, completion
information as well as surface equipment as applicable. A well can be created from scratch or
using a template well as starting point.

Important: You need to provide a unique name to all surface and downhole equipment to avoid
possible conflicts. A unique name also helps identify the object definitively when viewing or
analyzing results.

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1. Add a well using the Insert tab or the Inputs pane.

In network-centric mode, on the Insert tab, in the Boundary nodes group, click Well and
then click on the network diagram to release the object.
A new boundary node object is added to the network diagram.
In the Inputs pane, right-click Wells, and then click New.
A new well is added to the Wells object tree and to the network diagram.
On the Contextbar, click the plus (+) sign next to the well selector. In the Inputs pane,
right-click Wells, and then click New. A new well is added to the Wells object tree and to the
network diagram.

Note: A well is the only new boundary node that you can create from the Inputs pane.
However, you can copy and paste a sink or source from the Inputs pane.

2. On the network diagram, double-click the node object to open the Well editor.
3. On the General tab, define the well type, its status, and the flow direction

Field Action
Well name Change the name of the well, if necessary.
Active Indicates whether the well is active.

Note: Simulation tasks cannot be performed on an inactive well. If a network

contains an inactive well, that well and the equipment in its branch are ignored
during network simulation.

Well type Select Production or Injection, based on the intended flow direction. The final
solution depends on system hydraulics.
Check Models a check valve for the well and therefore controls the direction of the flow.
valve Block reverse
setting
The most common setting, Block reverse, ensures that flow is always as
intended; i.e., upward for a production well and downward for an injection well.
Block forward
Block forward blocks flow in the intended direction.
None
No flow block exists, so the flow can go in either direction based on system
hydraulics.
4. Add tubular data.
5. Add a deviation survey.
6. Add downhole equipment, if applicable.
7. Add artificial lift equipment, if applicable.

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8. Add heat transfer data.

9. Add completions.
10.Add surface equipment.
11.Create a meaningful title and Save.
The default title for new and imported models is New workspace.pips.
Each well-centric or network-centric model is stored in a single input file. (You do not need to store
each model in a separate directory.) The models are stored in binary data files with the .pips
extension.

Related links:
Adding Tubular Data (p.25)
Adding a Deviation Survey (p.29)
Adding Downhole Equipment (p.32)
Adding Artificial Lift (p.41)
Adding Heat Transfer Data (p.49)
Adding Completions (p.51)
Adding Surface Equipment using the Well Editor (p.91)

2.2.3 Adding Sources and Sinks

Boundary nodes set the beginning and end point of the fluid flow. The following are boundary
nodes: well, source, and sink.
1. Add boundary nodes using the Insert tab or the Inputs pane.
In network-centric mode, on the Insert tab, in the Boundary nodes group, click the
appropriate boundary node and then click on the network diagram to release the object.
A new boundary node object is added to the network diagram.
2. On the network diagram, double-click the source or sink to open its editor.

Related links:
Creating or Editing a Network Model (p.96)

Sink Properties
A sink is a point where the fluid leaves the system. Normally, it is used to represent a surface
outflow point (for example, separator), not an injection well. A model can have any number of
sinks. See Source, Sink, and Boundary Conditions.
The following table describes the properties.

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Property Description
Pressure Outlet pressure.
Flowrate Liquid, Gas, or Mass flowrate in corresponding units at stock tank conditions.
Table 2.5: Sink Properties

2.2.4 Adding Surface Equipment using the Network Diagram

In network-centric mode, you can drag equipment directly to the network diagram from the Insert
tab on the Internal nodes group. This topic covers how to add surface equipment using the
network diagram.
1. In network-centric mode, click the Insert tab.
2. In the Internal nodes group, drag the appropriate equipment icon to the network diagram.
3. Define the properties for the selected surface equipment object by completing one of the
following actions:
On the network diagram, double-click the equipment object to open its editor.
On the network diagram, right-click the equipment object and click Edit to open its editor.
On the network diagram, double-click a well to open the Well editor and select the
Surface equipment tab. You may then select Node objects to insert in the Surface
equipment schematic and use connection objects to connect the node objects together.

Related links:
Choke Properties (p.33)
Check Valves (p.33)
Compressor Properties (p.105)
Expander Properties (p.108)
Flowline - Simple Model Properties (p.109)
Generic Equipment Properties (p.117)
Generic Pump Properties (p.119)
Heat Exchanger Properties (p.121)
Injection Point Properties (p.122)
Source and Junctions Properties (p.123)
Multiphase Booster Properties (p.127)
Multiplier/Adder Properties (p.128)
User defined equipment (p.9)
Riser - Simple Model Properties (p.128)
Three Phase Separator (p.135)
Two Phase Separator (p.137)

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Configuring Wellstream Outlet or Inlet Conditions (p.138)

Viewing Surface Equipment Properties (p.142)
Engine Keywords (p.40)

Choke Properties
A choke is a device that limits flow by mechanically constricting the cross-sectional area through
which fluid flows. The fluid velocity increases through the constriction and a pressure loss occurs.

Important: Downhole chokes and surface chokes use the same properties, although they are
created differently and appear differently in the Well schematic.

A surface choke is not part of wellbore schematic. It appears on surface schematic as below:

Choke Properties

Property Description
Name Unique name of the choke.
Active Select this check box to activate the choke so that it will be used during simulation.
Clear the check box to deactivate and the choke will be bypassed during simulation.

General Choke Properties

Property Description
Subcritical Select a correlation from the list. (All correlations except Mechanistic and
Correlation API14B require hydrocarbon liquids at Stock tank conditions.)
Critical Select a correlation from the list. Can be used to set the critical flowrate. This
Correlation may not match the subcritical flow at the critical pressure ratio, so the
subcritical flow correlation is adjusted to ensure that the flow is correct at the
critical pressure.
Bean size Enter the diameter of the choke bean. The bean size represents the diameter
of the available flow area assuming that the constriction is circular.
Critical pressure Used to determine the downstream pressure when critical flow occurs in the
ratio choke. You can specify a value or have it calculated. If you select Calculate,
the calculations are performed using the Ashford-Pierce method.
Tolerance Tolerance for identification of critical flow conditions (given as a percentage or
fraction)
Upstream pipe ID Enter the inside diameter of the pipe upstream of the choke.
Measured depth Downhole location of the choke

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Advanced Choke Properties

Property Description
Gas Phase flow (Used in the Mechanistic correlation) Flow coefficient for the gas
coefficient phase. For API14B compatibility, set this to 0.9.
Liquid Phase flow (Used in the Mechanistic correlation) Flow coefficient for the liquid
coefficient phase. For API14B compatibility, set this to 0.85.
Table 2.6: Flow coefficients

Property Description
Discharge Used to calculate the flow coefficients.
coefficient
Fluid heat capacity Normally calculated, but can be specified. The valid range is 0.7 to 2.
ratio (Cp/Cv) Typically it is 1.26 for a natural gas, 1.4 for a diatomic gas. It is used to
calculate the Critical pressure ratio if that is set to 0.
Y at critical point Gas expansion factor at critical flow. Normally, it is calculated, but it can be
specified. The valid range is 0.5 to 1. It is used to modify the pressure drop
equation to allow for gas compressibility.
Table 2.7: Choke parameters

Property Description
Flowrate Flowrate to identify critical flow.
Pressure ratio Pressure ratio to identify critical flow.
Sonic upstream velocity Sonic upstream velocity to identify critical flow.
Sonic downstream velocity Sonic downstream velocity to identify critical flow.
Table 2.8: Identification of Critical and Supercritical Flow

The choke model calculates the pressure ratio across the choke for the current flowrate. The
pressure ratio calculated is then categorized as subcritical, critical, or supercritical based on criteria
defined by the user. Use the check boxes to define the criteria for identification of critical and
supercritical flow. Note the following behaviors:
Clearing all the check boxes prevents identification of critical and supercritical flow, so flow is
always subcritical. Do this for API14B compatibility.
If more than one check box is selected, critical flow will be identified by any of the selected
criteria that are met.

Property Description
Adjust sub-critical Adjust subcritical correlation to match flowrate predicted by critical
correlation correlation.

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Property Description
Print detailed calculations Detailed choke calculation output. It appears on your terminal
screen and on the primary output page.
Table 2.9: Miscellaneous options

For more information, see Choke (p.354).

Related links:
Adding Surface Equipment using the Well Editor (p.91)
Adding Downhole Equipment (p.32)
Adding Surface Equipment using the Network Diagram (p.102)

Check Valves
You may block the flow at any point in the surface network by using check valves.

Note: Blocking flow in wells do not require a check valve, instead this setting is defined in the
General tab in the well editor.

1. To create a check valve, use the surface equipment toolbar in the network diagram view to
insert a check valve in the model. Connect both ends using a flowline, riser or connector.
2. Double-click the check valve to define the direction flow will be blocked which will be relative to
the orientation of the yellow arrow on the check valve.

Icon name Icon

Block none

Block reverse

Block forward

Block both

Related links:
Adding Surface Equipment using the Network Diagram (p.102)

Compressor Properties
Built-in or user-developed compressor curves can be used to describe the relationship between
differential pressure, flowrate, and efficiency for a range of compressor speeds. If compressor
curves are used, the compressor speed and number of stages become additional factors.

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Compressor Properties

Property Description
Name Name of the compressor.
Active Select this check box to activate the compressor so that it will be used during
simulation. Clear the check box to deactivate.

Operation parameters

Property Description
Discharge pressure Pressure at the compressor outlet.
Pressure differential Pressure increases (positive) across the compressor.
Pressure ratio Discharge pressure/suction pressure ratio. This is Pout/Pin.
Power The horsepower of the compressor.
Route Adiabatic
The compressor follows an adiabatic (no heat transfer) compression
process. This is available for modeling with both black oil and
compositional fluid.
Polytropic
The compressor follows a polytropic compression process. This is
available for modeling with both black oil and compositional fluids.
Mollier
The compressor follows an isoentropic (no change in entropy)
compression process. This is available only for compositional models.
Efficiency Compressor efficiency.
Honor stonewall Specifies whether the centrifugal compressor honors the Stonewall
limit operating limit.
Use curves Specifies whether to use data from the Compressor catalog. When
selected, the Performance data properties section appears so you can
select a compressor from the catalog.
Reciprocating Specifies that the compressor is a reciprocating compressor. This property
compressor is visible only when the Use curves check box is selected.

Note: The four basic compressor parameters (discharge pressure, pressure differential, pressure
ratio, and power) indicate upper limits for these whenever more than one of these parameters is
supplied. Compressor performance will be controlled by the most limiting of these parameters.

Use Curves
When you select the Use curves check box, the Performance data properties section appears.
You can select the manufacturer and a model from the catalog; all other values are populated
frrom the catalog.

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Performance data has the following tabs:

General
editable properties are display units, Operating frequency, Operating speed, and Head
factor
Table
displays calculated performance data in a tabular format
Curve
graphically displays the catalog performance data

Performance Data - General Tab

Property Description
Manufacturer Selectable from the catalog.
Model (Catalog value) Compressor model name.
Centrifugal Compressor (Catalog Values)
Min flowrate Minimum recommended flowrate. The performance curve can be
constructed below this, but warning messages are shown.
Max flowrate Maximum recommended flowrate. The performance curve can be
constructed above this, but warning messages are shown.
Base speed Speed at which the performance curve is defined. To change the
value for simulation purposes, enter an operating speed.
Reciprocating Compressor (Catalog Values)
Abs. min. suction pressure Absolute minimum suction pressure.
Abs. max. capacity Absolute maximum capacity. (The performance curve can be
constructed outside this range. Warning messages show where the
operating point is outside this limit.)
Base speed Speed at which the performance curve is defined. To change the
value for simulation purposes, enter an operating speed.
Inter-stage temperature Temperature of the gas between stages.
Stages Number of stages used.
Operating and Tuning Parameters (editable properties)
Operating frequency (Both) Specify one of these; the other is calculated.
Operating speed
Head factor (Centrifugal compressor) Allows the compressor head to be factored.

Performance Data - Table Tab

Property Description
Centrifugal compressor (catalog performance
table)

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Property Description
displays a table with flowrate, head, and
efficiency taken from the catalog.
Flowrate Fluid flowrate measured at actual pressure and
temperature conditions.
Head Specifies the compressor head.
Efficiency (Catalog value) Specifies the efficiency of the
compressor.
Reciprocating compressor (catalog
performance table)
For a selected discharge pressure, displays a
performance table with flowrate, suction
pressure and efficiency (or power).
Performance tables for multiple discharge
pressure can be stored and displayed.
Discharge pressure (Reciprocating compressor) Pressure at the
compressor outlet. For each discharge pressure,
there is a dedicated performance table.
Flowrate Gas flowrate measured at standard conditions.
Suction Pressure (Reciprocating compressor) Pressure at the
compressor inlet.
Efficiency Power Performance data can have either efficiency or
power. The unknown parameter will be calculated
during simulation.

Note: If the model has two or more reciprocating compressors in a series (for example, field
compressors followed by a plant compressor) any downstream compressor must have a greater
capacity than the upstream compressor, even if only fractionally greater. For example, 10.00
mmscf/d followed by 10.01 mmscf/d.

For more information, see Compressor (p.595) keyword.

Related links:
Adding Items to the Compressor Catalog (p.244)

Expander Properties
An expander is used to recover energy from waste gas. The energy recovered can be used to
drive other equipment or to produce electricity. The gas passes over the nose cone of the
expander and into its stator blades, impacting the rotor blades resulting in a temperature drop in
addition to recovery of the pressure energy.

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Expander Properties

Property Description
Name Name of the expander.
Active Select this check box to activate the expander so that it will be used during simulation.
Clear the check box to deactivate.

Operation Parameters

Property Description
Discharge Pressure at the expander outlet.
pressure
Pressure Pressure decrease across the expander (negative number).
differential
Pressure ratio Ratio of inlet pressure to discharge pressure. This is Pin/Pout.
Power Power of the expander.
Route Adiabatic
Adiabatic expansion is performed. For black oil models the heat capacity
ratio (Cp/Cv) is used as the adiabatic exponent (assumed to be constant with
a value equal to 1.26). For compositional models the heat capacity ratio is
calculated (using the relationship: Cp = Cv - R). The heat capacity is
obtained as the average of the expander suction and discharge conditions.
Polytropic
Polytropic expansion is performed. The heat capacity ratio (Cp/Cv) is
calculated in a similar manner to that outlined above for Adiabatic expansion.
Mollier
Expansion is based on the Mollier method, isentropic expansion from suction
to discharge pressures. This option is valid for compositional models only.
Efficiency Efficiency of the expander

For more information, see Expander (p.599) keyword.

Related links:
Adding Surface Equipment using the Well Editor (p.91)
Adding Surface Equipment using the Network Diagram (p.102)

Flowline - Simple Model Properties

You can define a flowline in a simple model (with basic minimum data) or detailed model (to
capture detailed profile as well as heat transfer calculations). The property pane and the parameter
displayed will depend on the options that you choose.

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Simple model
Use this mode if the flowline is relatively linear (horizontal pipe, vertical pipe, or inclined
pipe with constant inclination angle) and you want to perform a simplistic heat transfer
calculation using the known heat transfer coefficient and a constant ambient temperature.
Detailed model
Allows you to capture complex flowline geometry and at the same time, you will be able to
perform detailed heat transfer calculation including pipeline coating, variation in
environmental conditions, pipe burial data, etc.

Flowline Properties

Property Description
Name Name of the flowline.
Active Select this check box to activate the flowline so that it will be used during
simulation. Clear the check box to deactivate. An inactive flowline will simply
bypass the flowline and assume direct connection between attached
equipment objects with a connector.
Environment Sets the type of flowline to Land (air data used) or Subsea (metocean data
used). In the network diagram, active land flowlines are displayed in black
while active subsea flowlines are displayed in dark blue.
Mode Based on data availability and need, you can switch between Simple and
Detailed mode. To switch to the detailed model, click Detailed. Click Simple
to return to the simple model (the detailed data will be deleted). Detailed
mode has an additional tab for detailed heat transfer modeling.
Override global Defines environmental data such as local ambient temperature.
environmental
data

Pipe Data Properties

Property Description
Inside diameter Inside diameter for the flowline. Only one diameter can be configured per
flowline.
Wall thickness Select and specify either wall thickness or outside diameter (excluding any
Outside diameter coatings).
Roughness Enter the typical value for the absolute pipe roughness based on the material
type. The default value is 0.001 inches (0.0254 mm).

Note: If there is any change in flowline inside diameter, wall thickness, or roughness along the
flowpath, add a second flowline object.

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Profile Data Properties

Property Description
Rate of An artificial factor used to introduce undulations into the flowline (specific to
undulations simple mode only). Undulation is typically used for a horizontal pipe to capture
terrain effects (unevenness of the underlying surface) and result in a higher
overall pressure drop due to the fact that liquid holdup is higher in inclined
sections and lower in declined sections resulting in less pressure recovery.
Enter the total change in elevation for every 1,000 units of length. (To model a
totally flat flowline, enter 0.) Undulations capture terrain effects and result in a
higher overall pressure drop.
Horizontal Select either the horizontal distance or length to specify the distance covered by
distance the flowline from start to end.
Measured
distance
Elevation Change in elevation between the start and end of the flowline object. Enter a
difference negative value for a downhill flowline, or a positive value for an uphill flowline.
Elevation changes are relative to the object itself and not influenced by adjacent
flowlines.

Heat Transfer Data Properties

Property Description
Ambient Ambient temperature for the fluid surrounding the flowline.
temperature
U Value type Heat transfer coefficient (U Value) is a measure of thermal property of pipe
(with/without coating) and surrounding material. In simple mode, a known
overall heat transfer coefficient is used. Available options are: Insulated,
Coated, Bare (in air), Bare (in water), and User supplied.
Heat transfer Based on selected U value type, the corresponding pre-defined heat transfer
coefficient coefficient is filled in. Enter a value if you have selected U value type as User
supplied.
Inside film Click the appropriate option to either Include the Inside film coefficient (within
coefficient the supplied heat transfer coefficient above) or Calculate separately.
Calculation is performed based on selected methods (under Home
Simulation settings Heat transfer tab)

Flowline Schematic

Property Description
Geometry For a typical land flowline, the geometry profile is a plot of horizontal distance
profile (plot) versus elevation, where horizontal distance is the primary axis (X-axis).
However, if you select a subsea flowline, the configuration changes to depth as
primary axis (Y axis) versus horizontal distance.

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Property Description
Ambient Similar to a geometry profile, for a land flowline, ambient temperature is plotted
temperature against horizontal distance (X axis). For a subsea flowline, the ambient
(plot) temperature is plotted against depth (Y axis).
Data view By default, the flowline geometry and ambient temperature profile is displayed
button (plot) graphically. A table control button at the bottom right of the plot allows you to
switch to a tabular view of data. When in tabular view, a chart shaped button
allows you to switch back to plot view
Flowline start This is a read only field that indicates the starting point of the flowline in the
at model and thus indicates the orientation (profile direction) of the flowline in the
network.
Flip geometry Flipping the geometry will swap the start and end nodes for flowlines. The start
node defines the flowline orientation and is also indicated by an arrow situated
on the flowline object on the network diagram. Simulation results report the flow
direction relative to the pipeline orientation as either "Forward" or "Reverse"
depending on whether the flow direction is with or against the flowline orientation
respectively. Therefore, the flowline orientation should be defined in the intended
direction of flow and when flowlines are manually inserted, the first node
selected when connecting the flowline becomes the start node.
The flipping behavior is slightly different depending on whether the survey data is
populated from GIS or not. If the survey data is manually specified, flipping the
geometry enables a convenient means of swapping the start and end nodes for
a given profile, saving the user from having to invert the order of entries in a
survey table if the original direction was incorrect. If the GIS mode is selected, in
addition to swapping the start and end nodes, the survey is inverted as well such
that the elevations associated with the geographic locations defined are correctly
preserved. For cases where flowlines are created by importing shapefiles, the
flowline orientations are arbitrarily assigned. When the Populate from GIS map
is enabled, flipping the geometry will not change the numerical simulation results
(in contrast to flipping manually defined profiles), aside from the reported flow
direction.

For more information, see Typical Values (p.487) and Heat Transfer Coefficient (p.399).

Related links:
Environmental Properties (p.183)
Flowline - Detailed Model Properties - General Tab (p.112)
Pipeline Comparison: Land, Subsea, and Riser (p.116)

Flowline - Detailed Model Properties - General Tab

Detailed mode allows modeling complex variation in flowline geometry and also exposes detailed
heat transfer calculation including modeling for pipe coatings, and so forth. One of the most
important features of detailed flowline is populating data directly from the GIS map elevation
services.

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Detailed Mode Properties

Property Description
Name Name of the flowline.
Active Select this check box to activate the flowline so that it will be used during
simulation. Clear the check box to deactivate. Inactive flowlines are treated as
connectors and do not cause a pressure drop.
Environment Sets the type of flowline to Land (atmospheric data used) or Subsea
(oceanic data used). In the network diagram, active land flowlines are
displayed in black. Active subsea flowlines are dark blue.
Mode To switch to the detailed model, click Detailed. Click Simple to return to the
simple model (the detailed data will be deleted).
Override global Defines environmental data such as local ambient temperature.
environment data

General Tab - Pipe Data Properties

Property Description
Inside diameter Inside diameter for the flowline. Only one diameter can be configured per
flowline
Wall thickness Select the appropriate property, and then enter either the wall thickness or the
Outside diameter outside diameter of the flowline, excluding any coatings.
Roughness Enter the typical value for the absolute pipe roughness based on the material
type. The default value is 0.001 inches (0.0254 mm).

Note: If there is any change in flowline inside diameter, wall thickness, or roughness along the
flowpath, add a second flowline object.

General Tab - Profile Data Properties

Property Description
Populate from Values for Measured distance and elevation are populated directly from the
GIS map map data, if the model is configured accordingly on the map.
Distance Click to calculate Horizontal distance or Measured distance to enter data.
The unknown will be calculated geometrically. The distance here refers to the
cumulative distance as you go along the flowline in the direction of its
orientation
Vertical Distance Absolute elevation of each flowline profile data point. For a land flowline,
(subsea elevation is the only option. These elevation/dept values are relative to the
environment) flowline starting node and are not influenced by any other data. The vertical
distance selection option is available for subsea flowline only. It allows you to
choose either elevation or depth.

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Property Description
Profile Table The table column options appear based on selected distance options. Specify
cumulative data in the direction of profile in the increasing order of horizontal/
measured distance and the corresponding elevation/depth at each point

Flowline Schematic
As you enter flowline data, you will notice a set of plots displaying geometric profile (distance vs.
elevation/depth) and the profile of ambient temperature (against distance/depth). The plot
orientation changes based on the flowline environment (land/subsea).

Property Description
Geometry For a typical land flowline, the geometry profile is a plot of horizontal distance vs.
profile (plot) elevation, where horizontal distance is the primary axis (X-axis). However, if you
select a subsea flowline, the configuration changes to depth as primary axis (Y
axis) vs. horizontal distance.
Ambient Similar to the geometry profile, for a land flowline, ambient temperature is plotted
temperature against horizontal distance (X axis). For a subsea flowline, the ambient
(plot) temperature is plotted against depth (Y axis).
Data view By default, flowline geometry and ambient temperature profile are displayed
button (plot) graphically. A table control button at the bottom right of the plot allows you to
switch to tabular view of data. When in tabular view, a chart shaped button
allows you to switch back to plot view.
Flowline start This is a read only field that indicates the starting point of the flowline in the
at model and thus indicates the orientation (profile direction) of the flowline in the
network.
Flip geometry Flipping the geometry will swap the start and end nodes for flowlines. The start
node defines the flowline orientation and is also indicated by an arrow situated
on the flowline object on the network diagram. Simulation results report the flow
direction relative to the pipeline orientation as either "Forward" or "Reverse"
depending on whether the flow direction is with or against the flowline orientation
respectively. Therefore, the flowline orientation should be defined in the intended
direction of flow and when flowlines are manually inserted, the first node
selected when connecting the flowline becomes the start node.
The flipping behavior is slightly different depending on whether the survey data is
populated from GIS or not. If the survey data is manually specified, flipping the
geometry enables a convenient means of swapping the start and end nodes for
a given profile, saving the user from having to invert the order of entries in a
survey table if the original direction was incorrect. If the GIS mode is selected, in
addition to swapping the start and end nodes, the survey is inverted as well such
that the elevations associated with the geographic locations defined are correctly
preserved. For cases where flowlines are created by importing shapefiles, the
flowline orientations are arbitrarily assigned. When the Populate from GIS map
is enabled, flipping the geometry will not change the numerical simulation results
(in contrast to flipping manually defined profiles), aside from the reported flow
direction.

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For more information, see Typical Values (p.487).

Related links:
Environmental Properties (p.183)
Flowline - Detailed Model Properties - Heat Transfer Tab (p.115)
Pipeline Comparison: Land, Subsea, and Riser (p.116)

Flowline - Detailed Model Properties - Heat Transfer Tab

After you enter the detailed properties on the General tab, enter the detailed properties on the
Heat transfer tab.

Heat Transfer Tab Properties (Multiple U Value Input Method)

Property Description
U Value input Overall heat transfer coefficient (U value)
method Specify
Select this option to enter a single U value if it is known.
Calculate
Select this option when the heat transfer coefficient of the surrounding
medium is not known. A heat balance is performed using heat transfer
coefficients calculated from supplied data describing coatings, burial
conditions, and ambient fluid properties.
U Value type Select the pipe type: Insulated, Coated, Bare (in air), Bare (in water), or User
supplied.
Heat transfer Based on selected U value type, a corresponding pre-defined heat transfer
coefficient coefficient is supplied. Enter a value if you have selected U value type as User
supplied.
Inside film Click the appropriate option to either Include the inside film coefficient (within
coefficient the supplied heat transfer coefficient above), or choose to Calculate
separately. Calculation is performed based on selected methods (under
Home Simulation settings Heat transfer tab).
Ambient This table appears only if the override global environmental data is checked.
temperature Depending on the flowline environment, the column option changes. For a
typical land flowline, you get a table of horizontal distance vs. ambient
temperature but for a subsea flowline the table option is depth vs. ambient
temperature.

Heat Transfer Tab - Thermal Data Properties (Calculate U Value Input Method)

Property Description
Pipe conductivity Thermal conductivity of the pipe material

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Property Description
Ground conductivity Thermal conductivity of the ground. Used when pipe is partially or fully
buried in the ground.
Pipe burial depth The burial depth refers to the depth of the centerline of the pipe with
respect to ground surface. Burial data takes into account pipe as well as
coating layers (if any). If left blank, pipe is assumed to be elevated above
ground. A zero depth indicates half-buried pipe.
Wind speed (land Wind speed is populated from global environment data but can be
environment) overridden here.
Environmental data This table appears only if the override global environmental data is
table checked. For a land environment, you can enter ambient temperature
against horizontal distance. However, for a subsea flowline, an additional
column to specify current velocity appears.

Heat Transfer Tab - Pipe Coating Details Properties (Calculate U Value Input Method)

Property Description
Pipe coating You can add multiple layers of coating. For each coating layer, following data is
details needed:
Thermal conductivity of the coating layer
Thickness of the coating layer
Description (for reference purposes only)
Overall outside Outside diameter of pipe and coating layers. This value is used to display pipe
diameter cross section schematic underneath
Pipe cross- This schematic underneath the coating table displays:
section Pipe cross-section showing pipe and coating layers in different colors
schematic
Pipe burial display (for a partially buried pipe, it will display sections of pipe
below and above ground)
Environment (sky blue for a land environment and dark blue for subsea
environment).

For more information, see Heat Transfer Coefficient (p.399) and Internal Fluid Film Heat Transfer
Coefficient (p.402).

Related links:
Adding Connections (p.144)
Flowline - Detailed Model Properties - General Tab (p.112)
Managing Flowlines and Risers (p.251)

Pipeline Comparison: Land, Subsea, and Riser

This table describes the attributes for each type of pipeline.

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Attribute Riser Subsea flowline Land flowline

Geometry Cannot be flipped. A Can be flipped. Can be flipped.
check box is available to
mark downcomers.
GIS Cannot use GIS to Cannot use GIS to capture Can use GIS to capture the
capture pipeline pipeline geometry profile.The geometry profile. The
geometry profile. ambient temperature and ambient temperature data on
current velocity table on the the Heat transfer tab does
Heat transfer tab does not not change. Ambient
change. Ambient temperatures temperatures for the GIS
and current velocities for the profile points are calculated
GIS profile points are by interpolation based on
calculated by interpolation available data using the
based on the available data interpolation method for land
using the interpolation method flowline (see interpolation
for subsea flowline (see method).
interpolation method).
Ambient Indexed on depth/ Indexed on depth/elevation. Indexed on horizontal
temperature elevation. The table has The table has to be monotonic distance. The table has to be
and current to be monotonic on on depth. Use of depth is monotonic on horizontal
velocity data (if depth. Use of depth is recommended. distance.
applicable) recommended.
Interpolation of Interpolation linearly Interpolation linearly between Interpolation linearly
ambient between two points two points provided. between two points
temperature provided. Interpolation Interpolation linearly outside the provided. Interpolation with
and current linearly outside the range of points provided. the constant last value
velocity data (if range of points provided. outside the range of points
applicable) provided.
Related links:
Flowline - Simple Model Properties (p.109)
Flowline - Detailed Model Properties - General Tab (p.112)
Riser - Simple Model Properties (p.128)
Riser - Detailed Model Properties - General Tab (p.131)

Generic Equipment Properties

You can use generic equipment properties to model any object that imparts a pressure and/or
temperature change to the flowing stream at any point in the model.

Property Description
Name Name of the generic equipment object

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Property Description
Active Select the Active check box to activate the generic equipment so that it will be used
during simulation. Clear the check box to deactivate and it will be bypassed during
simulation.

General Properties

Property Description
Route Select one of the following thermodynamic routes to calculate fluid temperature
change resulting from changes in pressure:
Isenthalpic
constant enthalpy (the default option)
Isentropic
constant entropy
Isothermal
constant temperature
Pressure Select one of the following pressure change options:
Discharge Pressure
A fixed flowing fluid discharge pressure. Pressure at the outlet. Specifying the
discharge pressure is discouraged, particularly in network simulations, as this
specification often creates pressure discontinuities. It is intended to be used
only when the downstream branch is a terminating branch and not pressure
specified.
Pressure differential
Pressure gain (positive) or loss (negative). In a network model, this is assumed
to follow the branch's flow direction, so if the branch flow reverses, this
property changes sign.
Pressure ratio
Ratio of discharge pressure to the inlet pressure.
Temperature Select one of the following temperature change options:
Temperature differential
Temperature increase (positive) or decrease (negative) across the equipment.
Discharge Temperature
Fixed flowing fluid outlet temperature.
Duty
Power required to change the temperature and/or pressure of the fluid. If this is
specified, the corresponding fluid enthalpy change is calculated and added to
that resulting from any pressure change using the Route. The outlet
temperature is then adjusted accordingly.

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Note: If Delta Pressure or Pressure Ratio is specified without the Discharge properties,
PIPESIM* uses the thermodynamic Route to calculate the fluid outlet temperature. Isenthalpic is
the most appropriate route when you want to simulate chokes, predict Joule-Thompson cooling
across pressure reduction valves, and so on.

Related links:
Adding Surface Equipment using the Well Editor (p.91)
Adding Surface Equipment using the Network Diagram (p.102)

Generic Pump Properties

The basic pump model uses centrifugal pump equations to determine the relationship between
inlet pressure and temperature, outlet pressure and temperature, flowrate, shaft power, hydraulic
power, and efficiency.

Property Description
Name Name of the pump.
Active Select this check box to activate the pump so that it will be used during simulation.
Clear the check box to deactivate.

Operation Parameters

Property Description
Discharge Pressure at the outlet. Specifying the discharge pressure is discouraged,
pressure particularly in network simulations, as this specification often creates pressure
discontinuities. It is intended to be used only when the downstream branch is
a terminating branch and not pressure specified.
Pressure Pressure change across the pump.
differential
Pressure ratio Discharge pressure/suction pressure ratio (Pout/Pin).
Power Shaft power required to increase the pressure of the fluid.
Efficiency Efficiency of the pump.
Use curves Specifies whether to use data from the Pump catalog. When selected, the
performance data properties section appears so you can select a pump from
the catalog.

Note: The four basic pump parameters (discharge pressure, pressure differential, pressure ratio,
and power) indicate upper limits. Whenever more than one of these parameters are supplied,
Pump performance will be controlled by the most limiting of these parameters.

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Use Curves
When you select the Use curves check box, the Performance data properties section appears.
You can select the manufacturer and a model from the catalog; all other values are populated from
the Pump catalog.
Performance data has the following tabs:
General
selection from catalog, operating data and tuning
Table
displays catalog performance data in tabular format
Curve
graphically displays the catalog performance data

Performance Data Properties - General Tab

Property Description
Manufacturer Selectable from the catalog.
Model (Catalog value) Pump model name.
Min flowrate (Catalog value) Minimum recommended flowrate. The performance curve
can be constructed below this value, but warning messages are shown.
Max flowrate (Catalog value) Maximum recommended flowrate. The performance curve
can be constructed above this value, but warning messages are shown.
Base speed (Catalog value) Speed at which the performance curve is defined. To
change the value for simulation purposes, enter the operating speed or
operating frequency.
Base stages (Catalog value) Number of stages for which the performance curve is
defined. This can be changed for the simulation.
Number of stages (Catalog value) A discreet set of stages is stored in the catalog. The pump
performance curve is adjusted based on the actual number of stages and
speed used during simulation.
Operating frequency Specify one of these values (the other value is then calculated).
Operating speed
Head factor Multiplier that adjusts the pump head (pressure differential) to account for
wear and other inefficiencies.
Viscosity correction Catalog performance data are typically generated with water as test fluid.
The Viscosity correction takes into account the correction applied to the
performance curve based on actual fluid being pumped.

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Performance Data Properties - Table Tab

Property Description
Flowrate (Calculated value) Fluid flowrate measured at actual pressure and temperature
conditions
Head (Calculated value) Specifies the pressure differential across the pump in units of
length of fluid column.
Efficiency (Catalog value) Specifies the efficiency of the pump.

For more information, see Centrifugal Pumps and Compressors (p.366).

Related links:
Adding Items to the Pump Catalog (p.246)

Heat Exchanger Properties

Use a heat exchanger to model a device that transfers heat from one liquid to another without
allowing them to mix. This results in a fluid temperature change and sometimes a small pressure
change.

Property Description
Name Name of the heat exchanger.
Active Select this check box to activate the heat exchanger so that it will be used during
simulation. Clear the check box to deactivate.

Operation Parameters

Property Description
Pressure Select one of the following pressure change options:
Discharge pressure
Pressure at the outlet. Specifying the discharge pressure is discouraged,
particularly in network simulations, as this specification often creates pressure
discontinuities. It is intended to be used only when the downstream branch is a
terminating branch and not pressure specified.
Pressure differential
Pressure change across the heat exchanger
Temperature Select one of the following temperature change options:
Temperature differential
Temperature increase (positive) or decrease (negative) across the heat
exchanger
Discharge temperature
A fixed flowing fluid outlet temperature

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Property Description
Duty
Power required to achieve the desired change in fluid temperature and
pressure.

Related links:
Adding Surface Equipment using the Well Editor (p.91)
Adding Surface Equipment using the Network Diagram (p.102)

Injection Point Properties

You can use a fluid injection point to inject fluid anywhere in the system. Injectors are commonly
used to model chemical injection (for example, methanol) or riser-based gas.

Property Description
Name Name of the injection point.
Active Select this check box to activate the injection point so that it will be used during
simulation. Clear the check box to deactivate.

General Properties

Property Description
Temperature Temperature of the incoming fluid at the injection point. Injected fluid will mix with
the flowing fluid and resultant temperature will be calculated.
Flowrate Incoming liquid, gas or mass flowrate for the injection stream

Fluid Model Properties

Property Description
Fluid model Select a predefined fluid to be injected. You can also edit selected fluid or
create a new fluid.
Override phase ratios You can override phase ratio for selected fluid.
Gas ratio Select the appropriate gas ratio type and enter a value.
Water ratio Select the appropriate water ratio type and enter a value.

Note: The injected fluid type must be consistent with the main fluid type (black oil or compositional)
set in the model.

Related links:
Creating or Editing Fluid Models (p.146)

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Source and Junctions Treated as Source Properties

A source is a point where fluid enters the network. It represents a generic fluid entry point such as
a tie-in to a separate pipeline or field and should be placed upstream of other components. You
can add multiple sources in a network to model multiple entry points.
On the other hand, a junction is a simple node that is used to connect multiple branches in a
network. A junction itself has no associated physical characteristics such as pressure drop and
temperature change. However, junction allows mixing of multiple fluids at a common pressure and
the temperature at the junction represents the combined stream temperature.
While source can be added only at the boundary of a network, a junction can be converted as a
source anywhere in a network to simulate (single branch operations) and analyze a branch in the
middle of the network. When converted as a source, a junction represents all the properties that
are used to model a source. Treating a junction as a source does not affect the network simulation
tasks.
Use the Source object to specify explicit upstream boundary conditions of pressure and
temperature. For example, use Source to emulate input boundary flow conditions for the following:
Wellhead or manifold conditions in a subsea production flowline system
Export flow conditions from an offshore platform
The following table describes the properties for sources and junctions treated as sources.

Source Properties for Sources and Junctions Treated as Sources

Property Description
Name Name of the source or junction that is being treated as a source.
Treat as Applies to junctions only. Select this check box to treat the junction as a source.
source When checked, the property editor adds parameters to model source properties.
Also, the junction appears on the network as a bigger circle with a dark blue color.
Active Indicates whether the source is active. An inactive source blocks the source and
connected branch in the network. Note that the active check box does not appear
for a junction or a junction treated as a source.

Pressure/Flowrate Boundary Conditions

Property Description
PQ curve By default a source requires a fixed pressure and/or fixed flowrate boundary
(checkbox) condition. When you select the PQ curve option, you can model a PQ curve
(typically wellhead performance curve). Additional tabs appear to record PQ
table (Table tab) and display PQ-curve (Curve tab).
Temperature Temperature at the source. (Always required)
Pressure Fluid pressure at the source. (Appears when PQ curve is unchecked)
Flowrate Fluid flowrate at the source. (Appears when PQ curve is unchecked)

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PQ Curve
When you select the the PQ curve check box, the Table and Curve tabs appear.

Property Description
PQ type (Table tab) Flowrate basis for the PQ curve. The options are liquid flowrate, gas
flowrate, or mass flowrate.
PQ Table (Table tab) Enter pressure vs. flowrate relationship in the table.
PQ Curve (Curve tab) Graphically displays the PQ curve.

Note: The unknown solution point (pressure or flowrate) will be interpolated or extrapolated during
iteration based on nearest supplied data points, provided the extrapolation does not lead to a
negative pressure. It is recommended to supply enough data points to cover the expected solution
and solution accuracy.

Fluid Model Properties

Property Description
Fluid model Define a fluid model for the source by using one of the following ways:
Selecting a predefined fluid from the fluid dropdown list
Creating a new fluid specific to the selected source
You can edit a selected fluid to change properties or simply override the phase
ratio.
Override phase Select this check box if you want to override the phase ratio of a selected fluid.
ratios
Gas ratio If you have checked override, select the gas phase ratio type and specify a
value.
Water ratio If you have checked override, select the water phase ratio type and specify a
value.

Note: You can also create a new fluid or edit the properties of a defined fluid.

Related links:
Configuring Junctions as Sources (p.124)
Converting Junctions to Wells, Sources, Sinks, and Equipment (p.124)
Creating or Editing Fluid Models (p.146)

Configuring Junctions as Sources

Treating a junction as a source allows the junction to act as a source for a single branch simulation
task performed on any branch exiting the junction. For the purpose of network simulation, this
junction (converted to source) will continue to function like a junction.

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1. Identify the branch that you want to simulate and select the appropriate junction upstream of
intended flow path.
2. Display the junction properties by completing one of the following actions:
On the Surface equipment tab of the well editor, click on the junction object on the surface
schematic.
Click the junction object name listed at the top of the Wellbore schematic.
Double-click the junction object name in the Inputs pane for network centric mode.
Right-click the junction object name in the Inputs pane and click Edit.
On the network diagram, double-click the junction object.
The junction properties display on the Surface equipment tab or in the appropriate editor
window.
3. Select the Treat as source check box.
4. Configure the source properties as needed.
5. Click Close.

Related links:
Source and Junctions Properties (p.123)

Converting Junctions to Wells, Sources, Sinks, and Equipment

Note: PIPESIM provides the ability to convert junctions to wells, sources, sinks, and other
equipment. This feature is to support to process of automatically creating networks from shapefiles,
due to the current limitation that wells and other equipment cannot be imported from the shapefile.

1. To convert a junction, click it in the network in the GIS map view, logical view or in the Inputs
pane.
2. Use the Right-mouse-button (RMB) on the selected junction and select Convert from the option
list.
An additional context-sensitive option list displays with the possible objects that could be placed at
the selected junction based on the number of flowlines connected to it. It is based on the logic
below.

Junction Context
Conversion options 1 junction 1 junction connected 1 junction 1 junction
connected to 1 to 2 flowlines connected to 3 connected to 4
flowline flowlines flowlines
Source x
Sink x
Well x
Heat Exchanger x

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Junction Context
Compressor x
Expander x
Generic Equipment x
Injection Point x
Multiplier/Adder x
User Equipment x
Choke x
Generic Pump x
Multiphase Booster x
Two-Phase Separator x x
3. Choose the object you would like to convert the junction to from the list. Repeat this process for
individual junctions in your network until it is a correct representation of what you would like to
simulate.
The PIPESIM junction conversion feature is irreversible (for example, after converting a junction
to a well, source, sink or other equipment), you cannot convert the object back to a junction. To
forestall any issues that may arise from this, make a copy of the model before converting the
junctions or exit the workspace without saving, after you have converted the junctions.

Related links:
Source and Junctions Properties (p.123)

User defined equipment

PIPESIM supports many types of equipment that can be inserted into a flow path to model devices
that affect the fluid (flowrate, pressure, temperature and enthalpy). Examples include pumps,
compressors, heaters, multipliers, chokes, etc.
If you want to model certain specialized or proprietary devices not currently supported by PIPESIM,
you can create a Dynamically Linked Library (DLL) to achieve this. Such devices may include jet
pumps, multiphase boosters, valves, etc.
Self-documenting code templates written in c++ and Fortran are provided in the .. \Program Files
\Schlumberger\PIPESIM2014.1\Developer Tools\User Equipment directory created during the PIPESIM
installation.

Related links:
Registering User Defined Equipment (p.10)
Using User defined equipment (p.9)

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Multiphase Booster Properties

A multiphase booster enables the mixed fluid stream to be boosted in a single equipment object.
The incoming fluid at the suction is directly boosted to the required discharge pressure without
physically separating the liquid and gas phases and the discharge fluid is exported via a
multiphase export line.
Define the properties in the Operation parameters area. Use the Discharge pressure, Pressure
differential, Pressure ratio, and Power parameters to apply limits to the curve. Supply values for
any one of the properties and the rest are calculated. If you do enter more than one property, the
most limiting (that which leads to the smallest pump differential pressure) is used, and the others
are discarded.

Property Description
Name Name of the multiphase booster.
Active Select this check box to activate the multiphase booster so that it will be used during
simulation. Clear the check box to deactivate.

Operation Parameters

Property Description
Discharge Pressure at the outlet. Specifying the discharge pressure is discouraged,
pressure particularly in network simulations, as this specification often creates
pressure discontinuities. It is intended to be used only when the downstream
branch is a terminating branch and not pressure specified.
Pressure Pressure differential across the multiphase booster.
differential
Pressure ratio Ratio of discharge pressure to suction pressure.
Power Power required by the multiphase booster.
Type Generic is the only option available presently.

Note: The four basic booster parameters (discharge pressure, pressure differential, pressure ratio,
and power) indicate upper limits for these whenever you supply more than one of these
parameters. The most limiting of these parameters will control booster performance.

Generic Booster Properties

Property Description
Pump efficiency Efficiency of the pump. The default value is 100%.
Compressor efficiency Efficiency of the compressor. The default value is 100%.

For more information, see Guide to Multiphase Booster Efficiencies (p.386).

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Related links:
Adding Surface Equipment using the Well Editor (p.91)
Adding Surface Equipment using the Network Diagram (p.102)

Multiplier/Adder Properties
A Multiplier/Adder device increases or decreases the flowrate, but does not change the fluid
properties.

Property Description
Name Name of the multiplier or adder.
Active Select this check box to activate the multiplier or adder so that it will be used during
simulation. Clear the check box to deactivate.

General Properties

Property Description
Function Add
This is the default option. Increases or decrease the flowrate, but does not change
the fluid properties.
Select a flowrate type from the Flowrate list.
Multiply
Click this option to multiply, rather, than add. Multipliers are typically used to model
the effect of identical parallel lines in single branch tasks.
Enter a multiplication factor in the Multiplier field.
Flowrate Options for flowrate types are Liquid, Gas, and Mass. You can add (a positive value)
or remove (a negative value) liquid, gas or mass. However, an added (or removed)
phase does not change phase ratio of the fluid as all three phases are added/removed
in the same proportion.
Multiplier The multiplication factor is always positive. A factor above 1 indicates increased flow
while below 1 indicates decreased flow.

Related links:
Adding Surface Equipment using the Well Editor (p.91)
Adding Surface Equipment using the Network Diagram (p.102)

Riser - Simple Model Properties

You can define a riser in a simple model (with basic minimum data) or a detailed model (to capture
detailed profile as well as heat transfer calculations). The property pane and the parameter
displayed will depend on the options that you choose.

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Simple model
Use this default mode if the riser has a simple geometry (a vertical pipe or inclined pipe
with constant inclination angle) and you want to perform a simplistic heat transfer
calculation using the known heat transfer coefficient.
Detailed model
Allows you to capture complex riser geometry and at the same time, you will be able to
perform detailed heat transfer calculation including pipeline insulation.

Riser Properties

Property Description
Name Name of the riser
Active Select this check box to activate the riser so that it will be used during
simulation. Active risers are displayed in light green. Clear the check box to
deactivate. Inactive flowlines are treated as connectors and do not cause a
pressure drop.
Mode Based on data availability and need, you can switch between Simple and
Detailed mode. Detailed mode has an additional tab for detailed heat transfer
modeling.
To switch to the detailed model, click Detailed. Click Simple to return to the
simple model (the detailed data will be deleted).
Override global By default, a riser uses global environment data (e.g., ambient temperature,
environmental wind, and current data, etc). If checked, it will use environmental data
data configured locally to the selected riser.

Pipe Data Properties

Property Description
Inside diameter Inside diameter for the riser
Wall thickness Select and specify either wall thickness or outside diameter (excluding any
Outside diameter coatings)
Roughness Enter the typical value for the absolute pipe roughness based on the material
type. The default value is 0.001 inches (0.0254 mm).

Note: If there is any change in the riser inside diameter, wall thickness, or roughness along the
pipeline, add a second riser object.

Platform Data Properties

Property Description
Platform height (above Platform height above the water surface. A vertical pipe section will be
waterline) created with air as the ambient fluid.

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Profile Data Properties

Property Description
Horizontal distance Select the appropriate property to specify the distance covered by the riser.
Measured distance
Seabed depth Distance from water surface to seabed.
Use as downcomer Select this check box if the riser is to be used as a downcomer in which case
fluids are transported from the platform to the seabed. This selection will set
the start point of the profile at the top of the air section as indicated by a
large blue circle on the riser schematic.

Note: Typically a riser is assumed to start from the seabed and end at the platform. Total height of
the riser is calculated by adding the platform height (section of riser in air) and the seabed depth
(section of the riser in water). For modeling purposes, if a riser is completely under water, specify 0
for platform height. Similarly, if a riser is fully in air, specify 0 for seabed depth.

Heat Transfer Data Properties

Property Description
Surface temperature Ambient air temperature (a fixed temperature used for air section only)
Seabed temperature Seabed water temperature. Variable temperature used for water
section
U Value type air section Overall heat transfer coefficient (U value) for air section. Available
options are: Insulated, Coated, Bare (in air) and User supplied.
U Value air section Used to calculate heat transfer for the riser section above the water
surface.
U Value type water Overall heat transfer coefficient (U value) for water section. Available
section options are: Insulated, Coated, or User supplied.
U Value water section Used to calculate heat transfer for the riser section in the water.
Inside film coefficient You can include the Inside film coefficient (within the supplied heat
transfer coefficient above), or choose to calculate separately.
Calculation is performed based on selected method (under Home
Simulation settings Heat transfer tab ).

Note: The water section temperature profile will be a linear gradient between Seabed
temperature and Surface temperature.

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Riser Schematic

Property Description
Geometry profile For a riser, the geometry profile is a plot of riser depth versus horizontal
distance.
Ambient Similar to geometry profile, ambient temperature is also plotted against
temperature (plot) depth.
Data view button By default the riser geometry and ambient temperature profiles are displayed
(plot) graphically. A table control button at the bottom right of the plot allows you to
switch to a tabular view of the data. When in tabular view, a chart shaped
button allows you to switch back to plot view.
Riser starts at This is a read only field that indicates the starting point of the riser in the
model and thus indicates the orientation (profile direction) of the riser in the
network. The riser schematic in the editor will display a large blue circle to
indicate the starting point in the profile data.

For more information, see Typical Values (p.487), Heat Transfer Coefficient (p.399), and Internal
Fluid Film Heat Transfer Coefficient (p.402).

Related links:
Environmental Properties (p.183)
Riser - Detailed Model Properties - General Tab (p.131)
Pipeline Comparison: Land, Subsea, and Riser (p.116)

Riser - Detailed Model Properties - General Tab

Detailed model allows modeling complex variations in riser geometry and also exposes detailed
heat transfer calculations including modeling for pipe insulation.
Simple model
Use this default mode if the riser has a simple geometry (a vertical pipe or inclined pipe
with constant inclination angle) and you want to perform a simplistic heat transfer
calculation using the known heat transfer coefficient.
Detailed model
Allows you to capture complex riser geometry and at the same time, you will be able to
perform detailed heat transfer calculation including pipeline coating.

Riser Properties

Property Description
Name Name of the riser
Active Select this check box to activate the riser so that it will be used during
simulation. Active risers are displayed in light green. Clear the check box to

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Property Description
deactivate. Inactive flowlines are treated as connectors and do not cause a
pressure drop.
Mode Based on data availability and need, you can switch between Simple and
Detailed mode. Detailed mode has an additional tab for detailed heat transfer
modeling.
To switch to the detailed model, click Detailed. Click Simple to return to the
simple model (the detailed data will be deleted).
Override global By default, a riser uses global environment data (for example, ambient
environmental temperature, wind, and current data, etc). If checked, it will use environmental
data data configured locally to the selected riser.

General Tab - Pipe Data Properties

Property Description
Inside diameter Inside diameter for the riser.
Wall thickness Select and specify either wall thickness or the outside diameter of the riser,
Outside diameter excluding any coatings.
Roughness Enter the typical value for the absolute pipe roughness based on the material
type. The default value is 0.001 inches (0.0254 mm).

Note: If there is any change in riser inside diameter, wall thickness, or roughness along the
flowpath, add a second riser object.

General Tab - Platform Data Properties

Property Description
Platform height (above Platform height above the water surface. A vertical pipe section will be
waterline) created with air as the ambient fluid.

General Tab - Profile Data Properties

Property Description
Use as Select this check box if the riser is to be used as a downcomer in which case
downcomer fluids are transported from the platform to the seabed. This selection will set the
start point of the profile at the top of the air section as indicated by a large blue
circle on the riser schematic.
Distance Select either Horizontal distance or Measured distance based on data that you
want to enter. The unknown will be calculated geometrically.
Depth MSL Mean sea level depth of each riser profile data point

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Property Description
Profile Table Based on selected distance, enter the appropriate data for distance and depth
in each row. The distance here refers to the cumulative distance as you go
along the riser in the direction of its orientation.

Riser Schematic

Property Description
Geometry profile For a riser, the geometry profile is a plot of riser depth vs horizontal distance.
(plot)
Ambient Similar to geometry profile, ambient temperature is also plotted against
temperature (plot) depth.
Data view button By default riser geometry and ambient temperature profile are displayed
(plot) graphically. A table control button at the bottom right of the plot allows you to
switch to a tabular view of data. When in tabular view, a chart shaped button
allows you to switch back to plot view.
Riser start at This is a read only field that indicates the starting point of the riser in the
model and thus indicates the orientation (profile direction) of the riser in the
network. The riser schematic in the editor will display a large blue circle to
indicate the starting point in the profile data.

For more information, see Typical Values (p.487).

Related links:
Environmental Properties (p.183)
Riser - Detailed Model Properties - Heat Transfer Tab (p.133)
Pipeline Comparison: Land, Subsea, and Riser (p.116)

Riser - Detailed Model Properties - Heat Transfer Tab

You can model a simple heat transfer using a known single value of heat transfer coefficient that is
applied over the entire length of riser. However, if you choose to calculate heat transfer coefficient,
you can model the effect of insulation and heat transfer with the surrounding water.

Heat Transfer Tab - Heat Transfer Properties (Multiple U Value Input Method)

Property Description
U Value input Overall heat transfer coefficient (U value)
method Specify
Select this option to enter a single U value if it is known.
Calculate
Select this option when the heat transfer coefficient of the surrounding
medium is not known. A heat balance is performed using heat transfer

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Property Description
coefficients calculated from supplied data describing coatings, burial
conditions, and ambient fluid properties.
Inside film You can either Include the Inside film coefficient (within the supplied heat
coefficient transfer coefficient above), or choose to calculate separately. Calculation is
performed based on selected methods (under Home Simulation settings
Heat transfer tab).

Heat Transfer Tab - Thermal Data - Air Section Properties (Multiple U Value Input Method)

Property Description
Surface temperature Ambient temperature (air section)
U Value type air section Overall heat transfer coefficient (U value) for the riser section above the
water surface. Options are: Bare (in air), Coated, Insulated, or User
supplied.
U Value air section Used to calculate outside heat transfer for the riser section above the
water surface.

Heat Transfer Tab - Thermal Data - (Specify U Value Option)

Property Description
U Value type water section Overall heat transfer coefficient (U value) for the riser section in the
water. Options are: Bare (in water), Coated, Insulated, or User
supplied.
U Value water section Used to calculate heat transfer for the riser section in the water.
Depth MSL Mean sea level depth.
Ambient water temperature Surrounding water temperature for the riser at the entered Depth
MSL.

The heat transfer coefficient is calculated from entered pipe and conductivity data. Enter the
following information to compute the overall heat transfer coefficient.

Properties Associated With Calculate U Option

Property Description
Pipe conductivity Thermal conductivity of the pipe material
Surface temperature Ambient air temperature
Wind speed Average velocity of the surrounding air

Heat Transfer Tab - Thermal Data (Specify U Value Option)

Property Description
Depth MSL Mean sea level depth.

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Property Description
Ambient water temperature Surrounding water temperature for the riser at the entered Depth
MSL.
Current velocity Average velocity of the surrounding water at each Depth MSL.
Thermal data table for water This table appears only if you have checked the option to override
section global environmental data.

Heat Transfer Tab - Pipe Coating Details (Calculate U Value Option)

Property Description
Pipe coating You can add multiple layers of pipe coatings. For each coating layer, specify
details the following:
Thermal conductivity of the coating material
Thickness of the coating layer
Description (for reference purposes only)
Overall outside The outside diameter of the pipe and coating layers. This value is calculated
diameter based on user supplied pipe diameter and coating thicknesses.
Pipe cross section This schematic underneath the coating table displays a Pipe cross-section
schematic showing pipe and coating layers in different colors.

For more information, see Heat Transfer Coefficient (p.399) and Internal Fluid Film Heat Transfer
Coefficient (p.402).

Related links:
Adding Connections (p.144)
Riser - Detailed Model Properties - General Tab (p.131)
Managing Flowlines and Risers (p.251)

Three Phase Separator

A separator is a cylindrical or spherical vessel used to separate oil, gas, and water phases from the
incoming mixed fluid stream.
In a 3-phase separator all three phases (oil, gas, and water) are separated and discharged from
three separate outlets and thus these separated streams follow different branches in a network. On
the other hand, in a typical well-centric mode, only one of the outlet streams can be considered for
onward flow modeling and assigned as product stream; the remaining streams cannot be
configured and are discarded.

Graphical Representation
A 3-phase separator has 4 ports; one for the feed stream (left) and three for the separated outlet
streams (right). All three outlet ports must be connected in a valid network. The outlets of the
separator icon on the network diagram are color coded.

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Output Product stream

Red Gas (the top outlet port of 3-phase separator)
Green Oil (the middle outlet port of 3-phase separator)
Blue Water (the bottom outlet port of 3-phase separator)
Table 2.10: Key to Outputs

The editor displays all available properties.

Three-Phase Separator Properties

Property Description
Name Name of the three-phase separator.
Active Select this check box to activate the three-phase separator so that it will be used
during simulation. Clear the check box to deactivate. An inactive separator does not
separate and acts like a simple junction.

Three-Phase Separator General Properties

Property Description
Product stream Select the phase to keep.
Gas/Oil Amount of gas removed from the incoming stream. For example, a 90% gas/oil
Efficiency efficiency indicates that 90% of the free gas at the separator condition (pressure
and temperature) will be removed from the separator and sent to the gas outlet
branch.
Water/Oil Amount of water removed. For example, 90% water/oil efficiency indicates that
Efficiency 90% of the water will be removed from the separator and sent to the water
outlet branch.
Separator Operating pressure refers to pressure set at the separator. If this is not set, it
pressure will be calculated. Specifying the separator pressure is discouraged, particularly
(optional) in network simulations, as this specification often creates pressure
discontinuities. It is intended to be used only when the downstream branch is a
terminating branch and not pressure specified.

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Note: For network separators, there will be a pressure discontinuity between the separator and the
separated branch inlet. This represents the pump, compressor, or choke required to adjust the
stream's pressure to that pressure necessary to balance the remainder of the network.

Related links:
Two Phase Separator (p.137)

Two Phase Separator

A separator is a cylindrical or spherical vessel used to separate phases from the incoming mixed
fluid stream. A two-phase separator separates gas from liquid or water from the hydrocarbons (gas
and/or oil). To split all three phases, use a three-phase separator instead.
A two phase separator can be used in either single branch or network models. In a single branch,
one of the outlet streams is discarded as waste. In a network model, the second outlet stream
forms a second branch in a network.

Graphical Representation
A two-phase separator has three ports; one for the feed stream (left) and two for the separated
outlet streams. If only one of the outlet ports of a 2-phase separator is connected to a branch
exiting separator, it is treated as a single-branch separator. However, if both outlet ports are
connected, it becomes a network separator. The outlets of the separator icon on the network
diagram are color-coded.

Output Product stream

Red Gas (always takes the top outlet port)
Yellow Hydrocarbons (gas and oil) (always takes the top outlet port)
Aqua Liquid (oil plus water) (always takes the bottom outlet port)
Blue Water (always takes the bottom outlet port)
Table 2.11: Key to Outputs

The editor displays all available properties.

Two-Phase Separator Properties

Property Description
Name Name of the two-phase separator
Active Select this check box to activate the two-phase separator so that it will be used during
simulation. Clear the check box to deactivate. An inactive separator does not separate
and acts like a simple junction.

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Two-Phase Separator General Properties (Single Branch Model)

Property Description
Production Stream Select the phase that you want to keep (the continuous stream).
Discarded Stream Select the phase to remove (if a 2-phase separator is used in a single branch
like well stream).
Discontinuous Phase that is separated from the production stream and branched out from
stream the main branch. However, network simulation tracks this phase to the
connected branch and sink.
Efficiency Amount of material removed from the production stream. For example, 90%
efficiency indicates that 90% of the discarded/discontinuous stream is
separated.
Separator Operating pressure refers to pressure set at the separator. This parameter
pressure (optional) appears only if a two-phase separator is part of a network with both
production and discontinuous branches connected. Specifying the separator
pressure is discouraged, particularly in network simulations, as this
specification often creates pressure discontinuities. It is intended to be used
only when the downstream branch is a terminating branch and not pressure
specified.

Note: For network separators, there will be a pressure discontinuity between the separator and the
separated branch inlet. This represents the pump, compressor, or choke required to adjust the
stream's pressure to that pressure necessary to balance the remainder of the network.

Related links:
Adding Surface Equipment using the Well Editor (p.91)
Adding Surface Equipment using the Network Diagram (p.102)
Three Phase Separator (p.135)

Configuring Wellstream Outlet or Inlet Conditions

Within the Well editor, use the Wellstream outlet conditions tab to specify boundary
conditions for the wellstream outlet. You may optionally provide boundary conditions for use in
network simulations with boundary conditions specified at the surface (wellstream outlet). The fluid
model defined represents the full wellstream fluid mixture to account for gas lift injection, multiple
completions, and so forth.
Often with a large network, a facility engineer focused on analyzing the network may not be
interested in modeling the entire well for multiple reasons (uncertainty of well data, faster
simulation, simplified network, etc.) and may want to simulate the network using the surface
measurements at the wells (typically at wellhead) as the boundary. By assigning a Wellstream
Outlet (for a production well) and/or Wellstream Inlet (for an injection well), you can perform such
analysis.

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This wellstream outlet (or wellstream inlet in case of an injection well), virtually replaces the entire
well upstream (or downstream, for an injection well) of this point and uses a representative
condition (pressure, temperature and fluid) to simulate the resultant simplified network, and is
typically located at the point of measurement. In case of a single branch involving an injection well,
you can use the Wellstream Inlet conditions to define the boundary conditions and fluid associated
with the surface injection source.
By default, the wellstream outlet/inlet is placed at the wellhead, but you can change the location to
any other point on the well branch where surface measurements are available. A small orange
block shown below indicates the location of the wellstream outlet for a production well.

Wellstream outlet at wellhead

Wellstream outlet at choke outlet

Wellstream outlet at end of flowline

Wellstream outlet/inlet requires all the parameters you would specify to a generic source in
PIPESIM. These are:

Wellstream Outlet and Inlet Conditions Properties

Property Description
PQ Curve By default a source requires a fixed pressure and/or fixed flowrate boundary
(checkbox) condition. When you select the PQ curve option, you can model a PQ curve
(typically wellhead performance curve). Additional tabs appear to record PQ
table (Table tab) and display PQ-curve (Curve tab).

Note: PQ Curves are used to represent the deliverability of a wellstream outlet/

inlet for network simulation tasks only. For single-branch simulation tasks, the
PQ curve is ignored and the single-value source pressure and/or rate defined in
the simulation task is used instead.

Temperature The fluid temperature at the wellstream outlet/inlet.

Pressure Fluid pressure at the wellstream outlet/inlet.
( Appears when PQ curve is unchecked)

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Property Description
Flowrate Fluid flowrate (liquid, gas or mass) at the wellstream outlet/inlet. (Appear when
PQ curve is unchecked)

Note: You can also create a new fluid or edit the properties of a defined fluid.

PQ Curve Properties - Table Tab

Property Description
PQ type Flowrate basis for the PQ curve. Options are liquid flowrate, gas flowrate
or mass.
PQ Table (Table tab) Enter pressure and flowrate relationship in the table.
PQ Table (Curve tab) Graphically displays the PQ curve

Fluid Model Properties

Property Description
Fluid model Define a fluid model for the wellstream outlet/inlet to represent the fluid
mixture at this point.
Override phase Select this check box if you want to override the phase ratio of selected fluid.
ratio
Gas ratio If you have checked override, select the gas phase ratio type and specify a
value.
Water ratio If you have checked override, select the water phase ratio type and specify a
value.

Note: You can also create a new fluid or edit the properties of a defined fluid.

Related links:
Creating or Editing Fluid Models (p.146)
Setting Wellstream Outlet (p.140)
Setting Wellstream Inlet (p.141)

Setting Wellstream Outlet

This wellstream outlet (applies to a production well) virtually replaces the entire well upstream of
this point and uses a representative condition (pressure, temperature and fluid) to simulate the
resultant simplified network. By default wellhead is treated as wellstream outlet. However, you can
assign any other surface equipment or connection as wellstream outlet.
1. Perform one of the following tasks:

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In the well-centric mode, go to surface equipment tab and on the surface schematic right
click on any object (wellhead, other equipment or connection except junction) and select Set
as Wellstream Outlet
In the network-centric mode, right click on any object (wellhead, other equipment or
connection except junction) in the well branch and select Set as Wellstream Outlet.
Your wellstream outlet is now set and is displayed on the object with a orange box attached to
the object.
2. To view and configure the properties of wellstream outlet, open well editor and select the
wellhead at the surface schematic under surface equipment tab of well editor.
Property pane for wellstream outlet appears underneath the surface schematic
3. Configure wellstream outlet conditions and assign a fluid model.

Note: The Wellstream outlet conditions tab properties are optional, except when running a network
simulation with boundary conditions associated with surface conditions.

Related links:
Configuring Wellstream Outlet or Inlet Conditions (p.138)

Setting Wellstream Inlet

This wellstream inlet (applies to an injection well), virtually replaces the entire well downstream of
this point and uses a representative condition (pressure, temperature and fluid) to simulate the
resultant simplified network. In case of a single branch operation, you can use the Wellstream Inlet
conditions to define the boundary conditions and fluid associated with the surface injection source.
1. Perform one of the following tasks:
In the well-centric mode, go to surface equipment tab and on the surface schematic right
click on any object (wellhead, other equipment or connection except junction) and select Set
as Wellstream Inlet.
In the network-centric mode, right click on any object (wellhead, other equipment or
connection except junction) in the well branch and select Set as Wellstream Inlet.
Your wellstream outlet is now set and is displayed on the object with a orange box attached to
the object.
2. To view and configure the properties of wellstream inlet, open the well editor and select the
wellhead at the surface schematic under the surface equipment tab of well editor.
Property pane for wellstream inlet appears underneath the surface schematic.
3. Configure wellstream inlet conditions and assign a fluid model.

Related links:
Configuring Wellstream Outlet or Inlet Conditions (p.138)

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Viewing Surface Equipment Properties

You can view properties for the various surface equipment objects associated with a well.
1. To view properties for a surface equipment object, complete one of the following actions:
On the Surface equipment tab of the well editor, click on an equipment object or
connection within the surface schematic.
Click an object name listed at the top of the Wellbore schematic.
(Network-Centric Mode) Double-click an object name in the Inputs pane.
(Network-Centric Mode) Right-click an object name in the Inputs pane and click Edit.
(Network-Centric Mode) On the network diagram, double-click an equipment object.
On the network diagram, right click an object and click Edit.
The specific equipment properties display on the Surface equipment tab or in the appropriate
editor window.

Related links:
Adding Surface Equipment using the Well Editor (p.91)
Adding Surface Equipment using the Network Diagram (p.102)

Engine Keywords
You can insert this tool in a well or as a surface equipment. The Engine Keyword Equipment writes
to the engine input file the keywords inline and entered by you.
To use the Engine keywords tool, perform the following steps:
1. Double click a well to open the Well Editor.
2. Drag and drop the Engine keywords equipment on the well.
The Downhole equipment tab is active to include the engine keywords parameters.
3. Click the Downhole equipment tab and update (if necessary) the engine keywords
parameters:

Name: Name of the engine surface equipment.

Active You can specify if the unit is active or not.
Measured depth The depth of the equipment in the well.

Note: The Measured depth parameter is only available in the Well Editor.

Engine keywords Enter the keyword used by the engine

For more information, see Keyword Reference (p.511).

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Related links:
Adding Downhole Equipment (p.32)
Adding Surface Equipment using the Network Diagram (p.102)

2.2.5 Creating a Network Model from a GIS Shapefile Automatically

Note:
PIPESIM currently only supports shapefiles with coordinates referenced to EPSG:4326, known
as the World Geodetic System (WGS) 1984 or WGS84. Shapefiles with coordinates referenced
to other coordinate reference systems must be de-projected to EPSG:4326 coordinates using
standard desktop GIS software such as ArcGIS for Desktop or QGIS, before importing them
into PIPESIM to create networks.
PIPESIM currently only supports the automatic creation of flowlines from polyline shapefile
features. Wells and other equipment cannot yet be automatically created from point and
polygon shapefile features. However, PIPESIM will automatically add junctions between
flowlines when the network is created and provides the ability to convert these junctions to
wells, sources, sinks and other equipment. Refer to the topic Converting Junctions to Wells,
Sources, Sinks and Equipment (p.124) for additional details.
PIPESIM supports the creation of networks from a shapefiles only in new workspaces (for
example, it does not support incremental network creation). You will get an error message if
you attempt to import a network into a workspace that already has any kind of equipment.

1. Go to the Home tab, in the Viewers and results group, select GIS map.
2. From the active Insert tab, click Import network and browse to the location of the shape files.
3. Select the main shape file with the *.shp extension and click Open.
The *.dbf and *.prj files must also be present in the same location. For more information,
refer to GIS Shapefile Basics (p.262).
The Import network dialog box opens where you can map the attributes in the shape file (if
available) to the PIPESIM properties required for simulation. They are the Flowline name, Pipe
Inside Diameter, Pipe wall thickness and Pipe roughness. The Import dialog box also enables
you to define other global environmental and flowline settings for the entire network that will be
imported. This is to speed up the facilitate network creation and process.
4. In the Shapefile property column, Map the available flowline name attribute in the shapefile to
the PIPESIM flowline name by selecting it from the Options list. If there is no Flowline name
attribute in the shapefile, leave the default [Create New] option. PIPESIM will automatically
create new names for each imported flowline.
The attribute options available in the options list for each Shapefile property are type-specific
(for example, Flowline name) will display only the text attributes in the shapefile, while Pipe ID,
wall thickness and roughness will display only numeric attributes.
5. Map the Shapefile property attributes for Pipe Inside Diameter, Pipe wall thickness, and Pipe
roughness, if available. If any one or all of these properties are unavailable in the shapefile,

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check the Override box and manually enter these values. The manual values will be assigned
to every flowline created from the shapefile.
6. The Air temperature, Wind speed, Soil type and Soil conductivity values in the Global
environment settings are the default values under Home in the Data group, select Simulations
settings and click the Environmental tab in the workspace itself. You may leave the default
values or change them by checking the Update global environment settings and entering your
preferred values. All flowlines created will be assigned these values and the global
environmental settings under Simulation settings will also be updated with these values.
7. The Flowline settings section also displays the default values. You may modify the heat
transfer properties for the flowlines, if desired.
The recommendation is to limit the use of the feature to automatically create networks from
shapefiles, to onshore environments only, because risers cannot currently be created from
shapefile features.
8. Click OK to complete the import network process. The created network appears on the GIS
map layer. PIPESIM will create a flowline for every polyline feature and automatically insert
junctions between consecutive polylines, where they share an endpoint.
9. Capture the elevation profiles for the imported network by using the steps from Capturing
Elevation (p.276). Alternatively, you can manually enter the elevation profiles for each flowline
in the Logical view of the Flowline editor by unchecking the Populate from GIS map box.
10.Complete the network creation process by manually converting individual junctions to wells,
sources, sinks and other equipment. For more information, see Converting Junctions to Wells,
Sources, Sinks and Equipment (p.124).

Related links:
Creating or Editing a Network Model (p.96)
Using the GIS Map (p.270)

2.2.6 Adding Connections

In network-centric mode, the connection objects are contained in the Connections group located
on the Insert tab. Connection objects are used to connect two node objects. The node objects
must have already been added to the model to be connected. Use a connector (a zero-length
flowline) to connect two equipment objects that have no significant pressure or temperature
change between them.
1. Perform one of the following actions:
On the Insert tab in the Connections group, click Connector.
On the Insert tab in the Connections group, click Flowline.
On the Insert tab in the Connections group, click Riser.
2. On the network diagram, hover the mouse pointer over the first object to be connected. A small
square appears on the object.
3. Click the object, and then click the second object (representing the end point).

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Note: A small

appears when the pointer is near the target; a small

appears when it is not close enough.

Either a connector (

), a flowline, or riser appears, connecting the two objects.

4. Double-click either the flowline or the riser, and then enter the properties in the corresponding
editor to define the flowline or riser profile (distance and elevation) by using either the simple
model or the detailed model.

Note: A connector has no configurable properties.

Related links:
Flowline - Simple Model Properties (p.109)
Flowline - Detailed Model Properties - General Tab (p.112)
Flowline - Detailed Model Properties - Heat Transfer Tab (p.115)
Flowline Overview
Riser - Simple Model Properties (p.128)
Riser - Detailed Model Properties - General Tab (p.131)
Riser - Detailed Model Properties - Heat Transfer Tab (p.133)
Riser Overview

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3
Creating or Editing Fluid
Models
Fluid modeling is a fundamental aspect of multiphase flow simulation. Before running any
simulations, you need to create one or more fluid models. Fluid models are used to describe phase
behavior and provide physical and transport properties of the fluid required for any simulation run.
PIPESIM* supports several types of fluids. After you select a fluid type on the Home tab, all the
objects within the model automatically use that fluid type. Even though you can store multiple types
of fluids within an object, PIPESIM only displays the one you selected on the Home tab and uses it
in simulation. These fluid types are currently available:

Fluid Type Description

Black Oil Black oil fluids are modeled as three phases: oil, gas, and water. The amount of
each phase is defined at stock tank conditions by specifying gas and water
phase ratios, typically the gas/oil ratio (GOR) and the watercut. Properties at
pressures and temperatures other than stock tank are determined by
correlations. Water is assumed to remain in the liquid phase. The key property
for determining the phase behavior of hydrocarbons is the solution gas/oil ratio,
which is used to calculate the amount of the gas dissolved in the oil at a given
pressure and temperature.
Compositional Compositional fluid refers to a fluid made up of a number of components.
fluid These can be real molecules, such as methane, ethane, or water, known as
library components, or user-defined pseudo-components that represent the
properties of several molecules known as petroleum fractions. The Flash
packages available in PIPESIM include ECLIPSE 300, GERG, and Multiflash.

Note: When the Multiflash package is chosen in the Compositional fluid mode,
the fluid definition is done using the PIPESIM interface (Multiflash "native").
However, when the MFL File mode is chosen, the fluid definition is done using
files generated by launching the Multiflash interface (Multiflash MFL file). Refer

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Fluid Type Description

to the section Multiflash in Compositional Fluid mode ("native") vs Multiflash

MFL files (p.146) for more details on these two options.

A compositional fluid can be defined within PIPESIM and written to a PVT file.
PVT File PVT files are generated from a third-party PVT simulator such as AspenTech's
HYSYS, Calsep's PVTSim, KBC's Multiflash, GUTS, DBR Solids, and OLI's
ScaleChem. The PVT simulator writes a data file that is stored externally to
PIPESIM in an ASCII file. When properties are required at a specific pressure
and temperature (PT), the data file will be interrogated, and interpolation (or
extrapolation) used to find the properties at the required PT point. You may
define only one PVT fluid per model.
MFL File MFL files are generated from KBC's Multiflash software, a 3rd-party PVT flash
package available as a separate licensed module in PIPESIM. Multiflash
enables full phase behavior modeling of multiphase fluids and solids using
standard models with petroleum fluid characterization. You may define a new
MFL fluid (p.156) or edit existing MFL fluid files (p.156) by launching the
Multiflash interface from PIPESIM or simply use existing MFL files (p.156) by
pointing to their locations. Multiple MFL files can be defined in one PIPESIM
model and mapped to different sources and wells in the Fluid Manager,
however care must be taken to ensure that the models and components are
consistent across all MFL files. Refer to the section Ensuring consistency
among multiple fluid files in a PIPESIM network model (p.164), for more
details.

Related links:
Defining Black Oil Fluids (p.147)
Defining Compositional Fluids (p.156)
Creating/Defining a new MFL fluid (p.156)
Displaying Phase Envelopes for Compositional fluid or MFL file (p.172)
Overriding Fluid Phase Ratios (p.174)
Importing a PVT File (p.176)
Managing Fluids (p.13)

3.1 Defining Black Oil Fluids

Black oil fluids are modeled as three phases: oil, gas, and water. The amount of each phase is
defined at stock tank conditions by specifying gas and water phase ratios, typically the gas/oil ratio
(GOR) and the watercut. Properties at pressures and temperatures other than stock tank are
determined by empirical correlations. Water is assumed to remain in the liquid phase. The key
property for determining the phase behavior of hydrocarbons is the solution gas/oil ratio, which is
used to calculate the amount of the gas dissolved in the oil at a given pressure and temperature.

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You can create a new fluid using the global Fluid manager or using the Fluid model tab that
appears whenever source properties (completions, injection points, and generic sources) are
defined.
1. On the Home tab, click Fluid manager and select Black oil fluid from the options list as the
global fluid option in the model.
The Fluid manager opens.
2. On the Fluids tab, click New (+) at the bottom left corner of the fluid table.
3. Perform one of the following actions:
To initialize a fluid description using an existing template, click Template and select the one
of the predefined fluids from the list, and then click OK. The new fluid is added to the fluid
table.
To create a new fluid model without a template, click New, and then click OK.
The Fluid editor window opens.
4. Edit the fluid Name, and enter a Description.
5. Double-click on the appropriate row in the fluid table to open the Fluid editor window, and
define the fluid properties.
6. Perform one of the following actions to save the fluid:
Click Close and the fluid is saved in the Fluid manager.
To save the fluid as a template, create a meaningful title and click Save as template, and
then click OK.

Note: The fluid template option is useful when other fluid sources have similar fluids with little or no
variation in properties, correlations, or calibration. The fluid is added to the Fluid templates
catalog and is available in the New fluid window the next time you create a new fluid.
If only the phase ratios (such as watercut/GOR) vary by source, you do not need to create a fluid
template. Instead, change the phase ration overrides on the Fluid mapping tab.

7. To map the defined fluid to one or more fluid sources, click the Fluid mapping tab, and
associate fluids and sources.
8. On the Fluid mapping tab, you may optionally override phase ratios for specific fluid sources
by selecting the Override Phase Ratios check box and specifying the phase ratio type and
value for individual sources.
This method is convenient to reuse defined fluid models for wells or completions associated
with a common fluid, but exhibit different phase ratios due to effects such as coning or exposure
of perforations across contact depths.

Related links:
Properties Tab (p.87)
Calibration Properties (p.154)
Thermal Properties (p.156)

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3.1.1 Properties Tab

This topic describes the stock tank properties and contaminant fractions properties for black oil
fluids.

Stock Tank Properties

Property Description
Watercut The following options are available to define water content:
GWR Watercut
WGR
Volume % aqueous phase in the total liquid phase at standard
conditions. Typically used when the fluid is predominantly liquid.
GWR
Gas/water ratio at stock tank conditions. Typical for a Gas-water system
when water is the primary phase.
WGR
Water/gas ratio at stock tank conditions. Typically used for fluid where
gas is the predominant phase.
GLR Total gas ratio of the fluid (includes associated and free gas)
GOR The following options are available to define a gas phase in a typical
LGR petroleum fluid:
OGR
GLR
Gas/liquid ratio at stock tank conditions
GOR
Gas/oil ratio at stock tank conditions
LGR
Liquid/gas ratio at stock tank conditions. Typically used when gas is the
predominant phase.
OGR
Oil/gas ratio at stock tank conditions. Typically used when gas is the
predominant phase.
Gas specific Stock tank gas specific gravity (MWt/28.97)
gravity Default value is 0.64.
Water specific Stock tank water specific gravity (default value: 1.02).
gravity
APl gravity Oil phase density at stock tank condition can be defined as API gravity
DOD (141.5/SGL)-131.5. The API gravity default is 30.
Or, you may enter the dead oil density (DOD). The DOD default is 54.7 lb/ft3
or 876 kg/m3.

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Contaminant Mole Fractions

Contaminants are used to improve the accuracy in calculating the compressibility factor (Z factor)
used in the gas equation of state (PV=ZnRT). The CO2 fraction is also used for corrosion
calculations.
You can add and track the following gas contaminants in a black oil fluid:

Contaminant Description
CO2 fraction Carbon dioxide
H2S fraction Hydrogen sulfide
N2 fraction Nitrogen
H2 fraction Molecular hydrogen
CO fraction Carbon monoxide

Related links:
Defining Black Oil Fluids (p.147)

3.1.2 Viscosity Properties

Viscosity is a measure of the fluid's internal resistance to flow. The viscosity of a crude oil is
impacted by several factors like composition, pressure and temperature conditions as well as
presence of dissolved gas.
Presence of dissolved gas lightens the crude oil and reduces its viscosity.
As the oil is compressed, viscosity increases.
Below the bubble point, the effect of gas dissolving in oil dominates, and the saturated viscosity
decreases with pressure. However, at the bubble point pressure, all the available gas has
dissolved in the oil.
For pressures above the bubble point, the oil is undersaturated (no more free gas is available).
With increasing pressure, viscosity increases.

Undersaturated oil viscosity

For pressures above the bubble point, there is no vapor phase. The oil is undersaturated because
more gas could be dissolved in the oil, if the gas were available.

Property Description
Correlation Correlations available for calculating undersaturated oil viscosity are:
None
Vasquez & Beggs
Kouzel
Khan
De Ghetto

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Property Description
Hossein
Elsharkawy
Bergman & Sutton
Petrosky-Farshad
These correlations cover a wide range of crude oil types. For more detail on these
including formulation and applicability, see the Technical Description section of the
PIPESIM Online help.

Note: If you select None as the undersaturated oil viscosity method, the
undersaturated oil viscosity is assumed to be the same as the saturated live oil
viscosity at the same temperature and pressure.

Par A The Kouzel correlation exposes these parameters for tuning. The default values
Par B (0.239 and 0.01638) are suggested.

For more information, see Undersaturated Oil Viscosity. (p.434)

Live oil viscosity

Live oil is above stock tank pressure and contains dissolved gas.

Property Description
Correlation Correlations available for calculating live oil viscosity are:
Beggs & Robinson
Chew & Connally
Khan
De Ghetto
Hossein
Elsharkawy
Petrosky-Farshad
These correlations cover a wide range of crude oil types. For more detail on these
including formulation and applicability, see the Technical Description section of the
PIPESIM Online help.

For more information, see Live Oil Viscosity Correlations. (p.432)

Dead oil viscosity

Dead oil is oil at stock tank pressure or oil with no dissolved gas; for example, an oil in which gas
has been removed by a separator and pumped through an export line.

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Property Description
Correlation Correlations available for calculating dead oil viscosity are:
Beggs & Robinson
Glaso
Kartoatmodjo
De Ghetto
Hossein
Elsharkawy
Petrosky-Farshad
User 2-point
User Table
These correlations cover a wide range of crude oil types. For more detail on
these including formulation and applicability, see the technical section of
PIPESIM Online help.

Note: To display dead oil viscosity calculated by any of these correlations,

specify two measured temperatures from the correlation drop-down selector.
Viscosities calculated by the selected correlation will be displayed.

User 2 Point Instead of using one of the listed correlations, you can enter measured viscosity
viscosity lab data at two temperatures.
Temperature (1st), Temperature (2nd) measured temperature points
Viscosity (1st), Viscosity (2nd), corresponding measured viscosities

Note: Viscosities at all other temperatures will be calculated by the curve fitting
between these two data points.

User-defined Similar to 2-point viscosity data; however ,a viscosity table is used when you
table have three or more lab measurement data points.

For more information, see Dead Oil Viscosity. (p.430)

Oil-Water Mixtures
An emulsion is a mixture of two immiscible liquids. One phase (the dispersed phase) is carried as
droplets in the other (the continuous phase). In oil/water systems at low watercuts, oil is usually the
continuous phase. As watercut increases, there is a point where phase inversion occurs, and water
becomes the continuous phase. This point is the watercut cutoff, and it typically occurs between
55% and 70% watercut. The viscosity of the mixture is usually highest at and just below the cutoff.
Emulsion viscosities can be many times higher than the viscosity of either phase alone.

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Property Description
Emulsion Liquid viscosity and oil/water emulsions methods. Based on the method you
Viscosity selected, you might need to enter values for some properties. Examples:
method Set to viscosity of the continuous phase
The liquid viscosity equals the oil viscosity when the watercut is equal to or less
than the cutoff; otherwise, it equals the water viscosity.
Volume ratio of oil and water viscosities
The mixture viscosity equals the volume ratio of the oil and water viscosities.
PIPESIM* Original Woelflin 1942 Loose Emulsion
Use the original Woelflin Loose Emulsion correlation when the watercut is equal
to or less than the cutoff; otherwise, set it equal to the water viscosity above.
Woelflin (p.499) 1942 Loose Emulsion
Use the Loose Emulsion correlation at watercuts below the cutoff; otherwise, set
it to the water viscosity above it.
Woelflin 1942 Medium Emulsion
Use the Medium Emulsion correlation at watercuts below the cutoff; otherwise,
set it to the water viscosity above it.
Woelflin 1942 Tight Emulsion
Use the Tight Emulsion correlation at watercuts below the cutoff; otherwise, set
it to the water viscosity above it.
Brinkman (p.499) 1952
Use Brinkman 1952 correlation. This method generally predicts elevated liquid
viscosities on either side of the cutoff.
Vand (p.499) 1948, Vand coefficients
Use Vand correlation with Vand's coefficients. This method generally predicts
elevated liquid viscosities on either side of the cutoff.
Vand (p.499) 1948, Barnea & Mizrahi coefficients
Use Vand correlation with Barnea & Mizrahi coefficients. This method generally
predicts elevated liquid viscosities on either side of the cutoff.
Vand (p.499) 1948, user-defined coefficients
Use Vand correlation with coefficients that you selected for tuning. This method
predicts liquid viscosities on either side of the cutoff. Based on your choice of
coefficients, the results can yield elevated or depressed viscosities.
Richardson (p.499) 1958
Enter two coefficients, one is for oil in water and the other is for water in oil. This
method predicts liquid viscosities on either side of the cutoff. Based on your
choice of coefficients, the results can yield elevated or depressed viscosities.
Leviton and Leighton (p.499) 1936
Use Leviton and Leighton correlation. This method generally predicts elevated
liquid viscosities on either side of the cutoff.

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Property Description
User-defined table
Enter a table of the Watercut and Viscosity ratio or emulsion viscosity.
Watercut Perform one of the following actions:
cutoff Click Calculate to use the Brauner-Ullman (p.499) method.
Click Specify and enter a watercut cutoff percent (%) or fraction (fract.).
The default method is Specify. A typical value is between 55% and 70%; the
default value is 60%.

Related links:
Liquid Viscosity and Oil/Water Emulsions (p.470)

3.1.3 Calibration Properties

Black Oil fluid models use a set of empirical correlations to calculate various properties like
viscosity, bubble-point pressure, density, and so forth. In many cases, these calculated properties
do not match the values measured at lab. Calibration is required to improve the accuracy of the
fluid property calculations by adjusting the correlations to match measured data obtained by
laboratory analysis.
The bubble-point pressure is one of the most important parameters in black oil fluid modeling as
most of the fluid properties and choices of correlation change above and below this point. The
bubble point refers to the pressure and temperature conditions at which all the available gas are
fully dissolved in the oil. A slight drop in pressure (assuming constant temperature) will result in the
first bubble of gas coming out of oil phase and as pressure drops further, more and more gas will
come out of solution. Oil above the bubble point is referred as under-saturated oil as the amount of
gas dissolved is always less than what it could dissolve. On the other hand, oil below the bubble
point is referred to as saturated oil. Oil with no dissolved gas is referred to as dead oil.
If the calibration data is omitted, PIPESIM will calibrate on the basis of oil and gas gravity alone.
To calibrate a black oil fluid, add measured data and corresponding pressure and temperature
conditions.

Property Description
Density Property above the bubble point.
OFVF Density
Compressibility
Mass per unit of volume
OFVF (Oil formation volume factor)
Ratio of the liquid volume at reservoir conditions to that at stock tank
conditions
Compressibility
1/psi

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Property Description
Pressure Measured pressure
Temperature Measured temperature
Correlation Fixed correlation
Table 3.1: Calibration Above the Bubble Point

Property Description
Sat. Gas Quantity of gas that dissolves in the oil and saturates it at a given
pressure and temperature, such as reservoir conditions.
Pressure Pressure at the bubble point
Temperature Temperature at the bubble point
Solution Gas correlation List of available correlations
Table 3.2: Calibration at the Bubble Point

Property Description
Density Property at or below the bubble point.
OFVF Density
mass per unit of volume
OFVF (Oil formation volume factor)
ratio of the liquid volume at reservoir conditions to that at stock tank
conditions
Live Oil Viscosity Viscosity of oil containing dissolved gas
Gas viscosity Viscosity of free gas
Gas Z gas compressibility factor
Pressure Measured pressure
Temperature Measured temperature
Correlations List of available correlations
Table 3.3: Calibration At or Below the Bubble Point

For more information, see Gas Compressibility (p.436), Oil Formation Volume Factor for Saturated
Systems (p.427), and Live Oil Viscosity Correlations (p.432).

Related links:
Oil Formation Volume Factor (p.427)
Gas Viscosity (p.439)

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3.1.4 Thermal Properties

The following table describes the thermal property options which primarily influence heat transfer
calculations.

Property Description
Specific heat Specific heat capacity data is required for the calculation of fluid
capacity enthalpies. Application has default values of specific heat capacities for all
three phases (oil, gas and water). You can override these.
Thermal conductivity
Enthalpy calculation Method to use for the enthalpy calculation:
method Method1983
Method2009
The black oil fluid model makes some approximations in the entropy
balance, based on the thermodynamic behavior of typical hydrocarbon
fluids.
Specific latent heat of (Only available with Method2009) Amount of heat required to convert unit
vaporization mass of a liquid into the vapor without a change in temperature.

For more information, see 2009 Method (p.441) and 1983 Method (p.442).

Related links:
Defining Black Oil Fluids (p.147)

3.2 Defining Compositional Fluids

Compositional fluid modeling involves defining mole fractions for each individual molecular
component or petroleum fraction. Equations of state are used to flash the fluid (calculate vapor-
liquid equilibrium) and determine thermodynamic and transport properties. Compositional fluid
modeling is generally regarded as the most accurate approach, especially for wet gas, condensate
and volatile oil systems which require more rigorous heat transfer calculations and more accurate
phase fractions.
Creating a compositional fluid is a two-stage process.
Define (or update) the global component list and model settings.
Specify the composition for each individual fluid source.
1. Define (or update) the global component list and model settings.
a. On the Home tab, click Fluid manager and select Compositional fluid from the option list
as the global fluid option in the model.
The Fluid manager opens.
b. Select the components that are present by selecting the check boxes next to the component
names.

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c. To define petroleum fractions (pseudo-components), click New and specify the name and
properties of the pseudo-component.
Depending on the flash package, certain minimum properties are required (as indicated with
the red boxes). Once these properties have been supplied, all other properties are
calculated. Additional properties may be entered unless the field is marked as read only in
which case this value is always calculated.
d. To specify user-defined binary interaction coefficients, check the Override binary
interaction coefficients in the Models section. This will display a tabular view of the binary
coefficients for the default BIP set for the PVT package, which can then be edited for
example, Oil and gas 4 for Multiflash. If you would like to override the values of another BIP
set, uncheck the Override binary interaction coefficients box, change the BIP set and
then check the Override box again.

Note: The only binary interaction coefficients you can modify are for the ECLIPSE 300 and
Multiflash PVT packages. The GERG-2008 flash package uses NIST-REFPROP for calculation of
transport properties, and REFPROP limits certain components from being used in combination.
You may switch flash packages even after fluid models have been defined. However, due to
differences in component libraries, petroleum fraction definitions, and limitations with component
combinations (GERG-2008), some aspects of the fluid definition may not fully convert. Please refer
to the Message center to view any issues encountered during the conversion process.

2. Specify the composition for each individual fluid source.

You may define compositional fluid models for individual sources once the global component
list and model properties has been specified. You may apply these fluid models to one or more
fluid sources entering at each sources that supply flow to the system. Each fluid consists of a
set of mole fractions that specify the composition of the total stream, regardless of any phase
split the composition may exhibit at any pressure and temperature.
You can create a new fluid using the global Fluid manager or using the Fluid model tab that
appears whenever source properties (completions, injection points, and generic sources) are
defined.
a. On the Home tab, click Fluid manager and select Compositional fluid from the option list.
The Fluid manager opens.
b. To create a new compositional fluid, perform one of the following actions:
In the Fluid manager , on the Fluids tab, click New (+).
On the Inputs pane, right-click Fluids, and then click New.
From within a completion, injection point, or generic source properties editor, on the
Fluids tab, click New.
The Fluid editor window opens.
c. Edit the fluid Name, and enter a Description.
d. Specify the mole fractions for the fluid.
As you enter the mole fractions, a phase envelope representing the fluid displays the fluid
properties at standard conditions.

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e. To view the phase compositions and properties at conditions of interest, enter Pressure and
Temperature in the Flash/Tune fluid section.
f. To calculate a composition to match measured phase ratios, click Specify and enter the
observed gas and water ratios.
Compare the phase envelope of the tuned fluid relative to the original one. Also, look at
the phase compositions and properties associated with the tuned fluid.
To update the fluid composition to the values calculated to achieve the match, click
Apply tuned results to fluid.

Notes:
The methods used to match phase ratios require that components be initially present in
some amount to achieve the match. For example, if no water is present in the fluid, a
composition corresponding to a non-zero watercut cannot be calculated. Likewise, if
hydrocarbon liquid is present, no solution will be calculated if, for example, the only
hydrocarbon component defined is methane. Also, consider that there is no unique
phase composition to match specified gas and water ratios. The method PIPESIM uses
minimizes the sum residual errors for all components present. This approach is generally
satisfactory for fine-tuning phase ratios to match observed data so long as the original
composition is based on the laboratory analysis of a representative fluid sample obtained
in the field.
If you are using Multiflash and have a Multiflash Hydrates license and water and light
gases in your composition, the Hydrate formation curve will automatically appear on the
phase diagram

g. Click Close to save the new fluid.

h. To map the defined fluid to one or more fluid sources, click the Fluid mapping tab, and
associate fluids and sources.
i. On the Fluid mapping tab, you may optionally override phase ratios for specific fluid
sources by selecting the Override Phase Ratios check box and specifying the phase ratio
type and value for individual sources.
This method is convenient to reuse defined fluid models for wells or completions associated
with a common fluid, but exhibit different phase ratios due to effects such as coning or
exposure of perforations across contact depths. The same method used to tune individual
compositional fluid models is automatically applied.
For more information, see the list of REFPROP and GERG-2008 component restrictions and
Compositional Fluid Modeling (p.449) in the Technical Description.

Related links:
Salinity Models (p.150)
Binary Interaction Parameter (BIP) Sets (p.57)

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3.2.1 Viscosity Properties

Viscosity is a measure of the fluid's internal resistance to flow. The viscosity of a crude oil is
impacted by several factors like composition, pressure and temperature conditions as well as
presence of dissolved gas.
Presence of dissolved gas lightens the crude oil and reduces its viscosity.
As the oil is compressed, viscosity increases.
Below the bubble point, the effect of gas dissolving in oil dominates, and the saturated viscosity
decreases with pressure. However, at the bubble point pressure, all the available gas has
dissolved in the oil.
For pressures above the bubble point, the oil is undersaturated (no more free gas is available).
With increasing pressure, viscosity increases.

Oil-Water Mixtures
An emulsion is a mixture of two immiscible liquids. One phase (the dispersed phase) is carried as
droplets in the other (the continuous phase). In oil/water systems at low watercuts, oil is usually the
continuous phase. As watercut increases, there is a point where phase inversion occurs, and water
becomes the continuous phase. This point is the watercut cutoff, and it typically occurs between
55% and 70% watercut. The viscosity of the mixture is usually highest at and just below the cutoff.
Emulsion viscosities can be many times higher than the viscosity of either phase alone.

Property Description
Emulsion Liquid viscosity and oil/water emulsions methods. Based on the method you
Viscosity selected, you might need to enter values for some properties. Examples:
method Set to viscosity of the continuous phase
The liquid viscosity equals the oil viscosity when the watercut is equal to or less
than the cutoff; otherwise, it equals the water viscosity.
Volume ratio of oil and water viscosities
The mixture viscosity equals the volume ratio of the oil and water viscosities.
PIPESIM* Original Woelflin 1942 Loose Emulsion
Use the original Woelflin Loose Emulsion correlation when the watercut is equal
to or less than the cutoff; otherwise, set it equal to the water viscosity above.
Woelflin (p.499) 1942 Loose Emulsion
Use the Loose Emulsion correlation at watercuts below the cutoff; otherwise, set
it to the water viscosity above it.
Woelflin (p.499) 1942 Medium Emulsion
Use the Medium Emulsion correlation at watercuts below the cutoff; otherwise,
set it to the water viscosity above it.
Woelflin (p.499) 1942 Tight Emulsion
Use the Tight Emulsion correlation at watercuts below the cutoff; otherwise, set
it to the water viscosity above it.

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Property Description
Brinkman (p.499) 1952
Use Brinkman 1952 correlation. This method generally predicts elevated liquid
viscosities on either side of the cutoff.
Vand (p.499) 1948, Vand coefficients
Use Vand correlation with Vand's coefficients. This method generally predicts
elevated liquid viscosities on either side of the cutoff.
Vand (p.499) 1948, Barnea & Mizrahi coefficients
Use Vand correlation with Barnea & Mizrahi coefficients. This method generally
predicts elevated liquid viscosities on either side of the cutoff.
Vand (p.499) 1948, user-defined coefficients
Use Vand correlation with coefficients that you selected for tuning. This method
predicts liquid viscosities on either side of the cutoff. Based on your choice of
coefficients, the results can yield elevated or depressed viscosities.
Richardson (p.499) 1958
Enter two coefficients, one is for oil in water and the other is for water in oil. This
method predicts liquid viscosities on either side of the cutoff. Based on your
choice of coefficients, the results can yield elevated or depressed viscosities.
Leviton and Leighton 1936
Use Leviton and Leighton correlation. This method generally predicts elevated
liquid viscosities on either side of the cutoff.
User-defined table
Enter a table of the Watercut and Viscosity ratio or emulsion viscosity.
Watercut Perform one of the following actions:
cutoff Click Calculate to use the Brauner-Ullman method.
Click Specify and enter a watercut cutoff percent (%) or fraction (fract.).
The default method is Specify. A typical value is between 55% and 70%; the
default value is 60%.

Related links:
Liquid Viscosity and Oil/Water Emulsions (p.470)

3.2.2 Salinity Models

PIPESIM provides the option to define a "Salt component" as part of a Compositional fluid. This is
a useful feature to model the effect of salt on hydrate inhibition and its depression of the freezing
point and vapour pressure of water. In PIPESIM, the salt component cannot be explicitly (or
manually) defined. It can only be defined in one of two ways:
Compositional fluid mode: You may choose one of two Salinity model options: Ion Analysis or
Total Dissolved Solids (TDS) to define a Salt component when creating a Compositional fluid.

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MFL file mode: You may define a Salt component when creating an MFL fluid in the Multiflash
interface using the Inhibitor Calculator. Refer to the Multiflash Help for details.
The Salt component is a pseudo-component defined with a certain number of moles that
represents the NaCl equivalence of the salinity defined by the specified TDS or Ion Analysis data.
Choosing a Salinity model and entering its associated data will do the following.
Add "Water" and the "Salt component" to the global component list
Calculate the moles of the "Salt component" which is the moles of NaCl in an aqueous solution
that is equivalent to the aqueous solution defined by the specified TDS or Ion Analysis data

Defining a Salt Component in Compositional Fluid mode using a Salinity

Model
The steps below outline the procedure.
1. Set the Fluid mode for the workspace to Compositional, from the Fluid Manager and select
the global Salinity model option: TDS or Ion Analysis from the option list in the Component/
model settings tab. This will automatically add a read-only Salt component and Water to the
component list. Add the remaining components to the Component list by checking the boxes
beside them.

Note:
The Salinity model option "None" implies that no Salt Component will be added to the
Compositional fluid. This is the default.
The Salinity model selection is a global setting. All compositional fluids created in the
workspace will only be able to use the chosen salinity model.

2. On the Fluids tab, click New (+) at the bottom left corner of the Fluids table. Double-click the
row of the newly-created fluid to launch the Fluid editor. A new tab, Salinity Analysis, appears
next to the Viscosity tab in the Fluid editor.

Note: The Salinity analysis tab will appear in the Fluid editor only when the Salinity model
option is set to either TDS or Ion analysis.

3. Click the Composition tab and enter the value for the Moles of all components except the Salt
Component, which is read-only. By default, the Salt Component molar composition will be blank
until a Salt component is calculated from the Salinity analysis tab.
4. Click the Salinity Analysis tab and enter the required Salinity information for the previously-
selected Salinity model option: TDS or Ion Analysis, by overriding the default zero values.

Note:
The required data for the Ion analysis option is: Cation and Anion concentration from a lab-
measured brine analysis (at least 1 of each must be specified) and Brine density*.
The required data for the TDS option is: TDS from a lab-measured brine analysis and Brine
density*.

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*Brine density: For both the TDS and Ion analysis options, the default calculated brine
density may be used or a measured density/salinity may be entered. PIPESIM also provides
the option to convert measured salinity at standard conditions to measured density. To do
this, choose Measured salinity (standard conditions) as the Brine density option, enter
the salinity value and then select Measured density from the option list. The converted
density value will be displayed.

5. If all the required data has been correctly entered, the Salt component moles in the Salinity
analysis tab will be computed and automatically updated in the Composition tab.
The phase envelope will also be regenerated and the phase compositions and phase properties
from the flash conditions will be automatically updated to reflect the calculated salt component
molar composition. You may observe the impact of the salt on the hydrate and water lines on the
phase envelope.

Note: There are several errors that may cause the Salt component moles to fail to calculate.
These errors will trigger red validation boxes in the data fields with validation issues and will
display clear mouse-over messages indicating the problems. The validation messages will also
appear in the Message center. Once all the validation issues are resolved, the Salt component
moles will be successfully computed.

Importing PIPESIM Classic models with Compositional Fluids including a Salt

component
PIPESIM Classic (2012 and previous) supports three (3) Salinity model options:
TDS
Ion Analysis
Salt Analysis
The new PIPESIM only supports TDS and Ion Analysis. When PIPESIM Classic models with Salt
Analysis data are imported in the new PIPESIM, the global Salinity model option under
Component/model settings in the Fluid manager, will be set to "None," and the data will not be
imported. For Classic models with other salinity models (TDS and Ion Analysis ), the data will be
imported. PIPESIM Classic models with multiple compositional fluids defined with a mix of different
Salinity models, will be imported, with the exception of data associated with the Salt Analysis
model type. For this special import case, the supported data (i.e. associated with the TDS and Ion
Analysis options only) will be imported, but the global Salinity model option will be set to "None."
To view the imported data, simply choose the supported Salinity model with data, from the global
Salinity model list. This is because only 1 global Salinity model may be defined for the entire
workspace. You will have to decide on one Salinity model option and enter the required data for
the same salinity model type for all the compositional fluids you choose to model with a Salt
component. Clear and descriptive messages related to the outcome of the salinity model import will
be displayed in the Message center.

Related links:
Defining Compositional Fluids (p.156)

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3.2.3 Binary Interaction Parameter (BIP) Sets

Binary interaction parameters ( BIPs) are adjustable factors, which are used to alter the predictions
from a model until the predictions match experimental data as closely as possible. BIPs are usually
generated by fitting experimental VLE or LLE data to the model in question. BIPs apply between
pairs of components, although the fitting procedure may be based on both binary and multi-
component phase equilibrium information.
Different PVT packages have different BIP sets as outlined below. All BIP sets can be overridden
in PIPESIM except the GERG BIP set.

BIP Set Multiflash E300 GERG

OilGas1 x BIP's are not exposed in the PIPESIM interface and cannot be
OilGas2 x overridden.

OilGas3 x
OilGas4 x
PVTi x

Multiflash BIP sets

The interaction parameters in OILGAS1 were from the correlation recommended by Nishumi et al.
They correlated parameters between all the light gases and hydrocarbons up to Decane. However,
when these were used in the prediction of hydrate dissociation temperatures for systems
containing a significant amount of condensate or crude, it became apparent that neither the bubble
or dew points nor the hydrate dissociation temperatures were being predicted accurately.
After further investigation new correlations contained in OILGAS2 based on BIPs recommended by
Whitson for Methane with heavy hydrocarbons were introduced. The new correlations provide
heavy hydrocarbon interaction parameters for Ethane to Pentane, all of which were previously set
to zero. For systems containing Methane and alkanes up to C10 there is no major difference
between OILGAS1 and OILGAS2 BIP sets, but after C10 OILGAS1 parameters decrease rapidly in
value, reaching negative values after C16. In contrast, the values of OILGAS2 parameters continue
to increase gently with increasing carbon number.
OILGAS3 and OILGAS4 were later introduced and the only difference is in the parameters for
MEG/alkanes for the RKSA-info (hydrate) model. The newer parameters predict a lower (correct)
solubility for MEG in heavy hydrocarbons but are less accurate for the solubility of hydrocarbons in
MEG. We would generally recommend the use of the latest parameters, OILGAS4.

Related links:
Defining Compositional Fluids (p.156)

3.3 Multiflash in the Compositional Fluid mode (native) vs.

Multiflash MFL files
PIPESIM enables two options for using the Multiflash package:

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Package Type Description

Multiflash in the This option is enabled when you set the fluid mode to Compositional fluid
Compositional and choose Multiflash as the PVT package. With this option, the entire fluid
Fluid mode definition is done at a global level using the PIPESIM interface. The models
("native") selected (equation of state, viscosity, BIP set, etc.) are applied to all individual
fluids defined in the model. The models available with this option are a subset
of the full extent of the models available with the Multiflash MFL files option,
which gives you access to the standalone Multiflash program directly.
Multiflash MFL This option is enabled when the fluid mode is set to MFL file. The fluid
files definition is done using files generated by launching the Multiflash interface
(Multiflash MFL file). This option gives you access to the full extent of the
models available in Multiflash and is the required option for wax and
asphaltene thermodynamics. For complete details about defining and
managing MFL files in PIPESIM, refer to the sections Creating/Defining a new
MFL fluids (p.156), Using existing MFL fluid files (p.156), Editing an MFL fluid
file (p.156), and Availability of Multiflash models in PIPESIM using the MFL
file fluid mode option . (p.164)

Related links:
Creating/Defining a new MFL fluid (p.156)

3.4 Ensuring consistency among multiple fluid files in a

PIPESIM network model
To ensure reasonable simulation results for network models using multiple fluid files (for example,
MFL files), it is important to maintain consistency in the fluid characterization in the various fluid
files used. Here are a few guidelines to follow when using multiple fluid files in a single PIPESIM
network model:
All fluid files should have the same template of components

Note: Some components may be set to have zero number of moles in the different fluids, but
the component set should be the same across all fluids.

All fluid files should be characterized to the same number of pseudo-components and use the
same correlations and methods to estimate the properties of the pseudo-components (for
example,critical properties, acentric factors, omegas, etc.).
All fluid files should be defined with the same Binary Interaction Parameter (BIP) set.

Note:
When only one (1) MFL file is mapped in the PIPESIM workspace, all of the information in the
MFL file will be honored by PIPESIM in the simulation. This includes the Equation of State,

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Models for Viscosity, Thermal Conductivity, Surface Tension, BIP sets, etc. including any tuning
done to the fluid.
PIPESIM can currently use tuned data in only 1 MFL fluid file in the workspace. If you tune the
models (EOS, Viscosity, etc.) to match experimental data e.g. viscosity, density, etc., in the
Multiflash interface, it is strongly recommended that you use only one MFL file (the one with the
tuned data) in the workspace. If you use multiple MFL files with tuned data in the PIPESIM
workspace, the tuned data in only one of the MFL files will be used in the PIPESIM simulation
run.

Related links:
Creating/Defining a new MFL fluid (p.156)

3.5 Creating/Defining a new MFL fluid

1. On the Home tab, select MFL file from the Fluid manager option list as the global fluid option
in the model.
The Fluid manager opens.
2. On the Fluids tab, click New (+) at the bottom left corner of the Fluids table.
3. Click New to launch the Multiflash application.

Note: An alternative workflow for Steps 2 & 3 is to right-click Fluids in the Inputs pane and
click New Click New again to launch the Multiflash application. (This applies only if a
PIPESIM layout is chosen which displays the Inputs pane).

4. Refer to the Multiflash Help to define the fluid composition, equation of state and to set all the
required parameters for the fluid. QC the fluid in Multiflash by generating and reviewing the
phase envelope and doing various flashes and reviewing the results.

Note: You must select all of the PVT models; Equation of State, Viscosity, Surface Tension and
Thermal Conductivity and click Define model in the Multiflash interface, before saving the MFL
file and referencing it in PIPESIM. If you fail to do so, you will get an error in PIPESIM and you
will have to return to the Multiflash interface to set all the models, before the MFL file can be
used in PIPESIM.

5. Save the problem setup in Multiflash as an MFL file and close the Multiflash interface. This will
populate the File path in the PIPESIM interface with the location of the fluid file you just
created.

Note: Starting with PIPESIM 2014, MFL files are handled slightly different from older PIPESIM
versions. MFL files are actually imported into the PIPESIM model and the PIPESIM model can
be run without having physical copies of the MFL files on the machine. The MFL file path
mentioned in Step 5 is simply for reference purposes. As such, even if the MFL file is removed

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from this location, the PIPESIM model will still run with the imported MFL fluid. Similarly, any
changes to the MFL file in the file path will not be reflected in the PIPESIM model unless the
MFL file is re-imported.

6. Click OK.
7. Double-click the row of the newly-created fluid in the Fluids tab to visualize the fluid
composition and phase envelope. Click Close twice to exit the Fluid manager and continue
with the model.

Note:
An alternative workflow for Step 7 if the fluid was created from the Inputs pane is to expand
the Fluids list in the Inputs pane and double-click the fluid you just created to visualize its
details. Click Close to exit and continue with the model.

8. Repeat Steps 2-7 to create new MFL fluid files for the workspace OR include additional existing
MFL files by browsing to their locations by following steps 3-5 of the Importing existing MFL
fluid files (p.156) topic.
9. Click the Fluid mapping tab in the Fluid manager and map all the wells and sources in the
workspace to the defined MFL fluid files.
Multiple MFL files can be defined in one PIPESIM model and mapped to different sources and
wells in the Fluid Manager, however care must be taken to ensure that the models and
components are consistent across all MFL files.

Notes:
PIPESIM can currently use tuned data in one (1) MFL fluid file in the workspace. If you tune
the models (EOS, Viscosity, etc.) to match experimental data for example, viscosity, density,
etc., in the Multiflash interface, it is strongly recommended that you use only one MFL file
(the one with the tuned data) in the workspace. If you use multiple MFL files with tuned data
in the PIPESIM workspace, the tuned data in only one of the MFL files will be used in the
PIPESIM simulation run. For more information, see Ensuring consistency among multiple
fluid files in a PIPESIM network model (p.164).
When using Multiflash MFL files, the formation temperatures for wax, hydrate and
asphaltene; as well as the sub-cooling delta temperatures for wax and hydrate, are not
calculated for branches where fluids are commingled and will not display for these branches
in the plots or grid.

Related links:
Multiflash in the Compositional Fluid mode (native) vs. Multiflash MFL files (p.146)
Ensuring consistency among multiple fluid files in a PIPESIM network model (p.164)
Importing existing MFL fluid files (p.156)
Viewing Wax or Asphaltene Curves on Phase Envelopes (p.57)

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Editing an MFL fluid file (p.156)

Availability of Multiflash models in PIPESIM using the MFL file fluid mode option (p.164)
Multiflash phases supported in PIPESIM (p.164)

3.5.1 Importing existing MFL fluid files

1. On the Home tab, select MFL file from the Fluid manager option list as the global fluid option
in the model.
The Fluid manager opens.
2. On the Fluids tab, click New (+) at the bottom left corner of the Fluids table.

Note: An alternative workflow for Step 2 is to right-click Fluids in the Inputs pane and click
New (This applies only if a PIPESIM layout is chosen which displays the Inputs pane).

3. Click to browse to the location of the MFL file to be imported. Select the file and click Open.
This will populate the File path in the PIPESIM interface with the location of the fluid file you just
selected.
4. Click OK.
5. Double-click the row of the newly-created fluid in the Fluids tab of the Fluid Manager to
visualize the fluid composition and phase envelope. Click Close twice to exit the Fluid
Manager and continue with the model.

Note:
An alternative workflow for Step 5 (if the fluid was created from the Inputs pane) is to
expand the Fluids lists in the Inputs pane and double-click the fluid you just created to view
its details. Click Close to exit and continue with the model.

6. Repeat Steps 2-5 to import additional existing MFL files into the workspace OR create new MFL
files by following steps 2-5 in the Creating/Defining a new MFL fluid (p.156) topic.
7. Click the Fluid mapping tab in the Fluid manager and map all the wells and sources in the
workspace to the defined MFL fluid files.
Multiple MFL files can be defined in one PIPESIM model and mapped to different sources and
wells in the Fluid Manager, however care must be taken to ensure that the models and
components are consistent across all MFL files.

Note: PIPESIM can currently use tuned data in one (1) MFL fluid file in the workspace. If you tune
the models (EOS, Viscosity, etc.) to match experimental data for example, viscosity, density, etc.,
in the Multiflash interface, it is strongly recommended that you use only one MFL file (the one with
the tuned data) in the workspace. If you use multiple MFL files with tuned data in the PIPESIM
workspace, the tuned data in only one of the MFL files will be used in the PIPESIM simulation run.
For more information, see Ensuring consistency among multiple fluid files in a PIPESIM network
model (p.164).

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Related links:
Creating/Defining a new MFL fluid (p.156)

3.5.2 Viewing Wax or Asphaltene Curves on Phase Envelopes

Waxes are complex mixtures of solid hydrocarbons that freeze (solidify) out of crude oils if the
temperature is low enough - below the critical wax deposition temperature. They are formed from
normal paraffins (n-paraffins) and isoparaffins and naphthenes, if present.
Asphaltenes are defined as the fraction of crude oil that is insoluble in n-alkanes (for example, n-
heptane or n-pentane) but soluble in aromatic solvents such as benzene and toluene. They are
extremely complex mixtures whose molecular structure is difficult to determine because the
molecules tend to stick together in solution. They do not have a specific chemical formula but are
generally made up of large rings of aromatic molecules consisting of carbon, hydrogen, sulfur,
oxygen and nitrogen.
The Wax precipitation line and Asphaltene precipitation envelope can only be visualized in
PIPESIM using Multiflash MFL fluid files. The requirements for displaying these precipitation lines
on the PIPESIM phase envelope are outlined below.

Requirements for Display of Wax Precipitation Line on Phase Envelope

The Coutinho model for the precipitation of the Wax phase must be used in conjunction with the
RKSA equation of state for the phase equilibria of the other phases (This is done by choosing
Waxes or Combined Solids in the Model set when defining the fluid in Multiflash).
Composition of Live Oil or Stock Tank Oil from a gas chromatography analysis, entered under
Select > PVT Lab. Input (if measured n-paraffin distribution is not available) or Select > PVT
Input with n-paraffin (if measured n-paraffin distribution is available).
The wax content must be provided in Multiflash when defining the fluid using any one of the
following options:
Enter a lab-measured n-paraffin distribution under Select > PVT Input with n-paraffin(Most
accurate and recommended
Enter a Total Wax content under Select > PVT Lab. Input. In this case, the n-paraffin
distribution will be estimated by Multiflash based on the provided total wax content using the
Coutinho & Daridon method
Check the box Estimate Wax Content under Select > PVT Lab. Input. Multiflash will
estimate both the total wax content and the n-paraffin distribution. The wax content will be
estimated empirically and the n-paraffin distribution will be estimated using the Coutinho &
Daridon method (Least accurate and not recommended).
Optional Tuning Data for improving wax prediction accuracy
Measured Bubble Point(s) (under Tools Matching Bubble Point / GOR in Multiflash
Measured Wax Appearance Temperatures at corresponding pressures (under Tools >
Matching > Wax Phase in Multiflash).
Measured amounts of precipitated wax at corresponding pressures and temperatures (under
Tools > Matching > Wax Phase in Multiflash)

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Requirements for Display of Asphaltene Precipitation Envelope on Phase

Envelope
The version of the RKSA equation of state that includes association terms for Asphaltene-
Asplatene and Asphaltene-Resin interactions must be defined (This is done by choosing
Asphaltenes or Combined Solids in the Model set when defining the fluid in Multiflash).
Composition of Live Oil or Stock Tank Oil from a gas chromatography analysis, entered under
Select > PVT Lab. Input (for asphaltene precipitation only) or Select > PVT Input with n-
paraffin (for both asphaltene and wax precipitation, if measured n-paraffin distribution is
available for the wax).
The amount of asphaltene in the oil and the ratio of resins to asphaltene, using any one of the
following options in Multiflash:
Lab-measured, complete SARA analysis for example, Amount of Saturates, Aromatics,
Resins and Asphaltenes (Most accurate and recommended).
Amount of Resins and Asphaltenes, as measured in the lab
Check the box Estimate RA (Resin-Asphaltene ratio) under Select > PVT Lab. Input or
Select > PVT Input with n-paraffin. Checking this box will cause Multiflash to estimate the
resin-asphaltene ratio using proprietary methods. (Least accurate and not recommended).
Optional Tuning Data for improving asphaltene prediction accuracy
Measured Bubble Point(s) (under Tools > Matching > Bubble Point / GOR in Multiflash)
All of the following (if available) under Tools > Matching > Asphaltene Phase in
Multiflash):
Measured Asphaltene Onset Pressures for Live Oil, ideally at two different temperatures
(Most accurate, recommended)
Measured Amount of n-Heptane required for the Onset of Asphaltene precipitation for the
Dead Oil (Most accurate, recommended in addition to (Measured Asphaltene Onset
Pressures for Live Oil) if available)
Reservoir pressure and temperature (Least accurate, should be provided if (i) and (ii) are
not available).

Using MFL files with Wax and Asphaltene Phases

Once the MFL fluid file has been created to meet the Requirements for Display of Wax
Precipitation Line on Phase Envelope or Requirements for Display of Asphaltene Precipitation
Envelope on Phase Envelope, you may incorporate it in your PIPESIM workspace by following the
steps in any of the following workflows; Creating/Defining a new MFL fluid (p.156), Importing
existing MFL fluid file (p.156), and Editing an MFL fluid file (p.156), which will also guide you on
how to visualize the phase envelope and composition in the PIPESIM interface. You can also
report and plot the following wax and asphaltene system and profile variables after adding them to
the report template under Home Simulation Output variables:
Wax formation temperature (profile): This is the wax precipitation temperature along the profile.
Wax sub-cooling delta temperature (profile): This is the wax precipitation temperature minus the
fluid temperature along the profile. A negative wax sub-cooling delta temperature indicates that

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the fluid is warmer than the wax formation temperature and there is no risk of forming wax.
Conversely, a positive value indicates there is tendency for wax to form at that location.
Maximum wax subcooling temperature difference (system): This is the maximum value of the
wax sub-cooling delta temperature and pinpoints the location in the entire system that is at the
greatest risk of forming wax, if it is a positive value.
Asphaltene formation temperature (profile): This is the asphaltene precipitation temperature
along the profile.

Note: When using Multiflash MFL files, the formation temperatures for wax, hydrate and
asphaltene; as well as the sub-cooling delta temperatures for wax and hydrate, are not calculated
for branches where fluids are commingled and will not display for these branches in the plots or
grid.

Related links:
Creating/Defining a new MFL fluid (p.156)

3.5.3 Editing an MFL fluid file

1. On the Home tab, select MFL file from the Fluid manager option list as the global fluid option
in the model.
The Fluid manager opens.
2. If the MFL fluid you want to edit already exists in the workspace, use either of the following
options to edit it and jump to step 5:
In the Fluids tab of the Fluid manager double-click the row of the fluid you want to edit in
the Fluids list.
Expand the Fluids list in the Inputs pane and double-click the fluid you want to edit. ( This
applies only if a PIPESIM layout is chosen which displays the Inputs pane).
3. If the MFL fluid you want to edit does not already exist in the PIPESIM workspace, browse to
the location of the MFL file by using either of the options below and continue with step 4.
Launch the Fluid manager and click New (+) on the Fluids tab.
Right-click Fluids in the Inputs pane and click New...
4. Click to browse to the location of the MFL file to be edited. Select the file and click Open.
This will populate the File path in the PIPESIM interface with the location of the fluid file you just
selected.
5. Click Edit to launch the Multiflash interface and modify the fluid as desired.
6. When the editing is complete, you have two options for saving the updated MFL file in the
Multiflash interface:
Save Problem Setup As: This option is used to save the file to a different name and/or a
different location. If you save the file with the same name and to the same location, this is
equivalent to the Save Problem setup (below). Saving the file with a different name or to a
different location will update the File path in the PIPESIM interface when you close the

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Multiflash interface. If you edit a pre-existing MFL fluid in your workspace and save the
updated MFL file with a different name and/or to a different location with this option, the File
path in PIPESIM will be updated once you close the Multiflash interface, and the updated
MFL file will overwrite the pre-existing PIPESIM fluid and the fluid name will be changed to
match the updated MFL file name. The phase envelope, and composition may change in the
PIPESIM interface to reflect the changes you made. If there was no pre-existing fluid in your
workspace, then the edited MFL file will be imported as a new fluid into PIPESIM.
Save Problem Setup: This option is used when you want to make changes to the fluid
defined in an MFL file but retain the same MFL file name and file location. If you edit a pre-
existing MFL fluid in your workspace and save the updated MFL file with this option, when
you close the Multiflash interface, the File path in PIPESIM will remain unchanged but the
updated MFL file will overwrite the pre-existing PIPESIM fluid and the phase envelope and
composition may change depending on your modifications. If there was no pre-existing fluid
in your workspace, then the edited MFL file will be imported as a new fluid into PIPESIM.
7. Click Close or OK.
Multiple MFL files can be defined in one PIPESIM model and mapped to different sources and
wells in the Fluid Manager, however care must be taken to ensure that the models and
components are consistent across all MFL files.

Note: PIPESIM can currently use tuned data in one (1) MFL fluid file in the workspace. If you tune
the models (EOS, Viscosity, etc.) to match experimental data for example, viscosity, density, etc.,
in the Multiflash interface, it is strongly recommended that you use only one MFL file (the one with
the tuned data) in the workspace. If you use multiple MFL files with tuned data in the PIPESIM
workspace, the tuned data in only one of the MFL files will be used in the PIPESIM simulation run.
For more information, see Ensuring consistency among multiple fluid files in a PIPESIM network
model (p.164).

Related links:
Creating/Defining a new MFL fluid (p.156)

3.5.4 Availability of Multiflash models in PIPESIM using the MFL file fluid
mode option
Multiflash is a 3rd party flash package that enables full phase thermodynamic modeling of
multiphase fluids and solids using standard and state-of-the-art models. Multiflash incorporates an
extensive suite of equations of state for advanced flashes and viscosity, interfacial tension and
thermal conductivity models for the prediction of transport properties. Multiflash enables flashes
that can result in up to 7 separate phases simultaneously including gas, liquid, water, ice, hydrates,
wax and asphaltene.
Multiple MFL files can be defined in one PIPESIM model and mapped to different sources and
wells in the Fluid Manager, however care must be taken to ensure that the models and
components are consistent across all MFL files. Refer to the section Ensuring consistency among
multiple fluid files in a PIPESIM network model (p.164), for more details.

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Note:
When only one (1) MFL file is mapped in the PIPESIM workspace, all of the information in the
MFL file will be honored by PIPESIM in the simulation. This includes the Equation of State,
Models for Viscosity, Thermal Conductivity, Surface Tension, BIP sets, etc. including any tuning
done to the fluid.
PIPESIM can currently use tuned data in only one (1) MFL fluid file in the workspace. If you
tune the models (EOS, Viscosity, etc.) to match experimental data e.g. viscosity, density, etc.,
in the Multiflash interface, it is strongly recommended that you use only one MFL file (the one
with the tuned data) in the workspace. If you use multiple MFL files with tuned data in the
PIPESIM workspace, the tuned data in only one of the MFL files will be used in the PIPESIM
simulation run.

Related links:
Creating/Defining a new MFL fluid (p.156)

3.5.5 Multiflash phases supported in PIPESIM

PIPESIM currently supports the following Multiflash phases:
Gas
Liquid
Water
Hydrate I
Hydrate II
Wax
Asphaltene

Related links:
Creating/Defining a new MFL fluid (p.156)

3.6 Displaying Phase Envelopes for Compositional fluid or

MFL file
When working with compositional fluid models, you will find it helpful to display phase envelopes
and fluid properties associated with individual sources using the Phase Envelope viewer. This is
useful for quickly inspecting fluid models associated with source branches (wells, generic sources
and junction sources). Additionally, after running a simulation task, you may view the pressure/
temperature simulation results superimposed on a phase envelope for each source branch simply
by selecting the object.

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1. On the Home tab, MFL file or Compositionalfrom the Fluid manager option list as the global
fluid option in the model.
The Fluid manager opens.
2. In the Fluid mapping tab, map the fluid(s) to the Wells and Sources, if you have not done so
already.
3. Exit the Fluid manager.
4. On the Home tab, in the Viewers and results group, click Phase envelope.
The fluid's phase envelope displays. For a Compositional fluid specifically, in addition to the phase
envelope; the flash conditions, fluid properties, phase compositions and properties are also
displayed.

Note:
An MFL fluid file cannot currently be flashed in the PIPESIM interface to display the fluid
properties, phase compositions and properties.
The Phase envelope is inactive if you do not have a fluid selected.

5. In the Network perspective, you can display the phase envelope for objects that have fluids
mapped to them, such as wells and sources. To do this, select the object in the Inputs pane
and click Phase envelope.
The phase envelope will display, as long as there is a fluid mapped to the object.

Note: The Phase envelope is inactive if you do not select a fluid, well or source that has an
associated fluid.

6. In the Well perspective, you do not have to select an object to display the phase envelope,
unless you have multiple well models in the workspace. If you have one well in the model in the
workspace, ensure that it has a mapped fluid and click the Phase envelope. If you have
multiple wells, navigate to the well of interest and click the Phase envelope.

Note: The Phase envelope displays for the fluid associated with the this source object, along with
the fluid properties based on flash results at the defined inlet conditions. For multilayer wells with
multiple compositions, a series of tabs display, each representing a separate completion.

7. If you have performed a simulation task, the pressure-temperature (PT) results of the last
simulation task performed will be superimposed on the phase envelope.

Note:
For simulation tasks involving sensitivities, only the final sensitivity case will be displayed on
the phase envelope.
For Compositional fluids and MFL files, the phase envelope viewer displays the phase
envelope with the superimposed simulated P-T profiles for only well and source branches. It

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will not display for any branches that are not directly connected to the well or source with the
mapped compositional fluid or MFL file.

8. To flash the fluid at other conditions of interest and display the detailed fluid property
information, perform one of the following actions.
The fluid information will be re-calculated and updated.
a. Enter a Pressure and Temperature in the Conditions section.
b. Right-click at a point of interest on the phase envelope and click Flash at this point.

Note: The Flash at this point feature, is only available for Compositional fluids, not MFL
fluids. An MFL fluid file cannot currently be flashed in the PIPESIM interface to display the
fluid properties, phase compositions and properties.

Tip: When viewing results of a network simulation on a phase envelope, dock the phase envelope
on one side of the screen by dragging the Phase Envelope tab to either side of the network
diagram. Then click individual network objects on the network diagram or Inputs pane to display
the production path on the phase envelope for that object.

Related links:
Creating or Editing Fluid Models (p.146)

3.7 Overriding Fluid Phase Ratios

It is common that single fluid models are available that represent production from multiple fluid
sources. For example, a fluid analysis may be performed based on fluid obtained from the
separator which is supplied with fluids from multiple sources, each having different phase ratios. In
these situations, you may define a single fluid to be mapped to multiple fluid sources and override
the phase ratios for the individual sources.
By overriding phase ratios on the Fluid mapping tab in the Fluid manager
By defining phase ratio overrides in the fluid tabs associated with individual fluid sources
Fluid override options vary by object type. All the objects with a fluid model assigned allow
overriding the phase ratio. However, with vertical completions, you may define a phase-ratio
versus draw down table to account for coning effects of water and gas phases. For all cases, the
impact is specific to that object only. That is, other objects sharing the same fluid are not affected.
1. On the property pane of a specific object, select one of the following override methods:

Object Type Override Options

Vertical completion Click the appropriate override method:
None
no override option is selected
Phase ratio
override phase ratios

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Object Type Override Options

Define coning
define a coning table (vertical completion only)
Horizontal completion Click the appropriate override method:
None
no override option is selected
Phase ratio
override phase ratios
Gas lift injection No phase ratio override is applicable.
Generic source Select the Override phase ratios check box to enter phase ratio
Junction source overrides.

Fluid Injection
2. If you selected Override phase ratios, perform the following actions:
a. Select one of the following values for gas phase:
GLR
GOR
LGR
OGR
b. Select one of the following ratio types and override values:
Watercut
GWR
WGR
3. If you selected Define coning, complete the following coning data:
a. Enter the Coned gas specific gravity value.
b. Enter the coning table values for each flowrate row you want to enter.

Notes:
Phase ratio overrides associated with fluid sources may also be overridden by simulation tasks.
Overriding phase ratios using simulation tasks will not affect the overrides associated with
model objects unless you click Publish Boundary Conditions on the network simulation
Parameters tab.
Overriding phase ratios for black oil fluids will also affect fluid properties that are dependent on
phase ratios, such as viscosity. Also, remember that any calibrations previously made based on
the original phase ratio will still be applied, but may no longer be valid. For compositional fluids,
overriding the phase ratio will result in an adjusted molar composition, similar to the tuning
operation used in the fluid definition.

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Related links:
Creating or Editing Fluid Models (p.146)

3.8 Importing a PVT File

A pressure-volume temperature (PVT) file describes the behavior of a fluid through the properties
table written in a specific file format supported by PIPESIM*. You can define only one PVT fluid per
model due to the limitation that tabular fluid representations cannot be accurately mixed. The PVT
file that you import is saved in a PIPESIM model until you import a different PVT file.
1. On the Home tab, click Fluid manager and select PVT file from the option list as the global
fluid option in the model.
2. Perform one of the following actions:
On the Home tab, click Fluid manager, and then on the Fluids tab, click New (+).
On the Inputs pane, right-click Fluids, and then click New.
3. On the new fluid window, click ... to import and browse to the location of the PVT file and then
click Open. Click OK to finish the import.
The new fluid is displayed in the Fluid manager window and on the Inputs pane.
4. If you want to view the current associations for the fluid, click the Fluid mapping tab.

Note: Models imported from PIPESIM 2012 or previous versions may contain several PVT file
associations: one each at the global, branch, and completion levels, so long as compositional
specifications are present. PIPESIM 2013 only allows a single PVT file to be associated with a
model.
Only the PVT file associated at the global level in the imported model is associated with models
that you import.

Related links:
Creating or Editing Fluid Models (p.146)

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4
Running Simulations
You can perform nodal analysis, reservoir simulation, and use other analytical tools (such as
pressure/temperature (P/T) profiles, VFP tables, and network simulation) to calculate the
distribution of flowrates, temperatures, and pressures throughout the system and plan new field
developments.

Related links:
Configuring Simulation Settings (p.177)
Running a P/T Profile (p.191)
Running a Nodal Analysis (p.197)
Creating a VFP Table (p.204)
Running a Network Simulation (p.208)
Running a System Analysis (p.223)
Designing an ESP (p.229)
Managing Results (p.236)

4.1 Configuring Simulation Settings

You can configure simulation settings for the entire network or well model. You can also apply local
overrides to some simulation settings, such as flow correlation and heat transfer options.

Note: The fields for each tab may be slightly different depending on whether you are using
network-centric mode or well-centric mode.

1. On the Home tab, in the Settings group, click Simulation.

2. Click the tab for the category that you want to configure.
To configure flow correlation and heat transfer options for the entire network or well model,
click Use global.

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To configure flow correlation and heat transfer options for individual flowlines, risers and
wells, click Use local. The content changes to a tabular format.
3. Configure the appropriate properties on each tab.
4. To change the global default values for the entire branch, update the Default row as necessary.
5. Click Close.

Related links:
Flow Correlation Properties (p.178)
Heat Transfer Properties (p.181)
Erosion/Corrosion Properties (p.181)
Environmental Properties (p.183)
Output Variables Properties (p.184)
Advanced Properties (p.9)
Overriding the Default Value in Specific Rows (p.190)

4.1.1 Flow Correlation Properties

Use the Flow correlations tab to set flow correlation options at the global level or at local levels. If
you set flow correlation options at the local level, the source, correlation, friction factor, and holdup
factor appear as individual columns for both vertical and horizontal geometries.

Property Description
Name Name of the individual wellbore, flowline, or riser for which the setting is applied.
This field appears only when the Use local branch correlation option is selected.
This value cannot be changed.
Source Defines the global, vertical, or horizontal source of the correlation.
Vertical Baker Jardine
multiphase Developed by Schlumberger (originally Baker Jardine) and tested
source extensively. This value is the default source selection.
Horizontal Neotec
multiphase
The Neotec flow correlations were developed by a company called Neotec
source
based in Calgary. Neotec was formed in 1972 by Gary Gregory and Khalid
Aziz, professors at the University of Calgary who specialized in Multiphase
Flow research. Neotec developed several software applications used in the
oil and gas industry, including WELLFLO, PIPEFLO and FORGAS. In 2010,
Neotec was acquired by SPT Group and became part of Schlumberger in
2012 when Schlumberger acquired SPT Group.
OLGAS
Based in large part on data from the SINTEF multiphase flow laboratory near
Trondheim, Norway. The OLGA-S mechanistic models are applicable for all

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Property Description
inclination angles, pipe diameters and fluid properties. The 2-phase model
considers gas-liquid flow. The 3-phase model considers gas-oil-water flow.
TUFFP Unified
Developed by the Tulsa University Fluid Flow Projects (TUFFP) research
consortium. The models are applicable for all inclination angles, pipe
diameters and fluid properties. The 2-phase model considers gas-liquid flow.
The 3-phase model considers gas-oil-water pipe flow.
LedaFlow PM
The LedaFlow Point Model is the steady-state version of the transient model
developed by SINTEF in collaboration with Total and ConocoPhillips and
commercialized by Kongsberg. It is applicable for all inclination angles, pipe
diameters and fluid properties. The 2-phase model considers gas-liquid flow.
The 3-phase model considers gas-oil-water flow.
Tulsa (Legacy 1989)
Developed by the University of Tulsa, USA, and last modified by Professor
Jim Brill, February 1989. The code is usually of academic quality and may
return errors. No modifications have been made to accommodate extreme
conditions or ensure mathematical stability. These models are included only
for the purpose of validating calculations against publications and other
simulators using the same code. Not recommended for general use.
Correlation Select the appropriate global, vertical, or horizontal correlation method.
Vertical Available correlation methods depend on the source selected.
multiphase
correlation
Horizontal
multiphase
correlation
Friction One of two factors used to adjust the friction and holdup prediction of a particular
factor flow correlation. The default value is 1.
Vertical
multiphase Note: A linear relationship is used for the friction pressure drop. For example, if
friction you set the friction factor to 0.5, the friction element of pressure drop computed
factor by the correlation is halved. The two factors are used often as calibration factors
when a good match to field data cannot be obtained by any other method.
Horizontal
Changing these factors affects the results. Use with caution.
multiphase
friction
factor
Holdup One of two factors used to adjust the friction and holdup prediction of a particular
factor flow correlation. The default value is 1.
Vertical
multiphase

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Property Description
holdup
factor Note: A non-linear relationship is used to calculate the liquid holdup from the
Horizontal value predicted by the correlation. The default value is 1. The two factors are
multiphase used often as calibration factors when a good match to field data cannot be
holdup obtained by any other method. Changing these factors affects the results. Use
factor with caution.

Swap angle Angle at which vertical correlations are used instead of horizontal correlations.
For angles less than 45, horizontal correlations are used. For angles greater
than 45, vertical correlations are used.

Single phase Based on the flow correlation selected, you may need to enter a drag factor, flow
correlation efficiency, or C factor (see SP factor). Single phase flow is assumed if the liquid
volume fraction is less than .0001 or greater than .99.

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Property Description
SP factor Single phase factor that represents a drag factor, flow efficiency, or C factor for
the single phase correlation selected.
Override Select this check box to override global values set for the branch. Appears only
when the Use local branch correlation option is selected.

For more information, see Flow Regimes (p.281), Horizontal Multiphase Flow Correlations
(p.283), Vertical Multiphase Flow Correlations (p.288), Friction and Holdup factors (p.296), Single
Phase Flow Correlations (p.296), and Swap Angle (p.301).

Related links:
Overriding the Default Value in Specific Rows (p.190)

4.1.2 Heat Transfer Properties

Use the Heat transfer tab to specify the heat transfer calculation methods used for flowlines.

Property Description
Name Name of the individual wellbore, flowline, or riser for which the setting is applied.
This field appears only when the Use local heat transfer option is selected.
Pipe burial Model to use for pipeline heat transfer calculations. The calculations use the
method burial configuration of the pipe (fully buried, partially buried, or fully exposed) and
give different U-value results based on the model selected. The options, in
decreasing order of accuracy, are:
2009 Method (default)
2000 Method
1983 Method
All options produce identical results for a fully exposed pipeline, but the results
are different for a fully buried or partially buried pipe.
Inside film Inside film coefficient (IFC) calculation model for heat loss calculations.
coefficient Kaminsky model
method
Kreith combined Reynolds number model (default)
U-value Multiplier for user entered U-values in heat loss calculations. This is particularly
multiplier useful when performing a temperature match. The default value is 1.
Override Select this check box to override global values set for the branch. Appears only
when the Use local heat transfer option is selected.

Note: When this check box is selected, you can change the Pipe burial method,
Inside file coefficient method, and U-value multiplier.

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For more information, see 2009 Method (p.441), 1983 Method (p.442), Internal Fluid Film Heat
Transfer Coefficient (p.402), Kreith (p.402), and Kaminsky (p.405).

Related links:
Overriding the Default Value in Specific Rows (p.190)

4.1.3 Erosion/Corrosion Properties

PIPESIM has several models to predict erosion and corrosion in the piping system and report
important parameters for analysis and prediction.
The following results are reported:
Erosion velocity - The maximum allowable erosion velocity.
Erosion velocity ratio A ratio of fluid velocity over maximum allowable erosion velocity
predicted by selected erosion model. Values greater than 1.0 indicate erosion risk.
Corrosion rate (where applicable) An indication of the rate of loss of pipe material due to
corrosion.
These parameters are calculated at every segment/node and reported under node result tables
and profile plots. Also, branch level maximum values are reported under branch result tables and
system plots.
Follow these steps to model erosion and corrosion in PIPESIM:
1. Go to the Home Data group Simulation settings.
2. In the Simulation dialog box, select the Erosion/Corrosion tab and specify related properties
as indicated in the tables below.

Property Description
Erosion model By default, API 14 E is selected with its default properties. The API 14 E is
the only available option through the user interface. This model comes from
the American Petroleum Institute, Recommended Practice 14 E, to predict
solid free erosion only.
Erosion velocity Also referred as C-factor and is applicable to API 14 E model. This constant
constant depends on several factors like pipe material, fluid properties, etc. and can
(dimensional) be user defined.
The default value of erosion velocity constant is: 122 kg 0.5m -0.5s-1(SI units);
100 lbm 0.5ft -0.5s-1 (field units)
Table 4.1: Erosion options

Property Description
Corrosion The only available option is the de Waard (1995) corrosion model that calculates
model corrosion rate caused by presence of CO 2 dissolved in water.

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Property Description
The concentration of CO 2 and Water are obtained from the fluid properties
definition (black oil, compositional or ScaleChem generated PVT files). If either
CO 2 or Water is absent in the fluid, the resulting corrosion rate reported will be
zero.
Corrosion A multiplier, C c, to correct for inhibitor efficiency, or to match the field data.
efficiency
Actual pH: Options are to specify or calculate. When calculated, PIPESIM will calculate the
pH as a function of CO 2 fugacity and temperature. If the pH is known, it may be
specified. However, this is recommended only for analysis over a narrow range of
pressures and temperatures.
Table 4.2: Corrosion options

Related links:
Configuring Simulation Settings (p.177)

4.1.4 Environmental Properties

Use the Environmental tab to define environmental conditions used for heat transfer calculations.
By setting the conditions to be defined in one place, the information can be used by multiple wells,
flowlines, and pipes. Optionally, for individual flowlines and risers, this data may be ignored by
selecting override environmental data for individual flowline and riser objects.

General data
Atmospheric pressure displays the read-only air pressure value that is used to convert from
gauge to absolute pressures.

Air data

Property Description
Temperature Air temperature. This value is used for heat transfer calculations for flowlines in a
land environment. Because the ambient temperature is constant for the system
being modeled in most cases, setting a global value allows you to conveniently
model the effects across the system. This value may be easily modified to account
for diurnal or seasonal variations in air temperature to analyze the effects on
pipeline hydraulics and compressor performance.
Wind speed Velocity of air used for heat transfer calculations. The default value (8.43 ft/s or
2.57 m/s) equals 5 knots (which, in meteorological terms, corresponds to a light
breeze.
Pressure The atmospheric pressure used by PIPESIM to convert between absolute and
gauge units. Currently read only.

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Soil data

Property Description
Soil type One of various soil types may be selected if the soil conductivity is not known.
The default value, Moist Clay, is common in onshore fields. However, for
offshore applications, the conductivity is generally higher and a type such as
Deepwater Gulf of Mexico may be more appropriate. This data has been
compiled from various sources by Neotec.
Soil Representative soil conductivity for each soil type you chose. The property may
conductivity be specified by setting the Soil type to User defined.

Metocean Data
Metocean data is used to define seawater temperature and current velocity as a function of depth.
For cases where measured data is not available, typical data representing several active
development areas are provided based on the analysis of data published by several publically
available sources including NORA, SIMORC, and NOAA. Seawater temperature data near the
surface (up to about 100 feet below sea level) will vary by season, and the typical data presented
tends to represent winter conditions which are more conservative for flow assurance studies
involving solids predictions.

Note: The data presented represent typical conditions. Actual conditions may vary significantly.
Therefore, for detailed flow assurance studies, specify measured data as User defined.

Related links:
Flowline - Simple Model Properties (p.109)
Flowline - Detailed Model Properties - General Tab (p.112)
Riser - Simple Model Properties (p.128)
Riser - Detailed Model Properties - General Tab (p.131)
Configuring Simulation Settings (p.177)

4.1.5 Output Variables Properties

The Output variables tab contains various lists of simulation output variables. Each selected
variable is available to be tabulated or plotted after running a simulation.

Note: Each template has specific associated variables. You can create a new report template with
different variables.

Property Description
Report Select a report template from the available report templates. PIPESIM provides
template the following predefined templates:

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Property Description
Gas Field
Well Performance
Flow Assurance
Large Network

Note: Predefined templates cannot be deleted or renamed.

Selected Click to toggle the display between selected variables and the complete list of all
variables associated with the report template.
Profile Click to display a list of profile variables associated with the report template.
System Click to display a list of system variables associated with the report template.
unlabeled Type part or all of the variable name to find a specific variable in the complete
search field list.

Related links:
Managing Output Variable Report Templates (p.185)

Managing Output Variable Report Templates

Each report template has specific output variables associated with it. If you want to customize the
output variables list and reuse the customized list later in other workspaces, you can create a new
report template by copying a predefined template and updating its properties, delete a template, or
rename a template.
1. On the Home tab, in the Data group, click Simulation settings, and then click the Output
variables tab.
2. In the Report template list, select the template that most closely resembles the one you want
to create, and then click Clone.
3. Enter a New name for the template (you can use spaces and special characters), and then
click OK.
4. Click Selected until the display shows the complete list of all variables associated with the
report template.
5. Click either Profile or System to display the appropriate variable types in the list.
6. Perform the following actions:
To add a variable to the template, select the check box in its Selected column.
To remove a selected variable, clear the check box.
7. To rename a custom report template, perform the following actions:
a. In the Report template list, select the custom template, and then click Rename.
b. Enter a New name for the template (you can use spaces and special characters), and then
click OK.

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Note: You cannot rename a default report template.

8. To rename a custom report template, perform the following actions:

a. In the Report template list, select the custom template, and then click Delete.
b. To confirm that you want to delete the template, click Yes.

Note: You cannot delete a default report template.

9. Click Close.

Related links:
Output Variables Properties (p.184)

4.1.6 Advanced Properties

Use the Advanced tab to configure additional calculation options and specify keyword input.

Pipe segmentation data

Property Description
Max. report Optionally specify the maximum report interval length to generate profile
interval length results at shorter distances along the pipe segment.
Print computation Select this check box to report the results for each computation segment.
segment results This report may include very short pipe segments if required for the solution
to converge or the option to use additional short segments across nodes, if
selected.
Computation You may specify the number of computational segments the engine uses per
segments per report interval. This action is similar to specifying the Max. computation
report interval segment length; however, the specification is relative to the report interval
(either automatically set by the engine or user specified) rather than explicit.
This option may be helpful when analyzing results associated with specific
pipe segments that are reported.
Max. computation Initial maximum segment length to be used by the program. Regardless of
segment length pipe length, data is calculated for sections of the given length. For example, if
you specify 100ft, data is calculated for 10 segments of a 1000-foot-long pipe,
or for 200 segments of a 20,000-foot-long pipe.
To obtain a converged solution, PIPESIM may further subdivide the segment.
Additional short Adds short (one foot) segments to the start and end of each pipe section.
segments across This feature ensures the reported fluid properties and flowrates are calculated
nodes at an almost identical temperature and pressure to that reported at the node.
(In fact, the fluid properties are calculated at segment average pressure and
temperature.)

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Property Description
Enabling this parameter minimizes the discrepancies caused by this
mismatch; however, this does effect run time. To disable this feature, clear
the check box.

Compositional flashing options

Compositional flashing options control the way fluid properties are calculated. It is only applicable
to compositional fluid models and MFL files.
The options are:
Temperature energy balance: - Controls the Temperature-Energy Balance. These values are
used to maintain the temperature/enthalpy/entropy balance of the fluid.
Physical properties: - Controls determination of transport Physical properties (PP). These are
the values required to perform the multiphase fluid flow and heat transfer calculations, and
include phase volume fractions, densities, viscosities, heat capacities and surface tensions.

Note: The Interpolate, Hybrid, and Rigorous parameters apply to Temperature energy
balance and Physical properties options.

Properties Description
Interpolate This option uses interpolation between physical properties determined by in a
predefined grid of temperature and pressure points.
Hybrid This option is a compromise between speed and accuracy, which assumes that
properties will change more rapidly when close to a phase boundary.
Interpolation is performed whenever the grid points comprising a rectangle all
show the presence of the same phases. For example, if all four (4) points in the
rectangle have some oil, some gas, and no water, then you can assume the
rectangle lies entirely within the 2-phase region of the hydrocarbon phase
envelope, so interpolation is appropriate. If however one, two, or three of the
points have no oil, then clearly the hydrocarbon dew point line crosses the
rectangle, so a rigorous flash is required.
Rigorous This option enables rigorous flash calculations at all times. This will produce the
most accurate results, through will significantly increase runtimes.

Notes:
For those requiring more accuracy, the recommended setting (that is the greatest increase
in accuracy for the smallest effect on performance) is Physical Properties = Hybrid and
Temperature Energy balance = Interpolate. This option typically increases runtime 2-4
fold compared to using the Interpolate option, though this depends on the number of flash
calculations required in the proximity of phase boundaries.

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In most simulations, for every PP flash that is performed, there are about 5 to 10 TH
flashes, thus the TH flashes will have the greatest effect on speed and run time. The
inaccuracies of TH interpolated flashes are usually minimal.
The speed impact of each choice will obviously depend on the composition, and the
phase behavior in the PT region of interest. As a rough guide, taking the base case as
interpolation, swapping just the PP flashes to "rigorous" will multiply your run time by
about 4. With TH flashes also "rigorous", run time will probably increase at least 20 fold.
Use of the 'compromise' choices will be faster.

Single component system: - Controls "one component" behavior. Can be enabled or disabled
by you through following options. If enabled, the fluid is assumed to consist entirely of one
component molecule, and hence does not exhibit a classical phase envelope when graphed on
axes of pressure versus temperature. Salient Examples of such systems are pure water or
steam, pure Carbon Dioxide, pure methane, and so on. One component, if enabled, forces the
engine to use enthalpy as master and force a pressure-enthalpy flash.
Yes - One component system is enabled.
No - One component system is disabled.
Auto - If the composition contains a single component, 'One component' behavior is
automatically enabled. If multiple components are detected, 'One component' behavior is
disabled.

Note: When Modeling single component systems, you should set both flash options to Hybrid
or Rigorous.

Advanced engine options

Property Description
Thermal This feature specifies how the engine will determine the ambient temperature
interpolation as a function of distance along pipe segments. For well deviation surveys,
method flowlines and risers, the ambient temperature for each specified survey point
(distance or depth) will be interpolated from the ambient temperatures specified
in the Heat Transfer data. However, the calculation engine often adds shorter
computation segments during the simulation run. These options apply only to
these computation segments, as opposed to user-defined survey points.
Interpolate
This method will interpolate the value for ambient temperature for all
computation segments. Interpolate is the default method for newly-created
models and is generally recommended.
Step function
This method will use the ambient temperature from the previously-defined
survey point for all computation segments until the next defined survey
point is used. This method is discouraged, particularly for wells, as this is
not often representative of actual conditions.

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Property Description
Automatic
This method will interpolate the value for ambient temperature for
computation segments associated with wells, and apply a step-function to
determine the ambient temperature value for flowlines and risers. This
method is the default method for models imported from PIPESIM* 2012
and previous versions as it mostly closely replicates (though does not
exactly match) the default methods for these versions.

Note: The Step-function method in PIPESIM 2012 and previous versions

behaves differently than the method in PIPESIM 2013 and later versions. With
PIPESIM 2012, the step-function method would reset the ambient temperature
only when a new temperature is specified in the ambient temperature table.
Starting with PIPESIM 2013, the ambient temperature reset at the end of the
user-defined (that is. not computation) segment to the interpolated value based
on the specified ambient temperatures.
For example, for a pipe with five survey points and differing ambient
temperatures specified at the start and end of the pipe, PIPESIM 2012 will only
use the first value for the entire length of the pipe, whereas PIPESIM 2013 will
interpolate the ambient temperature and apply it to these five points.

Max number of The maximum number of iterations in which to try and determine a solution.
network solver The simulation will stop after this number of iterations unless the tolerance has
iterations been met. The default value is 100.
Network This option defines the solution tolerance for the network solver. A network has
solution converged when the pressure balance and mass balance at each node is
tolerance within the specified tolerance. The calculated pressure at each branch entering
and leaving a node is averaged. The default value is .01 (1%).

Miscellaneous options

Property Description
ESP slippage ESP Slippage factor is used to de-rate pump operating speed. The specified
factor operating frequency (Hz) of the motor in the ESP property pane is multiplied by
this factor and converted to display operating speed of the pump (c/min).
The default value of .9722 will result in a speed of 3500 RPM for a frequency of
60 Hz.

Engine keywords
Engine keywords can be used to generate PIPESIM input language for the engine/solver for
features that may not have exposed to the user interface or to perform advanced tasks.

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Property Description
Single When entering keywords in this area, the PIPESIM engine uses the associated
branch values specified for all single branches in the network.
keywords Single branch keywords applies to well or branch while performing single branch
tasks like PT Profile, Nodal Analysis, System Analysis, VFP Table, etc.
Network Network keyword is applied to the whole network and impacts results of Network
keywords Simulation.
(top) Location of the keyword depends on the type of keywords used. Network (top)
keywords are written at the top of the *.TNT file and therefore should be
information that are not part of a typical *.TNT file, else the keywords will be
replaced by information found elsewhere. Example could be keyword that prints
additional heat transfer output data, etc.

Note: It is recommended not to use both single branch and network keywords in
the same model.

Network Network (bottom) keywords are written at the bottom of the *.TNT file and therefore
keywords works by overriding any existing keyword that may be present elsewhere in the
(bottom) *.TNT file. Example could be using Steam keywords that overrides any fluid
information we may have in the *TNT file.

For more information, see keywords from the PIPESIM Engine Keyword Tool (EKT) (p.511) and
COMPOSITION: Compositional Fluid Specification (p.648).

Related links:
Configuring Simulation Settings (p.177)

4.1.7 Overriding the Default Value in Specific Rows

You can override simulation settings in specific rows.

Note: The fields for each tab may be slightly different depending on whether you are using
network-centric mode or well-centric mode.

1. On the Home tab, in the Data group, click Simulation.

2. Click the tab for the category that you want to configure.
3. In the row that you want to change, select the Override check box.
Many of the properties that could not be changed become editable. For example, you can
select a different Vertical multiphase correlation method.
4. Change the values in that row as necessary.
5. To reapply global simulation settings to specific rows, in the row that you want to change, clear
the check box in the Override column.

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All the values for that row return to the global setting.
6. To reapply global simulation settings to all rows, perform the following actions:
a. Click Apply global flow correlations to all or Apply global heat transfer options to all.
b. To apply the default settings to all branches, overwriting any values previously entered, click
Yes.
7. Click Close.

Related links:
Configuring Simulation Settings (p.177)
Flow Correlation Properties (p.178)
Heat Transfer Properties (p.181)

4.2 Running a P/T Profile

Use the pressure/temperature profile (P/T profile) task to generate pressure and temperature
profiles as a function of distance or elevation along the defined single-branch flow path.
1. (Network-centric mode) On the network diagram, or in the Inputs pane, select the well or
source where the analysis will start. (Well-centric mode) No selection is required.
2. Perform one of the following actions:
On the Home tab, in the Tasks group, click P/T profile.
In the Tasks pane, double-click P/T profile.
3. On the Parameters tab, enter the properties, including the branch endpoint, the calculated
variable, and any sensitivity variables.
4. Click Run.
To monitor simulation progress, check the message center or progress monitor.
5. View the profile results by clicking the System results tab or the Profile results tab.

Related links:
P/T Profile Parameters Tab (p.191)
System Results Tab Properties - P/T Profile (p.195)
Profile Results Tab Properties - P/T Profile (p.195)

4.2.1 P/T Profile Parameters Tab

Enter the properties for the pressure/temperature profile (P/T profile) task, including the branch
endpoint, the calculated variable, and any sensitivity variables.

General Properties
In this area, enter the endpoint that defines the selected branch for the P/T Profile.

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Property Description
Branch start The well, source, or junction (if treated as a source) selected when the task was
started. You cannot change this value.
Branch end The default value is the junction farthest from the selected Branch start. To change
the Branch end, select the endpoint of the selected branch from the list. Setting the
endpoint at an object (for example, a flowline) includes that object in the simulation.

Default Profile Plot Properties

In this area, define the X and Y axes that will appear by default on the Profile plot tab, which
displays the results of the P/T Profile task. Double-click the resulting plot to configure it.

Property Description
Elevation vs. pressure Plots the elevation change against pressure. Subsurface
elevations are expressed as negative values.
Elevation vs. temperature Plots the elevation change against temperature.
Pressure vs. total distance Plots pressure against total distance. This setting is selected
automatically for source models.
Temperature vs. total distance Plots temperature against total distance.

Calculated Variable Properties

In this area, specify one of three key variables (inlet pressure, outlet pressure, or flowrate) as the
calculated variable. The calculated variable is derived from the other two values.
To specify a calculated variable other than inlet pressure, outlet pressure, or flowrate, click
Custom. You can select a single custom variable related to any object within the branch being
evaluated by the P/T profile.

Property Description
Inlet pressure To calculate the inlet pressure, enter both outlet pressure and any flowrate.
Outlet pressure To calculate the outlet pressure, enter both inlet pressure and any flowrate. The
inlet pressure is determined by the pressure at the start node.
Liquid flowrate Select the flowrate (liquid, gas, or mass) to be calculated. To calculate the
Gas flowrate flowrate, enter both inlet pressure and outlet pressure. The inlet pressure is
determined by the pressure at the start node.
Mass flowrate
Custom To calculate a custom variable, click Custom and then enter inlet pressure,
outlet pressure, and flowrate. The inlet pressure is determined by the pressure
at the start node.

Custom Variable Properties

If you want to specify inlet pressure, outlet pressure, and flowrate (all three), you must also specify
how to achieve the specified outlet pressure by defining a custom variable. A custom variable is a
user-defined variable whose value is calculated to match the specified conditions.

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Select an object and a variable whose value will have an effect on the system outlet pressure. For
example, in a production well model, a choke positioned at the wellhead may have Bean size as
the variable. You can select any object and variable, as long as they have an effect on the system
hydraulics.
You must specify the allowable maximum and minimum values for the variable, and the
proportionality relationship (whether an increase in the variable's value causes an increase or a
decrease in outlet pressure).
If you select Direct, the outlet pressure is assumed to be directly proportional to the variable,
and will increase when the variable increases (for example, the choke bean diameter).
If you select Inverse, the outlet pressure is assumed to be inversely proportional to the
variable, and will decrease when the variable increases. As an example, consider the watercut
of a black oil fluid in a production well: as watercut increases, the well's static delta pressure
increases, and therefore its outlet pressure decreases.

Note: For some object and variable choices, proportionality can be difficult to predict. For example,
if the tubing inside diameter (ID) is used as a variable in an oil production well, you would expect
outlet pressure to increase as diameter increases from a small initial value. However, once
diameter exceeds a certain critical value, the well will probably suffer from excessive liquid holdup,
causing the outlet pressure to decrease. In this situation, the simulation may have two solutions:
one with a small ID, and another with a much larger ID. In this case, the choice of proportionality
relationship lets you pick the solution you want. However, the simulation may have no solution; this
happens if the specified outlet pressure is too great.

Property Description
Object This list contains all objects within the selected branch, plus any tubulars or
completions defined for included wells. Select the object for which you want to
adjust a variable to affect the calculated flowrate.
Variable This list contains all calculated variables, including custom variables, associated
with the selected object. Select a variable for which you will specify minimum and
maximum values in the flowrate calculation. (When you select a variable, the Min
value, Max value, and Proportionality fields appear.)
Min value Enter the minimum allowable value for the variable.
Max value Enter the maximum allowable value for the variable.
Proportionality Determines whether an increase in the variables value causes an increase or
decrease in outlet pressure. Select one of the following options:
Direct
Outlet pressure is assumed to be directly proportional to the variable,
increasing as the variable increases; for example, the behavior of the choke
bean diameter.
Inverse
Outlet pressure is assumed to be inversely proportional to the variable,
decreasing as the variable increases. For example, as the watercut of a black

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Property Description
oil fluid in a production well increases, the wells static delta pressure
increases and its outlet pressure decreases.

Sensitivity Data Properties

In this area, you can modify a variable to determine its specific effect over a range of values.
Sensitivity data overrides existing information for the selected variable.

Property Description
Item Select System Data, Fluid Data, or any system component for which you want to
specify a range of variables.

Note: If the selected branch contains more than one fluid, you cannot select Fluid
Data as the sensitivity item.

Variable Select a variable associated with the selected item for which you will specify a range of
values. When you select a sensitivity variable, the Range button appears above the
value range table, which may be useful for quickly defining a set of evenly spaced
values.
Range 1. Click Range.
2. Specify the Start and End values and the Step increment between those two
values.
3. Click OK.
The results appear in the values table (limited to 50 rows)
You can also complete the values table manually. To add a new row of data, click the
New(+) button; or simply type a number, and then press ENTER to move to the next
row. To delete a row, right-click the row, and then click Delete.

When entering sensitivity data, you can use sensitivity variables to adjust the desired flowrate.

Item Variables
Fluid Data API Gravity
(available unless the selected branch Gas Specific Gravity
contains more than one fluid) Gas-Oil Ratio (GOR)
Watercut
Water Specific Gravity
System Data Gas flowrate
(always available) Inlet pressure
Liquid flowrate
Mass flowrate

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Item Variables
Outlet pressure
All objects within the selected branch, plus All calculated or custom variables associated with
any defined tubulars or completions for the selected object.
included wells

Related links:
Running a P/T Profile (p.191)

4.2.2 System Results Tab Properties - P/T Profile

The System results tab displays P/T profile results in two modes: Node or Branch. This tab
displays the range of calculated results when the profile includes sensitivity data. You can also
select the columns to be shown in the results table. You can also expand the rows to display
additional information for completions and equipment objects.

Node Display Mode Properties

Property Description
Show grid Click this option to display the system profile results in a table.
Show plot Click this option to display the system profile results as a graphical plot.
Double-click the resulting plot to configure it.
Display mode Click Node or Branch to switch the display mode.
Equipment filter In the list, click All to show all network objects in the results table, or click a
single equipment type for display.
Select columns Click this button to open the Select columns window where you can select
the columns to be shown in the results table.
Expand Click this button to show or hide detailed information for all network objects in
the results table.
For example, a compressor row expands to display data such as pressure
difference and differential temperature. (Some object types, such as junctions,
sinks, and wellheads, do not expand.)

Note: You may also click on a row in the results table to show detailed results
for certain individual objects.

unlabeled Enter part or all of the name of a case, equipment, or equipment type to filter
search field the rows to show specific cases.
Case (column) Name of the sensitivity case.

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Branch Display Mode Properties

Property Description
Show grid Click this option to display the system profile results in a table.
Show plot Click this option to display the system profile results as a graphical plot.
Double-click the resulting plot to configure it.
Display mode Click Node or Branch to switch the display mode.
Select columns Click this button to open the Select columns window where you can
select the columns to be shown in the results table.
unlabeled search Enter part or all of the name of a case, equipment, or equipment type to filter
field the rows to show specific cases.
Case (column) Name of the sensitivity case.

Related links:
Running a P/T Profile (p.191)

4.2.3 Profile Results Tab Properties - P/T Profile

The Profile results tab displays the calculated results of the P/T profile task. You can also select
the columns to be shown in the results table. After selecting the desired columns, you can expand
the rows to display additional information about particular data types.

Property Description
Show grid Click this option to display the system profile results in a table.
Show plot Click this option to display the system profile results as a graphical plot.
Double-click the resulting plot to configure it.
Equipment filter In the list, click All to show all network objects in the results table, or click a
single equipment type for display.
Select columns Click this button to open the Select columns window where you can select
the columns to be shown in the results table.
Expand all Click this button to show or hide detailed information for all network objects in
Collapse all the results table.
For example, a compressor row expands to display data such as pressure
difference and differential temperature. (Some object types, such as junctions,
sinks, and wellheads, do not expand.)

Note: You may also click on a row in the results table to show detailed results
for certain individual objects.

unlabeled search Enter part or all of the name of a case, equipment, or equipment type to filter
field the rows to show specific cases.

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Property Description
Case (column) Name of the sensitivity case.

For more information, see Flow Regimes (p.281).

Related links:
Running a P/T Profile (p.191)

4.3 Running a Nodal Analysis

Nodal analysis is a methodology that views the total producing system as a group of components
potentially encompassing the reservoir, completions, tubing and surface equipment, restrictions,
flow lines, and risers. An improper design of any one component, or a mismatch of components,
adversely affects the performance of the entire system. The chief function of a system-wide
analysis is to increase well rates. It identifies bottlenecks and serves as a framework for the design
of efficient field-wide production systems. Together with reservoir simulation and analytical tools,
nodal analysis is commonly used in planning new field developments.
Estimate production potential of an oil/gas well.
Identify system bottlenecks, such as skin (inflow) and plugged tubing (outflow), and assist in
remedial action.
Optimize system design, such as completion design or determining tubing size.
Determine status of the well, whether it is stable or unstable.
Identify flow assurance issues, if any (by combining other modules in PIPESIM*).
Quantify the benefits of artificial lift.
Analyze abnormal flow restrictions in an existing system.
Nodal analysis points are used to split the system into two parts for analysisan inflow and an
outflow. The nodal point can be placed between any two equipment objects or at any point along
the tubing or casing in a well so long as it is located at or above the uppermost completion.
Typically, nodal analysis is performed at the following locations:
Bottomholewith the nodal point placed between the completion and the tubing
Wellheadupstream of any wellhead equipmentwith the nodal point placed between the
tubing and the equipment
Wellheaddownstream of any wellhead equipmentwith the nodal point placed between the
equipment and the following object (flowline, riser, and so on)
Riser basewith the nodal point placed between the flowline and the riser
Operating Points
An operating point (sometimes called the solution node) is defined as the condition where
the pressure differential upstream (inflow) and downstream (outflow) of the nodal point is
zero. The operating point is represented graphically by the intersection of the inflow and
outflow performance curves. It is possible to infer the system flowrate geometrically from
the line intersections alone; however, it is more accurate and far safer to calculate the

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flowrate by simulating the system end-to-end. The resulting pressure and flowrate appears
on the nodal analysis graph as an operating point. This explicit calculation ensures the
inflow and outflow fluid properties and temperature are identical, which eliminates the
possibility of a mismatch and consequent error in answer interpretation.
Operating points are generated for each permutation from the lists of inflow and outflow
sensitivity variables. However, it is possible to set sensitivities so some combinations are
invalid. Invalid sensitivities do not generate operating points. For example, if you set both
inflow and outflow sensitivity to the fluid watercut, most permutations are invalid, because
the fluid at the intersection cannot have two different values for watercut. Valid
intersections are clearly distinguishable from the invalid ones. Operating points are
generated for valid combinations.
Sometimes the displayed operating point does not coincide with the geometric intersection
(which is always caused by the outflow fluid properties or temperature not matching that of
the operating point). Use this mismatch as an alert to a problem or condition that requires
your attention.
1. Select a well or source.
2. Perform one of the following actions:
On the Home tab, in the Tasks group, click Nodal analysis.
In the Tasks pane, double-click Nodal analysis.

Note: If the Nodal analysis task is launched and a nodal point has not been identified, you will be
prompted to insert one automatically at the bottomhole or wellhead. Nodal points imported from
earlier versions of PIPESIM* will have the same name, and all points will be active.

3. Enter a name and description for the task.

4. Define the properties for the nodal analysis.
5. Click Run.

Note: You can stop a running nodal analysis by clicking Stop.

6. View the results by clicking the System results tab or the Profile results tab.

Note: You can use simulation settings to select output variables.

Related links:
Nodal Analysis Properties (p.198)
Adding a Nodal Point (p.201)
Nodal Analysis Results Tab Properties (p.203)

4.3.1 Nodal Analysis Properties

Define the properties for a nodal point and the associated nodal analysis task.

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Property Description
Branch Wells
start starts at well completion(s)
Generic Source
starts at source
Nodal point Lists defined nodal points. If there are multiple defined nodal points, you must select
a specific nodal point from the drop-down menu.
If there are no defined nodal points, when you click Nodal analysis, you are
prompted to define a nodal point at the bottomhole (mid-perforation for a single
point completion, mid-perforation of the uppermost perforation in the case of a
multilayer well, or the top depth of the topmost layer in the case of a distributed
completion) or at the wellhead.

Note: For a nodal analysis performed on surface facilities using a generic source,
the nodal point must be predefined.

Branch end The default value is the junction farthest from the selected Branch start. To change
the Branch end, select the endpoint of the selected branch from the list. Setting the
endpoint at an object (for example, a flowline) includes that object in the simulation.
Outlet Pressure that exists at the end of the last object in the model. For example:
pressure Vertical Completion with tubing, choke, flowline, and riser
outlet pressure is at the top of the riser.
Vertical Completion with tubing and choke
outlet pressure is downstream of the choke
Source with flowline
outlet pressure is at the end of the flowline
Source with tubing and vertical completion
outlet pressure is the static reservoir pressure (injection well)
Table 4.3: General Properties

Property Description
Override phase ratios Select this check box to show user-editable gas ratio and water ratio
properties in the table.
Inflow Name of the flow source.
Active Select this check box to specify that the well inflow object is active.
Pressure Pressure in the inlet. If multiple completions are present in production
wells, you must specify the pressure for each completion individually.
Temperature Temperature at the inlet. If multiple completions are present in production
wells, you must specify the temperature for each completion individually.

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Property Description
Gas ratio type Valid types are GLR, GOR, LGR, OGR.
Gas ratio Gas ratio and units of measure.
Water ratio type Valid types are GWR, Watercut, and WGR.
Water ratio Water ratio and units of measure.
Table 4.4: Inlet Conditions Tab

Property Description
Inflow Each value produces one inflow curve.
sensitivity
Item Object on which sensitivity is being performed, such as System Data, Completion,
Fluid Data, or Equipment Objects.
Variable Variable being defined. The list of variables depends on which object was chosen.
Range Optional method to generate by entering evenly-spaced sensitivity values. The
Step value increments the Start value and each successive value by that number
until the End value is reached. For example, a Start value of 0, an End value of
20, and a Step value of 5 generates 0, 5, 10, 15, and 20.
1. Click Range.
2. Specify the Start and End values and the Step increment between those two
values.
3. Click OK.
The results appear in the values table (limited to 50 rows)
Values Sensitivity values. Each value produces one inflow or outflow curve.
You can complete the values table manually instead of using the Range method.
To add a new row of data, click the New(+) button; or simply type a number, and
then press ENTER to move to the next row. To delete a row, right-click the row,
and then click Delete.
Units Units of measure for the variable.
Outflow Each value produces one outflow curve. Item and variables work the same as with
sensitivity inflow.
Table 4.5: Sensitivities Tab

Property Description
Flowrate Max liquid flowrate
Maximum liquid flowrate to be used when generating the outflow curves.
Max gas flowrate
maximum gas flowrate to be used when generating the outflow curves

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Property Description
Max mass flowrate
maximum mass flowrate to be used when generating the outflow curves
If this property is left blank, the outflow curves extend to the maximum absolute
open flow potential (AOFP) of the inflow curves or to the Max outflow pressure
value, whichever is smaller.
Max outflow Maximum pressure to be used when generating the outflow curves. If supplied,
pressure the outflow curves extends to this pressure or to the maximum rate, whichever
gives the smallest curve.
If this property is left blank, PIPESIM* uses a default value that is calculated at
run-time. The default is double the maximum pressure in any of the inflow curves.
Inflow points Number of points on each inflow curve. Default = 30, maximum 100.
Outflow Number of points on each outflow curve. Default = 30, maximum 200.
points
Limit inflow Rate limit option for the inflow curves.
curves Select the check box to constrain the inflow curves to the maximum flowrate on
the outflow curves. Clear the check box to allow the inflow curves to extend to the
AOFP (the rate where the curve meets the X axis).
Limit outflow Pressure limit option for the outflow curves.
curves Select the check box to limit the outflow curves to the Max inflow pressure
(usually the reservoir pressure). Clear the check box to allow the outflow curves to
extend to the flowrate limit.
Table 4.6: Options Tab

Related links:
Running a Nodal Analysis (p.197)

4.3.2 Adding a Nodal Point

The nodal point defines where the system is broken into two parts for the nodal analysis operation.
The parts break around a particular (solution) point and then PIPESIM* computes the inflow to and
outflow from that point separately. You can add a nodal point in a well or network diagram.
1. Perform one of the following actions:
For nodal points in the wellbore, in the Inputs pane, double-click the well to edit, and then
on the Insert tab in the Downhole equipment group, drag the Nodal point icon to the
appropriate location on the Wellbore schematic.
For surface equipment, on the Insert tab in the Others group, click Nodal point and then
click in the desired object to add the nodal point to the upstream side of the object.
To add nodal points to objects in the network diagram, right-click the object, and then click
Add nodal analysis point.
2. To add another nodal point, repeat step 1.

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3. For nodal points within wells, the measured depth may be adjusted by dragging the triangular
handle at the point of attachment to the tubing or casing, or by editing the depth directly in the
downhole equipment tab
4. Edit the properties for each nodal point.
Scenarios
Nodal points defined in wellbores are either associated with the tubing (light blue) or casing (dark
blue). This distinction enables provides the user with additional flexibility to determine the nodal
analysis point location for complex flowpaths.

Scenario Diagram
Combined tubing-annulus flowpath
In this example, one tubing nodal point and
one casing nodal point are defined. If you
select the casing nodal point in the nodal
analysis task, the operating point will occur at
the location of the casing point, where the
fluids are flowing downwards towards the
bottom of the tubing. If you select the tubing
nodal point in the nodal analysis task, the
operating point will occur where fluids are
flowing upwards in the tubing, some distance
above the bottom of the tubing section.
Invalid nodal points
In this example, there are two casing nodal
points, neither of which is positioned within
the flowpath and, therefore, they cannot be
used. Any nodal points present that are not
within the flowpath specified are shown in the
validation pane, although this will not prevent
you from running a nodal analysis task on
another valid point if one is defined.

Tubing + annulus flow

For wells producing up both the tubing and
the annulus, you can only select the tubing
nodal point for the simulation task. Selection
of the tubing nodal point will split the flow
across the entire tubing-annulus flowpath at
the same depth. The casing nodal point is
invalid in this case.

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Scenario Diagram
Annulus flow only
In cases of annulus flow only, you must define
and select the casing nodal point for nodal
analysis tasks.

Related links:
Running a Nodal Analysis (p.197)

4.3.3 Nodal Analysis Results Tab Properties

After you successfully run a nodal analysis, the System results and Profile results tabs are
visible in the Nodal analysis window and on the Results tab.
System results
plots the inflow, outflow, intersection point, liquid loading line, and any other additional
information (such as the bubble point, maximum drawdown line, inversion point and
erosional velocity line, and units of measure) that you set.
Profile results
shows solution point pressure and flow for all operating points in tabular or plot format.
Expand the table to view equipment result details.
You can also select the columns to be shown in the results table and on the plot. After selecting
the desired columns, you can expand the rows to display additional information about particular
data types.

Property Description
Bubble point Plots the bubblepoint pressure as a function of flowrate.

Note: The rate slightly influences the temperature at the nodal point which
results in a slight change in bubblepoint pressure as a function of rate.

Inversion point Plots a line corresponding to the inversion point of the outflow curve. The
inversion point implies stable flow at rates higher than this point and unstable
flow at lower rates.
Erosional Plots a line corresponding to the erosional velocity limit (erosional velocity
velocity line ratio equal to one).

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Property Description
Maximum Plots a line corresponding to the maximum drawdown pressure specified.
drawdown line
Select columns Click this button to open the Select columns window, where you can select
the columns to be shown in the results table.
Table 4.7: System Results Tab

Note: If you run sensitivity, you do not have the above options.
To open the Edit chart/series dialog box so you can change chart attributes, double-click the
chart.

Property Description
Show grid Click this option to display the detailed profile in grid (tabular) format.
Show plot Click this option to display a graphical plot of each solution point.
Equipment filter In the list, click All to show all network objects in the results table, or click a
single equipment type for display.
Select columns Click this button to open the Select columns window, where you can
select the columns to be shown in the results table.
Expand all Click this button to show or hide additional information about certain types of
network objects in the results table.
unlabeled search Enter part or all of the name of a case, equipment, or equipment type to find
field specific nodal analysis cases.
Table 4.8: Profile Results Tab

Related links:
Running a Nodal Analysis (p.197)

4.4 Creating a VFP Table

Generally, reservoir simulators do not take into account the pressure changes occurring in tubing,
wellbore, or surface equipment. The VFP tables task simulates the wellbore hydraulics for a wide
range of conditions and writes that data in tabular format to a file that can be used with a reservoir
simulator. When simulating a reservoir, it is often necessary to generate VFP curves to supply the
simulator with the necessary data to enter bottomhole pressure as a function of various
parameters, such as flowrate, phase ratios, and surface pressure. PIPESIM* creates tabular data
in the format specific to the selected reservoir simulator.
ECLIPSE*/INTERSECT
PORES
VIP
COMP4

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MoRes (Shell's In-house simulator)

To generate tables, PIPESIM uses all combinations of the variables that you enter.
1. Create and save the well performance model.
2. Select a well, source, or junction source.
3. Perform one of the following actions:
On the Home tab, in the Tasks group, click VFP tables.
In the Tasks pane, double-click VFP tables.
4. Enter a description, which can be alphanumeric and can contain spaces and special characters.
5. Enter the General properties.
6. Enter the Settings properties.

Note: To create a temperature VFP table in addition to the pressure VFP table, select the Include
temperature check box (ECLIPSE/INTERSECT only).

7. Enter values for the sensitivity properties:

Flowrate
Gas ratio
Water ratio
System outlet pressure
Gas lift injection properties for wells with a single gas lift injection point (multiple gas lift
injection points are not supported for VFP tables)

Note: For VFP tables created using a black oil fluid model, if gas lift is applied, the quantity can be
any of the following:
the injection rate of lift gas
the ratio of injected gas to liquid production
the ratio of injected plus produced gas to liquid production
For compositional VFP tables, the gas lift variable is restricted to the injection rate of lift gas.

8. Click Run.
When the run is complete, the VFP table tab and the VFP table (with temperature) tab appear
next to the Parameters tab. These tabs contain the PIPESIM* generated data in the format
specific to the selected reservoir simulator.
9. View and analyze the results.

Note: If you want to view the last generated VFP table, on the Home tab, in the Viewers group,
click Results. The most recent run for each study appears in the table, with VFPTables in the Task
type column.

10.Save the VFP table to a file.

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Related links:
VFP Table Properties (p.206)
Saving a VFP Table to a File (p.207)

4.4.1 VFP Table Properties

Define the properties to create a VFP table file.

Property Description
Branch start Wells
starts at the uppermost well completion
Generic Source
starts at source
Junction Source
starts at junction source
Branch end The default value is the junction farthest from the selected Branch start. To
change the Branch end, select the endpoint of the selected branch from the list.
Setting the endpoint at an object (for example, a flowline) includes that object in the
simulation.

Note: You can choose any node in the branch as the Branch end.

Table 4.9: General Properties

Property Description
Reservoir Available simulators are:
simulator ECLIPSE*/INTERSECT
Pores
VIP
Comp4
MoRes
Table number Creates a VFP table. The reservoir simulator uses the table number in the
simulation. When you save the file, PIPESIM* also uses the table number as
part of the file name.
To view the last table generated, click the Home tab, and then click Results.
Include (ECLIPSE/INTERSECT simulators only) Generates a temperature VFP table
temperature in addition to the pressure VFP table.
Bottomhole (ECLIPSE/INTERSECT simulators only) Enters the depth of bottomhole from
datum depth the reference depth in your ECLIPSE/INTERSECT model. The input value

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Property Description
cannot be negative. If Bottomhole datum depth is left blank, the default VFP
output value is the total elevation change from inlet to outlet.
Table 4.10: Settings Properties

Property Description
Flowrate Type of flow. Valid values are Liquid flowrate and Gas flowrate.
Gas ratio GOR, GLR, OGR, or OLR.
Water ratio Watercut, WGR, or GWR.
System outlet (Production well) Pressure that exists at the end of the last object in the
pressure model.

Note: For injection wells, the property name is System inlet pressure.

Range 1. Click Range.

2. Specify the Start and End values and the Step increment between those
two values.
3. Click OK.
The results appear in the values table (limited to 50 rows)
You can also complete the values table manually. To add a new row of data,
click the New(+) button; or simply type a number, and then press ENTER to
move to the next row. To delete a row, right-click the row, and then click
Delete.
Item (available Select the gas lift component for which you want to specify a range of
only if a gas lift variables.
exists)
Variable (available Select a variable associated with the selected item for which you will specify
only if a gas lift a range of values. When you select a sensitivity variable, the Range button
exists) appears above the value range table, which may be useful for quickly
defining a set of evenly spaced values.
Table 4.11: Sensitivity Properties

Related links:
Creating a VFP Table (p.204)

4.4.2 Saving a VFP Table to a File

To a VFP table in a reservoir simulator, save the table to a file.
1. Create the VFP table.
2. Click the VFP table tab or the VFP table (with temperature) tab.

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3. Right-click within the table, and then click Save as.

4. Navigate to the directory in which to store the file, and enter the file name.
5. Click Save.
The file is ready to use in the reservoir simulator.

Related links:
Creating a VFP Table (p.204)

4.5 Running a Network Simulation

Run a network simulation to calculate the distribution of flowrates, temperatures, and pressures,
and other properties throughout the system. You can run the simulation using either known or
hypothetical conditions. To run a network simulation, your network must include at least one
source and one sink or injection well.
1. Verify that the network includes at least one source (well, source, or junction treated as source)
and one sink or injection well.
2. Review and resolve any error messages in the Message center pane or in the Validation
pane.
3. On the Home tab, in the Settings group, click Simulation to configure the simulation settings.
4. Perform one of the following actions:
On the Home tab, in the Tasks group, click Network simulation.
In the Tasks pane, double-click Network simulation.
5. Click the Parameters tab.
6. Enter a name and description for the simulation.
7. On the Parameters tab, review or edit the simulation parameters in the data table.
8. In the Boundary conditions check area, perform the following actions:
a. If you want to refresh the table with data from the network objects, click Populate from
model. If you want to update the network objects with the current data in table, click Update
back to model.
b. If the Required number of boundary conditions does not match the Supplied number
(indicating that boundary conditions are missing or incorrect), review and resolve the error
messages that appear. When all required boundary conditions are supplied, the Run and
Restart buttons become available.
9. Perform one of the following actions to simulate the model:
Click Run.
The simulation uses the initial pressure and flowrate estimates. Use this option if this is the
initial run, or if wells have been added to the model since the last run.
Click Restart.

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The simulation uses the final results from the last run for the initial guess, shortening the
simulation time. You can use this option if no wells, flowlines, or any other objects have
been added to the model since the last run.

Note: When the simulation is complete, the Run and Restart buttons become available again.

10.Perform one of the following actions to simulate the model:

If the simulation fails, review and resolve the error messages in the Message center pane
or in the status bar.
If the simulation completed successfully, view the simulation results by clicking the Node/
Branch results tab or the Profile results tab.

Note: If you want to access simulation results from multiple studies in one place, view the
results from the Results tab.

Important: If you must terminate a simulation in progress, always click Stop. Do not simply close
the Network simulation window. Clicking Stop deletes temporary files and frees disk space.

Related links:
Configuring Simulation Settings (p.177)
Boundary Conditions (p.209)
Rate Constraints (p.209)
Node/Branch Results Tab Properties - Network Simulation (p.213)
Profile Results Tab Properties - Network Simulation (p.214)

4.5.1 Boundary Conditions

Network simulation requires boundary conditions to be provided at boundary objects so that the
system can be solved. Boundary conditions are configured differently depending on the simulation
task.
Sources
Wells, completions within wells (in a multilayer well, each completion is a separate
source), source objects, and injection points
Sinks
Sink objects and injection wells
1. The total number of P/Q specifications - pressure (P), flowrate (Q), or PQ table - must equal the
number of boundary nodes.
2. All sources must have at least one specified boundary condition, which can be P, Q, P+Q, or
PQ table. EXCEPTION: All injection points must have at least one specified boundary condition,
which must be flowrate (Q).
3. All sources must have temperature specified.

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4. Sinks can have pressure or flowrate data.

5. Sources and sinks can have two boundary conditions, as long as rule 1 is satisfied.
6. At least one supplied boundary condition within the model must be pressure (or a PQ curve). In
other words, you cannot specify flowrate as the condition for all boundary nodes.

Differences between Single-Layer and Multi-Layer Wells in Network

Simulation
Single-layer well
You can specify pressure or flowrate. The algorithm used by PIPESIM* calculates
reservoir pressure if you specify flowrate. Flowrate is calculated if you specify pressure.
Multi-layer well
You must specify the pressure at each layer (completion). PIPESIM will calculate the
producing rates for the individual completions.

Network Simulation Properties

In the Parameters tab, enter the data used to run a network simulation on the selected network.
To run the simulation, the data must meet the boundary conditions requirements.

Note: The first time you open the Network simulation window, data is automatically retrieved
from the model. If you make changes made to the model (for example, to run other simulation
studies) and want to refresh the data in the Parameters tab, click Populate from model.

Property Description
Object filter In the Object filter list, select one of the following filters to display only objects
of the selected type:
All
Well
Source
Sink
Injection point
Zone
Location of Click the appropriate option to specify whether to include the well models in the
Well Boundary simulation run.
Conditions Reservoir
When selected, the Completion and Zone columns appear in the table and
boundary conditions are associated with the reservoir.
Surface
When selected, boundary conditions are associated with the wellstream
outlet conditions defined for the production wells or the wellstream inlet

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Property Description
conditions defined for the injection wells. The Completion and Zone
columns disappear because they pertain only to reservoir conditions.
Override By default, this check box is not selected, and the simulation uses the phase
phase ratios ratios from the assigned fluids. If you want to modify the phase ratios for the
simulation, select the check box, and then enter the new values in the following
columns:
Gas ratio type
Gas ratio
Water ratio type
Water ratio
Table 4.12: Parameters Tab Properties - Global Settings

Property Description
Name Displays the name of the network object.
Type Displays the type of network object. Network simulations may include wells,
sources, injection points, sinks, and zones.
Completion Displays the name of the well completion. This column appears when you
select Reservoir as the Well BC location.
Active Select this check box to include the network object in the simulation scenario.
To exclude the object from the simulation, clear the check box.
Pressure (P) You can enter the pressure for the network object. If you do not specify a value,
it will be calculated.
Rate type If entering a flowrate, select the type of material in the flowline (Liquid, Gas, or
Mass).
Flowrate (Q) You can enter the flowrate for the network object. If you do not specify a value,
it will be calculated.
Temperature You must enter the inlet temperature associated with the fluid source.
Zone Displays zone parameters, which are optionally used to consolidate boundary
conditions for any completions defined within the zone. This column appears
when you select Reservoir as the Well BC location.
PQ Table When this check box is selected, the simulation uses the PQ curve defined for
the source. If you select the check box and the source has no defined PQ
curve, an error will appear in the Boundary conditions check area.
Gas ratio type If you selected the Override phase ratios check box, select one of the
following gas ratio types:
GLR
Gas/liquid ratio

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Property Description
GOR
Gas/oil ratio
LGR
Liquid/gas ratio
OGR
Oil/gas ratio
Gas ratio Enter the ratio value and units of measure for the selected Gas ratio type.
Water ratio type If you selected the Override phase ratios check box, select one of the
following water ratio types:
GWR
Gas/Water Ratio
WGR
Water/Gas Ratio
Watercut
Ratio of water present in an overall liquid volume
Water ratio Enter the ratio value and units of measure for the selected Water ratio type.
Table 4.13: Parameters Tab Properties - Table Columns

Related links:
Running a Network Simulation (p.208)

4.5.2 Rate Constraints

To enter maximum flowrate constraints:
1. Select the Rate Constraint tab in the network simulation task.
2. Specify the maximum flowrate limits for the desired rate types and branches.
Branches that have flowrate constraints defined must contain one or more chokes. When the
network solves, the constraint is met by adjusting the bean size of the choke. If more than one
choke is present in the branch, the most downstream choke in the branch is adjusted. If you want
the choke to only be active if the flow rate exceeds the limit, fully open the choke in the model.
One or more flowrates constraints may be defined for each branch for the following rate types:
Gas
Liquid
Oil
Water
Mass

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For cases where multiple rate constraints are defined, the most limiting constraint is applied such
that all constraints are honored. If the flow rate is below the defined limit, the choke operates at its
specified bean size (for example, no adjustment is applied). If the flow rate is above the limit, the
bean size is decreased by the engine such that the flow rate limit is achieved. The modified bean
size is reported in the output results.
You may not specify flowrate constraints associated with rate specified objects as these values will
create a conflict.

Note: Over constraining the network may prevent the simulation from converging on a result. For
models containing separators, certain configurations will effectively rate specify the streams
leaving the separator and therefore cannot be rate specified themselves. More specifically, do not
place rate constraints on a sink or injection well downstream of the discontinuous stream leaving
the separator. Additionally, for separators that have a pressure specification, do not place a rate
constraint on any sink or injection well downstream of the separator.

Related links:
Running a Network Simulation (p.208)

4.5.3 Node/Branch Results Tab Properties - Network Simulation

The Node/Branch results tab displays network simulation results in two modes: Node or Branch.
Node
In this display mode, objects with no associated physical dimensions are shown. These
include sources, sinks, equipment, and completions. You can show all equipment types, or
filter the results table to show only a specific equipment type (such as chokes,
compressors, or pumps). You can also select the columns to be shown in the results table.
After selecting the desired columns, you can expand the rows to display additional
information about particular objects.

Property Description
Display mode Click Node or Branch to switch the display mode.
Equipment In the list, click All to show all network objects in the results
filter table, or click a single equipment type for display.
Select Click this button to open the Select columns window where
columns you can select the columns to be shown in the results table.
The available properties correspond to the system variables
selected in the Output variables tab (located in the
Simulation settings window).
Expand all Click on a row in the results table to show detailed results for
certain individual objects.
Click the Expand all button to show or hide detailed information
for all network objects in the results table.

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Property Description
For example, a compressor row expands to display data such
as pressure difference and differential temperature. (Some
object types, such as junctions, sinks and wellheads, do not
expand.)

Branch
In this display mode, individual branches that comprise various objects (such as flowlines
and equipment) may be shown. Branch results are used to display the inlet and outlet
conditions of the branch, as well as minimum and maximum values. You can also select
the columns to be shown in the results table.

Property Description
Display Click Node or Branch to switch the display mode.
mode
Select Click this button to open the Select columns window where
columns you can select the columns to be shown in the results table.

Note: For branch results, the available columns are fixed and
not associated with the results configurable from the Output
variables tab (located in the Simulation settings window).

Related links:
Output Variables Properties (p.184)

4.5.4 Profile Results Tab Properties - Network Simulation

The Profile results tab displays the results as a function of distance along a specific network
branch in tabular or graphical format.
You can also filter the results table to show specific branches (for example, typing well will display
all branches that contain well in the name).
You can also select the columns to be shown in the results table. After selecting the desired
columns, you can expand the rows to display additional information about particular network
objects.

Property Description
Show grid Click this option to display the simulation profile results in a table.
Show plot Click this option to display the simulation profile results as a graphical plot. If you
want to view plots for all branches at once, click the upper-left hand corner of the
table. Double-click the plot to configure it.
Select Click this button to open the Select columns window, where you can select the
columns columns to be shown in the results table.

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Property Description
The available properties correspond to the profile variables selected in the Output
variables tab (located in the Simulation settings window).
Expand all Click this button to show or hide detailed information for all network objects in the
results table.
For example, a compressor row expands to display data such as pressure
difference and power required. (Some object types, such as junctions, sinks and
wellheads, do not expand.)

Note: Click on a row in the results table to show detailed results for certain
individual objects.

Related links:
Output Variables Properties (p.184)

4.5.5 Improving Network Simulation Performance

In general, Performance is a trade-off between speed and accuracy. When dealing with models
that are taking too long to run, there are several approaches that can be taken to improve the
network speed. Improving the speed may compromise the accuracy and you may need to reverse
some of the changes outlined in the approaches below to restore the appropriate level of accuracy,
once you have fine-tuned the model.

Approaches for Improving Network speed

Approach 1: Change the PIPESIM execution and reporting settings
Approach 2: Make high and low-level changes to the PIPESIM model

Note: After using the approaches above to improve the network speed and fine-tune the model, it
is important that you carefully reverse some/all of the changes, in order to regain accuracy.

Approach 1: Change the PIPESIM execution and reporting settings

The options outlined below do not modify the model but attempt to reduce the engine workload to
improve speed. You may need to do some trial-and-error to determine which one, or combination
of options below, is best for speeding up your model.

Option Details
Increase the no. PIPESIM has introduced a parallelized network solver where you can run
of allocated network simulations with multiple processors to increase the speed.
processors How do I do this?

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Option Details
Go to Workspace Options Advanced Engine Options. Increase the
Number of processes for Network engine. For more information, see
Advanced Options (p.9).
Decrease the Decreasing the verbosity level will reduce the amount of output displayed in
verbosity level the engine console during simulation.
How do I do this?
Go to Workspace Options Advanced Engine Options. Decrease the
Network verbosity level. 0 is minimal, 1 is default and higher generally
increases the amount of output.
Restart the Restarting a network simulation, as opposed to running it, increases the
simulation network speed. This option uses a restart file to initialize the simulation by
using the results from the previous simulation as estimates for the unknown
variables. This is most effective when you are running many similar scenarios
with only small variations. If minor changes (such as flow rates, pipe
dimensions, etc.) have been made to a network, use the Restart function.
However, if structural changes (such as new pipes, wells deleted, inactive
branches reactivated, etc.) have been made, run the model from scratch, by
clicking Run instead.
How do I do this?
If you have not run the model at all, launch the Network simulation task and
run it to generate restart files. To run subsequent simulations faster, after
minor changes have been made to the model as described above, launch the
Network simulation task and click Restart. For more information, see Restart
Simulation (p.221).
Do not display Choosing not to display the engine console window during the simulation
engine console should increase the network speed.
window How do I do this?
Go to Workspace Options Advanced Engine Options. Uncheck the
Show engine console box.
Do not generate Choosing not to generate the engine output files after the simulation is
engine output complete, should increase the network speed.
files How do I do this?
Go to Workspace Options Advanced Engine Options. Uncheck the
Show engine output files box.
Run the model How do I do this?
locally Save the model to the local PC rather than to a Network drive. This will
eliminate any potential network delays. Also use a local PIPESIM license file,
rather than a network license, if possible.

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Approach 2: Make high and low-level changes to the PIPESIM model

The following options will increase the simulation speed, but may sacrifice accuracy in doing so.
Use these options to fine-tune the model, but reverse them to get more accuracy, once this is
done. You may need to do some trial-and-error to determine which one, or combination of options
below, is best for speeding up your model. The high level changes are easy to reverse, the low
level changes might require a bit more work to reverse.

Option Level of Details

Change
Increase the High and PIPESIM solves the network using an iterative approach. It stops the
Tolerance Low calculation when the iterative error is less than a given tolerance.
Thus, the specified tolerance has a direct impact on the number of
iterations and the time taken to achieve an acceptable result. The
default tolerance is 1% (0.01). Increasing the tolerance will increase
the speed but will compromise the accuracy.

Note: The results with tolerance greater than 2% are not

recommended.

How do I do this?
For a network model, go to Home Simulation settings
Advanced Engine Options and enter a higher value for the
Network solution tolerance.
Specify flow Low Specifying flow rates as the boundary conditions at inlet nodes
rate as the inlet usually result in faster performance.
boundary How do I do this?
conditions
For a network model, launch the Network simulation task. Delete
the pressure boundary conditions for inlet nodes (wells and sources)
and enter flow rate boundary conditions instead, but ensure that at
least 1 pressure is specified to satisfy the criteria required for the
network to solve.
Change the High and The Moody friction factor is calculated as part of the multiphase
calculation Low pressure drop calculations (vertical and horizontal) when the single
method for the phase flow correlation option is set to Moody or Cullender-Smith. For
Moody friction more information, see Single Phase Flow Correlations. (p.296)
factor to There are three (3) options for the Moody fiction factor calculation. In
Approximate increasing order of accuracy, they are: Approximate/Moody (refer to
the Moody paper (p.499)), Explicit/Sonnad (refer to the Sonnad and
Goudar paper) (p.499), and Implicit/Iterative (Colebrook-White
equation or Moody chart). The default option is Explicit. Changing the
calculation method to Approximate will increase the speed but
decrease the accuracy.
How do I do this?

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Option Level of Details

Change
Go to Home Simulation settings Advanced Engine
Keywords and enter the following lines of PIPESIM keywords in the
Network keywords (bottom)field. This will add the keywords to the
bottom of the engine network file.
OVERRIDE
SPHASE MOODYCALC = APPROXIMATE
Decrease the High and PIPESIM divides pipes into shorter segment lengths to do the
number of Low pressure drop calculations. The greater the pipe segmentation, the
segments per better the accuracy, but the slower the performance. The default
pipe length number of segments per pipe length in PIPESIM is 4. Decreasing
this number to 3, for example, will speed up the simulation.
Decreasing it to 2 will further speed up the simulation, but the
answers may become more unstable. Furthermore, if when using the
user-specified number of segments, PIPESIM encounters
discontinuities, it will override the specification and this will ultimately
slow down the simulation.
How do I do this?
Go to Home Simulation settings Advance Pipe
Segmentation Data and enter a value less than the default value of
4, in the Computation segments per report intervalfield.
For the single branch model, enter a value less than the default value
of 4, in the Segments per pipe length field.
For the network model, click the Option Control tab and follow the
previous step.
Deactivate the High PIPESIM calculates fluid properties at the average pressure and
option to temperature for each segment. The average values for these
include short properties may not be representative for the beginning and end of
segments the segment (for example, the nodes), particularly if the segment is
long and there are significant changes in pressure and temperature
across it. PIPESIM resolves this by adding short 1 foot segments at
both ends of each segment, by default. This will ensure accurate
values at the start and end of each node are reported, but it also
slows down the engine. If you are not interested in the exact values
at the beginning and end of each node, or are performing some fine
tuning, you may deactivate this option to speed up the simulation.
How do I do this?
Go to Home Simulation settings Advanced Pipe
Segmentation Data, and uncheck the box Additional short
segments across nodes.

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Option Level of Details

Change
Changing the High In the Compositional fluid mode, the fluid is flashed for the
Flashing temperature energy balance and for the calculation of the fluid
Settings physical properties, but depending on the option chosen in PIPESIM,
this can be a computationally expensive process. To speed up the
network simulation, change the flashing option for Temperature
energy balance and Physical properties, to a faster, but less
accurate one, as described below.
PIPESIM has 3 flashing options for Temperature energy balance
and Physical properties. In order of increasing accuracy but
decreasing network speed, they are:
Interpolate (fastest): This option uses interpolation between
physical properties determined by a predefined grid of
temperature and pressure points.
Hybrid: This is a compromise between speed and accuracy, which
assumes that properties will change more rapidly when close to a
phase boundary. Interpolation is performed whenever the grid
points comprising a rectangle all show the presence of the same
phases. For example, if all 4 points in the rectangle have some oil,
some gas, and no water, then we assume the rectangle lies
entirely within the 2-phase region of the hydrocarbon phase
envelope, so interpolation is appropriate. If however one, two or
three of the points have no oil, then clearly the hydrocarbon dew
point line crosses the rectangle, so a rigorous flash is required.
Rigorous (slowest): Interpolation never occurs. Properties are
obtained by rigorous flashing at every required pressure and
temperature. This is the slowest, but the most accurate method.
For more information, see Advanced Properties (p.9).
How do I do this?
Go to Home Simulation settings Advanced Compositional
Flashing Options, and select the fastest flashing option for
Temperature energy balance and Physical properties.
Switch to a Low Generally, black oil fluid models run faster than compositional fluid
Black Oil fluid models. However, Compositional fluid models are more accurate,
model particularly when dealing with gas condensates and volatile oils. If
your model does not undergo a lot of compositional or phase
changes and/or the difference in results between running the
simulation in black oil vs. compositional mode is minimal, then it
would be reasonable to run the model in black oil mode to speed up
the simulation.
How do I do this?

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Option Level of Details

Change
If you have a compositional fluid model, change it to Black Oil by
selecting Home Fluid manager. Select Black Oil from the option
list and enter the required values.
Changing Flow Low Changing flow correlations is another way of speeding up
Correlations simulations, but this option should be used with great caution. Flow
correlations should be chosen based on their ability to reproduce/
match the flowing pressures, holdups, etc. observed in the field.
However, if different correlations yield similar (accurate) results but
varying simulation speeds, then it would be reasonable to choose the
flow correlation that yields the fastest simulation speed. The native
bja package is the fastest. 3rd party flow correlations, specifically the
3-phase mechanistic flow correlations, will typically be the slowest,
but most accurate.
How do I do this?
Change the flow correlations under Home Simulation settings
Flow correlations.
Avoid loops in Low Loops in the network require PIPESIM to do extra checks to ensure
the network overall consistency (for example, elevation difference). Avoid loops
topology where possible to speed up the performance.
Follow these High and Try to split the model into smaller networks, which can be solved
general tips Low independently, before linking them all together. (This helps in
troubleshooting the model.)
When first building the model, leave out equipment such as
compressors and separators, then incorporate them one at a time.
(Again, this helps troubleshooting.)
When using a compressor or pump, define it initially with a Delta P
rather than with a power or user curve. It can be changed as
required later. Also, avoid defining a compressor with discharge
pressure, as this can have the effect of over-constraining a
system.
Try to avoid unnecessary nodes in a network, as this increases
the computing time required to solve it.
Avoid dangling or redundant branches.
If the sinks are flow rate specified, and are consistently being
reported at atmospheric pressure upon simulation (see messages
in engine window), try changing the boundary condition to an
outlet pressure to see what flow rate can be achieved.
When first attempting to solve a large network, increase the
convergence tolerance to 5% and check the validity of the results.
The tolerance can later be reduced and the model restarted.

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Option Level of Details

Change
If a branch appears to be behaving strangely, or is ill-conditioned,
split it into smaller segments. This aids troubleshooting and
improves continuity along the branch.
If the program crashes part way through an iteration with "file
open" or "macopen" errors, this is due to the processor running
out of memory. Simply restart the model; the program will start
from where it left off. Use the PIPESIM toolbar Restart button in
this case.
Try to avoid having long flowlines and risers in the same branch.

Related links:
Reversing the changes made to PIPESIM models to optimize their simulation performance (p.223)
PIPESIM Differences from other Simulators (p.222)
Restart Simulation (p.221)

Restart Simulation
When a Network simulation run is complete, the final solution results are stored in a restart file.
The results in the restart file can be reused as initial estimates for a subsequent simulation, if the
new simulation is launched by restarting the model (as opposed to rerunning it).
The restart file results will be used as initial estimates, instead of the PIPESIM default estimates
(Production/injection well static pressure = 5,000 psia, Source/sink/node pressure = 1,000 psia &
Flowrate = 10 lb/s). Restarting the model is a good option for increasing network speed, and is
most effective when you are running many similar scenarios with only small variations. If minor
changes (such as flow rates, pipe dimensions etc.) have been made to a network, use the Restart
function. However, if structural changes (such as new pipes, wells deleted, inactive branches
reactivated, etc.) have been made, run the model from scratch, instead. For more information, see
Improving Network Simulation Performance (p.215).
To restart a model:
1. Launch the Network simulation task and click Run to run the simulation (if the model has not
been run at all).
2. Make the minor changes you want to make to the model, as described above.
3. Re-launch the Network simulation task and click Restart to initialize the simulation.
The Restart function, by default, restarts the model by keeping all deactivated branches
permanently deactivated. So if you deactivate a branch, run the model, and reactivate the branch
again before using the Restart function, the deactivated branch remains deactivated.

Note:

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If the model has changed significantly (for example, a well was added, or a branch or node
was de- or re-activated), the use of the Restart function may actually slow down the
simulation.
If minor changes have been made to a network (for example, a flow rate or pipe dimension
change), Restart should provide a faster convergence than a normal run.
The Restart function is particularly useful to continue a simulation from where it left off, in
the following scenarios: if the program crashes part way through an iteration; if the model
does not solve in the allowed number of iterations; or if the run is terminated prematurely by
user intervention or some other system error.

Related links:
Improving Network Simulation Performance (p.215)

PIPESIM Differences from other Simulators

It is important to understand how PIPESIM works in order to assess its performance in comparison
with other network simulators, which may or may not appear to be faster. PIPESIM differs from
other simulators in the following ways:
PIPESIM is a multiphase flow simulator. Other simulators with apparent faster performance
may be single-phase simulators, which cannot capture important multiphase effects.
PIPESIM can model general networks including loops and crossovers. Other simulators may be
limited to solving gathering networks only (multiple sources, 1 sink).
PIPESIM does not require (good) initial estimates at each source and sink, which may be a
requirement for other simulators.
PIPESIM does not require (good) internal node estimates, which may be a requirement for
other simulators.
The tolerance in PIPESIM may be defined differently from other simulators.
PIPESIM performs a rigorous heat balance, which may not be the case for other simulators.
Other simulators may have to define the fluid composition for each branch in the model at the
start of the simulation, before the flow rates are known! This is not a PIPESIM requirement.
PIPESIM rigorously checks for network inconsistencies, for example elevation mismatches,
prior to the simulation, which is a step other simulators may skip.
Other simulators may need to have non-return valves placed in lines to indicate the direction of
flow. This is not a PIPESIM requirement.
PIPESIM has a strong and rigorous fluid Compositional PVT characterization supported by the
Multiflash package, which is also embedded in OLGA, allowing better alignment and transition
from steady-state to transient workflows.
PIPESIM includes more PVT correlations for heavy oil characterization.
PIPESIM includes a comprehensive list of flow correlations; single-phase, multiphase, empirical
and state-of-the-art mechanistic flow correlations such as the OLGA-S correlations.
PIPESIM has more engineering tools for flow assurance analysis (hydrates, asphaltenes, wax).

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PIPESIM data matching is more rigorous as the (U value and pressure hydraulics) are
simultaneously tuned to give a more accurate thermo-hydraulic representation of the system
being modeled.

Related links:
Improving Network Simulation Performance (p.215)

Reversing the changes made to PIPESIM models to optimize their simulation

performance
After using the approaches above to optimize the network performance and fine-tune the PIPESIM
model, it is important that you carefully reverse some/all of the above changes in order to regain
accuracy. A subset of some (not all) of the changes that may need to be reversed are outlined
below:
Tolerance:Restore the default tolerance of 1%. Generally, increasing the tolerance above the
default value of 1% will increase network speed but decrease accuracy. Decreasing the
tolerance to 0.1% or lower will significantly increase the simulation time.
Moody friction factor: Change the Moody friction factor calculation method back to the default,
EXPLICIT, or the most accurate method, IMPLICIT. Do this by replacing the keyword
APPROXIMATE, which was recommended in the previous section to speed up the
performance, with EXPLICIT or IMPLICIT (Refer to the previous section for Help with entering
the keywords correctly).
Boundary conditions: Enter the appropriate boundary conditions that are fit for purpose.
Extra one foot segments: Reactivate the option to add extra one foot segments under
Simulation settings Advanced.
Flashing settings:If working with a Compositional fluid, select a more accurate flashing option;
Rigorous or Hybrid. For more information, see Improving Network Simulation Performance
(p.215).
Flow correlations:Select the flow correlations that most closely reproduce the rates,
pressures, holdups, etc. recorded in the field.
Loops: Enter accurate and representative topology for the loops in the network.

Related links:
Improving Network Simulation Performance (p.215)

4.6 Running a System Analysis

Set up a system analysis to determine the performance of a given system by sensitizing on various
operating conditions or object properties. You can generate performance curves for the system by
varying sensitivity variables in groups (change-in-step) or by applying permutations to individual
sensitivity variables. The ability to perform analysis by combining sensitivity variables in different
ways makes the system analysis operation a very flexible tool for analyzing a large range of
operating conditions.

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1. Click on a well or source.

2. On the Home tab, in the Tasks group, click System analysis.
3. Define the calculated variables.
4. Configure the sensitivity variables.
5. Click Run.
To monitor processing progress, check the progress monitor. When processing is complete, the
Stop button appears dimmed.
6. View the profile results by clicking the System results tab or the Profile results tab.

Related links:
System Analysis Properties (p.224)
System Results Tab Properties - System Analysis (p.227)
Profile Results Tab Properties - System Analysis (p.195)

4.6.1 System Analysis Properties

Enter the properties for the system analysis, including the branch endpoint, the calculated variable,
and any sensitivity variables.

General Properties

Property Description
Branch start The well, source, or junction (if treated as a source) selected when the task was
started. You cannot change this value.
Branch end The default value is the junction farthest from the selected Branch start. To change
the Branch end, select the endpoint of the selected branch from the list. Setting the
endpoint at an object (for example, a flowline) includes that object in the simulation.

Calculated Variable Properties

Property Description
Inlet pressure To calculate the inlet pressure, enter both outlet pressure and any flowrate.
Outlet pressure To calculate the outlet pressure, enter both inlet pressure and any flowrate. The
inlet pressure is determined by the pressure at the start node.
Liquid flowrate Select the flowrate (liquid, gas, or mass) to be calculated. To calculate the
Gas flowrate flowrate, enter both inlet pressure and outlet pressure. The inlet pressure is
determined by the pressure at the start node.
Mass flowrate
Custom To calculate a custom variable, click Custom and then enter inlet pressure,
outlet pressure, and flowrate. The inlet pressure is determined by the pressure
at the start node.

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Custom Variable Properties

If you want to specify inlet pressure, outlet pressure, and flowrate (all three), you must also specify
how to achieve the specified outlet pressure by defining a custom variable. A custom variable is a
user-defined variable whose value is calculated to match the specified conditions.
Select an object and a variable whose value will have an effect on the system outlet pressure. For
example, in a production well model, a choke positioned at the wellhead may have Bean size as
the variable. You can select any object and variable, as long as they have an effect on the system
hydraulics.
You must specify the allowable maximum and minimum values for the variable, and the
proportionality relationship (whether an increase in the variable's value causes an increase or a
decrease in outlet pressure).
If you select Direct, the outlet pressure is assumed to be directly proportional to the variable,
and will increase when the variable increases (for example, the choke bean diameter).
If you select Inverse, the outlet pressure is assumed to be inversely proportional to the
variable, and will decrease when the variable increases. As an example, consider the watercut
of a black oil fluid in a production well: as watercut increases, the well's static delta pressure
increases, and therefore its outlet pressure decreases.

Note: For some object and variable choices, proportionality can be difficult to predict. For example,
if the tubing inside diameter (ID) is used as a variable in an oil production well, you would expect
outlet pressure to increase as diameter increases from a small initial value. However, once
diameter exceeds a certain critical value, the well will probably suffer from excessive liquid holdup,
causing the outlet pressure to decrease. In this situation, the simulation may have two solutions:
one with a small ID, and another with a much larger ID. In this case, the choice of proportionality
relationship lets you pick the solution you want. However, the simulation may have no solution; this
happens if the specified outlet pressure is too great.

Property Description
Object This list contains all objects within the selected branch, plus any tubulars or
completions defined for included wells. Select the object for which you want to
adjust a variable to affect the calculated flowrate.
Variable This list contains all calculated variables, including custom variables, associated
with the selected object. Select a variable for which you will specify minimum and
maximum values in the flowrate calculation. (When you select a variable, the Min
value, Max value, and Proportionality fields appear.)
Min value Enter the minimum allowable value for the variable.
Max value Enter the maximum allowable value for the variable.
Proportionality Determines whether an increase in the variables value causes an increase or
decrease in outlet pressure. Select one of the following options:
Direct
Outlet pressure is assumed to be directly proportional to the variable,
increasing as the variable increases; for example, the behavior of the choke
bean diameter.

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Property Description
Inverse
Outlet pressure is assumed to be inversely proportional to the variable,
decreasing as the variable increases. For example, as the watercut of a black
oil fluid in a production well increases, the wells static delta pressure
increases and its outlet pressure decreases.

Sensitivity Configuration Properties

Property Description
X-axis Click the desired model object from the drop-down list.
Variable Select a variable associated with the selected model for which you will specify a range
of values. When you select a sensitivity variable, the Range button appears above the
value range table, which may be useful for quickly defining a set of evenly spaced
values.
Range 1. Click Range.
2. Specify the Start and End values and the Step increment between those two
values.
3. Click OK.
The results appear in the values table (limited to 50 rows)
You can also complete the values table manually. To add a new row of data, click the
New(+) button; or simply type a number, and then press ENTER to move to the next
row. To delete a row, right-click the row, and then click Delete.
Table 4.14: X-axis Properties

Item Variables
Active Select this check box to activate the variable so that it will be used during simulation.
Clear the check box to deactivate.
Variable Click the desired model object from the drop-down list.
Range 1. Click Range.
2. Specify the Start and End values and the Step increment between those two
values.
3. Click OK.
The results appear in the values table (limited to 50 rows)
You can also complete the values table manually. To add a new row of data, click the
New(+) button; or simply type a number, and then press ENTER to move to the next
row. To delete a row, right-click the row, and then click Delete.
Table 4.15: Additional Sensitivity Variables

If one or more sensitivity variables are defined, choose how these should be combined with the X-
axis, by clicking one of the following options:

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Permuted
Runs a case for every combination of X-axis and all sensitivity variables. This option
produces a plot with the most lines (and takes the longest time to run).
Change in step with Variable 1
Runs a case for every combination of X-axis and Variable 1, with the remaining sensitivity
variables following Variable 1 in step. This option produces a plot with the number of lines
equal to the number of Variable 1 values.
Change in step with X-axis
Runs a case for every X-axis variable value, with all sensitivity variables following the X-
axis in step. This option produces a plot with just one line (and takes the least time to run).

Related links:
Running a System Analysis (p.223)

4.6.2 System Results Tab Properties - System Analysis

The System results tab displays system analysis results in two modes: Node or Branch. This tab
displays the range of calculated results when the profile includes sensitivity data. You can also
select the columns to be shown in the results table. After selecting the desired columns, you can
expand the rows to display additional information for completions and equipment objects.

Node Display Mode Properties

Property Description
Show grid Click this option to display the system analysis results in a table.
Show plot Click this option to display the system analysis results as a graphical plot.
Double-click the resulting plot to configure it.
Display mode Click Node or Branch to switch the display mode.
Equipment filter In the list, click All to show all network objects in the results table, or click a
single equipment type for display.
Select columns Click this button to open the Select columns window where you can select
the columns to be shown in the results table.
Expand all Click this button to show or hide detailed information for all network objects in
the results table.
For example, a compressor row expands to display data such as pressure
difference and power required. (Some object types, such as junctions, sinks,
and wellheads, do not expand.)

Note: You may also click on a row in the results table to show detailed results
for certain individual objects.

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Property Description
unlabeled search Enter part or all of the name of a case, equipment, or equipment type to filter
field the rows to show specific cases.
Case (column) Name of the sensitivity case.

Branch Display Mode Properties

Property Description
Show grid Click this option to display the system analysis results in a table.
Show plot Click this option to display the system analysis results as a graphical plot.
Double-click the resulting plot to configure it.
Display mode Click Node or Branch to switch the display mode.
Select columns Click this button to open the Select columns window where you can select
the columns to be shown in the results table.
unlabeled search Enter part or all of the name of a case, equipment, or equipment type to filter
field the rows to show specific cases.
Case (column) Name of the case or case group.

Related links:
Running a System Analysis (p.223)

4.6.3 Profile Results Tab Properties - System Analysis

The Profile results tab displays the calculated results of the system analysis. You can also select
the columns to be shown in the results table. After selecting the desired columns, you can expand
the rows to display additional information for completions and equipment objects.

Property Description
Show grid Click this option to display the system analysis results in a table.
Show plot Click this option to display the system analysis results as a graphical plot.
Double-click the resulting plot to configure it.
Equipment filter In the list, click All to show all network objects in the results table, or click a
single equipment type for display.
Select columns Click this button to open the Select columns window where you can select
the columns to be shown in the results table.
Expand all Click this button to show or hide detailed information for all network objects in
the results table.
For example, a compressor row expands to display data such as pressure
difference and power requirement. (Some object types, such as junctions,
sinks, and wellheads, do not expand.)

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Property Description

Note: You may also click on a row in the results table to show detailed results
for certain individual objects.

unlabeled Enter part or all of the name of a case, equipment, or equipment type to filter
search field the rows to show specific cases.
Case (column) Name of the case or case group.

Related links:
Running a System Analysis (p.223)

4.7 Designing an ESP

ESP Design task allows you to select suitable ESPs from the database and performs necessary
calculations to determine the number of stages required to achieve target flowrate under given
well, fluid and operating conditions. Multiple operations are performed as part of well's ESP design
to calculate and report well performance before and after an ESP is installed.
PIPESIM is primarily configured to perform single ESP Design and pump selection. However, you
may design and select pumps in tandem by performing successive design steps.
Prerequisites:
Well is completely defined with all the components and properties are required.
One or more fluid models are defined and each completion of a well is mapped to a fluid.
1. Click ESP design from the Tasks in a Well-centric workspace. In Network-centric mode,
select the well and then click ESP Design to open the ESP Design Task.
2. Under Boundary Conditions, specify all the required data.

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Parameter Description
Branch end By default, this field is populated as the wellstream outlet that is set in the model.
You can change the branch end to any other object in the well branch.
Outlet pressure You must specify this value.
Reservoir Represents pressure of the reservoir and populated directly from the base model.
Pressure You can update the value.
Reservoir Represents temperature of the reservoir and populated directly from the base
Temperature model. You can update the value.
Phase ratios Ratio type displayed here are GOR and Water Cut only. If the base fluid is defined
with other ratio types, necessary calculation will be performed in the background to
display GOR and WC.

Note: The phase ratio will be displayed for black oil or compositional fluid types
only.

Also, you will be allowed to modify the phase ratio for the design. In case of PVT
and MFL fluid, the phase ratio options will be hidden.
Note: For multilayer wells, the display of Inlet pressure, Inlet Temperature, and Phase ratio are
provided in a tabulated form showing all layers. All edited values of the base model properties are
local to the task (for example, it does not update the base model). When all the required data is
populated, a nodal plot is generated to display Initial Nodal Result for the base model (before the
ESP design). This Nodal plot considers the Nodal Analysis point to be at the Design intake depth.
Any changes in the boundary condition data will re-run Nodal analysis to refresh the plot.

3. Specify Design Criteria.

4. Click ... under pump selection group to open pump selection menu.
5. View/specify pump filtering option to control pump list under display.
6. Select a suitable pump from the pump selection table and click OK to exit pump selection
window and go back to the task window.
7. Click Run.
Results tab displays once Run is performed to populate the results.

Note:
The initial nodal analysis run considers a virtual nodal analysis point at pump intake. The
inflow includes the flowpath from reservoir to the pump intake including a separator if
defined. The outflow includes the section from the pump (including the pump) and all
components downstream including any surface equipment present. Note that outflow fluid
does not include separated/discarded gas.
Initial nodal analysis does not include any existing ESP(s) if the design option is Replace all
ESP(s).

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Required pressure reported at the bottom of the plot is the difference between outflow and
inflow pressure from the initial nodal run.
Intake gas volume fraction represents the value of the fluid entering pump intake (leaving
out separated gas that gets discarded). The gas volume fraction reported in ESP Design
represents the original fluid before separation.
Pump selection triggers a PT Profile run to estimate and report fluid flowrate at pump
intake condition - liquid rate, gas rate (excluding separated/discarded gas) and total rate.
Running the design task will create: (a) special nodal plot (with nodal point at pump
discharge), (b) Nodal analysis (with nodal point at bottomhole) and (c) P-T Profile.

Parameter Description
Target Must be smaller than the maximum delivery predicted by the displayed inflow curve (@
production rate pump intake). Target rate is blank by default. Once you set a value of target rate, the
initial nodal plot displays a dotted vertical line at the target rate.
Design Option Controls how the new ESP is added to the base well. Options are to Add a new ESP
(p.12) or Replace existing ESP.

Note:
(a) If the base well has no ESP, display is a read only option Add a new ESP
(b) If the base well has one or more existing ESPs, show the default option as
Replace existing ESP(s). The design process must replace all existing ESPs
by the new ESP at specified pump intake depth.
c) In case of b), you should be able to select the option Add a new ESP. The
design process will add a new ESP in addition to existing ESP(s).

Pump Intake The default option is to populate the depth as the bottom MD of the tubing or top of the
Depth topmost completion; whichever comes later in the intended flow path. You should be
able to edit it though ensuring the pump intake depth to be downstream of any
existing/active completion. (validation is optional).
Design 60 Hz shown as default. You may edit this value.
Frequency
Gas separator Unchecked by default. If checked, the separation efficiency default value is 100%. You
can change the value of separation efficiency.

Note: If the design option is Add a new Pump, the initial Nodal plot considers all the existing
ESPs in the well as part of the base model. However, if you select Replace existing ESP(s), the
base nodal analysis does not consider existing ESP(s) in analysis. Any changes in the Design
option (if allowed) or separator property should re-run nodal analysis to refresh initial nodal plot.
When all the required data is populated, a nodal plot is generated to display the Initial Nodal Result
for the base model (before the ESP design). This Nodal plot considers the Nodal Analysis point to
be at the Design intake depth. Any changes in the boundary condition data will re-run Nodal
analysis to refresh the plot.

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Related links:
ESP Design Task Parameters (p.232)
Tapered ESP Design (p.51)

4.7.1 ESP Design Task Parameters

The following tables explain the parameter options for the ESP Design task.

Pump Selection
The Pump selection and Performance tuning options are hidden if any data under the
Boundary Conditions or Design Criteria section is missing. Once data is complete, Pump
selection is enabled. Tuning factors appear after the pump is selected.

Parameter Description
Pump By default it is blank or empty, (for example, no pump is selected). The ...
command allows you to select the pump.
Stage by Allows staging calculation. It is checked by default. You can uncheck it. [not
Stage recommended]
calculation
Derating These are tuning factors for catalog pump performance curve. Head, Rate and
factors Power can be adjusted by the supplied factor (by default these are all 1, for
example, no tuning). You can change these.
Viscosity Viscosity correction is applied to the pump performance using one of the
correction/ selected models for correction factor. Model options (displayed once viscosity
correction correction is checked) depend on selected pump manufacturer: - If the selected
factor pump is REDA, viscosity correction models are - REDA, TURZO, CENTRILIFT
(default) - If selected pump is Centrilift - Centrilift (default) and Turzo - For all
other pumps - Turzo is the only option available/selected.

Note: Viscosity correction factor is applied during the simulation. Catalog

performance plot does not correct for viscosity. Clicking pump selection should
run a PT profile at design rate to calculate intake rates for liquid and gas phases
to aid pump selection.

Pump Selection Interface

The Pump selection interface pops up when the control button "..." is clicked under the Pump
selection. The window should display all the pump that is fit for purpose and filtered based on
following criteria.

Parameter Description
Casing ID Read only display of Casing ID from the base model at the location of
wellbore where pump is intended. The displayed pump must fit into the

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Parameter Description
casing with minimum equipment clearance provided by the user. (OD of
displayed pump < Casing ID - 2*Equipment clearance).
Equipment Represents minimum clearance between casing inside wall and ESP
Clearance outside wall (assuming the pump is concentric with the casing).
Design flowrate Read only field (for display only) - same as Design production rate (stock
tank conditions).
Design frequency Read only field (for display only). The pump selection table displays all
flowrates adjusted to this speed.
Intake Liquid Rate Read only value for liquid (including dissolved gas) flowrate at pump intake
condition.
Intake Gas Rate Read only value for free gas flowrate at pump intake condition after
separation (separated gas is assumed to be discarded).
Intake Total Rate Read only value of total fluid rate (liquid with dissolved has + free gas) at
pump intake condition. This rate is used for pump filtering based on rate
criteria.
Show Checked by default. This means all pumps displayed in pump table (see
recommended next section) fit into the casing (with given equipment clearance) and also
pumps satisfy the recommended flowrate range for total fluid at intake conditions.
If unchecked, the rate filter is disabled; all pumps that fit into the casing are
displayed.
Pump selection You can select any row in the pump table. Click OK to display the selected
controls pump on the main task window or Cancel to ignore the selection.

Pump Table
The Pump table is displayed after filtering with the following column options.

Parameter Description
Casing ID Read only display of Casing ID from the base model at the location of
wellbore where pump is intended. The displayed pump must fit into the
casing with minimum equipment clearance provided by the user. (OD of
displayed pump < Casing ID - 2*Equipment clearance).
Equipment Represents minimum clearance between casing inside wall and ESP
Clearance outside wall (assuming the pump is concentric with the casing).
Design flowrate Read only field (for display only) - same as Design production rate (stock
tank conditions).
Design frequency Read only field (for display only). The pump selection table displays all
flowrates adjusted to this speed.
Intake Liquid Rate Read only value for liquid (including dissolved gas) flowrate at pump intake
condition.

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Parameter Description
Intake Total Rate Read only value of total fluid rate (liquid with dissolved has + free gas) at
the pump intake condition. This rate is used for pump filtering based on
rate criteria.
Show recommended Checked by default. This means all pumps displayed in pump table (see
pumps next section) fit into the casing (with given equipment clearance) and also
satisfy the recommended flowrate range for total fluid at intake conditions.
If unchecked, rate filter is disabled; all the pumps that fits into casing are
displayed.
Manufacturer ESP Pump Manufacturer. These are REDA, ODI, ESP, etc.
Model ESP Pump Model (every manufacturer has a list of models as stored in the
database).
Series ESP Pump series (every model has a series that reflects the size of the
pump). A higher series represents larger OD of the pump.
Min. flowrate Recommended minimum flowrate for the pump operation.
Max flowrate Recommended maximum flowrate for the pump operation.
Efficiency at design Efficiency of the pump at the design flowrate.
condition

Note: The pump can operate outside of recommended range. However the efficiency will be
undetermined.

Plots on Task ESP Design

The plot area displays multiple plots. Initially, when the task is launched the only tab displayed in
the plot area is Base/Initial Nodal Analysis with/without the plot depending on whether the data is
complete or not. Once the pump is selected, other plot tabs appear. The Nodal Plot is a Nodal
Analysis plot generated with a Nodal point at pump intake.

Parameter Description
Initial Nodal Analysis Displays the Nodal Analysis Plot for the base model before the ESP
Design.
Required DP at the Displayed at the bottom of the plot and indicates the pressure
design rate differential between inflow and outflow at the design rate.
Intake gas volume Displayed at the bottom of the plot. This value is the gas volume
fraction fraction reported after discarding the separated gas, if any.
Catalog Performance Populated after pump is selected. The catalog curve displayed takes
Curve into account derating factors (head, rate and power) but no viscosity
correction. (The design rate series line shown here is total volumetric
rate at intake conditions.)
Catalog Variable Speed Performance curve (tuned with derating factors) displayed for variable
Curve speeds.

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Run/Stop command
The Run command performs ESP design taking all the data in the Parameter tab. The Run button
is active only if the required data is complete. The Stop command stops the task. Once the run is
complete, additional tabs appear - The Engine console tab displays the engine log and the
Results tab displays the results of ESP design.

Results
The Result tab displays the following results (including key input parameters):

Parameter Description
Design Design flowrate and design frequency as specified as input.
parameters
Operating Operating conditions (Operating flowrate, Outlet pressure and Total dynamic
conditions head) are the values considering calculated stages (rounded off to nearest
integer value)
Intake conditions (Pump intake pressure, intake liquid rate, intake gas volume fraction) refer to
conditions at the pump intake (suction)

Note: Gas volume fraction is the free gas after separated gas is discarded.

Pump Simulated result across pump. There are: Selected pump, Stages (nearest
parameters integer), Speed (pump rpm), efficiency, power, head, differential pressure,
discharge pressure and fluid temperature rise across pump

Plot
The following plots are produced:

Parameter Description
ESP Well A variation of Nodal Analysis - multispeed performance for the ESP that
Performance shows discharge pressure at various speeds, pump suction pressure,
bubble point pressure, gas volume fraction, etc.
Actual pump Catalog curve corrected for the actual number of stages, all derating
performance curve factors applied, viscosity correction factors applied, and fluid properties
at operating conditions. This curve reflects tabulated results for head,
power and efficiency at the operating point.
Well nodal analysis Nodal analysis plot including the ESP along with the bubble point line
superimposed.
Well P-T Profile Pressure-temperature profile showing both pressure and temperature
against elevation.

For more information, see Electrical Submersible Pumps (ESP) (p.390).

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Related links:
Designing an ESP (p.229)

4.7.2 Tapered ESP Design

A tapered ESP refers to multiple ESP's in the same well. A tapered electric submersible pump
(ESP) is mainly used to pump wells with a high gas-oil ratio. Free gas is separated and vented
using a shroud or gas separator. Alternatively, it is compressed using a tapered larger-than-normal
pump or specially designed gas handler below the normal pump. Another scenario could be
unavailability of required number of stages in the inventory for the intended ESP pump. A second
ESP can then be used to provide additional states as required.
Although the PIPESIM ESP Design task is configured to calculate required number of stages that
provides the required total pressure differential for the well at given operating conditions, tapered
design can be done through the following steps.
1. Perform the ESP Design as you would normally for a single ESP Design (p.229) to calculate the
required number of stages for the first ESP and Install the pump in the well.
2. Return to the Well editor and under the Artificial Lift tab select the ESP you have installed in
step 1. Edit the property by changing the number of stages to a lower value.
3. Return to the ESP Design and repeat the ESP design task after performing the following
actions:
a. Change the Design option as Add new ESP
b. Ensure the depth is changed to a new value.
c. Select a different pump as required.
As you have lowered the number of stages for the first pump, the new design will calculate the
number of stages required for the second ESP to achieve the additional pressure differential
and thereby meet the original total differential pressure requirement.
4. Install the second ESP.
5. Repeat steps 2 and 3 to add additional ESPs as required.

Note: PIPESIM performs hydraulic calculations for the ESP without considering the length of the
ESP equipment. For better accuracy, be careful in estimating the depth of subsequent ESP by
taking into account of the length of ESP stages you have already installed.

For more information, see Electrical Submersible Pumps (ESP) (p.390).

Related links:
Designing an ESP (p.229)

4.8 Managing Results

Result files may become quite large, and therefore are not included in the main .pips workspace
file. Instead, the result files are referenced by the workspace file. Whenever you run a simulation

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task, PIPESIM* creates a results directory named modelname.pipr in the same root path as
your model file. Results are stored in a database file created inside this directory. If you use
multiple studies, multiple database files will be created inside this directory, and each is named to
correspond with the study name.
The .pips workspace file will manage the studies and task configurations so that the same
results may be generated as long as the underlying model data has not been changed. For
example, the Send feature (accessible from Workspace Help) will attach a .pips file
(generally under 1 MB) to an email, but will not send model results. The recipient can regenerate
the results by rerunning the tasks.
PIPESIM 2013 introduced the study concept that allows you to archive the results of multiple
simulation runs without having to save separate versions of the model in separate directories. This
approach makes it easier to manage models and associated results without creating multiple
models files with different settings and revisions.
When you run a simulation task , it produces a result record with the following context:
Study
Entity (source object or start node)
Task
Study
A study is effectively a container for task configurations, references to the entities involved
in the task, and the results which are produced. All workspaces are initialized with a
default study named Study 1. You can rename the default study and create others. By
partitioning task references and results into studies, you can investigate multiple simulation
scenarios for cases where a sensitivity analysis is insufficient. Such cases may use
different fluid models, simulation methods, and inactive equipment.
Users are always functioning within a study as one or more studies must exist within a
workspace.
A single entity may produce results referenced by multiple studies.
Each study may contain multiple tasks, but each task has exactly one task
configuration per entity.
Many users will operate within the default study only.
You can access the current study on the Home tab in the Studies group. Any simulation
task run will be associated with this study. To add a new study, on the Home tab in the
Studies group, click Study New Study (+). You can also change the active study by
clicking Study studyname .
Entity
The entity is the model object or start node associated with the tasks and results. It may
include:
Networks
A network may include wells, sources, sinks, equipment, flowlines, and so forth.

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Wells
Includes the wellbore model and any surface equipment defined leading up to the
defined wellstream outlet (defaulted at wellhead, but user configurable to potentially
include surface equipment).
Sources
A generic source is considered an entity. A generic source may have equipment
attached to it, though is not included as part of the source entity. Additionally, for
special cases, internal network junctions may be treated as sources to model internal
network branches, such as trunk lines. For the purposes of task context, each task run
on a source entity contains a reference to the terminal point of the branch extending
from the source.
Task
Simulation tasks reference entities, contain configuration information (boundary conditions,
task options), and produce results when executed. These tasks include Network
Simulation, PT Profile, System Analysis, Nodal Analysis and VFP tables.
A study can have only one simulation task configuration (and result set) as rerunning a
simulation task will reset the task configuration and overwrite the result record.

Related links:
Running a P/T Profile (p.191)
Running a Nodal Analysis (p.197)
Creating a VFP Table (p.204)
Running a Network Simulation (p.208)
Running a System Analysis (p.223)
Launching the Results Viewer (p.238)

4.8.1 Launching the Results Viewer

The Results viewer allows you to browse all results generated from a workspace.
1. On the Home tab, in the Viewers group, click Results.
2. Perform one of the following actions:
To display results in the Results tab, click a row. The results appear below the table.
To display results in a separate window, double-click a row, or right-click a row and then
click Show results.

Note: You can open multiple result records for side-by-side comparison.

Property Description
Current selection Click this button to filter the results table to display only results associated
with the current selected entities.

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Property Description

Note: You automatically toggle the current selection when you right-click on
a model object and click Show results.

Current study Click this button to show results associated with the current (active) study.
unlabeled filter box Enter text into the filter box to find specific entries containing this text (for
example, Nodal).
Date Date and time the task was run.
Study Name of the study associated with the result record.
Task name Name of the task provided by the user.
Task type Type of the task run (for example, Network Simulation or Nodal Analysis).
Start node Name of the entity associated with the simulation task (for example, well or
source).
Status Status of the task (Completed, Running, Unconverged).
Description A description of the task (if provided).

Related links:
Running a P/T Profile (p.191)
Running a Nodal Analysis (p.197)
Creating a VFP Table (p.204)
Running a Network Simulation (p.208)
Running a System Analysis (p.223)

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5
Managing Model Data
You can create, edit, or delete your model data (such as equipment items, templates, flowline and
riser connections, fluids, and zones) by using the catalogs and the data managers available from
the Home tab.
1. On the Home tab, in the Application options group, click Catalogs to manage equipment or
template from catalogs.
2. On the Home tab, in the Data group, click Flowline manager to manage flowline and riser
connections.
3. On the Home tab, in the Data group, click Fluid manager to manage fluids.
4. On the Home tab, in the Data group, click Zone manager to manage zones.

Related links:
Managing the Catalogs (p.240)
Managing Flowlines and Risers (p.251)
Managing Fluids (p.13)
Managing Zones (p.253)

5.1 Managing the Catalogs

On the Home tab, in the Application options group, click Catalogs to view and edit equipment or
templates from the appropriate catalog.
1. You can filter the catalog view for any of the following hardware catalogs:
Casing
Tubing
Flowline/Riser
Centrifugal compressor
Reciprocating compressor

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Pump
2. You can create, delete, and edit catalog items for any of the following hardware catalogs:
Centrifugal compressor
Reciprocating compressor
Pump
3. You can create, delete, and edit catalog items for any of the following template catalogs:
Fluid templates
Well templates

Related links:
Filtering Catalog Views (p.241)
Adding Items to the Compressor Catalog (p.244)
Adding Items to the Pump Catalog (p.246)
Managing the Fluid Templates Catalog (p.247)
Managing the Well Templates Catalog (p.249)

5.1.1 Filtering Catalog Views

Catalogs can contain thousands of items, so most catalogs provide filters to display only the items
you need. For each filter, you can instantly display items that are less than, greater than, or equal
to the entered value.

Note: When you open a catalog, the filters are inactive, so all catalog items appear by default.

1. On the Home tab, in the Application options group, click Catalogs to select equipment from
the appropriate catalog.
2. Select the unit of measure from the list.
3. Click the filter button, and then click Contains, Equals, Greater than, Less than, or Starts
with.
The filter button changes based on your selection.
4. In the box to the left of the filter button, enter the filter value.
The catalog contents change to display only the items that match the filter.
5. To stop using a filter, perform one of the following actions:
Delete the filter value.
Click the filter button, and then click None.

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Related links:
Casing Catalog Properties (p.242)
Tubing Catalog Properties (p.243)
Flowline/Riser Catalog Properties (p.243)

Casing Catalog Properties

Casing is pipe cemented to the formation, typically filled with a completion fluid but may instead
serve as a flow conduit for produced fluids. Casing serves the following purposes:
Prevents the formation wall from caving into the wellbore
Isolates the different formations to prevent the flow or crossflow of formation fluid
Provides a way to maintain control of formation fluids and pressure as the well is drilled
Use the Casing catalog to select a specific casing size and grade after adding casing to a
wellbore schematic. You can also filter the catalog view.

Property Description
Catalog Several separate catalogs are aggregated into the PIPESIM* casing Catalog. The
API catalog represents standard casing sizes. The GOST, Tenaris, and VAM
catalogs represent connections.
OD Outside diameter of the casing.
ID Inside diameter of the casing.
Thickness Thickness of the casing wall.
Weight Weight of the casing per standard length.
Roughness The typical value for the absolute pipe roughness based on the material type. The
default value is 0.001 inches (0.0254 mm).
Grade Strength rating for the casing material.
Table 5.1: Casing Catalog Properties

Note: The casing catalog is read-only. If you wish to specify your own casing, enter the values
directly into the casing table on the Tubulars tab in the Well editor.

For more information, see Typical Values (p.487).

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Related links:
Adding Casing and Tubing to a Simple Wellbore Schematic (p.25)
Adding Casing and Tubing to a Detailed Wellbore Schematic (p.27)

Tubing Catalog Properties

Use the Tubing catalog to select a specific tubing size and grade after adding tubing to a
wellbore schematic. You can also filter the catalog view.

Property Description
Catalog Several separate catalogs are aggregated into the PIPESIM* tubing catalog. The
API catalog represents standard tubing sizes. The Tenaris and VAM catalogs
represent connections, not full tubing strings.
OD Outside diameter of the tubing.
ID Inside diameter of the tubing.
Thickness Thickness of the tubing wall.
Weight Weight of the tubing per standard length.
Roughness The typical value for the absolute pipe roughness based on the material type. The
default value is 0.001 inches (0.0254 mm).
Grade Strength rating for the tubing material.
Table 5.2: Tubing Catalog Properties

Note: The tubing catalog is read-only. If you wish to specify your own tubing data, enter the values
directly into the tubing table on the Tubulars tab in the Well editor.

For more information, see Typical Values (p.487).

Related links:
Adding Casing and Tubing to a Simple Wellbore Schematic (p.25)

Flowline/Riser Catalog Properties

Use the Flowline/Riser catalog to select a specific size and grade after adding a flowline or
adding a riser to a network diagram. You can also filter the catalog view.

Property Description
Type The catalog name or manufacturer of the flowline or riser.
Nom. Diameter Nominal diameter of the pipe. Pipe diameter is commonly classified in terms of
nominal diameter, although the actual outside diameter is a different value. For a

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Property Description
given nominal diameter, the outside diameter stays fixed and the well thickness
increases with schedule.
Schedule American National Standards Institute schedule rating, which results in a specific
pipe wall thickness as an indicator of pressure rating. For a given schedule, the
outside diameter increases with nominal diameter, while the wall thickness stays
constant or increases.
OD Outside diameter of the flowline or riser.
ID Inside diameter of the flowline or riser.
Thickness Thickness of the pipe wall (excluding any coatings).
Roughness The typical value for the absolute pipe roughness based on the material type.
Weight Weight per length of the pipe.

For more information, see Typical Values (p.487).

Related links:
Adding Connections (p.144)

5.1.2 Adding Items to the Compressor Catalog

There are no predefined items in the Compressor catalog. As you create new items, they
appear in the catalog.
1. On the Home tab, in the Application options group, click Catalogs, and then click either
Centrifugal compressor catalog or Reciprocating compressor catalog.
2. Click New.
3. On the Properties tab, enter the compressor properties.
4. If you want to enter performance curve information, perform the following actions:
a. Click the Performance data tab, and then enter the compressor curve properties.
b. Click New (+) to add more curves.
c. When finished, click OK.
5. Click Close.

Related links:
Compressor Catalog Properties (p.244)

Compressor Catalog Properties

Use the Compressor catalog to select a compressor object upon adding a compressor to a
network diagram. You can also create new catalog items, edit or delete existing items, and filter the
catalog view.

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Centrifugal Compressors
Dynamic machines in which one or more rotating impellers, usually shrouded on the sides,
accelerating the gas. This compressor model uses centrifugal compressor equations to
determine the relationship between inlet pressure and temperature, outlet pressure and
temperature, flowrate, shaft power, and efficiency. You can add performance curve
information to the database.
Reciprocating Compressors
Positive-displacement machines in which the compressing and displacing element is a
piston having a reciprocating motion within a cylinder. These compressors always use
performance curves that you entered. If you use compressor curves, the compressor
speed and number of stages become additional factors.
The following properties are available for centrifugal and/or reciprocating compressors. If you want
to enter performance curve information, enter the compressor curve properties on the
Performance data tab.

Property Description
Manufacturer Manufacturer of the compressor.
Model Model name or number of the compressor.
Centrifugal Compressor
Min flowrate Minimum recommended flowrate for the performance curve. You can
construct the curve outside this limit, but warning messages appear
when the operating point is outside this limit.
Max flowrate Maximum recommended flowrate for the performance curve. You can
construct the curve outside this limit, but warning messages appear
when the operating point is outside this limit.
Base frequency Frequency at which the performance curve is defined.
Base speed Speed at which the performance curve is defined.
Reciprocating Compressor
Base frequency Frequency at which the performance curve is defined.
Base speed Speed at which the performance curve is defined.
Abs. min. suction Absolute minimum suction pressure.
pressure
Abs. max. capacity Absolute maximum capacity. (The performance curve can be
constructed outside this range. Warning messages show where the
operating point is outside this limit.)
Stages Number of stages used.
Inter-stage temperature Temperature of the gas between stages.
Table 5.3: Properties Tab

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Property Description
Flowrate (Centrifugal compressor) Flowrate associated with the discharge pressure.
This is in flowing (actual) conditions, not stock tank conditions.
Head (Centrifugal compressor) Specifies the pressure at the compressor head.
Efficiency (Both) Specifies the efficiency of the compressor.
Discharge (Reciprocating compressor) Pressure at the compressor outlet. For each
pressure discharge pressure, there is at least one flowrate, suction pressure, and
efficiency percent.
Suction Pressure (Reciprocating compressor) Pressure at the compressor inlet.
Power (Reciprocating compressor) The horsepower of the compressor.
Table 5.4: Performance Data Tab

For more information, see Centrifugal Pumps and Compressors (p.366) and Reciprocating
Compressor (p.369).

Related links:
Adding Surface Equipment using the Network Diagram (p.102)

5.1.3 Adding Items to the Pump Catalog

There are no predefined items in the Pump catalog. As you create new items, they appear in the
catalog.
1. On the Home tab, in the Application options group, click Catalogs, and then click Pump.
2. Click New.
3. On the Properties tab, enter the pump properties.
4. If you want to enter performance curve information, perform the following actions:
a. Click the Performance data tab, and then enter the pump curve properties.
b. Click New (+) to add more curves.
c. When finished, click OK.
5. Click Close.

Related links:
Pump Catalog Properties (p.246)

Pump Catalog Properties

Use the Pump catalog to select a pump upon adding a pump to a network diagram. You can also
create new catalog items, edit or delete existing items, and filter the catalog view.
If you want to enter performance curve information, enter the pump curve properties on the
Performance data tab.

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Property Description
Manufacturer Manufacturer of the pump.
Model Model name or number of the pump.
Min flowrate Minimum recommended flowrate for the performance curve. You can construct
the curve outside this limit, but warning messages appear when the operating
point is outside this limit.
Max flowrate Maximum recommended flowrate for the performance curve. You can construct
the curve outside this limit, but warning messages appear when the operating
point is outside this limit.
Base frequency Frequency at which the performance curve is defined.
Base speed Speed at which the performance curve is defined. This cannot be changed for
the simulation, but you can set a different operating speed in the Pump editor
window. The curve is then adapted for that operating speed.
Base stages Initial point at which the performance curve is defined. This can be changed for
the simulation.
Stage number If the number of stages is supplied, it is used to adjust the supplied curve
against its specified speed.
Table 5.5: Properties Tab

Property Description
Flowrate Flowrate associated with the discharge pressure. This is the actual flowrate and not
the stock tank conditions.
Head Shows the actual pressure at the pump head.
Efficiency Efficiency associated with the discharge pressure.
Table 5.6: Performance Data Tab

For more information, see Centrifugal Pumps and Compressors (p.366).

Related links:
Adding Surface Equipment using the Network Diagram (p.102)

5.1.4 Managing the Fluid Templates Catalog

Use the Fluid templates catalog to create custom fluid templates from either existing or new
fluids, edit custom fluid templates, and view built-in or custom fluid templates. The Fluid
templates catalog includes the built-in templates and any custom templates that have been
created.

Related links:
Viewing a Built-in Fluid Template (p.248)
Creating a Custom Fluid Template (p.248)

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Viewing or Editing a Custom Fluid Template (p.249)

Creating or Editing Fluid Models (p.146)

Viewing a Built-in Fluid Template

Built-in fluid templates appear as expandable objects in the Fluid templates catalog. You can
view built-in templates, but you cannot edit them.

The following built-in fluid templates are available:

Dry Gas
Light Oil + Gas
Heavy Oil + Gas
Dead Oil
Water
1. On the Home tab, in the Application options group, click Catalogs, and then click Fluid
templates catalog.
2. Click a template to expand the view that shows the phase ratio and watercut percentage.
3. Double-click the template, or right-click the template and then click View.
4. View the fluid properties, and then click Close.

Related links:
Managing the Fluid Templates Catalog (p.247)

Creating a Custom Fluid Template

When you create custom fluid templates, they appear in the Fluid templates catalog. Custom
templates appear bright blue, with a face icon. You can edit or delete custom templates.

1. On the Home tab, in the Data group, click Fluid manager.

2. Perform one of the following actions:
To create a custom fluid template from an existing fluid, go to step 3.

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Create a new fluid without a template by clicking New, and then clicking OK.
3. Double-click the row number of the fluid to open the Fluid editor.
4. Enter any fluid properties, if necessary, and then click Save as template.
The fluid appears as a custom template in the Fluid templates catalog.
5. Click Close.

Related links:
Managing Fluids (p.13)

Viewing or Editing a Custom Fluid Template

View or edit a custom fluid template in the Fluid templates catalog.
1. On the Home tab, in the Application options group, click Catalogs, and then click Fluid
templates catalog.
2. Click a template to expand the view that shows the phase ratio and watercut percentage.
3. Double-click the template, or right-click the template and then click Edit.
4. View or edit the fluid properties, and then click Close.

Related links:
Managing Fluids (p.13)

5.1.5 Managing the Well Templates Catalog

Use the Well templates catalog to create custom well templates from either existing or new
wells, edit custom well templates, and view built-in or custom well templates. The Well
templates catalog includes one built-in template and any custom templates that have been
created.

Related links:
Viewing a Built-in Well Template (p.249)
Creating a Custom Well Template (p.250)
Viewing or Editing a Custom Well Template (p.250)

Viewing a Built-in Well Template

The built-in well template, Simple Vertical, appears as an expandable object in the Well
templates catalog. You can view the built-in template, but you cannot edit it.

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1. On the Home tab, in the Application options group, click Catalogs, and then click Well
templates catalog.
2. Click a template to expand the view that shows the template type.
3. Double-click the template, or right-click the template and then click View.
4. View the well properties, and then click Close.

Related links:
Managing the Well Templates Catalog (p.249)

Creating a Custom Well Template

When you create custom well templates, they appear in the Well templates catalog. Custom
templates appear bright blue, with a face icon. You can edit or delete custom templates.

1. Perform one of the following actions:

To create a well template from an existing well, go to step 2.
Create a new well.
2. In the Inputs pane, right-click the well, and then click Save as template.
3. On the Home tab, in the Application options group, click Catalogs, and then click Well
templates catalog.
The well appears as a custom template.

Related links:
Adding Wells (p.99)

Viewing or Editing a Custom Well Template

View or edit a custom well template in the Well templates catalog.
1. On the Home tab, in the Application options group, click Catalogs, and then click Well
templates catalog.
2. Click a template to expand the view that shows the template type.

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3. Double-click the template, or right-click the template and then click Edit.
4. View or edit the well properties, and then click Close.

Related links:
Adding Wells (p.99)

5.2 Managing Flowlines and Risers

The Flowline manager provides a table-view summary of all flowlines and risers in a network
diagram. Flowlines are used to model horizontal or near-horizontal flow while risers are used to
model vertical or near-vertical flow in offshore environments.
1. On the Home tab, in the Data group, click Flowline manager.
2. To edit flowline or riser properties, perform one of the following actions:
Click a table cell, and then enter the new value. You can edit limited properties in the
Flowline manager.
Double-click the row number of a flowline to edit the flowline in the Flowline editor (all
properties).
Double-click the row number of a riser to edit the riser in the Riser editor (all properties).

Related links:
Flowline - Simple Model Properties (p.109)
Flowline - Detailed Model Properties - General Tab (p.112)
Flowline - Detailed Model Properties - Heat Transfer Tab (p.115)
Riser - Simple Model Properties (p.128)
Riser - Detailed Model Properties - General Tab (p.131)
Riser - Detailed Model Properties - Heat Transfer Tab (p.133)
Adding Connections (p.144)

5.3 Managing Fluids

Use the global Fluid manager to create or edit fluids. The Fluid manager provides a table-view
summary of all fluids entering the system at each inflow source. All fluids listed in the Fluid
manager are of the type selected on the Home tab in the Fluid mode group. You may switch back
and forth between fluid types, but you cannot mix fluid types for simulation purposes.

Fluids
On the Fluids tab in the Fluid Manager, you may perform the following actions:
1. Create a new fluid by clicking New (+) below the last row.
2. Delete a fluid by right-clicking on the row and clicking Delete.

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3. Edit a limited set of fluid properties from directly within the table, including fluid name,
description, phase-ratio types and values.
4. Open the Fluid editor for more detailed editing of fluids by double-clicking the row
associated with the fluid.

Fluid Mapping
The Fluid mapping tab allows you to associate the defined fluids with sources and completions in
the model. You can associate every source in the model with a single fluid, associate each source
with its own individual fluid, or any combination therein. For example, for fields where different
groups of wells or completion layers are associated with different fluid models, you can easily
manage how these are mapped.
From the fluid mapping table, for any source listed in the table, click Fluid to associate a fluid to
a source.
If you wish to override the phase ratio for a specific source, select the Override phase ratios
check box to make the phase ratio types and values editable.
Gas ratio type
Select the phase ratio: Gas/Liquid Ratio (GLR), Gas/Oil Ratio (GOR), Liquid/Gas Ratio
(LGR), or Oil/Gas Ratio (OGR).
Gas ratio
Enter the value of the phase ratio (defined by the ratio type).
Water ratio type
Select the phase ratio: Watercut, Gas/Water Ratio (GWR), or Water/Gas Ratio (WGR).
Water ratio
Enter the value of the phase ratio (defined by the ratio type).

Note: Clearing this box will return the phase ratio to the value associated with the base fluid as
shown on the list on the Fluids tab.

To display mappings only for the selected sources or fluids, click Current selection.
To display mappings for wellstream outlets, click Wellstream outlet. You only need to define
fluids for wellstream outlets if you intend to run a network simulation task using surface
boundary conditions.

Tip: To quickly assign a single fluid to all sources in the model, click the fluid for the top row and
press F3.

Component/Models Settings (Compositional Fluid Mode only)

You can select the PVT package, methods, and components that are used by all compositional
fluids on the Component/models settings tab.

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Related links:
Creating or Editing Fluid Models (p.146)

5.4 Managing Zones

Use the Zone manager to create or edit zones or to delete zones. Defining zones is optional;
however, it is useful for aggregating certain reservoir properties shared by individual completions
across a large number of wells. Pressure, temperature, and fluid models are currently associated
with zones.
After you create zones, you can reference the zones on the Completions tab in the Well
editor. When you are running network simulations to study the effects of changing reservoir
conditions (pressure and fluid properties), you can conveniently change these values for a small
number of zone objects rather than for a large number of individual completions.

Note: Currently, no correction is made for pressure and temperature differences as a function of
data depth for individual wells.

1. On the Home tab, in the Data group, click Zone manager.

2. Perform one of the following actions:
To edit an existing zone, go to step 3.
To create a new zone, click New (+) and then go to step 3.
3. Enter a Name for the zone.
4. Select the appropriate Zone material (shale, sand, water, or unknown).
5. Enter the Pressure and Temperature, as measured from the zone midpoint (depth corrections
are not applied).
6. Select an existing Fluid.
7. Perform any of the following actions:
To deactivate the zone, double-click the row number of the zone to open the Zone editor
and clear the Active check box.
To edit the fluid selected for the zone, double-click the row number of the zone to open the
Zone editor and click Edit.
To create a new fluid for the zone, double-click the row number of the zone to open the
Zone editor and click New.
The following example shows a shale zone that is 350 feet thick.

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Related links:
Creating or Editing Fluid Models (p.146)
Associating Zones with Completions (p.90)
Running a Network Simulation (p.208)

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6
Working with the GIS Map
The Geographic Information System (GIS) Map in PIPESIM* allows you to build and visualize your
wells and surface pipelines alongside cultural data from a wide variety of sources in geographic
context.
Additionally, you can quickly define accurate profiles for flowlines through digitization and
automatic population of elevation data at configurable intervals, resulting in more accurate
calculation of pressure losses in pipelines and better assessment of where liquid is collecting in
lines to help predict corrosion hot spots and identify pigging locations. This approach may avoid
errors associated with manual data entry and ensure that there are no elevation mismatches for
adjacent flowlines or in looped systems.
Some of the GIS data formats supported in PIPESIM include:
Shapefile, an Esri file-based vector format
ArcGIS Server, an Esri server-based tiled or dynamic imagery format
Web Map Service (WMS), an Open Geospatial Consortium (OGC) server-based dynamic
imagery format

Related links:
Choosing a Basemap (p.255)
Navigating the GIS Map (p.257)
Zooming to Bookmarks (p.259)
Working with Layers (p.261)
Using the GIS Map (p.270)

6.1 Choosing a Basemap

The first step to take after opening the GIS Map is to choose a basemap. A basemap serves as a
backdrop against which all other data is displayed and determines how data added to the map
view are to be projected. PIPESIM* comes pre-configured with a set of basemaps provided
through Esri's ArcGIS Online service. Additional basemaps provided through Microsoft's Bing

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Maps service can be unlocked via a Bing Maps key. Furthermore, custom basemaps can be added
by connecting to internally or externally facing ArcGIS Server or WMS map services.
To select one of the Esri ArcGIS Online gallery basemaps:
1. On the Home tab, in the Viewers and results group, click GIS map.
2. On the Format tab, in the Layers group, click Basemaps, and then click any of the available
basemaps to select it as the basemap for the workspace.
Esri Basemaps
Esri basemaps are included as part of the PIPESIM Base License and include:
Delorme
National Geographic
Ocean
World Satellite (default basemap)
World Street
World Topographic

Note: To display a basemap in PIPESIM, it must have been published having Web Mercator as its
coordinate reference system (EPSG:3857 or ESRI:102100). This is to ensure that geographic data
from different sources line up properly when overlaid on the GIS map and to avoid geodetic error
that can be introduced when invoking on-the-fly re-projection.

Related links:
Adding Bing Basemaps (p.256)
Using Map Services (p.264)

6.1.1 Adding Bing Basemaps

To choose from one of the available Bing Maps basemaps, you must first obtain a valid Bing Maps
key.
See Getting a Bing Maps Key.
Once a valid Bing Maps key has been obtained, it must be supplied to PIPESIM* to unlock Bing
Maps enhanced capabilities:
1. On the Workspace tab, click Options, click GIS map, and then enter your Bing key in the field
provided.
When providing your Bing key, you will gain access to the following additional basemaps:
Bing Aerial with Labels
Bing Road Map
Bing Aerial Map
2. To verify that the Bing Maps basemaps have been unlocked successfully, perform the following
steps:

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a. On the Home tab, in the Viewers and results group, click GIS map.
b. On the Format tab, in the Layers group, click Basemaps.
Icons for the newly added basemaps should appear in the User defined (Application) section.
Providing a Bing Maps key will also unlock the Go to location feature and enable geocoding of
street addresses to geographic locations.

Note: In some cases, Bing Maps basemaps may provide higher resolution imagery with faster load
and response times than the default gallery basemaps, serving as a more suitable default when
working with the GIS map.

Related links:
Zooming to a Geographic Location or Address (p.258)

6.2 Navigating the GIS Map

After selecting a basemap, the next step is to determine where in geographic space to place an
existing network or create a new network.
You can navigate to a desired location using the tools provided on the Format tab in the Zoom
group, the Navigation widget located in the lower left-hand corner of the map, or via a
combination of mouse movements and keystrokes while directly interacting with the map.
There are multiple ways to specify the viewable area of your GIS map, including:
Panning and zooming to an area
Specifying geographic coordinates
Geocoding an address
Zooming to a bookmark

Related links:
Panning and Zooming to Your Map Area (p.257)
Zooming to a Geographic Location or Address (p.258)
Zooming to Bookmarks (p.259)

6.2.1 Panning and Zooming to Your Map Area

There are several ways to move from one area to another on the GIS map.
1. On the Home tab, in the Viewers and results group, click GIS map.
2. To zoom to the smallest area (extent) that will fit all objects defined on the map: On the Format
tab, in the Zoom group, click Zoom to fit.
3. To pan across the map: Press the CTRL key and then drag across the map using the left
mouse button.

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4. To use the Navigation widget in the lower-left corner:

Move the size slider up or down to increase or decrease the zoom level.
Drag the circular compass to change the map orientation.
To change the map orientation so North is at the top, click the Reset North button (which is
located between the size slider and circular compass).
5. To zoom to a specific layer on the map:
a. On the Format tab, in the Layers group, click Layers to view the layers on the map.
b. Click to select the layer, and then click Zoom to fit.
6. To use the Overview inset window to adjust the center of the map view:
a. On the Format tab, in the Show/hide group, select Overview.
The Overview inset window displays in the upper-right corner of the GIS map. A red box
with a small plus sign (+) marks the area of the map you are viewing.
b. In the Overview inset window, drag the red + to a new location.
The map is re-centered at that location.
c. To close the inset window: On the Format tab, in the Show/hide group, clear the Overview
check box.

Related links:
Navigating the GIS Map (p.257)

6.2.2 Zooming to a Geographic Location or Address

You can quickly zoom to a specified map coordinate or address.
To zoom to a specified location:
1. On the Home tab, in the Viewers and results group, click GIS map.
2. On the Format tab, in the Zoom group, click Go to location.
3. Perform one of the following actions:
Select Coordinate and supply geographic coordinates in the Longitude/X and Latitude/Y
fields.
Example: For a location with the longitude 95.3631 W and latitude 29.7631 N, enter the
values -95.3631 and 29.7631, respectively. Note that longitude coordinates west of the
prime meridian and latitude coordinates south of the equator are expressed as negative
values.
Select Address and enter an address (available only with a valid Bing Maps key).
Example: 5599 San Felipe, Houston, Texas, 77056
4. Click Apply to zoom to and create placemarks on the map for additional locations, or OK to
close the window.
The following table summarizes the various navigation controls available and where they can be
accessed:

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Format tab Navigation Map Format tab Format tab

Zoom group Widget Show/Hide Layers

group group

Edit Layers
Go to location X
Rotate/Reset North X
Pan N, E, S, or W CTRL via Overview
+Drag left Map
mouse
Full extent X X
Zoom in/Zoom out X X Scroll
mouse
wheel
Zoom area X
Zoom to fit X
Zoom to selected X X
Previous zoom/Next X
zoom

Note: In the GIS map, geographic positions (longitude and latitude) are always referenced relative
to the World Geodetic System (WGS) 1984 ellipsoid (EPSG:4326). This ellipsoid, in turn, serves as
the datum for the Web Mercator projected coordinate reference system (EPSG:3857 / ESRI:
102100) required of all basemaps.

Related links:
Adding Bing Basemaps (p.256)
Navigating the GIS Map (p.257)

6.3 Zooming to Bookmarks

Bookmarks make it easy to return to locations that you refer to often. PIPESIM* provides a few
example bookmarks to illustrate their usage and you can create your own bookmarks for locations
of interest to you.
1. On the Home tab, in the Viewers and results group, click GIS map.
2. On the Format tab, in the Zoom group, click Bookmarks.
3. Perform one of the following actions:
To zoom to a defined bookmark, perform one of the following actions:
Click one of the built-in bookmarks.

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If you have previously defined a bookmark, you can select it from the User-defined list.
The map zooms to the extent defined by the bookmark selected.
To create a new bookmark, click Add bookmark, enter a Name and Description for the
bookmark, and then click OK.
You can rename or delete a bookmark by right-clicking the bookmark and clicking Delete.

Related links:
Importing a Bookmark File (p.260)

6.3.1 Importing a Bookmark File

A bookmark file can be used to import previously created bookmarks.
1. On the Home tab, in the Viewers and results group, click GIS map.
2. On the Workspace tab, click Options.
3. Click GIS map.
4. Click the browse button for Bookmarks file and enter the file name.
Example: Major_oil_fields.xml
5. Click Open.
To verify that the bookmarks have imported successfully, on the Format tab, in the Zoom
group, click Bookmarks to view the imported bookmarks.

Related links:
Creating a Custom Bookmark File (p.260)

Creating a Custom Bookmark File

You can create a file that contains a set of bookmarks for geographic extents of interest to you.
1. Create a new text file and save it with an extension of xml for example, MyBookmarks.xml.
2. Open the file in a text editor.
3. The first line in your file should have the <Bookmarks> tag.
4. For each bookmark entry in your file, add a new tag based on this example:

<Bookmark Name=My First Bookmark Description=Description of my first

bookmark CrsId=4326 Minx=-10.0 Miny=-10.0 Maxx=10.0 Maxy=10.0/>

Parameter Description
Name Required.
Description Optional.
Crsld Required. Must be "4326" as shown above, corresponding with World Geodetic
System (WGS) 1984

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Parameter Description
Minx Required.
Miny Define the geographic extent being bookmarked according to the lateral units
Maxx defined by the specified CrsId. For the WGS84 geographic coordinate system
(CrsId = "4326"), X and Y represent longitude and latitude in decimal degrees,
Maxy respectively.
5. The last line in your file should have the </Bookmarks> tag.

Example
This example illustrates a complete bookmark file containing three bookmarks.

<Bookmarks>
<Bookmark Name=Gulf of Mexico CrsId=4326 Minx=-99.58 Miny=17.27
Maxx=-79.83 Maxy=33/>
<Bookmark Name="North Sea" CrsId="4326" Minx="-4.42" Miny="51.4"
Maxx="11.67 Maxy=63.82" />
<Bookmark Name="Teapot Dome" CrsId="4326" Minx="-106.24157"
Miny="43.24099" Maxx="-106.12088" Maxy="43.30976" />
</Bookmarks>

Related links:
Importing a Bookmark File (p.260)

6.4 Working with Layers

The first or bottom-most layer in the GIS map is the basemap layer, which defines the coordinate
reference system of the map as Web Mercator (EPSG:3857 or ESRI:102100) and serves as a
backdrop against which other layers can be added.
Some of the other layer types that can be added on top of the basemap layer include:
Map cache
A cached representation of satellite imagery tiles extracted from the Esri ArcGIS Online
World Imagery service which can be used when a live network connection is unavailable.
Map service layer
A dynamic (ArcGIS Server or WMS) or tiled (ArcGIS Server) representation of a map
accessible through a service endpoint.
Shapefile layer
A graphic representation of the vector geometry (point, polyline or polygon) and textual
representation of the associated attributes from an Esri-compatible shapefile on disk.
Each layer has properties that are dependent on its type. By making changes to the properties, you
can:
Improve layer visibility through show and hide operations and transparency adjustments
Display attributes as map tips that display when hovering the mouse over displayed features

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Change display properties such as color

Change label properties such as visibility, color, position, and font
The last or top-most layer in the GIS map is the network layer which is composed of network
components and connections between these components.

Note: The basemap layer cannot be deleted, but can be turned off if not needed, for example, due
to the presence of other layers that provide geographic context.

Related links:
GIS Shapefile Basics (p.262)
Using Shapefiles (p.263)
Using Map Services (p.264)
Using a Map Cache (p.268)
Changing the Display Options (p.269)

6.4.1 GIS Shapefile Basics

A shapefile is a file based vector data format that facilitates exchange of geospatial information
with other Geographic Information System (GIS) systems. Each row within a shapefile represents a
single feature or logical entity and consists of the geometric description of this entity and
associated attribute information. Geometries are defined as points, polylines (composed of paths)
or polygons (composed of rings) and can represent a variety of features such as wells, flowlines,
lease blocks and political boundaries. Attributes can be numeric (integer or floating point), textual
or in date/time format.
In order for a shapefile to be loaded successfully, four necessary component files having the same
filename must be present within the same folder, differentiated by file extension and contents:
The main shapefile (*.shp) containing geometric definitions of features
The shape index file (.shx) used for efficient loading of geometric features within the main
shapefile
The attribute file (.dbf) containing a dBase table of attributes related to geometric features
within the main shapefile
The projection file (.prj) containing a well-known text (WKT) string defining the coordinate
reference system in which the geometric features within the main shapefile have been persisted
Shapefiles can be created programmatically or using any standard desktop GIS software such as
ArcGIS for Desktop or QGIS.
References
Wikipedia
Esri Shapefile Technical Description

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GIS Shapefile Feature Types

In PIPESIM*, three types of features or shapes are supported within shapefiles:
Point: A geographic point consisting of a single (X, Y) coordinate pair.
Polyline: One or more paths, each containing an ordered set of two or more geographic points
defined by (X, Y) coordinate pairs.
Polygon: One or more rings, each containing an ordered set of three or more geographic
points that form a closed geometry and are defined by (X, Y) coordinate pairs.

Note:
In contrast to basemaps, map caches and map service layers, all shapefiles in PIPESIM must
have a coordinate reference system of World Geodetic System 1984 (WGS84) (EPSG:4326).
Only Point, Polyline and Polygon shapefiles are supported for visualization: Multipoint and
Multipatch shapefiles are not supported.
Only Polyline shapefiles are supported for automatic network creation: networks cannot be
automatically created from Point, Polygon, Multipoint or Multipatch shapefiles.
Shapefiles having measurement or height attributes (M-Aware or Z-Aware) can be read by
PIPESIM, but only (X, Y) coordinates are preserved: M and Z coordinates are discarded and
ignored for the purposes of visualization and are not used as a substitute for elevation values
obtained via the elevation capture operation.

Related links:
Using Shapefiles (p.263)
Capturing Elevations (p.276)

6.4.2 Using Shapefiles

See GIS Shapefile Basics (p.262) for an introduction to the shapefile format.
1. On the Home tab, in the Viewers and results group, click GIS map.
2. To add a shapefile to the GIS map as a graphic layer, perform the following actions:
a. On the Format tab, in the Layers group, click Layers, and then click Shapefile.
b. Select a shapefile (.shp), and then click Open. You can also drag the file directly onto the
map from Windows Explorer.
3. After you add a shapefile to the map, you can select display options and adjust the
transparency by performing the following actions:
a. To select a layer for editing, perform one of the following actions:
On the Format tab, in the Layers group, click Layers, right-click a shapefile name, and
click Edit.
Right-click the map background, and then click Edit.
b. To change the layers displayed on the map, select or clear the layer check boxes.

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c. To change the transparency of a layer, perform the following actions:

1. On the left pane of the layer editor, select the layer.
2. On the right, move the Transparency slider to the left to make the layer more opaque, or
to the right to make it more transparent.
d. To change the color of a layer, select a new Color and Outline color if applicable.

Related links:
Working with Layers (p.261)
GIS Shapefile Basics (p.262)

6.4.3 Using Map Services

PIPESIM* provides users the ability to add custom map services to the list of services provided in
the basemap gallery. ArcGIS Server tiled and dynamic map services and Web Map Service (WMS)
dynamic map services are supported.
To configure custom map services for use in PIPESIM and display them on the GIS map:
1. To enable display of map services within the map view and configure a map service, perform
the following actions:
a. Click Workspace Options GIS map Map service layers.
b. Click New and enter the specifications for the map service.
To add an ArcGIS Server tiled or dynamic map service, provide the name and URL.
To add a Web Map Service (WMS) dynamic map service, provide the name, URL,
coordinate reference system (CRS), layer name(s), version and image format (.png
or .jpeg).
Additional custom map services can be created, cloned, edited, or deleted before switching to the
GIS map view.

Note: If the custom ArcGIS Server map service provided is publicly accessible or has been
secured using Windows Authentication, a username and password should not be provided using
the corresponding map services properties fields. However, if the service has been secured using
HTTP or token-based authentication, a username and password must be provided using the
corresponding map service properties fields.

2. To activate a map service for display within the GIS map of the currently active workspace,
perform the following actions:
a. On the Home tab, in the Viewers and results group, click GIS map.
b. On the Format tab, in the Layers group, click Layers, and then click Map service.
c. Click the map service of interest, and then click OK.
The map view resizes automatically to the extent of the selected map service layer.

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Related links:
Network Prerequisites (p.265)
Obtaining WMS Parameters (p.266)

Network Prerequisites
In order to successfully connect to and leverage web services in the GIS map, you must configure
Internet Explorer, proxy server, and firewall settings on the network where PIPESIM* will be
executed.

Internet Explorer Settings

On the Internet Explorer Local Area Network (LAN) Settings dialog box (accessed
from Internet Explorer Settings Internet Options Connections LAN settings), set the
following Automatic configuration options:
Select the Automatically detect settings check box
Clear the Use automatic configuration script check box
Purpose: Allows the proxy server on your company intranet to see the credentials of the currently
logged in Windows user and to grant or deny permission to access the following network resources
from within PIPESIM:
ArcGIS Server or Web Map Service (WMS) servers on the company intranet
ArcGIS Server, Web Map Service (WMS), Bing Maps or Geonames servers on the external
Internet

Proxy Server Settings

The following domain names must be unblocked / opened for access:
http://services.arcgisonline.com
Purpose: Used for ArcGIS Server tiled and dynamic map services, including the default
basemaps in the GIS map gallery
http://dev.virtualearth.net
Purpose: Used for Bing Maps tiled map services and geocoding services, enabled when a valid
Bing key has been provided
https://secure.geonames.net
Purpose: Used for Geonames elevation capture services

Firewall Settings
The following IP addresses must be unblocked / opened for access:

176.9.107.169 176.9.39.79 178.63.52.141 178.63.92.242 188.40.33.19

188.40.55.18 188.40.62.8 199.189.87.43 199.189.87.89 199.217.116.173
199.217.119.198 209.126.105.58 5.9.152.54 5.9.41.208 69.64.43.233
69.64.51.148 78.46.40.212 88.198.40.75 88.198.66.142

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Purpose: Used for load balancing of requests made to Geonames elevation capture services

Note: In PIPESIM 2013, the Geonames domain name used for elevation capture was http://
ws.geonames.net, whereas in PIPESIM 2014, this has been upgraded to the secure https://
secure.geonames.net. Proxy servers may need to be updated to reflect this change. Furthermore,
the list of IP addresses used by Geonames for elevation capture has been updated to include the
following additional address in PIPESIM 2014: 209.126.105.58. Firewalls may need to be updated
to reflect this change.

Related links:
Using Map Services (p.264)

Obtaining WMS Parameters

In order to successfully connect to a custom Web Map Service (WMS), you will need to know the
name, URL, coordinate reference system (CRS), layer names, version, and image format (.png
or .jpg). If these parameters are not readily available, they can be obtained by making a Get
Capabilities request to the WMS service.

Example WMS Map Service URL

http://mrdata.usgs.gov/services/ca

1. Assuming that the above URL points to the WMS service of interest, append the following tags
to the URL:

?request=getcapabilities&service=WMS

to produce the following Get Capabilities request URL:

http://mrdata.usgs.gov/services/ca?request=getcapabilities&service=WMS

2. Copy this URL into your browser and press ENTER.

Either an XML file will appear within the browser or a file will be downloaded to disk. If a file is
downloaded to disk, open it with a text editor.
3. Search the file for a section that shows a version number appearing as 1.0.0, 1.1.0, 1.1.1, or
1.3.0.
In this example, the version appears as 1.1.1 in the following tag:

<WMT_MS_Capabilities version="1.1.1">

Enter this value as the Version.

4. Search the file for a <GetMap> section under which several <Format> tags may appear.
In this example, these tags appear as the following:

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<Format>image/png</Format>
<Format>image/jpeg</Format>
<Format>image/gif</Format>
<Format>image/png; mode=8bit</Format>
<Format>application/x-pdf</Format>
<Format>image/svg+xml</Format>
<Format>image/tiff</Format>
<Format>application/vnd.google-earth.kml+xml</Format>
<Format>application/vnd.google-earth.kmz</Format>

If only a .png or .jpg format tag appears, enter that value as the Format.
In this example, because both the .png or .jpg format tags appear, you can choose either
value.

Note: In cases where the map service represents a basemap spanning the full extent of the
world, .jpg will usually be the preferred choice as it produces smaller, highly compressed images
that transmit faster than the equivalent .png requests. In cases where the map service represents
features of interest that are to be overlaid on an existing basemap or displayed using
transparency, .png would be the preferred choice, as .jpg images do not support these
features.

5. Search the file for the first <Layer> tag. This layer is the main layer, under which sub-layers
may be defined. Under this <Layer> tag is a <Name> tag.
In this example, the name appears as:

California_Geology

Enter this value as the Layers and all the sub-layers will be added automatically.
Alternatively, you can add only the sub-layers of interest by entering them as comma-separated
values. If you are entering comma-separated values, ensure no spaces exist between the
names or the layers may not be accepted.
In this example, you could enter California_Lithology,California_Faults to display
only these two sublayers.
6. Search in the same <Layer> tag for <SRS> tags.
In this example, these tags appear as:

<SRS>EPSG:4267</SRS>
<SRS>EPSG:4269</SRS>
<SRS>EPSG:4326</SRS>
<SRS>EPSG:3857</SRS>
<SRS>EPSG:900913</SRS>
<SRS>EPSG:102113</SRS>

If a SRS entry for 3857 or 102100 can be found, set the CRS parameter to this value. If a SRS
entry for 3857 or 102100 cannot be found, then PIPESIM cannot support this map service, as
PIPESIM can only display Web Mercator (EPSG: 3857 or ESRI:102100) map services.

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7. After providing a name for the service, such as "My Map Service", the resulting parameters for
this example service would be:

Field Value
Type WMS
Name My Map Service
Url http://mrdata.usgs.gov/services/ca
CRS 3857
Layers California_Geology
Version 1.1.1
Format png
8. Click OK to add the service to the list of available map services.

Related links:
Using Map Services (p.264)

6.4.4 Using a Map Cache

A cached representation of a subset of the Esri World Satellite imagery basemap can be created
on disk to enable use of the GIS map in situations where network connectivity is slow, unreliable or
unavailable altogether (offline).
1. On the Format tab, in the Layers group, click Basemaps, and then click ESRI World Satellite
Map.
2. On the GIS map, use the navigation controls to zoom to the desired cache extent.

Note: Only the tiles visible in the current map extent are cached; any tiles falling outside of the
visible extent are not saved to disk.

3. On the Format tab, in the Utilities group, click Download map cache.

Note: If the current map extent exceeds the maximum allowable cache area, a prompt will appear
to zoom to the maximum allowable cache area. Once zoomed to this area, click Download map
cache to create a map cache.

If your map extent fits within the allowable cache area, a meter at the bottom of the window shows
the progression of the cache download request and allows cancellation if needed. The progress is
dependent on the extent of the cache area requested and connection speed.
4. Once prompted that the cache has downloaded successfully, click Yes to save the map cache.
Saving the map cache will have the effect of:
Adding the map cache layer on top of the existing basemap and enabling it for display

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Writing the map cache (a MapFoundationConfiguration.xml file along with

associated imagery tiles) to disk in the user's temp folder. The path is %Temp%/
MapCache/Cach_cache_id
When zooming to the full extent of the map, a globe icon will appear representing the
cached area. Zoom to the area by clicking this icon.

Note: Only one map cache may be present within a PIPESIM workspace at any given time: any
subsequent download map cache requests will have the effect of replacing previously cached data.
The maximum allowable cache area is 100 square miles (approximately 256 square kilometers)
and maximum duration at which a cache may be kept is 90 days: once a cache has expired, it
must be re-created using a live network connection. When working offline, shapefile layers will
remain visible alongside cached imagery provided the shapefile still exists on disk in the location
where it was first referenced. However, basemaps from Esri, Bing Maps or custom map services
will not be visible as these require a live network connection.

Related links:
Working with Layers (p.261)

6.4.5 Changing the Display Options

You can change the appearance of layers by changing the settings for map tips. You can also
change the appearance of the labels on the GIS map by changing properties such as label
visibility, color, position, and font. The basemap layer does not have display properties you can
change.

Note: If you are displaying well clusters, you cannot show map tips.

1. On the Home tab, in the Viewers group, click Map.

2. To enable map tips:
a. On the Format tab, in the Layers group, click Basemaps, and then click the layer for which
you want to add map tip information.
b. Double-click the map to open the Edit layer window.
c. On the right pane, under Layer, select the Map Tip check box.
d. Click Close to save your selection and close the window.
e. To view a map tip, place the pointer over an object in the network.
The map tip is displayed.
3. To hide the map tips from layers you added:
a. Double-click the map to open the Edit layer window.
b. Clear the Map Tip check box, and then click Close.
4. To change the transparency of the layer:

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a. Double-click the map to open the Edit layer window.

b. Move the Transparency slider to the preferred setting.
You can view the change in the layer as you move the slider.
5. To change the label display properties:
a. Double-click the map to open the Edit layer window.
b. In the left pane, select the layer with display properties you want to change.
The properties you select display immediately on the GIS window.
c. The following display properties for labels are displayed on the right pane, under Label.
Make selections for the map:

Label Description
Label Select or clear this check box to show or hide the label.
Color Make new selections in these fields to change the font attributes for the label. A halo is
Fields a white glow behind the label text.

Font
Style
Size
Halo
Position Make new selections in these fields to change the position of the label relative the area
Offset associated with it.

d. Click Close to save your selections.

Related links:
Working with Layers (p.261)

6.5 Using the GIS Map

For models built and edited on the GIS map canvas, the same objects will appear on the schematic
canvas. Newly-inserted objects on either canvas will be placed at roughly the same relative
location on the other canvas. While moving objects on the GIS canvas define locations and,
therefore, pipe geometries, you may arrange objects anyway you want on the schematic canvas
without impacting the flowline profiles.

Related links:
Creating a New Network Model on the GIS Map Manually (p.271)
Locating a Previously Built Schematic Network on the GIS Map (p.271)
Moving the Entire Network to a New Map Location (p.272)
Displaying Object Clusters (p.272)

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Capturing Elevations (p.276)

ASTER and SRTM Elevation Data Sources (p.22)
Changing the PIPESIM Data Source for GIS Elevation Data Capture (p.22)
Viewing Profile Direction (p.276)
Editing Equipment Locations (p.277)
Creating a Network Model from a GIS Shapefile Automatically (p.23)
Using Additional Functions within the GIS Map (p.279)

6.5.1 Creating a New Network Model on the GIS Map Manually

You can construct PIPESIM* models directly on the GIS map canvas. Building a network model on
the GIS map canvas is very similar to building a network on the schematic canvas with the
exception that flowlines can be digitized with multiple points.
1. Open a model in network mode, and on the Home tab, in the Viewers group, click Map and
then zoom to the desired network extent.
2. On the Insert tab, click the objects you want to create and click the map canvas to insert them.
To insert multiple objects hold the SHIFT key down while clicking the map.
3. To begin digitizing a flowline, on the Home tab, in the Connections group, click Flowline and
then click on a starting node object (boundary or internal node) to define the start point of the
flowline.
4. To digitize the flowline, click the points on the flowpath.
5. To end the flowline, click on a second node object
6. You can refine the digitized points by inserting or removing additional nodes.

Related links:
Using the GIS Map (p.270)

6.5.2 Locating a Previously Built Schematic Network on the GIS Map

You can assign a physical location to a model that was originally built on the schematic diagram or
imported from earlier versions of PIPESIM or PIPEFLO.
1. Open a model in network mode, and on the Home tab, in the Viewers group, and click Map.
The Zoom to a network extent window is displayed. Do not click OK yet.
2. On the Format tab, click one of the options in the Zoom group to select an appropriate map
area for your model. The options you have include the following choices:
Click Go to location and enter map coordinates or a physical address.
Use one of the zoom functions in the Zoom group.
Select a Bookmark.
Use the directional guide in the lower-left corner to zoom into an area.
In the Show/hide group, click Overview to reposition the center of your map.

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3. In the Utilities group, click Relocate network.

The model is relocated to the map area that you set up.

Related links:
Using the GIS Map (p.270)

6.5.3 Moving the Entire Network to a New Map Location

Follow these steps to change the physical location of a model.
1. On the Home tab, in the Viewers group, click Map.
2. On the Format tab, click one of the options in the Zoom group to select a new map area for
your model. The options you have include the following choices:
Click Go to location and enter map coordinates or a physical address.
Use one of the zoom functions in the Zoom group.
Select a Bookmark.
Use the directional guide in the lower-left corner to zoom into an area.
In the Show/hide group, click Overview to reposition the center of your map.
3. In the Utilities group, click Relocate network.
The model is relocated to the map area that you set up.

Related links:
Using the GIS Map (p.270)

6.5.4 Displaying Object Clusters

The only way to view the exact physical location of objects that are linked by connectors is to view
the network diagram in cluster mode.
Surface equipment may be connected using either connectors or flowlines. Connectors convey
fluid between objects but do not represent any physical distance and no hydraulic calculations are
performed. Connectors are commonly used to connect chokes to wellheads and for surface
equipment in close proximity such as separators, pumps, compressors and heat exchangers.
While flowlines can also be used across short distances, you might find that the icons for a group
of objects positioned closely together may appear cluttered when zoomed out and might make it
difficult to view result annotations.
The only way to view the exact physical location of objects that are linked by connectors is to view
the network diagram in cluster mode. In cluster mode, one of the objects in the group is
automatically designated as the anchor object which can be identified by the location of the cluster
when the cluster mode is toggled. The anchor object for wells connected to chokes will always be
the well, but the anchor object for other facilities may vary.
The true geographic location of flowlines entering and leaving clusters can only be visualized in
cluster mode. Additionally, elevation points can only be viewed in cluster mode.

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1. On the Home tab, in the Viewers group, click Map.

2. On the Format tab, in the Show/hide group, select Cluster.
The clusters are shown as a circle, and the number of objects within a cluster is shown in the
circle.
3. To turn off cluster mode, clear the Cluster check box.
To illustrate the usage of clusters, consider the field processing facility shown below consisting of a
separator connected to a pump, compressor and heat exchanger. The equipment may be
positioned and visualized easily in non-cluster mode (6.1 (p.273)); however, only the true map
locations of the objects can be seen in cluster mode (6.2 (p.274)). In this example, the pump
serves as the anchor object for the cluster.

Figure 6.1. Processing Facility in Non-cluster Mode

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Figure 6.2. Processing Facility in Cluster Mode

Related links:
Using the GIS Map (p.270)

6.5.5 ASTER and SRTM Elevation Data Sources

There are two (2) sources available for elevation data capture in PIPESIM. They are:
Shuttle Radar Topography Mission (SRTM)
Advanced Spaceborne Thermal Emission and Relection Radiometer (ASTER)
services. The elevation data for both sources is hosted by Geonames, http://www.geonames.org.
The following table covers the details about each source.

Advanced Spaceborne Thermal Shuttle Radar Topography Mission (SRTM)

Emission and Reflection
Radiometer (ASTER)
Source Ministry of Economy, Trade, and United States National Geospatial Intelligence
Industry (METI) of Japan and the Agency (NGA) and United States National
Unitd States National Aeronautics Aeronautics and Space Administration
and Space Administration (NASA) (NASA)

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Advanced Spaceborne Thermal Shuttle Radar Topography Mission (SRTM)

Emission and Reflection
Radiometer (ASTER)
Date June 2009 February 2000
Version V1 V4.1
Resolution 30 meters (1 arcsecond) 90 meters (3 arcseconds)
Coverage 83 degrees N to 60 degrees N to
83 degrees S latitude 56 degrees S latitude
URL http://asterweb.jpl.nasa.gov/ http://www2.jpl.nasa.gov/srtm/
gdem.asp
Notes The data has been processed by CGIAR to
contain SRTM data where available and
GTOPO30 elsewhere (for example, in areas
over water bodies, mountainous regions and
desert regions where small holes were
present in the original data provided by
NASA). For more info, visit this link.

Related links:
Using the GIS Map (p.270)

6.5.6 Changing the PIPESIM Data Source for GIS Elevation Data Capture
There are two (2) ways to change the elevation data source.
OPTION 1
1. From the Home tab, click GIS map to open the map canvas.
2. Go to the Format tab. In the Elevation group, from the Data source, select either SRTM or
ASTER from the dropdown menu
3. Create or import the network.
4. Capture the elevations by following the steps in Capturing elevations (p.276).
OPTION 2
1. Go to the Workspace tab and select Options, then GIS map.
2. For the Default elevation source, select either SRTM or ASTER from the option list.
3. Return to the Home tab, click GIS map to open the map canvas.
4. Create or import the network.
5. Capture the elevations by following the steps in Capturing elevations (p.276).

Related links:
Using the GIS Map (p.270)

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6.5.7 Capturing Elevations

When you draw a flowline on the GIS map canvas, you implicitly define the x-y (lat-long) locations
for the flowline. To obtain elevation profiles, you can easily capture elevation data to define
detailed flowline profiles quickly.
There are two (2) sources available for elevation data capture in PIPESIM: SRTM and ASTER
services. For more information about these services, see ASTER and SRTM Elevation Data
Sources. (p.22)

Note: To access the elevation data service, you need an Internet connection.

If the labels for objects in your well or network display object names, you must first change a
setting in the map layer. Double-click the map to open the Edit layer window, and then in the
Label section change the Fields selection from Names to Elevation.
1. On the Home tab, in the Viewers group, click Map.
2. On the Format tab, in the Elevation group, enter the desired distance for interval and the
maximum number of points.
If you are in cluster mode, red points along the flowlines will indicate the sampling interval.
If the number of maximum points times the interval is less than the total distance, the allotted
number of elevation points will be spaced equidistant from the two end points of the connection.
3. Click Capture Elevation.
The elevation point intervals will change from red to green to indicate elevation data has been
successfully captured. If you move an object attached to a flowline, the points on that object will
turn red to indicate that the elevation data for that flowline is no longer valid and the elevation
needs to be recaptured.
4. To view the captured elevation profiles, double-click a flowline from the network diagram or the
Inputs pane.

Related links:
GIS Shapefile Basics (p.262)
Using the GIS Map (p.270)

6.5.8 Viewing Profile Direction

Show arrows on the model to indicate the profile direction for flowlines and risers in the displayed
map area that specify the start and end points and order of the profile data.
1. On the Home tab, in the Viewers group, click Map.
Because the GIS map will capture elevation at the true physical locations, this setting is more
relevant in the schematic view where it is used to ensure that the start and end point references
are correct relative to the order of the data entered in the table.
2. On the Format tab, in the Show/hide group, select Profile direction.

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3. To hide the arrows, clear the Profile direction check box.

Related links:
Using the GIS Map (p.270)

6.5.9 Editing Equipment Locations

You can view and edit the latitudinal and longitudinal coordinates for each node object in your
model, including the elevation if this attribute has been captured.
1. On the Home tab, in the Viewers group, click Map.
2. On the Format tab, in the Utilities group, click Equipment locations.
The Equipment locations window displays the x-y (lat-long) locations for equipment in the
displayed map area.
3. Click Close.
The Equipment locations table is also very convenient for initially defining equipment
locationsif coordinates are availableand for renaming objects.

Related links:
Using the GIS Map (p.270)

6.5.10 Creating a Network Model from a GIS Shapefile Automatically

Note:
PIPESIM currently only supports shapefiles with coordinates referenced to EPSG:4326, known
as the World Geodetic System (WGS) 1984 or WGS84. Shapefiles with coordinates referenced
to other coordinate reference systems must be de-projected to EPSG:4326 coordinates using
standard desktop GIS software such as ArcGIS for Desktop or QGIS, before importing them
into PIPESIM to create networks.
PIPESIM currently only supports the automatic creation of flowlines from polyline shapefile
features. Wells and other equipment cannot yet be automatically created from point and
polygon shapefile features. However, PIPESIM will automatically add junctions between
flowlines when the network is created and provides the ability to convert these junctions to
wells, sources, sinks and other equipment. Refer to the topic Converting Junctions to Wells,
Sources, Sinks and Equipment (p.124) for additional details.
PIPESIM supports the creation of networks from a shapefiles only in new workspaces (for
example, it does not support incremental network creation). You will get an error message if
you attempt to import a network into a workspace that already has any kind of equipment.

1. Go to the Home tab, in the Viewers and results group, select GIS map.
2. From the active Insert tab, click Import network and browse to the location of the shape files.
3. Select the main shape file with the *.shp extension and click Open.

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The *.dbf and *.prj files must also be present in the same location. For more information,
refer to GIS Shapefile Basics (p.262).
The Import network dialog box opens where you can map the attributes in the shape file (if
available) to the PIPESIM properties required for simulation. They are the Flowline name, Pipe
Inside Diameter, Pipe wall thickness and Pipe roughness. The Import dialog box also enables
you to define other global environmental and flowline settings for the entire network that will be
imported. This is to speed up the facilitate network creation and process.
4. In the Shapefile property column, Map the available flowline name attribute in the shapefile to
the PIPESIM flowline name by selecting it from the Options list. If there is no Flowline name
attribute in the shapefile, leave the default [Create New] option. PIPESIM will automatically
create new names for each imported flowline.
The attribute options available in the options list for each Shapefile property are type-specific
(for example, Flowline name) will display only the text attributes in the shapefile, while Pipe ID,
wall thickness and roughness will display only numeric attributes.
5. Map the Shapefile property attributes for Pipe Inside Diameter, Pipe wall thickness, and Pipe
roughness, if available. If any one or all of these properties are unavailable in the shapefile,
check the Override box and manually enter these values. The manual values will be assigned
to every flowline created from the shapefile.
6. The Air temperature, Wind speed, Soil type and Soil conductivity values in the Global
environment settings are the default values under Home in the Data group, select Simulations
settings and click the Environmental tab in the workspace itself. You may leave the default
values or change them by checking the Update global environment settings and entering your
preferred values. All flowlines created will be assigned these values and the global
environmental settings under Simulation settings will also be updated with these values.
7. The Flowline settings section also displays the default values. You may modify the heat
transfer properties for the flowlines, if desired.
The recommendation is to limit the use of the feature to automatically create networks from
shapefiles, to onshore environments only, because risers cannot currently be created from
shapefile features.
8. Click OK to complete the import network process. The created network appears on the GIS
map layer. PIPESIM will create a flowline for every polyline feature and automatically insert
junctions between consecutive polylines, where they share an endpoint.
9. Capture the elevation profiles for the imported network by using the steps from Capturing
Elevation (p.276). Alternatively, you can manually enter the elevation profiles for each flowline
in the Logical view of the Flowline editor by unchecking the Populate from GIS map box.
10.Complete the network creation process by manually converting individual junctions to wells,
sources, sinks and other equipment. For more information, see Converting Junctions to Wells,
Sources, Sinks and Equipment (p.124).

Related links:
Creating or Editing a Network Model (p.96)
Using the GIS Map (p.270)

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6.5.11 Using Additional Functions within the GIS Map

Several additional functions are available within the GIS map.

Related links:
Showing the Map Legend (p.279)
Measuring Distance and Area (p.279)
Printing the Map (p.280)

Showing the Map Legend

On the GIS map, the legend displays for the area you are viewing.
1. On the Home tab, in the Viewers and results group, click GIS map.
2. On the Format tab, in the Show/hide group, select Legend.
The legend displays layers, network components and associated symbols for the currently
displayed map. When in cluster mode, an associated cluster symbol appears.
3. To hide the legend, clear the Legend check box.

Related links:
Using Additional Functions within the GIS Map (p.279)

Measuring Distance and Area

You can measure distance and area on any basemap within the GIS map. The measure area tool,
for example, may be useful in quickly estimating the drainage area of a well for entry into the Darcy
IPR model.
1. On the Home tab, in the Viewers and results group, click GIS map.
2. To measure the distance between geographic points on the GIS map:
a. On the Format tab, in the Utilities group, click Measure line.
b. Click on the basemap to begin measuring, and click one or more times if needed to add
points of inflection to the line measured.
c. To complete the line measurement, double click on the basemap.
The distance measured by your line displays in the status bar in the lower-left corner of the
application.
3. To measure an area:
a. On the Format tab, in the Utilities group, click Measure area.
b. Click on the basemap to begin measuring, and click one or more times if needed to add
points of inflection to the area measured.
c. To complete the area measurement, double click on the basemap.
The area measured by your shape displays in the status bar in the lower-left corner of the
application.

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4. To remove the line or shape from the GIS map, on the Format tab, in the Utilities group, click
Clear Graphics.

Note: Distance measurements are performed in geographic space using Vincenty's formula which
honors the World Geodetic System 1984 (WGS84) ellipsoid underlying the Web Mercator
basemap and avoids the distortion that can occur when such measurements are performed in
projected space. This means that the distance measured is actually the shortest path on the
WGS84 ellipsoid between the points of inflection digitized (curved lines on a flat map) rather than
the loxodrome or rhumb line connections between these points of inflection (straight lines on a flat
map) which would appear to be measured based on the straight lines drawn on the map. Area
measurements, however, are not performed in geographic space, but rather performed in projected
space and then applied a correction factor to account for the projection error. One must ensure that
polygons digitized on the map for area calculation are simple (non-self-intersecting), otherwise
errors may result.

Related links:
Using Additional Functions within the GIS Map (p.279)

Printing the Map

You can print the displayed map area.
1. On the Home tab, in the Viewers and results group, click GIS map, and then use the
navigation controls to zoom to the desired print extent.
2. To print the currently visible extent, perform one of the following actions:
On the Format tab, in the Utilities group, click Print.
Right-click the map, and then click Print.
3. Select print options, and then click Print.
The currently visible map extent is printed.

Related links:
Using Additional Functions within the GIS Map (p.279)

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7
Technical Description
This section of the User Guide provides additional details and references on the theory and
methods implemented in PIPESIM.
Flow Models (p.281)
Completion (IPR) Models (p.308)
Equipment (p.354)
Heat Transfer Models (p.399)
Fluids Models (p.417)

7.1 Flow Models

7.1.1 Flow Regimes
Flow Regimes Classification for Vertical Two Phase Flow
The general problem of predicting the pressure drop for the simultaneous flow of gas and liquid is
complex.
The problem consists of being able to predict the variation of pressure with distance along the
length of the flow path for known conditions of flow. Multiphase vertical flow can be categorized
into four different flow patterns or flow regimes, consisting of bubble flow, slug flow, slug-mist
transition (churn) flow and mist flow.
A typical example of bubble flow is the liberation of solution gas from an undersaturated oil at and
above the point in the flow path where its bubble point pressure is reached.
In slug flow, both the gas and liquid phases significantly contribute to the pressure gradient. the
gas phase exists as large bubbles almost filling the pipe and separated by slugs of liquid. In
transition flow, the liquid slugs between the gas bubbles essentially disappear, and at some point
the liquid phases becomes discontinuous and the phase becomes continuous.
The pressure losses in transition (churn) flow are partly a result of the liquid phase, but are more
the result of the gas phase. Mist flow is characterized by a continuous gas phase with liquid

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occurring as entrained droplets in the gas stream and as a liquid film wetting the pipe walls. A
typical example of mist flow is the flow of gas and condensate in a gas condensate well.
PIPESIM Vertical Flow correlations

Bubble Slug Churn Annular/Mist

Flow Regimes Classification for Horizontal Two Phase Flow

Prediction of liquid holdup is less critical for pressure loss calculations in horizontal flow than for
inclined or vertical flow, although several correlations will require a holdup value for calculating the
density terms used in the friction and acceleration pressure drop components. The acceleration
pressure drop is usually minor and is often ignored in design calculations; however, PIPESIM
includes them.
As in the vertical flow, the two-phase horizontal flow can be divided into the following flow regimes:
Stratified Flow (smooth, wavy), Intermittent Flow (plug and slug) and Distributed Flow (bubble and
mist).
PIPESIM Horizontal Flow correlations

Stratified Flow Smooth

Wavy

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Intermittent Slug
Flow

Elongated bubble/
Plug

Distributed Annular/Mist and

Bubble

Dispersed Bubble

See also: Flow regimes (p.281),

7.1.2 Horizontal Multiphase Flow Correlations

The following horizontal multiphase flow correlations are available:

Baker Jardine (BJA) Correlation

Baker Jardine (p.499) (now Schlumberger) has developed a correlation for two phase flow in gas-
condensate pipelines. This model represents no major advance in theory, but rather a
consolidation of various existing mechanistic models, combined with a modest amount of
theoretical development and field data testing. The model uses the Taitel Dukler flow regime map
and a modified set of the Taitel Dukler momentum balance to predict liquid holdup. The pressure
loss calculation procedure is similar in approach to that proposed by Oliemans, but accounts for
the increased interfacial shear resulting from the liquid surface roughness. The BJA correlation is
used for pressure loss and holdup with flow regime determined by the Taitel Dukler correlation.
The BJA correlation has been developed specifically for applications involving low liquid/gas ratios,
for example gas/condensate pipelines with a no-slip liquid volume fraction of lower than 0.1.

Beggs and Brill Original

ORIGINAL: The original Beggs and Brill (p.500) correlation is used for pressure loss and liquid
holdup. Flow regime is determined by either the Beggs and Brill or Taitel Dukler correlation. The
Beggs and Brill correlation was developed following a study of two-phase flow in horizontal and
inclined pipes. The correlation is based upon a flow regime map which is first determined as if the
flow was horizontal. A horizontal holdup is then calculated by correlations, and this holdup is
corrected for the angle of inclination. The test system included two 90 ft long acrylic pipes, winched
to a variable elevation in the middle, so as to model incline flow both upwards and downwards at
angles of up to 90.

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Beggs and Brill Revised

REVISED: As above except that the revised version of the Beggs and Brill correlation is used, with
rough pipe friction factors, holdup limits and corrective constants as proposed by Palmer (p.507)
and Payne (p.507). The following enhancements to the original method are used; (1) an extra flow
regime of froth flow is considered which assumes a no-slip holdup, (2) the friction factor is changed
from the standard smooth pipe model, to utilize a single phase friction factor based on the average
fluid velocity.

Dukler (AGA) and Flanigan

1. The AGA and Flanigan correlation was developed for horizontal and inclined two phase flow of
gas-condensate gathering systems. The Taitel Dukler flow regime map is used which considers
five flow regimes, stratified smooth, stratified wavy, intermittent, annular dispersed liquid, and
dispersed bubble. The Dukler (p.502) equation is used to calculate the frictional pressure loss
and holdup, and the Flanigan (p.502) equation is used to calculate the elevational pressure
differential.
2. As above but with liquid holdup calculated according to the Eaton (p.502) correlation. The
Eaton liquid holdup correlation is based on a study performed on 2 in. and 4 in. steel pipe using
water and natural gas as test fluids. Test pressures ranged from 305 to 865 psia and liquid
holdup measurements ranged from .006 - 0.732.

Eaton-Oliemans
The Eaton, Oliemans combination of methods uses the correlation developed by Eaton et al (1967)
to predict liquid holdup and the Oliemans Pressure Drop Calculations correlation (1976) to predict
frictional pressure losses. This set of correlations has been found to be reliable for gas-condensate
systems in which the liquid loading varies from very small amounts to levels high above that which
is normally found in gas gathering systems. Additionally, while the Eaton method tends to over-
predict liquid holdup, the results for crude oil systems are generally reasonable. Note that since the
Eaton et al correlation does not incorporate elevation change in its computation of liquid holdup,
hydrostatic pressure losses can be significantly underestimated in cases of low flow rates over hilly
terrain.
The Oliemans correlation was developed following the study of large diameter condensate
pipelines. The flow regime is predicted using the Taitel Dukler flow regime map, and a simple
model, which obeyed the correct single phase flow limits was introduced to predict the pressure
drop. The model was based on a limited amount of data from a 30-in, 100-km pipeline operating at
pressures of 100 barg or higher. The Oliemans pressure loss correlation can be used with the
Eaton, BJA1, BJA2, BRIMIN1 or BRIMIN2 holdup correlations.

Hughmark-Dukler
The Hughmark (1962) (p.504) / Dukler et al (1964) (p.502) method is the procedure that was
recommended by the AGA /API (1970). This approach uses the Dukler model for pressure loss
calculations and the Hughmark model for liquid holdup calculations.
The use of the Hughmark (1962) liquid volume fraction correlation for pipelines is somewhat
anomalous since it was originally based solely on data for flow in vertical pipes. Hughmark did
however, compare its predictions with some limited data from horizontal pipes and found the
agreement to be reasonable. Since then, a number of studies (Dukler et al, 1964; Mandhane et al,

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1975; Gregory, 1975; Gregory and Fogarasi, 1985) have confirmed it to be one of the better
correlations for pipeline applications.
It can generally be expected to give reasonable pressure drop and liquid holdup results for gas-
crude oil pipelines. This procedure is not recommended however for gas-condensate systems,
where the Hughmark correlation generally predicts excessive liquid holdups; errors of up to 600%
have been observed.

LEDA
The Leda Point Model (PM) (http://www.kongsberg.com/ledaflow) is a mechanistic model
applicable for all inclination angles, pipe diameters and fluid properties. The 2-phase model
considers gas-liquid flow whereas the 3-phase model considers gas-oil-water flow.
The 3-phase Leda PM considers 9 fields in the mass (continuity) equations (oil, gas, water, oil in
gas and water, gas in oil and water, water in oil and gas). Separate momentum equations are
solved for oil, gas and water.
The 2-phase Leda PM considers 4 fields in the mass (continuity) equations (liquid, gas, liquid in
gas and gas in liquid. Separate momentum equations are solved for gas and liquid phases. The
flow regimes predicted by LedaPM are stratified smooth flow, stratified wavy flow, slug flow,
annular and bubbly flow. The Leda 2-phase model uses the liquid viscosity associated with the
fluid model defined in PIPESIM. The Leda 3-phase model assumes that the liquid viscosity is equal
to that of the continuous phase; liquid viscosity options defined with the PIPESIM fluid model are
ignored. The continuous phase is determined by the Brauner-Ullman (p.500) inversion criteria.
The Leda Point Model is the steady-state version of the transient model developed by SINTEF in
collaboration with Total and ConocoPhillips and commercialized by Kongsberg. The model has
been calibrated against data collected at the SINTEF Multiphase Flow Laboratory near Trondheim
Norway. Over 10,000 experimental data points have been collected for single-phase, two-phase
(oil-water, water-gas) and three-phase (oil-water-gas) flow. Pipe diameters ranging from 4-12
were used at pressures up to 90 barg. The models have been validated with field data supplied by
ConocoPhillips and Total.

Minami and Brill

The Minami and Brill correlation calculates liquid holdup though does not predict flow regime or
pressure gradient. The experimental holdup data was obtained by passing spheres through a
1,333 ft long 3 steel horizontal pipe and measuring the liquid volumes removed. Holdup
measurements ranged from .001 to .44. Fluids used in the experiment included air, kerosene and
water with the liquid viscosities ranging from .6 cp to 2 cp.
Two correlations were proposed. The first (BRIMIN1) is valid for all ranges of liquid holdup; the
second (BRIMIN2) is strictly for wet gas pipelines (holdup < .35).
The Minami and Brill (p.506) holdup correlations can be used with any correlation except
Mukherjee and Brill and No Slip. To activate the Minami and Brill correlation, enter the appropriate
engine keyword under Setup Engine Options (for example, hcorr holdup = brimin1)

Mukherjee and Brill

The Mukherjee and Brill (p.506) correlation is used for Pressure loss, Holdup and Flow Map. Note:
selection of alternative flow maps and/or holdups will cause unpredictable results. The Mukherjee

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and Brill correlation was developed following a study of pressure drop behavior in two-phase
inclined flow. The test facility consisted of a U-Shaped pipe that was inclinable +/-90. Each leg of
the U section was 56 ft with 22 ft entrance lengths and a 32 ft test sections on both sides. Fluids
were air, kerosene and lube oil with liquid viscosities ranging from .9 to 75 cp. Approximately 1000
pressure drop measurements and 1500 liquid holdup measurements were obtained from a broad
range of oil and gas flows.
For bubble and slug flow, a no-slip friction factor calculated from the Moody diagram was found
adequate for friction head loss calculations. In downhill stratified flow, the friction pressure gradient
is calculated based on a momentum balance equation for either phase assuming a smooth gas-
liquid interface. For annular-mist flow, a friction factor correlation was presented that is a function
of holdup ratio and no-slip Moody friction factor. Results agreed well with the experimental data
and correlations were further verified with Prudhoe Bay and North Sea data.

NOSLIP Correlation
The NOSLIP correlation assumes homogeneous flow with no slip between the phases. Fluid
properties are taken as the average of the gas and liquid phases and friction factors are calculated
using the single phase MOODY correlation.

OLGAS 2-phase / OLGAS 2000 3-phase

The OLGAS mechanistic models are applicable for all inclination angles, pipe diameters and fluid
properties. The 2-phase Bendiksen (p.500) model considers gas-liquid flow, whereas the 3-phase
model considers gas-oil-water flow.
This model employs separate continuity equations for gas, liquid bulk and liquid droplets, which are
coupled through interphase mass transfer. Two momentum equations are solved: one applied to
the combined balance for the gas and liquid droplets, if present, and a separate momentum
equation for the liquid film. OLGAS considers four flow regimes: stratified, annular, slug and
dispersed bubble flow; and uses a unique minimum slip criteria to predict flow regime transitions.
The OLGA 2-Phase model uses the liquid viscosity model defined within the PIPESIM fluid
property definition. The 3-Phase model uses the Pal and Rhodes emulsion correlation to calculate
liquid viscosity based on the oil and water viscosities defined with the PIPESIM fluid model
definition; liquid viscosity options defined with the PIPESIM fluid model are ignored.
OLGAS is based in large part on data from the SINTEF multiphase flow laboratory near
Trondheim, Norway. The test facilities were designed to operate at conditions that approximated
field conditions. The test loop is 800 m long and 8 inches in diameter. Operating pressures
between 20 and 90 barg were studied. Gas superficial velocities of up to 13 m/s, and liquid
superficial velocities of up to 4 m/ s were obtained. In order to simulate the range of viscosities and
surface tensions experienced in field applications, different hydrocarbon liquids were used (naptha,
diesel, and lube oil). Nitrogen was used as the gas. Pipeline inclination angles between 1 were
studied in addition to flow up or down a hill section ahead of a 50m high vertical riser. Over 10,000
experiments were run on this test loop during an eight year period. The facility was run in both
steady state and transient modes.

Oliemans
The Oliemans correlation was developed following the study of large diameter condensate
pipelines. The flow regime is predicted using the Taitel Dukler flow regime map, and a simple

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model, which obeyed the correct single phase flow limits was introduced to predict the pressure
drop. The model was based on a limited amount of data from a 30-in, 100-km pipeline operating at
pressures of 100 barg or higher. The Oliemans (p.507) pressure loss correlation can be used with
the Eaton, BJA1, BJA2, BRIMIN1 or BRIMIN2 holdup correlations.

TUFFP Unified Mechanistic Model (2-phase and 3-phase)

The TUFFP Unified Mechanistic Model is the collective result of many research projects performed
by the Tulsa University Fluid Flow Projects (TUFFP) research consortium. The model determines
flow pattern transitions, pressure gradient, liquid holdup and slug characteristics. A 2-phase
version is available for gas-liquid flow [Zhang et.al, development (p.510) and validation (p.510)]
and a 3-phase version is available for gas-oil-water pipe flow [Zhang and Sarica (p.510)]. The
model is valid for all inclination angles, pipe diameters and fluid properties.
The principle concept underlying the model is the premise that slug flow shares transition
boundaries with all the other flow patterns. The flow pattern transition from slug flow to stratified
and/or annular flow is predicted by solving the momentum equations for slug flow. The entire film
zone is treated as the control volume and the momentum exchange between the slug body and the
film zone is introduced into the combined momentum equation. This approach differs from
traditional methods of using separate models for each transition. The advantage of a single
hydrodynamic model is that the flow pattern transitions, slug characteristics, liquid holdup and
pressure gradient are implicitly related.
The 3-phase model contains separate momentum balances for the gas, oil and water phases. The
model determines whether the oil and water phases are separated or fully mixed. If the phases are
separated, individual phase viscosities are used. If the phases are fully mixed, the liquid viscosity
can be determined either by the method within the TUFFP model (emul default option) or
overridden (emul override option) by the liquid viscosity method defined with the PIPESIM fluid
model, which is useful when rheology data are available. In the latter case, for black oil fluid
models, selecting the Brinkman emulsion viscosity method with the Brauner-Ullman watercut cutoff
method will replicate the method used within the TUFFP model. For the 2-phase (gas-liquid)
model, the liquid viscosity from PIPESIM is always used, so the emulsion options defined in the
PIPESIM fluid definition always apply.
The closure relationships included in the model are based on focused experimental research
programs at University of Tulsa and elsewhere. As new and improved closure relationships
become available, the TUFFP Unified Model is updated and validated.

Note: The TUFFP Unified 2-Phase Model v 2007.1 is no longer supported in PIPESIM. Upon
import, TUFFPU2P is used instead.

Xiao
The Xiao comprehensive mechanistic model was developed as part of the TUFFP research
program. It was developed for gas-liquid two-phase flow in horizontal and near horizontal pipelines.
The model first predicts the existing flow pattern, and then calculates flow characteristics, primarily
liquid holdup and pressure drop, for the stratified, intermittent, annular, or dispersed bubble flow
patterns. The model was tested against a pipeline data bank. The data bank included large
diameter field data culled from the AGA multiphase pipeline data bank, and laboratory data
published in literature. Data included both black oil and compositional fluid systems. A new

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correlation was proposed which predicts the internal friction factor under stratified flow. The former
has the advantage of making the film friction sensitive to both the gas and liquid velocities making
the model as a whole more interconnected and a better holdup predictor. The Xiao et al. model is
valid for all fluid types and pipe inclinations between -15degC and +15degC relative to horizontal.

Xiao (film modified)

The Xiao mechanistic model was developed as part of the TUFFP research consortia at the
University of Tulsa (p.510). The standard implementation was modified in the stratified flow pattern
to produce a second method called Xiao film modified. Unlike the Baker-Jardine implementation
(which is based on the TUFFP version of the code, yet also contains a film modification), the
Neotec version was coded independently and therefore the numerical methods and film
modification approach are slightly different.
The modification consists of using the Ouyang and Aziz (p.499) two-phase correlation for film wall
friction instead of the more traditional single phase correlation. The former has the advantage of
making the film friction sensitive to both the gas and liquid velocities making the model as a whole
more interconnected and a better holdup predictor. The Xiao et al. model is valid for all fluid types
and pipe inclinations between -15degC and +15degC relative to horizontal.

7.1.3 Vertical Multiphase Flow Correlations

Setup Flow Correlations
See also: Flow regimes (p.281), Suggested flow correlation (p.294),
The flow correlations available are affected by the Moody friction Factor calculation method option.
By default, PIPESIM uses the explicit Moody friction factor calculation method ("Explicit
Reformulation of the Colebrook-White Equation for turbulent Flow friction Factor calculation" by J.
Sonnad and C. Goudar, Ind. Eng. Chem. Res, 2007, 46, pp. 2593-2600).
The following vertical multiphase flow correlations are available:

Ansari
The Ansari mechanistic model was developed as part of the Tulsa University Fluid Flow Projects
(TUFFP) research program. A comprehensive model was formulated to predict flow patterns and
the flow characteristics of the predicted flow patterns for upward two-phase flow. The
comprehensive mechanistic model is composed of a model for flow pattern prediction and a set of
independent models for predicting holdup and pressure drop in bubble, slug, and annular flows.
The model was evaluated by using the TUFFP well databank that is composed of 1775 well cases,
with 371 of them from Prudhoe Bay data.

Aziz Govier Fogarasi

The Aziz, Govier, and Fogarasi model was developed especially for wellbore pressure drop
calculations for upward flow in production wells. The flow regime (for example, annular-mist, slug,
etc.) is determined using the correlation of Govier and Aziz (1972). The flow pattern is predicted
first, and then a corresponding correlation is used to calculate liquid holdup and frictional pressure
loss. The Duns and Ros method is used for holdup and pressure calculations in the annular mist
flow regime as recommended in the published work.

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The correlation of Aziz, Govier, and Forgasi is used for pressure loss, holdup, and flow regime.
The Govier, Aziz and Fogarasi correlation was developed following a study of pressure drop in
wells producing gas and condensate. Actual field pressure drop versus flowrate data from 102
wells with gas-liquid ratios ranging from 3,900 to 1,170,000 scf/bbl were analyzed in detail. The
phase conditions in the well bore were determined by standard flash calculations. Pressure-
gradient data for flow under single-phase conditions were compared with conventional predictions,
and found generally to confirm them. For the test in which two-phase conditions were predicted
throughout the well bore, the field data were compared with several wholly empirical prediction
methods, with a previously proposed method, and with a new prediction method partly based on
the mechanics of flow. The new prediction method incorporates an empirical estimate of the
distribution of the liquid phase between that flowing as a film on the wall and that entrained in the
gas core. It employs separate momentum equations for the gas-liquid mixture in the core and for
the total contents of the pipe.

Note: This method tends to overpredict the minimum stable flow rate (minimum rate to lift liquids)
and thus can overpredict pressure losses, especially for gas-water wells.

Beggs and Brill Original

ORIGINAL: The Original Beggs and Brill (p.500) correlation is used for pressure loss and holdup.
Flow regime is determined by either the Beggs and Brill or Taitel Dukler correlation. The Beggs
and Brill correlation was developed following a study of two-phase flow in horizontal and inclined
pipes. The correlation is based upon a flow regime map which is first determined as if the flow was
horizontal. A horizontal holdup is then calculated by correlations, and this holdup is corrected for
the angle of inclination. The test system included two 90 ft long acrylic pipes, winched to a variable
elevation in the middle, so as to model incline flow both upwards and downwards at angles of up to
90.

Beggs and Brill Revised

REVISED: As above except that the revised version of the Beggs and Brill correlation is used, with
rough pipe friction factors, holdup limiters and corrective constants as proposed by Palmer (p.507)
and Payne (p.507). The following enhancements to the original method are used; (1) an extra flow
regime of froth flow is considered which assumes a no-slip holdup, (2) the friction factor is changed
from the standard smooth pipe model, to utilize a single phase friction factor based on the average
fluid velocity.

Duns and Ros

The Duns and Ros correlation is used for pressure loss and holdup with flow regime determination
by either the Duns and Ros (p.502) or the Taitel (p.509) Dukler (p.502) correlations. The Duns
and Ros correlation was developed for vertical flow of gas and liquid mixtures in wells. Equations
were developed for each of three flow regions, (I) bubble, plug and part of froth flow regimes, (II)
remainder of froth flow and slug flow regimes, (III) mist flow regime. These regions have low,
intermediate and high gas throughputs respectively. Each flow region has a different holdup
correlation. The equations were based on extensive experimental work using oil and air mixtures.

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Gomez
The Gomez mechanistic flow model was developed at The University of Tulsa (p.503), and the
code written by Neotec based on the published work.
The Gomez et al. model is valid for all fluid types and inclinations between 0 and 90degrees.
(Recommended for 30-90 degrees).

Gomez enhanced
The standard Gomez et al. implementation was modified by Neotec to produce the Gomez et al.
enhanced method.
The modification consists of using the Oliemans (p.507) liquid entrainment correlation for vertical
annular mist flow instead of the standard Wallis correlation. Even though the Oliemans correlation
was developed using low pressure, mainly water-air, small diameter data, it does a good job of
smoothing the response surface around the slug to annular mist transition region where the Gomez
et al. correlation shows unusual behavior. This improves the statistical performance of this method
in simulations of gas-lift wells as shown by Adames (p.499). The result is an improved method that
works well for all types of wells.

Govier and Aziz

The correlation of Aziz, Govier, and Forgasi (p.499) is used for pressure loss, holdup, and flow
regime. The Govier, Aziz and Fogarasi correlation was developed following a study of pressure
drop in wells producing gas and condensate. Actual field pressure drop versus flowrate data from
102 wells with gas-liquid ratios ranging from 3,900 to 1,170,000 scf/bbl were analyzed in detail.
The phase conditions in the well bore were determined by standard flash calculations. Pressure-
gradient data for flow under single-phase conditions were compared with conventional predictions,
and found generally to confirm them. For the test in which two-phase conditions were predicted
throughout the well bore, the field data were compared with several wholly empirical prediction
methods, with a previously proposed method, and with a new prediction method partly based on
the mechanics of flow. The new prediction method incorporates an empirical estimate of the
distribution of the liquid phase between that flowing as a film on the wall and that entrained in the
gas core. It employs separate momentum equations for the gas-liquid mixture in the core and for
the total contents of the pipe.

Gray
The Gray Vertical Flow correlation is used for pressure loss and holdup. This correlation was
developed by H E Gray of Shell Oil Company for vertical flow in gas and condensate systems
which are predominantly gas phase. Flow is treated as single phase, and dropped out water or
condensate is assumed to adhere to the pipe wall. It is considered applicable for vertical flow
cases where the velocity is below 50 ft/s, the tube size is below 3.5 in, the condensate ratio is
below 50 bbl/mmscf, and the water ratio is below 5 bbl/mmscf.

Gray Modified
As above, but with the following modifications: (1) Actual Reynolds number used (Gray Original
assumed Reynolds number to always be 1 million), and (2) Pseudo-roughness is constrained to be
less than the pipe radius.

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Gregory
The Gregory et al model (1989) is a modification of the Aziz, Govier and Fogarasi (1972) method
(described in Aziz, Govier and Fogarasi (p.499)). The Gregory et al model uses the Govier and
Aziz flow pattern map (1972) except for the transition from annular-mist flow to froth flow. The
transition between annular-mist (stable flow) and froth flow (unstable flow) is computed using the
technique proposed by Turner et al (1969). Turner et al postulated that the minimum gas velocity
required to lift liquids would correspond to the terminal velocity of the largest stable liquid droplet
that would form. The Gregory model uses the procedure recommended by Coleman which does
not include the 20% increase in velocity added by Turner. If the gas velocity (superficial gas
velocity divided by the gas volume fraction in the input stream) is larger than the velocity expressed
in the equation below, the flow pattern will be annular-mist, otherwise froth flow will be assumed.

where

gas-liquid surface tension (dynes/cm)

droplet drag coefficient

liquid density (lbm/ft3)

gas density (lbm/ft3)

velocity at the boundary between froth and annular-mist (ft/s)

liquid input volume fraction

The rest of the calculations are the same as for the Aziz, Govier and Fogarasi method (described
in Aziz, Govier and Fogarasi), with the exception that the parameter VGfm (required for froth flow
calcuations) is computed as shown in the following equation:

A default value of 0.44 (which corresponds to a spherical droplet shape) is provided for the droplet
drag coefficient. Additionally, the Gray Revised method for pressure drop is used instead of the
Duns and Ros method in the annular-mist regime.

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Hagedorn and Brown

The correlation of Hagedorn and Brown (p.503) is used for pressure loss and holdup. While the
Hagedorn and Brown correlation does not predict flow pattern, the flow pattern as predicted by
Orkiszewski is reported. The Duns and Ros flow pattern prediction can also be reported. Neither of
these flow pattern prediction methods affects any of the calculations. The Hagedorn and Brown
correlation was developed following an experimental study of pressure gradients occurring during
continuous two-phase flow in small diameter vertical conduits. A 1,500 ft experimental well was
used to study flow through 1 in., 1.25 in., and 1.5 in. nominal size tubing. Air was the gas phase
and four different liquids were used: water and crude oils with viscosities of about 10, 30 and 110
cp. Liquid holdup was not directly measured, rather a pseudo liquid-holdup value was determined
that matched measured pressure gradients.
Further work by Brill and Hagedorn have led to two modifications: (1) If the Griffith and Wallis
criteria predicted the occurrence of bubble flow, the Griffith bubble-flow method should be used to
predict pressure gradient, and (2) If the predicted liquid holdup is less than the no-slip liquid
holdup, then the no-slip liquid holdup is used.
All of the correlations involve only dimensionless groups, which is a condition usually sought for in
similarity analysis but not always achieved.

Mukherjee and Brill

The Mukerjee and Brill (p.506) correlation is used for Pressure loss, Holdup and flow map. Note:
selection of alternative flow maps and/or holdups will cause unpredictable results. The Mukherjee
and Brill correlation was developed following a study of pressure drop behavior in two-phase
inclined flow. For bubble and slug flow, a no-slip friction factor calculated from the Moody diagram
was found adequate for friction head loss calculations. In downhill stratified flow, the friction
pressure gradient is calculated based on a momentum balance equation for either phase assuming
a smooth gas-liquid interface. For annular-mist flow, a friction factor correlation was presented that
is a function of holdup ratio and no-slip Moody friction factor. Results agreed well with the
experimental data and correlations were further verified with Prudhoe Bay and North Sea data.

NOSLIP Correlation
The NOSLIP correlation assumes homogeneous flow with no slip between the phases. Fluid
properties are taken as the average of the gas and liquid phases and friction factors are calculated
using the single phase MOODY correlation. Note: selection of alternative flow maps and/or holdups
will cause unpredictable results.

OLGAS 2-phase/ OLGAS

The OLGAS mechanistic models are applicable for all inclination angles, pipe diameters and fluid
properties. The 2-phase Bendiksen (p.500) model considers gas-liquid flow, whereas the 3-phase
model considers gas-oil-water flow.
This model employs separate continuity equations for gas, liquid bulk and liquid droplets, which are
coupled through interphase mass transfer. Two momentum equations are solved: one applied to
the combined balance for the gas and liquid droplets, if present, and a separate momentum
equation for the liquid film. OLGAS considers four flow regimes: stratified, annular, slug and
dispersed bubble flow; and uses a unique minimum slip criteria to predict flow regime transitions.

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The OLGA 2-Phase model uses the liquid viscosity model defined within the PIPESIM fluid
property definition. The 3-Phase model uses the Pal and Rhodes emulsion correlation to calculate
liquid viscosity based on the oil and water viscosities defined with the PIPESIM fluid model
definition; liquid viscosity options defined with the PIPESIM fluid model are ignored.
OLGAS is based in large part on data from the SINTEF multiphase flow laboratory near
Trondheim, Norway. The test facilities were designed to operate at conditions that approximated
field conditions. The test loop is 800 m long and 8 inches in diameter. Operating pressures
between 20 and 90 barg were studied. Gas superficial velocities of up to 13 m/s, and liquid
superficial velocities of up to 4 m/ s were obtained. In order to simulate the range of viscosities and
surface tensions experienced in field applications, different hydrocarbon liquids were used (naptha,
diesel, and lube oil). Nitrogen was used as the gas. Pipeline inclination angles between 1 were
studied in addition to flow up or down a hill section ahead of a 50m high vertical riser. Over 10,000
experiments were run on this test loop during an eight year period. The facility was run in both
steady state and transient modes.

LEDA
The (Leda Point Model (PM)) is a mechanistic model applicable for all inclination angles, pipe
diameters and fluid properties. The 2-phase model considers gas-liquid flow whereas the 3-phase
model considers gas-oil-water flow.
The 3-phase Leda PM considers 9 fields in the mass (continuity) equations (oil, gas, water, oil in
gas and water, gas in oil and water, water in oil and gas). Separate momentum equations are
solved for oil, gas and water.
The 2-phase Leda PM considers 4 fields in the mass (continuity) equations (liquid, gas, liquid in
gas and gas in liquid. Separate momentum equations are solved for gas and liquid phases. The
flow regimes predicted by LedaPM are stratified smooth flow, stratified wavy flow, slug flow,
annular and bubbly flow. The Leda 2-phase model uses the liquid viscosity associated with the
fluid model defined in PIPESIM. The Leda 3-phase model assumes that the liquid viscosity is equal
to that of the continuous phase; liquid viscosity options defined with the PIPESIM fluid model are
ignored. The continuous phase is determined by the Brauner-Ullman (p.500) inversion criteria.
The Leda Point Model is the steady-state version of the transient model developed by SINTEF in
collaboration with Total and ConocoPhillips and commercialized by Kongsberg. The model has
been calibrated against data collected at the SINTEF Multiphase Flow Laboratory near Trondheim
Norway. Over 10,000 experimental data points have been collected for single-phase, two-phase
(oil-water, water-gas) and three-phase (oil-water-gas) flow. Pipe diameters ranging from 4-12
were used at pressures up to 90 barg. The models have been validated with field data supplied by
ConocoPhillips and Total.

Orkiszewski
The Orkiszewski (p.507) correlation is used for pressure loss, holdup, and flow regime. The
Orkiszewski correlation was developed for the prediction of two phase pressure drops in vertical
pipe. Four flow regimes were considered, bubble, slug, annular-slug transition, and annular mist.
The method can accurately predict, to within 10%, the two phase pressure drops in naturally
flowing and gas lifted production wells over a wide range of well conditions. The precision of the
method was verified when its predicted values were compared against 148 measured pressure

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drops. Unlike most other methods, liquid holdup is derived from observed physical phenomena,
and is adjusted for angle of deviation.

TUFFP Unified Mechanistic Model (2-phase and 3-phase)

The TUFFP Unified Mechanistic Model is the collective result of many research projects performed
by the Tulsa University Fluid Flow Projects (TUFFP) research consortium. The model determines
flow pattern transitions, pressure gradient, liquid holdup and slug characteristics. A 2-phase
version is available for gas-liquid flow Zhang et.al, development (p.510) and validation (p.510)]
and a 3-phase version is available for gas-oil-water pipe flow [Zhang and Sarica (p.510)]. The
model is valid for all inclination angles, pipe diameters and fluid properties.
The principle concept underlying the model is the premise that slug flow shares transition
boundaries with all the other flow patterns. The flow pattern transition from slug flow to stratified
and/or annular flow is predicted by solving the momentum equations for slug flow. The entire film
zone is treated as the control volume and the momentum exchange between the slug body and the
film zone is introduced into the combined momentum equation. This approach differs from
traditional methods of using separate models for each transition. The advantage of a single
hydrodynamic model is that the flow pattern transitions, slug characteristics, liquid holdup and
pressure gradient are implicitly related.
The 3-phase model contains separate momentum balances for the gas, oil and water phases. The
model determines whether the oil and water phases are separated or fully mixed. If the phases are
separated, individual phase viscosities are used. If the phases are fully mixed, the liquid viscosity
can be determined either by the method within the TUFFP model (emul default option) or
overridden (emul override option) by the liquid viscosity method defined with the PIPESIM fluid
model, which is useful when rheology data are available. In the latter case, for black oil fluid
models, selecting the Brinkman emulsion viscosity method with the Brauner-Ullman watercut cutoff
method will replicate the method used within the TUFFP model. For the 2-phase (gas-liquid)
model, the liquid viscosity from PIPESIM is always used, so the emulsion options defined in the
PIPESIM fluid definition always apply.
The closure relationships included in the model are based on focused experimental research
programs at University of Tulsa and elsewhere. As new and improved closure relationships
become available, the TUFFP Unified Model is updated and validated.

Note: The TUFFP Unified 2-Phase Model v 2007.1 is no longer supported in PIPESIM. Upon
import, TUFFP version 2011.1 is used instead.

7.1.4 Suggested correlations

Use the Flow correlations tab to set flow correlation options at the global level or at local levels. If
you set flow correlation options at the local level, the source, correlation, friction factor, and holdup
factor appear as individual columns for both vertical and horizontal components.
If no production data are available, Schlumberger have found the following to give satisfactory
results based on previous studies using field data:
Single phase system
Moody (p.297)

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Vertical oil well

Hagedorn and Brown (p.292)
Highly deviated oil well
Hagedorn and Brown (p.292) or Duns and Ros (p.289) or OLGA-S (p.292)
Gas/condensate well
Hagedorn and Brown (p.292)
Oil pipelines
Oliemans (p.286)
Gas/condensate pipelines
BJA Correlation (p.283)

Correlation Vertical and Highly Vertical Gas/ Oil Gas/

Predominantly Deviated Condensate Pipelines CondensatePipelines
Vertical Oil Oil Wells Wells (p.288) (p.283) (p.283)
Wells (p.288) (p.288)
Duns and Ros yes yes yes no no
Orkiszewski yes no yes no no
Hagedorn and yes no yes no no
Brown
Beggs and Brill yes yes yes yes yes
Revised
Beggs and Brill yes yes yes yes yes
Original
Mukherjee and yes yes yes yes yes
Brill
Govier, Aziz yes yes yes no no
and Forgasi
NoSlip yes yes yes yes yes
OLGAS yes yes yes yes yes
Ansari yes no yes no no
BJA for no no yes no yes
Condensates
AGA and no no no no yes
Flanigan
Oliemans no no no yes yes
Gray no no yes no no
Gray Modified no no yes no no
Xiao no no no yes yes

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LEDA yes yes yes yes yes

TUFFP yes yes yes yes yes

7.1.5 Friction and Holdup factors

These two factors can be used to adjust the friction and holdup prediction of a particular flow
correlation. By default these factors are 1.
A linear relationship is used for the friction pressure drop. Setting the friction factor to 0.5, for
example, will mean that the friction element of pressure drop computed by the correlation will be
halved.

A non-linear relationship is used to calculate the liquid holdup H L from the value predicted by the
correlation H Lc :

H L = f H H Lc + (1 f H ) H Lc
2
Eq. 7.1

This ensures that the liquid holdup is sensible 0 H L 1 when 0 f H 2.

These factors are often used as calibration factors when a good match to field data cannot be
obtained by any other method. Changing these factors will affect the results and should be
undertaken with care.

7.1.6 Single Phase Flow Correlations

See also: SPHASE Single Phase Flow Options (p.564)
The steady-state pressure gradient in single phase sections is given by the equation:

dp
dL
=
dp
dL ( ) elev .
+ ( dLdp ) fric .
+ ( dLdp )
acc .
Eq. 7.2

where elevation, friction and acceleration components of the pressure drop are:

( dLdp ) elev .
= g sin Eq. 7.3

( dLdp ) fric .
=
fv
2D
Eq. 7.4

( dLdp ) acc .
= v
dv
dL
Eq. 7.5

where

f is the friction factor dimensionless

is the fluid density lb / ft
3

v is the fluid velocity ft / s

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g is the gravitational acceleration ft / s

2

is the angle of the pipe to the horizontal degrees

D is the pipe diameter ft
L is the length of the pipe ft

There are a number of different ways of calculating the friction factor, which usually depends on
the Reynolds number:
vD
Re = Eq. 7.6

where:

is the fluid viscosity lb / ft s

Moody (default for liquid or gas)

See Sonnad and Goudar paper (p.509) and Moody paper (p.506) for more technical details.

For laminar flow (Re < 2000) 64

f Lam =
Re
For turbulent flow (Re > 4000) 1
f Turb
1/2 = a ln ( qc + )
For transition flow (2000 Re 4000) (Re Remin )( f Turb f Lam )
f = + f Lam
(Remax Remin )
where:

f Turb is the Moody friction factor

Re is the Reynolds Number
a 2
is
ln (10)
is the pipe roughness
D is the pipe diameter
b /D
is
3.7
c
is ( ln5.02
(10)
)Re
s is bc + ln (c)

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q
is s s /(s +1)
z
is ln ( gq )
g
( qc )
is bc + ln

is (
g +1)
g
z

The friction factor is interpolated in the transition region (2000 < Re < 4000). The limits for the
transition zone and the interpolation method can be reset by the user.
The various friction factor calculation methods available are:

Friction Factor Approximation used Equation

Calculation method
EXPLICIT or SONNAD Sonnad 2007 linear
approximation (default)
f Turb
1
1/2 = a ln ( qc + )

( )
APPROXIMATE or Moody 1947 6 1/3
MOODY approximation 10
f Turb = 0.0055 1 + 20000 +
D Re
IMPLICIT or ITERATIVE Colebrook-White
equation (Moody chart)
f Turb
1
1/2 = 1.74 2log10
( 2
D
+
18.7
Re f Turb
1/2
)
AGA (for gas)
The AGA friction factor is the same as the Moody friction factor at high and low Reynolds numbers,
but differs in between:

For laminar flow (Re < 1000) 64

f =
Re
For transition flow

(1000 < Re < 4

c2 3.7D
c1
( )
1 c1
/ log10 ( 3.7 D
)) f
1
1/2 = 2c1log
10 ( Re c1
2 c
2
f
1/2
)
For turbulent flow
c2 3.7D
1
1/2 = 2log10 ( 3.7 D ) = 1.74 2log ( 2D ) 10
(Re > 4
c1
( )
1 c1
/ log10( 3.7D
)) f

where:

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c1 = 0.98 is the drag factor

c2 = 10
0.15 is a constant

Cullender and Smith (for gas)

The total pressure drop can be calculated from

dp pdown pup
=
dL L
where:
2 2
2
pdown a
pup =
b
where:

25 f qvG
2 2 2
2
T ZG (b 1)
a = 5
0.0375(12 D )

b = exp ( 0.0375 G L

TZ G
)
f is the Moody friction factor dimensionless
L is the pipe length ft
pdown is the downstream pressure psi

pup is the upstream pressure psi

qvG is the stock tank gas volume flow rate scf / day

T is the average temperature R
ZG is the gas compressibility factor dimensionless

G is the gas specific gravity dimensionless

Other friction pressure drops for gas

The friction pressure drop can be calculated from

( dLdp ) fric .
=
pdown pup
L
where:

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( )( )
2 1/a3
Z L
T ps
a4
2 2 G 1 qvG G
pup pdown =
5280 Ts a1 (12 D )a5

where:

L is the pipe length ft

pdown is the downstream pressure psi

pup is the upstream pressure psi

ps is the stock tank pressure psi

qvG is the stock tank gas volume flow rate scf / day

T is the average temperature R
Ts is the stock tank temperature R

ZG is the gas compressibility factor dimensionless

G is the gas specific gravity dimensionless

is a flow efficiency factor dimensionless

and the constants are given by

a1 a3 a4 a5
Panhandle A 435.87 0.5394 0.4604 2.618
Panhandle B 737.00 0.5100 0.4900 2.530
Weymouth 433.50 0.5000 0.5000 2.667

Hazen-Williams (for liquid water)

The friction pressure drop can be calculated from:

( )
1.85

( dLdp ) fric .
=
0.015 m
144(12 D )
4.87
qvL
c
Eq. 7.7

where:

c is the pipe condition factor

qvL is the liquid volume flow rate bbl / day

m is the mixture density lb / ft

3

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7.1.7 Swap Angle

The multiphase flow correlations used to predict the pressure loss and holdup are split into two
categories: vertical and horizontal. Each category lists the correlations that are appropriate for that
type of flow.
By default the selected vertical correlation is used in the situation where the tubing/pipe is within 45
degrees of the vertical, up (+90 degrees) or down (-90 degrees). Outside this range the selected
horizontal correlation is used. This angle can be changed.

7.1.8 deWaard (1995) Corrosion Model

The de Waard model (p.501) predicts the corrosion rate of carbon steel in the presence of water
and CO2. The model was developed primarily for use in predicting corrosion rates in pipelines
where CO2 is present in a vapor phase. The model has not been validated at high pressures where
CO2 is entirely in the liquid phase. Corrosion rate is calculated as a function of:
Temperature
Pressure
Mol% CO2
Wt% Glycol (Multiflash and ScaleChem only)
Liquid velocity
Pipe Diameter
pH
The model accounts for the flow-independent kinetics of the corrosion reaction as well as the flow-
dependent mass transfer of dissolved CO2 using a resistance model. Additionally, effects of
protective scale at high temperatures are considered in addition to glycol inhibition.

Note: The equations that follow are based on the de Waard 1995 model (p.501). This model is a
revision to the de Waard 1991 model (p.501). Some of the equations below appear only in the
original paper].

General Equation

CcFsFg
Vcor =
1 1 Eq. 7.8
+
Vr Vm

CO2 Partial Pressure/Fugacity

(mole % CO2 * Ptotal )

pCO2 = Eq. 7.9
100

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PIPESIM User Guide

1.4
log ( f CO 2) = log ( pCO2) + (.0031 )P
t + 273

Reaction Rate term (Vr)

1119
log (Vr ) = 4.93 + 0.58log ( fCO2) .34( pH act pH CO 2) Eq. 7.10
T

pH
By default, the correlation assumes that the actual pH of the water is affected strictly by the
presence of CO2. However, the user may specify the actual pH of a water sample that accounts for
the additional presence of electrolytes and dissolved FeCO3 liberated from the pipe wall. Since pH
is dependent on pressure and temperature, care must be taken when specifying this value. If a
ScaleChem generated PVT file is used, the actual pH is taken from the ScaleChem fluid
description.

pH CO 2 = 3.82 + .00384t 0.5log ( fCO2) Eq. 7.11

pHact = assumed to equal pHco 2 unless user specified or ScaleChem PVT file is used

Mass Transfer rate term (Vm)

0.8
UL
Vm = 2.45 0.2 fCO2 Eq. 7.12
d

Effect of Temperature (protective scale)

2400
Ts = Eq. 7.13
6.7 + 0.44log ( fCO2)

(if T > Ts)

1 1
log (Fs ) = 2400 Eq. 7.14
T Ts
Else,
Fs = 1 Eq. 7.15

Glycol Reduction Effect

log F g = 1.6 log (W % ) 2 Eq. 7.16

Where W% is the weight percent of water in a water-glycol mixture (100% water results in a factor
of 1.0). The Glycol component is only available when using Multiflash (MEG or DEG) or with
ScaleChem (MEG).

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Variable Units Description Default Acceptable Variable

Input Range Source
Vcor (mm/yr) corrosion rate calc
T temperature pipesim

t temperature pipesim

pCO2 atm partial pressure of CO2 calc

fCO2 atm, fugacity of CO2 calc
mol%CO2 mol % CO2 (comp, BO, pipesim
ScaleChem PVT file)
Ptotal atm pressure pipesim
pHact actual pH of the system pHco2 1.010.0 user spec
pHCO2 pH of dissolved CO2 in pure water calc
UL m/s liquid velocity pipesim
d m/s pipe diameter pipesim
W% fraction Weight percent water in a water- 100 pipesim
glycol mixture
Ts Vcor inversion temperature calc

Fs scaling factor calc

Cc multiplier to correct for inhibitor 1 0.110.0 user spec
efficiency or match to field data

7.1.9 Cunliffe's Method for Ramp Up Surge

Cunliffe's Method is used to predict the liquid surge rate due to an overall gas rate change for
condensate pipelines. This method is particularly useful for estimating liquid handling capacity for
ramp-up (increasing gas rate) cases. As the gas rate increases, the total liquid holdup in the line
will drop owing to less slippage between the gas and liquid phases. The liquid residing in the line is
therefore accelerated to the equilibrium velocity at the final gas rate and thus expelled at a rate
higher than the final equilibrium liquid rate for the duration of the transition period. The transition
period is assumed to be equal to the residence time at the final gas rate, that is, the time it takes
the liquid to travel from one end of the line to the other.
The average liquid rate during the transition period can be determined as follows:

(H L Ti HL
Tf
)
qL = qL +
T i tr

qL = qG ( LGR out )
t i

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PIPESIM User Guide

HL
Tf
tr =
qL
i
where:

liquid rate during the transition period

qL
T
initial liquid rate
qL
i
total liquid holdup volume in line - initial gas rate
qG = H L
i T
total liquid holdup volume in line - final gas rate
HL
Tf

LGR out liquid/gas ratio at outlet pressure (assumed constant)

tr liquid residence time (at final flowrate)

Note: The total liquid holdup volume in the line is provided in the summary output report. Cunliffe
tested this method with field measurements for a 67 mi. 20 in. pipeline with an average operating
pressure of 1300 psig and an LGR of 65 bbl/MMscf. He found that the change in condensate flow
rate can be predicted to within 15% using this method.

Reference: Cunliffe, R.: "Prediction of Condensate Flow Rates in Large Diameter High Pressure
Wet Gas Pipelines", APEA Journal (1978), 171-177.

7.1.10 Liquid by Sphere

The liquid holdup throughout the pipe will be divided into two notional fractions, that is . the
'moving' and the 'static'. Since the liquid normally flows slower than the gas, the division will
normally result in a positive value for both of these volumes. (If the pipe goes downhill the liquid
often flows faster, so the 'static' will be negative in these sections, but this does not affect the
equation.) If the fluid's phase split is assumed to be constant throughout the pipe, the size of the
slug that issues when sphered can be calculated using the following formula:

SGLV = ( TPVSLV
MLV )
MLV + SLV Eq. 7.17

where:
SGLV is Sphere Generated Liquid Volume
SLV is Static Liquid Volume in pipe
MLV is Moving Liquid Volume in pipe
TPV is Total Pipeline Volume

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Note: SLV + MLV = Total pipeline holdup, which PIPESIM calculates and writes to the summary
output.

The explanation for this formula is as follows. The slug of liquid starts to issue from the pipe when
the pipe is full of liquid from its exit, back along to the position of the sphere. The liquid in the slug
comprises 2 notional fractions: firstly, the entire SLV in the pipe, and secondly, that portion of the
MLV that lies between the sphere and the outlet. Now: the volume available for the SLV to occupy
in the pipe is TPV - MLV. Dividing this into SLV gives us the position of the sphere in the pipe as a
value between 0 and 1, where 0 is the outlet. Multiplying the MLV by this gives us the portion of the
MLV that is entrained in the slug, so adding this to the SLV gives the total slug volume.
The liquid holdup is calculated from the integration of the predicted holdup from the selected
Multiphase Flow Correlation (MFC) along the entire pipeline length. The pipeline is simulated in
segments, each of which has a length and cross sectional area, which multiplied together yield its
volume. The MFC calculates a value for holdup in the range 0 to 1, so this multiplied by the
segment volume gives holdup for the segment. The holdups for all the pipe segments are added
together to yield the pipeline total holdup as reported in the summary file.
When a sphere is introduced into the line, it will gather in front of itself a liquid slug made from "all
the liquid that is flowing slower than the mean fluid flowrate in the pipeline at any given point". Thus
the crucial value that determines Sphere Generated Liquid Volume (SGLV) is the Slip Ratio (SR),
which is the average speed of the fluid divided by the speed of the liquid. If the liquid and gas move
at the same speed, the slip ratio will be 1, that is there is 'no slip' between the phases. In this
situation the sphere will not collect any liquid, so the SGLV will be zero. Normally the liquid flows
slower than the gas, that is the slip ratio is greater than 1, so "some" of the liquid in the pipeline will
collect in front of the sphere to form the SGLV. The only way that "all" of the liquid in the pipeline
will collect to form the SGLV, is if the liquid velocity is zero, i.e.. the slip ratio is infinite. This cannot
happen in a steady-state reality, so the SGLV is always smaller than the total liquid holdup.
One complicating factor is that the slug of liquid swept up by the sphere will begin to emerge from
the end of the pipe some considerable time before the sphere itself emerges. This slug will be
composed of the liquid that the sphere collected on its way, plus the normal liquid production of the
system. This total volume is the figure required to size the slug catcher, which is why we report it
as "Volume by sphere".
To determine the sizes of terrain slugs or slugs from start up it is necessary to use a dynamic
multiphase flow simulator such as LEDA or OLGA. More details. (p.556)

PI-SS (Severe-Slugging Group)

PI-SS (severe-slugging group) is the ratio between the pressure buildup rates of gas phase and
that of liquid phase in a flowline, when followed by a riser:
ZRT
MG WG Eq. 7.18
ss =
gL < GF > W L
where

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Z Gas compressibility factor

R = 8314 J / K kmol Gas constant
T Temperature K
MG Molecular weight of gas (kg/kmol)

WG Gas mass flow rate kg / s

WL Liquid mass flow rate kg / s

g = 9.81m / s Acceleration due to gravity

2

L Flowline length m
< GL > Average flowline gas holdup

This expression is with assumptions of no mass transfer between the phases L G , and the
liquid fall back in the riser is neglected.
This PI-SS expression is based upon a correlation developed at Koninklijke Shell-Laboratorium
(see Pots and Bromilow (p.508) 1985) to quantify the likelihood of severe riser slugging, that is .
when ss < 1.0.
For severe slugging to occur, at least two conditions must be in evidence:
1. the flowline gas flow must be completely inhibited during slug buildup (that is due to a partly
declining flowline or the presence of flowline undulations ) .
2. the rate of hydrostatic pressure buildup in the riser due to the growth of the slug must exceed
the rate of gas pressure buildup in the flowline.
Under such conditions, the riser becomes filled with liquid before the gas pressure can drive the
liquid slug out of the line.

In PIPESIM if the value of ss is less than one at the riser base and the flow regime (as predicted
by the Taitel-Dukler correlation) is stratified (or wavy stratified), then severe riser slugging is
possible. Conversely, ss values significantly greater than one indicate that severe riser slugging is
not likely.

The PI-SS number (ss ) can also be used to estimate slug size. As a rule of thumb the slug length
will be approximately equal to the riser height divided by ss :

Slug Length = Riser Length / ss

Hence PI-SS values (ss ) less than unity imply slug lengths greater than the riser height. PI-SS is
calculated at each node in the flowline (while PISS=ON) using averaged holdup data

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7.1.11 Liquid Loading

Critical Unloading Velocity
The critical unloading velocity is defined as the minimum gas velocity required to lift liquid droplets
out of a gas well. Lower flowing gas velocities will result in liquid loading in the well. The critical
unloading velocity is predicted by Turners Equation.
0.25
N ( L G )
vt = Eq. 7.19
(CD25 G0.5)
where

is the gas phase density lb / ft

3
g

L is the liquid phase density lb / ft

3

is the interfacial tension dynes / cm

vt is the terminal velocity of liquid droplet ft / s

is pipe angle from vertical

CD is the drag coefficient dimensionless

N is a constant dimensionless

The values of N and CD are given in the following table for Turner's model and various others:

Model N CD
Turner (1969) 1.56 0.44
Coleman (1991) 1.3 0.44
Nossier II (2000) 1.482 0.2
Li (2002) 0.724 1.0

Combining N and CD , and discounting Turner's "built-in" 20% "correction factor" gives a constant
of 1.593. The correction factor is split out into the E term below.

Turner's Equation (General)

Turner's Equation (General Form):
0.25
(
1.593 E L G )
vt = Eq. 7.20
0.5
G

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Where E is the correction (efficiency) factor. The values of E for Turner's model and various others
are given in the following table:

Model E
Turner (1969) 1.2
Coleman (1991) 1.0
Nossier II (2000) 1.391
Li (2002) 0.454

Critical Gas Rate

The critical gas rate is the minimum gas rate required to prevent liquid loading.

7.2 Completion (IPR) Models

7.2.1 Inflow Performance Relationships for Vertical Completions
Inflow performance relationships (IPRs) have been developed to model the flow of fluids from the
reservoir, through the formation, and into the well. They are expressed in terms of the well static
(or reservoir) pressure Pws , the well flowing (or bottom hole) pressure Pwf , and flowrate Q .
Typically, volume flow rates are proportional to the pressure drawdown:

QV (Pws Pwf ) Eq. 7.21

For liquid IPRs the stock tank liquid rate is roughly proportional to the volume flow rate at well
conditions, and this form of the equation is used:

QL (Pws Pwf ) Eq. 7.22

For gas IPRs the stock tank flow rates are roughly proportional to the volume flow rate at reservoir
conditions times the average reservoir pressure:

(Pws + Pwf )
QG Qv
2
( 2 2
Pws Pwf ) Eq. 7.23

See also Vertical Completion Options (p.54), Multilayer Completions (p.87)

PIPESIM offers a comprehensive list of IPR options, for both oil and gas reservoirs, as follows:

IPR Oil reservoirs Gas and Gas Multi-rate

Condensate test (p.87)
Reservoirs
Backpressure Equation (p.313) Yes Yes
Fetkovich (p.311) Yes Yes
Hydraulically fractured (p.59) Yes Yes
IPR Table (p.324) Yes

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Jones / Forchheimer (p.312) Yes Yes Yes

Pseudo Steady State Equation / Darcy Yes Yes
(p.314)
Transient (p.319) Yes Yes
Vogel (p.310) Yes
Well PI (Productivity Index) (p.309) Yes Yes Yes

The Well PI (p.309), Pseudo Steady State (p.314) and Transient (p.319) liquid IPRs can be
combined with a Vogel (p.310) IPR to model flow at pressures below the bubble point; see bubble
point correction (p.325) .

Related links:
Vertical Completions Overview (p.53)

Productivity Index (PI)

PI is one of a number of methods that can be used to specify the Inflow Performance Relationship
(p.308) (IPR) for a completion. It can be regarded as a simplified version of the pseudo-steady
state (p.314) or transient (p.319) IPRs.

Liquid PI
The (straight line) productivity index relationship for liquid reservoirs is perhaps the simplest and
most widely used IPR equation. It states that rate is directly proportional to pressure drawdown
between the bottom hole and the reservoir.

QL = J L ( pws pwf ) Eq. 7.24

where:

QL is the stock-tank oil rate

pws is the well static (or reservoir) pressure

pwf is the well flowing (or bottom hole) pressure

J L is the liquid productivity index.

Below bubble point correction

The liquid PI equation can be combined with a Vogel equation (p.310) to model inflows when the
bottom hole pressure is below the bubble point, see, Bubble point correction. (p.325)

Gas PI
For gas reservoirs a non-linear relationship is used:

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( 2
QG = J G pws pwf
2
) Eq. 7.25

where:

QG is the stock-tank gas rate

pws is the well static (or reservoir) pressure

pwf is the well flowing (or bottom hole) pressure

J G is the gas productivity index

Vogel's Equation
Vogel's (1968) (p.510) equation is one of a number of methods that can be used to specify the
Inflow Performance Relationship (p.308) (IPR) for a completion. It was developed to model
saturated oil wells. Vogel's equation is a best-fit approximation of numerous simulated well
performance calculations. Vogel's work considers only the effect of rock and fluid properties on
saturated systems. The Vogel relation does not account for high-velocity-flow effects that may exist
in high-rate wells, see the Fetkovich equation (p.311).
Vogel's equation is:

( ( ) ( ))
2
pwf pwf
Q = Qmax 1 (1 C ) C Eq. 7.26
pws pws

Where

Q is the liquid flow rate (STB/D or m3/d)

Qmax is the absolute open hole flow potential, that is the liquid flow rate when the bottom hole
pressure is zero

pwf is the well flowing (or bottom hole) pressure (psia or bara)

pws is the well static (or reservoir) pressure (psia or bara)

C is the Vogel coefficient.

The Vogel equation has the following properties:

Q = Qmax at pwf = 0

Q=0 at pwf = pws

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Q Qmax (1 + C ) at pwf = pws

Productivity index =
pwf pws

Related links:
Vogel's Reservoir Properties (p.55)

Fetkovich's Equation
Fetkovich's equation is one of a number of methods that can be used to specify the Inflow
Performance Relationship (p.308) (IPR) for a completion. The Fetkovich equation is a development
of the Vogel equation (p.310) to take account of high velocity effects.

( ( ))
2 n
Pwf
Q = Qmax 1 Eq. 7.27
Pws

Where

Q is the liquid flow rate (STB/D or m 3/d)

Qmax is the absolute open hole flow potential, that is the liquid flow rate when the bottom hole
pressure is zero

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pwf is the well flowing (or bottom hole) pressure (psia or bara)

pws is the well static (or reservoir) pressure (psia or bara)

n is the Fetkovich exponent.

Related links:
Fetkovich's Reservoir Properties (p.56)

Jones' Equation
Jones' equation (p.504) is one of a number of methods that can be used to specify the Inflow
Performance Relationship (p.308) (IPR) for a completion. It is similar to the PI (p.309) method but
contains an extra term to model turbulence.

Jones equation for gas inflow

The Jones equation for gas reservoirs is :
2 2 2
Pws Pwf = AQG + BQG Eq. 7.28

where

QG is the stock-tank gas rate

pws is the well static (or reservoir) pressure

pwf is the well flowing (or bottom hole) pressure

A 0 is the turbulence coefficient

B 0 is the laminar coefficient

In the case when A = 0 the Jones equation is the same as the gas PI (p.309) equation with
/
productivity index J G = 1 B . Values of B > 0.05 (psi2/MMscf/d) indicate low permeability or the
presence of skin damage .

Jones equation for liquid inflow

Jones proposed the equation for gas flow, but it can also be used to model oil wells. However the
Fetkovich equation (p.311) can also be used for saturated oil wells and is the recommended
method for IPRs in reservoirs producing below the bubble point.
The Jones equation for liquid reservoirs is :
2
Pws Pwf = AQL + BQL Eq. 7.29

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where

QL is the stock-tank oil rate

In the case when A = 0 the Jones equation is the same as the liquid PI (p.309) equation with
productivity index J L = 1 B/
Forchheimer Equation
Forchheimer, 1901 (p.503) gave an equation for non-Darcy flow in the reservoir, which is
essentially the same as the Jones equation (p.312) for liquid inflow.

Related links:
Forchheimer's Equation (p.58)

Back Pressure Equation

The Back Pressure Equation is one of a number of methods that can be used to specify the Inflow
Performance Relationship (p.308) (IPR) for a completion.
The Back Pressure Equation was developed by Rawlins and Schellhardt (1935) (p.508) after
testing 582 wells. The equation is typically applied to gas wells although its application to oil wells
has also been proven. If correlations already exist for oil wells, use the Back Pressure Equation on
gas wells only. The equation has the following form:

( 2
QG = C Pws Pwf )
2 n
Eq. 7.30

where

QG is the gas flow rate (MMscf/d) (m3/d),

pws is the well static (or reservoir) pressure (psia) (bara)

pwf is the well flowing (or bottom hole) pressure (psia) (bara)

C is the back pressure constant (MMscf/d/(psia2)n) (m3/d/(bar 2) n)

n is the dimensionless back pressure exponent

The back pressure exponent, n , which ranges between 0.5 and 1.0, accounts for high velocity flow
(turbulence). When n = 1 the back pressure equation is the same as the gas PI (p.309) equation.
The back pressure constant, C , represents reservoir rock and fluid properties, flow geometry and
transient effects.
The parameters C and n must be obtained by multi-rate testing (p.87) of the well. Since

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( 2
log QG = log C + n log Pws Pwf
2
) Eq. 7.31

2 2
A plot of flow rate QG versus pws p on a log-log scale will give a line with slope n and
wf
intercept C . To avoid unit conversion problems when obtaining the parameters, check that the
slope has a value between 0.5 and 1.0. If n is less than 0.5, this implies that the reservoir
stabilization conditions are slow, or that liquid has accumulated in the wellbore (in gas condensate
wells). The value of n can be greater than 1.0 if liquid is removed from the well during testing, or by
removing drilling or stimulation fluids. Also, changes in well capacity during isochronal testing will
cause a wider scatter of data points. This might be the result of liquid accumulation or cleaning of
the wells.

Related links:
Backpressure's Reservoir Properties (p.57)

Pseudo Steady State Equation / Darcy Equation

The pseudo steady state IPR (p.308) equation (PSS), is derived from the equation for single phase
Darcy flow into a well. A number of versions of the equation can be used (some require keywords
(p.571)):
for liquid flow the PSS equation is written in terms of the stock tank liquid (p.317) flow rate
this can be optionally combined with a Vogel formula for pressures below the bubble point
(p.317).
the liquid flow can be modelled using a two phase version of the radial flow equations for oil
and water (p.317)
for gas flow the PSS is written in terms of the stock tank gas (p.317) flow rate
a version using the gas pseudo pressure (p.318) (more accurate for high pressure
systems).
the PSS expressed in terms of reservoir flow (p.314) rates can be used for either liquid or gas
flow.
the liquid flow can be modelled using a two phase version of the reservoir flow equations for
oil and water (p.316)

Reservoir flow
The pseudo steady state equation, like the transient IPR (p.319), is calculated by solving the
radial, single phase, Darcy flow into a well. It applies for relatively long times, after the well has
passed through the transient stage. The solution is given by Dake 1978 (p.501):

QR = M T (Pws Pwf ) Eq. 7.32

where the PSS transmissibility term is defined by:

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2 kh
T =
C1 ln ()
re
rw
0.75 + S
Eq. 7.33

Here:

QR is the volume flow rate at RB / d or

reservoir conditions of phase MCF / d

M is the mobility of phase 1 / cp

pws is the average reservoir pressure psia

pwf is the bottom hole pressure psia

k is the formation permeability mD

h is the formation thickness ft

rw is the wellbore radius ft

re is the drainage radius ft

S is the skin

C1 is a conversion factor depending

on the flow units
2
14.7 0.3048 5.61458 10
3 If the flow is in RB / d
C1 = 10 = 2 141.2
86400 10

14.7 0.3048
2 If the flow is in
C1 = 10 MCF / d
86400 10

Note: The constant 0.75 comes from using the average reservoir pressure pws =
p . A similar
formula can be derived using the pressure at the drainage radius pws = p (re ), but the value 0.75 is
replaced by 0.5.

The phase mobility is defined in terms of the phase relative permeability and viscosity:

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kr
M = Eq. 7.34

kr is the relative permeability for phase

is the viscosity of phase at reservoir conditions cp

For single phase flow the relative permeability is kr = 1, and the inflow equation simplifies to :

1
QR = T ( Pws Pwf ) Eq. 7.35

This version of the PSS IPR can be used for liquid or gas inflow.
For multiphase inflow, the total inflow can be written as the sum of the phase inflows:

QR = QRO + QRW + QRG Eq. 7.36

This can be rearranged to give:

QR = M T (Pws Pwf ) Eq. 7.37

Where the total mobility is defined by

M = MO + MW + MG Eq. 7.38

Oil and water flow

A two phase version of the multiphase inflow equation can be used to model liquid inflow.

QRL = ( krO
O
+
krW
W
) T (Pws Pwf ) Eq. 7.39

The relative permeabilities can be determined from permeability tables (p.352).

Injection
The reservoir injection flow equation is similar to the PSS production IPR:

QR = M I T (Pwf Pws ) Eq. 7.40

Here however, the mobility term represents the mobility of the fluid in the reservoir, rather than that
of the injection fluid, and must be specified. In production, the fluid being produced is the same as
that moving through the reservoir. In injection systems the two fluids may be different. For
example, we would expect different flow rates if gas is injected into a liquid filled reservoir or a gas
filled reservoir. If the injection fluid does differ from the reservoir fluid, then the injection mobility will
change with time, as the reservoir fluid changes.

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Stock tank liquid flow

The pseudo steady state equation can be expressed in stock tank flow rates. For liquid flow, the
/
stock tank flow rate QL = QR BL is given by

2 kh ( pws pwf )
QL =
C1 L BL ln () re
rw
0.75 + S
Eq. 7.41

QL is the liquid flowrate STB / d

BL is the liquid volume formation factor RB / STB

L is the liquid viscosity at reservoir conditions cp

Below bubble point correction

The pseudo steady state equation can be combined with a Vogel equation (p.310) to model inflows
when the bottom hole pressure is below the bubble point, see, Bubble point correction. (p.325)

Oil and water flow

The two phase version (p.316) of the reservoir liquid flow equation can also be written in terms of
stock tank liquid flow rate:

QL = QR / BL = QRO / BL + QRW / BL Eq. 7.42

Stock tank gas flow

This pseudo steady state equation can be expressed in stock tank flow rates. For gas flow, the
formation volume factor can be expressed in terms of pressure and temperature
V ZRT Ps
BG = = . The reservoir pressure is taken to be the average pressure in the
Vs P Zs RT s
pws + pwf
reservoir: P = , which gives a stock tank flow rate QG = QR / BG :
2
( 2
2 kh pws pwf
2
)
QG =
C2 G TZ ln ()
re
rw
0.75 + S + DQG
Eq. 7.43

The quadratic term in pressure arises from a combination of the pressure difference and the
reservoir average pressure term

(p ws
2
pwf ) = (p
2
ws )(
pwf pws + pwf .)
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The constant term arises from a combination of the conversion factor and stock tank properties

2C1Zs P
s
C2 = .
Ts
The skin has been modified to include a flow rate dependent term.

QG is the gas flowrate MSCF / d

BG is the gas volume formation factor CF / SCF

G is the gas viscosity at reservoir conditions cp

S is the constant skin

DQ is the near wellbore turbulence factor or rate

dependent skin

T is the reservoir temperature o

R

Z is the reservoir compressibility factor

Ps is the stock tank pressure 14.7 psi

Ts is the stock tank temperature 519.67 R

o

Zs is the stock tank compressibility factor 1

2
2 14.7 0.3048
2 is a constant, arising from conversion factors
C2 = 10 = 2 1422 and stock tank properties
86400 10 519.67

Gas pseudo pressure

Dake 1978 (p.501) gives another version of the Pseudo steady state IPR for gas inflow, that is
more accurate for large drawdowns, based on work by Al-Hussainy et al (p.499):

2 kh m pws m pwf( ) ( )
QG =
C2T ln ()
re
rw
0.75 + S + DQG
Eq. 7.44

Here the gas pseudo pressure is given by:

m( p ) = 2 pZ d p
G
Eq. 7.45

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Transient IPR
The transient IPR (p.308) equation, is derived from the equation for single phase Darcy flow into a
well. A number of versions of the equation can be used (some require keywords (p.587)):
for liquid flow the transient IPR is written in terms of the stock tank liquid (p.321) flow rate
this can be optionally combined with a Vogel formula for pressures below the bubble point
(p.322).
the liquid flow can be modelled using a two phase version of the radial flow equations for oil
and water (p.322)
for gas flow the transient IPR is written in terms of the stock tank gas (p.322) flow rate
a version using the gas pseudo pressure (p.323) (more accurate for high pressure
systems).
the transient IPR expressed in terms of reservoir flow (p.319) rates can be used for either liquid
or gas flow.
the liquid flow can be modelled using a two phase version of the reservoir flow equations for
oil and water (p.321)

Reservoir flow
The transient IPR, like the pseudo steady state IPR (p.314), is calculated by solving the radial,
single phase, Darcy flow into the well. It applies for relatively small times, before the well has
reached the pseudo steady state. A similarity solution is given by Dake 1978 (p.501):

QR = M T (Pws Pwf ) Eq. 7.46

where the transient IPR transmissibility is defined by:

2 kh
T =
1 4kt Eq. 7.47
C1 ln ( 2 )+S
2 C Cr
0 w

QR is the volume flow RB / d or MCF / d

rate at reservoir
conditions of phase

M is the mobility of 1 / cp
phase

pws is the average psia

reservoir pressure

pwf is the bottom hole psia

pressure

t time hours

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k is the formation mD
permeability

h is the formation ft
thickness

rw is the wellbore ft
radius

S is the skin

is the reservoir
porosity

C is the total 1 / psi

compressibility of
the reservoir and
the reservoir fluids

is a constant equal = e 0.5772 = 1.781

to the exponential
of Euler's constant

C0 is a conversion 2
14.7 0.3048 10
3
factor C0 = 10
10 3600

C1 is a conversion
factor depending
on the flow units
2
14.7 0.3048 5.61458 10
3 If the flow is in
C1 = 10 = 2 141.2 RB / d
86400 10

14.7 0.3048
2 If the flow is in
C1 = 10
MCF / d
86400 10

The transient IPR equation can be written in similar terms to the pseudo steady state IPR (p.314)
by defining a radius
2 4kt
r = Eq. 7.48
C0 C
2 kh
T =
r Eq. 7.49
C1 ln ( )+S
rw

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The phase mobility is defined in terms of the phase relative permeability and viscosity:

kr
M = Eq. 7.50

kr is the relative permeability for phase

is the viscosity of phase at reservoir conditions cp

For single phase flow the relative permeability is kr = 1, and the inflow equation simplifies to :

1
QR = T ( Pws Pwf ) Eq. 7.51

This version of the transient IPR can be used for liquid or gas inflow.
For multiphase inflow, the total inflow can be written as the sum of the phase inflows:

QR = QRO + QRW + QRG Eq. 7.52

This can be rearranged to give:

QR = M T (Pws Pwf ) Eq. 7.53

Where the total mobility is defined by

M = MO + MW + MG Eq. 7.54

Oil and water flow

A two phase version of the multiphase inflow equation can be used to model liquid inflow.

QRL = ( krO
O
+
krW
W
) T (Pws Pwf ) Eq. 7.55

The relative permeabilities can be determined from permeability tables (p.352).

Stock tank liquid flow

This transient IPR equation can be expressed in stock tank flow rates. For liquid flow, the stock
tank flow rate QL = QR BL is given by /
2 kh ( pws pwf )
QL =
1 4kt Eq. 7.56
C1 L BL ln ( 2 )+S
2 C0 L Cr w

QL is the liquid flowrate STB / d

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BL is the liquid volume formation factor RB / STB

L is the liquid viscosity cp

The equation can be written using base 10 logarithms, since

4x 4x 4
ln = ln 10 log = 2.302 (log x + log ) = 2.302 (log x 3.23):
C0 C0 C0

2 kh ( pws pwf )
QL =
kt S Eq. 7.57
1.151 C 1 L BL log ( 2) 3.23 +
1.151
L Crw

Below bubble point correction

The transient IPR equation can be combined with a Vogel equation (p.310) to model inflows when
the bottom hole pressure is below the bubble point, see, Bubble point correction. (p.325)

Oil and water flow

The two phase version (p.321) of the reservoir liquid flow equation can also be written in terms of
stock tank liquid flow rate:

QL = QR / BL = QRO / BL + QRW / BL Eq. 7.58

Stock tank gas flow

V ZRT Ps
This transient IPR equation can be expressed in stock tank f BG = = low
Vs P Zs RT s
rates. For gas flow, the formation volume factor can be expressed in terms of pressure and
temperature: . The reservoir pressure is taken to be the average pressure in the reservoir:
pws + pwf
P= , which gives a stock tank flow rate QG = QR / BG :
2
2 2
2 kh ( pws pwf )
QG =
1 4kt Eq. 7.59
C2 G TZ ln ( 2 ) + S + DQG
2 C0 G Cr w
The quadratic term in pressure arises from a combination of the pressure difference and the
average pressure term pws pwf( 2
) = (p
2
ws )(
pwf pws + pwf . )

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The constant term arises from a combination of the conversion factor and stock tank properties
2C1Zs P
s
C2 = .
Ts
The skin has been modified to include a flow rate dependent term.

QG is the gas flowrate MSCF / d

BG is the gas volume formation factor CF / SCF

G is the gas viscosity cp

S is the constant skin

DQ is the near wellbore turbulence factor or rate

dependent skin

T is the reservoir temperature o

R

Z is the reservoir compressibility factor

Ps is the stock tank pressure 14.7 psi

T s is the stock tank temperature

o
519.67 R

Zs is the stock tank compressibility factor 1

C2 is a constant, arising from conversion For MSCF / d :

factors and stock tank properties 2 2
2 14.7 0.3048
C2 = 10 = 2 1422
86400 10 519.67

The equation can also be written using base 10 logarithms:

2 2
2 kh ( pws pwf )
QG =
kt S + DQG Eq. 7.60
1.151 C 2 G TZ log ( ) 3.23 +
2
G Cr w 1.151

Gas pseudo pressure

Dake 1978 (p.501) gives another version of the Pseudo steady state IPR for gas inflow, that is
more accurate for large drawdowns, based on work by Al-Hussainy et al (p.499):

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( )
2 kh m pws m pwf ( )
QG =
1 4kt Eq. 7.61
C2T ln ( 2 ) + S + DQG
2 C0 G rw
Here the gas pseudo pressure is given by:

m( p ) = 2 pZ d p
G
Eq. 7.62

Time to pseudo steady state solution

According to Dake 1978 (p.501), the solution to the well inflow equations changes from transient
to pseudo steady state (p.314) when the dimensionless time tDA is given by

kt
tDA = > 0.1 Eq. 7.63
C0 CA
2
Writing A = re , where re is the drainage radius of the reservoir, the time when the pseudo steady
state (p.314) solution becomes applicable is
2
Cre
t pss = (0.1 C0) Eq. 7.64
k
A warning will be issued if the time t exceeds this value.

Data File
Enter an IPR in table form (Flowrate versus Pressure) rather than using an IPR (p.308) equation.
This feature is currently only available by using an EKT or in expert mode.
Place the EKT (Spanner icon) between the completion and the tubing and enter the IFPTAB
(p.578) data.
Example:

! n liq pwf gor wcut

ifptab 0 0 3000 986 0
ifptab 0 1000 2990 986 2.0
ifptab 0 2699 2920 1096 2.2
ifptab 0 6329 2800 2540 2.8
ifptab 0 7288 2600 2980 3.9
ifptab 0 8082 2400 3370 5.6
ifptab 0 8805 2003 3770 8.0
ifptab execute

Note: The GOR and water cut values are optional.

All IPR data associated with the completion will be ignored.

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Bubble Point Correction

The Productivity Index (p.309), Pseudo steady state (p.314) and Transient (p.319) IPRs for liquid
inflow can be modified to use a form of Vogel's equation (p.310) below the bubble point
( pwf < pbp ). This allows the effects of gas break-out to be modelled.

( ( ) ( ))
2
pwf pwf
Q Qbp = Qmax 1 (1 C ) C Eq. 7.65
pbp pbp

Where

Q is the liquid flow rate (STB/D or m3/d)

Qbp is the flow at the bubble point flow

Qbp Pbp is the absolute open hole flow potential, that is the liquid flow rate
Qmax = when the bottom hole pressure is zero
1+C P P
ws bp

pbp is the bubble point pressure (psia or bara)

pwf is the well flowing (or bottom hole) pressure (psia or bara)

pws is the well static (or reservoir) pressure (psia or bara)

C is the Vogel coefficient.

The Vogel equation has been shifted to match a linear IPR above the bubble point:

Q = Qbp at pwf = pbp

Q Qmax (1 + C ) Qbp at pwf = pbp

Productivity index = =
pwf pbp pws pbp

This correction only works if the bubble point pressure is less than the static (reservoir) pressure,
pbp < pws .

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Vertical Well Skin Factor

The skin factor S is used in the pseudo steady state (p.314) and transient (p.319) IPRs to
represent friction caused by damage to the formation close to the well (mechanical skin) and the
effects of high flow (dynamic skin).

S = SM + D Q Eq. 7.66

Mechanical skin factor

The pseudo steady state (p.314) and transient (p.319) IPRs are derived from Darcy's equation for
a homogenous reservoir with a vertical completion. The mechanical skin can be used to represent
friction terms arising from any departure from this idealized model. The mechanical skin has a
number of separate components:

SM = S pp + S + Sd + Sg + S p + S f Eq. 7.67

Different components are used in different completion types:

Open Open hole Perforated Gravel Packed Frac Pack

hole gravel pack & Perforated

S pp partial penetration Yes Yes Yes Yes Yes

(p.329)

S deviation (p.329) Yes Yes Yes Yes Yes

Sd damaged zone Yes Yes Yes Yes

(p.330)

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Sg gravel pack (p.330) Yes Yes Included in S f

S p perforated well Yes Yes Included in S f

(p.331)

S f frac pack (p.335) Yes

Dynamic skin factor

The pseudo steady state (p.314) and transient (p.319) IPRs are derived from Darcy's equation for
a homogenous reservoir with a vertical completion. The dynamic skin can be used to represent
friction terms arising from turbulence in the flow entering the well. The dynamic skin has a number
of separate components:

D = Dd + Dr + D + Dc + D f Eq. 7.68
g
Different components are used in different completion types:

Open hole Open hole Perforated Gravel Packed & Frac

gravel pack Perforated Pack

Dd damaged zone Yes Yes Yes Yes

Dr reservoir Yes Yes Yes Yes

Ds gravel pack screen Yes

Dg gravel pack Yes

Dc crushed zone Yes Yes

D f frac pack Yes

Formulas for these skin components can be found in Golan and Whitson (1986) (p.503). The
damaged zone, reservoir and gravel pack screen dynamic skins all use the same formula DG for
gas flow and the same formula for liquid flow DL :

Dd = { DG (rw , rd , d )
DL (rw , rd , d )
Eq. 7.69

Dr = { DG (rd , rr , r )
DL (rd , rr , r )
Eq. 7.70

Ds = { DG (rs , rw , s )
DL (rs , rw , s )
Eq. 7.71

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The general gas flow dynamic skin term is given by:

( )
k h G 1 1
DG (rin , rout , ) = 2.222 10
18
2 Eq. 7.72
h c G rin rout
The general liquid flow dynamic skin term is given by:

( )
k h L BL 1 1
DL (rin , rout , ) = 1.635 10
16
2 Eq. 7.73
h c L rin rout
The gravel pack dynamic skin for gas flow is given by:

13
k h G L pack
Dg = 2.45 10 g 4 Eq. 7.74
(2r p) 2
n p G

The gravel pack dynamic skin for liquid flow is given by:

k h L BL L
11 pack
Dg = 1.8 10 g 4
Eq. 7.75
(2r p) 2
np L

The crushed zone dynamic skin for gas flow is given by:

15
k h G
Dc = 3.84 10 c 2 2
Eq. 7.76
L p n p r p G
The crushed zone dynamic skin for liquid flow is given by:

Dc = 0 Eq. 7.77

The frac pack dynamic skin is given as the sum of the tunnel and annulus terms:

D f = Dt + Da Eq. 7.78

The frac pack dynamic skin annulus term uses the same general formula as used for the damaged
zone, reservoir and gravel pack screens:

Da = { DG (rs , rc , s )
DL (rs , rc , s )
Eq. 7.79

The frac pack dynamic skin tunnel term for gas flow:

18
k h G L tun
Dt = 2.222 10 s 4

( )
4
rp Eq. 7.80
2
den shot G
12
The frac pack dynamic skin tunnel term for liquid flow:

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k h L BL L
16 tun
Dt = 1.635 10 s 4.

( )
4 Eq. 7.81
rp 2
den shot L
12

Partial Penetration Skin

Brons and Marting (p.500) (1961) (quoted in Golan and Whitson (p.503)) expressed the effect of
partial penetration and limited entry as a skin factor :

S pp = ( Lh 1) ln( rh kr
kz
) Y Eq. 7.82
w
with
2 3 L
Y = 2.948 7.363 X + 11.45 X 4.675 X and X =
h
h Reservoir Thickness

rw Wellbore Radius

kr Reservoir Permeability

kz Completion Vertical Permeability

L Completion Open Interval or Perforated Interval

The skin factor is dimensionless. The equation for the skin factor involves ratios of permeability
and ratios of length. It is assumed the same units (e.g. md) are used for all permeability terms, and
the same units are used for all lengths (e.g. feet).

Related links:
Skin Components (p.66)

Deviation Skin
Cinco et al. (p.501) (1975) approximate the pseudo-skin factor caused by the slant of a well as :

( ) ( ) ( )
2.06 1.865
h kr
S = log 10 Eq. 7.83
41 57 100rw kz

is measured in degrees:

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kz
tan ( ) = tan( ) Eq. 7.84
kr

h Reservoir Thickness

rw Wellbore Radius

kr Reservoir Permeability

kz Completion Vertical Permeability

0 < < 75 deviation from vertical in degrees

o

The skin factor is dimensionless. The equation for the skin factor involves ratios of permeability
and ratios of length. It is assumed the same units (e.g. md) are used for all permeability terms, and
the same units are used for all lengths (e.g. feet).

Damaged Zone Skin

The effect of formation damage on productivity was treated analytically by Muskat (p.506) (1937).
Hawkins (p.504) (1956) translated the Muskat Model of a near wellbore altered permeability into
the following expression for the skin factor :

Sd = ( )
kr
ka
1 ln (d )
dw
a
Eq. 7.85

da Damaged Zone Diameter

dw Wellbore Diameter

kr Reservoir Permeability

ka Damaged Zone Permeability

The skin factor is dimensionless. The equation for the skin factor involves ratios of permeability
and ratios of length. It is assumed the same units (e.g. md) are used for all permeability terms, and
the same units are used for all lengths (e.g. feet).

Gravel Pack Skin

Two different formula are used in PIPESIM. The skin factor is dimensionless. The equations for the
skin factor involves ratios of permeability and ratios of length. It is assumed the same units (e.g.
md) are used for all permeability terms, and the same units are used for all lengths (e.g. feet).

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Open hole gravel pack skin

Assuming a radial flow through formation and gravel, the contribution to the skin is expressed as:

Sg =
kr
kg
ln ( ) rev
rs
Eq. 7.86

rev Reservoir Drainage Radius

rs Screen Radius

kr Reservoir Permeability

kg Gravel Permeability

Compare this with the Annulus skin (p.337) for a Frac Pack.

Gravel pack skin

Applying Darcy's law for linear flow in packed perforations for the steady state skin term due to
gravel pack gives :

kr h lt
Sg = 2 2
Eq. 7.87
kg n rp
where

lt = lt + ric rs

h Reservoir Thickness

lt Tunnel Length

ric Casing Internal Radius

r p Perforation Radius

Compare this with the Gravel skin (p.337) for a Frac Pack.

Perforated Well Skin

McLeod Model
McLeod (p.331) (1983) used a model of a horizontal microwell with formation damage around it
as an analogy to a perforation surrounded by a crushed zone. He quantified the effect of the
crushed zone as the following skin factor :
Compacted or crushed zone

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Sp =
np L
1

h
lp
(
kr

kc ka
kr
) (
ln
dc
dp
) Eq. 7.88

where:

h Reservoir Thickness
L Completion Open Interval or Perforated Interval

n p Perforation Density

l p Depth of Penetration (or perforation length)

dc Compacted Zone Diameter

d p Perforation Diameter

kr Reservoir Permeability

kc Compacted Zone Permeability

ka Damaged Zone Permeability

Karakas Model
Karakas and Tariq (p.504) (1991) have developed a semi analytical solution for the calculation of
the perforation skin effect. Depending on the size of the damaged zone and the length of the
perforation , the well radius and the perforation length, or their modified value are used in the
model .
The thickness of the damaged zone is :
1
la = (d dw ) Eq. 7.89
2 a
For perforation sitting inside the damaged zone :

}

rw = rw

if l p la Eq. 7.90
lw = lw
For perforations extending beyond the damaged zone

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( )
}

ka
rw = rw + 1 la
kr
if l p > la Eq. 7.91

lp = lp 1 ( ) ka
kr
la

rw Wellbore Radius (dw / 2)

rw Wellbore Radius or modified Wellbore Radius

l p Perforation Length or modified Perforation Length
The perforation skin effect is divided into the following components :

Horizontal Component of the skin

( )

rw
Sh = ln
Eq. 7.92
rwc
where

rwc = ( ) rw + l p Eq. 7.93

Phase Angle
( ) Function of phase angle (see table 7.1 (p.334))
Well bore skin

rw
Sw = c1exp c2 Eq. 7.94
(l p + rw )
with

c1 = c1( ) and c2 = c2( ) Functions of the phase angle (see table 7.1 (p.334))

Vertical skin
A B 1 B
Sv = 10 H n Rn Eq. 7.95

with

1 kr
Hn =
n p l p kz

Rn =
npd p
4
1+
kz
kr
( )
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A = a1( ) log 10Rn + a2( )

B = b1( )Rn + b2( )

a1( ), a2( ), b1( ) and b2( ) functions of phase angle (see table 7.1 (p.334))

The equation 7.95 (p.333) is valid for H n 10 and Rn 0.01

Crushed zone effect

Sck =
1
n p l p kc
( )(
kr
1 ln
dc
dp
) Eq. 7.96

The combined skin effect caused by perforations added to the crushed zone effects is given by :

St = Sh + Sw + Sv + Sck Eq. 7.97

If the perforations go beyond the damaged zone, the total perforation skin is the sum of these four
contributions :

St = St for l p > la Eq. 7.98

Damaged zone effect

For perforations within damaged zone, the skin caused by the combined effects of perforations and
damage is :

St = ( )( )
kr
ka
1 ln
da
dw
+
kr
ka
(St + S x ) for l p l a
Eq. 7.99
da
S x = S x (r ) and r =
dw + 2l p
r Ratio of the damaged zone diameter over the penetration zone diameter
S x (r ) function of r (see table 7.2 (p.335))

(degre) 45 60 90 120 180 360 (0)

0.860 0.813 0.726 0.648 0.500 0.250
a1 1.788 1.898 1.905 2.018 2.025 2.091

a2 0.2398 0.1023 0.1038 0.0634 0.0943 0.0453

b1 1.1915 1.3654 1.5674 1.6136 3.0373 5.1313

b2 1.6392 1.6490 1.6935 1.7770 1.8115 1.8672

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5 4 3 3 2 1
c1 4.6 10 3.0 10 1.9 10 6.6 10 2.6 10 1.6 10

c2 8.791 7.509 6.155 5.320 4.532 2.675

Table 7.1: Karakas and Tariq Skin Correlation Coefficients

r = da / (dw + 2l p ) S x
18.0 0.000
10.0 0.001
2.0 0.002
1.5 0.024
1.2 0.085
Table 7.2: Skin caused by boundary effect, 180 degree phasing

Frac Pack Skin

The Frac Pack Skin is calculated only in association with a case hole gravel pack. If the gravel
pack is not defined the Frac Pack Skin is 0.
Pucknell and Mason (p.508) (1992) give a review of the contributions to the skin in a cased hole
gravel pack completion.

S f = Shf + S ff + Scf + San + Stg

Shf Hydraulic fracture (p.335)

S ff Fracture face skin (p.336)

Scf Choke fracture skin (p.337)

San Annulus skin (p.337)

Stg Tunnel gravel skin (p.337)

The skin factor is dimensionless. The equations for the skin factor involves ratios of permeability
and ratios of length. It is assumed the same units (e.g. md) are used for all permeability terms, and
the same units are used for all lengths (e.g. feet).

Hydraulic fracture
The following model is also applied in IPR Model Hydraulic Fracture.
Hydraulic fracture is characterized by its length, capacity or conductivity and related equivalent skin
effect. Prats (p.508) (1961) introduced the concept of effective wellbore radius, providing pressure
profiles in a fractured reservoir as functions of the fracture half-length and a relative capacity. He
provided a graph relating the effective well radius and the capacity. Cinco-Ley et al. (p.501) (1978,
1981a) (see also Economides et al. (p.502) 1994) introduced the fracture conductivity instead,

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which is proportional to the inverse of the capacity, and provided an alternative graph relating the
fracture conductivity to the skin. The following correlations are derived from Cinco-Ley and
Samaniego graph.
Dimensionless fracture conductivity:

kp w f
F cd = Eq. 7.100
kr x f
Pseudo-skin factor for a well with a finite-conductivity vertical fracture

{
( )
0.7205 * ln F cd + 1.6368 if F cd < 1
3.0386 2.349exp ( 0.511 F cd )
0.909
Shf = if 1 F cd < 1000 Eq. 7.101

0.692 if F cd 1000
and the hydraulic skin is given by:

Shf = Shf ln ( )
xf
rw
Eq. 7.102

x f Fracture Half Length

w f Fracture Width

kr Reservoir Permeability

k p Proppant Permeability

rw Wellbore Radius

Damaged hydraulic fracture performance can deviate substantially from undamaged fracture. Two
types of damage are considered: fracture face (p.336) and choke fracture (p.337).

Fracture Face Skin

Cinco-Ley and Samaniego (p.501) (1981b) quantified the damage that may develop on the
fracture face, by a skin effect of the form

S ff =
waf
2

xf

kr
kaf
1( ) Eq. 7.103

waf Depth of Damage (normal to the fracture face) is very thin (0.2 ft or less)

kaf Frac Face Damage Permeability

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Choke Fracture Skin

Damage at the connection between the fracture and a well is referred to as a choke. Different to
the fracture face skin, the damaged zone is within the fracture. Romero et al. (p.508) (2002)
express the extra pressure drop in the fracture in term of a skin effect:

Scf =
xcf
xf
( kr
kcf

kr
kp
) Eq. 7.104

xcf Choke Length

kcf Frac Choke Permeability

Annulus Skin
Between the casing internal radius and the screen outer radius, assuming a radial flow through the
gravel the contribution to the skin is expressed as:

San =
kr
ln (d )ic
Eq. 7.105
kg ds

dic Casing Internal Diameter

ds Screen Diameter

kg Gravel Permeability

Gravel Skin in tunnel

If a perforation is not defined, a default perforation diameter and a default perforation density are
set (equal to 0.5 inches and 4 shots/ft respectively) for the calculation of the Frac Pack Skin. If the
perforation tunnels through the casing and cement, where the most significant pressure drops
usually occur, the skin component is:

kr lt
Stg = 2 2
Eq. 7.106
kg np r p

lt Tunnel length

n p Perforation Density

r p Perforation radius

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7.2.2 Inflow Performance Relationships for Horizontal Completions

Theory
The main purpose of drilling horizontal wells is to enhance production. There are also many
circumstances that lead to drilling horizontal wells (Cooper, 1988):
Thin reservoirs
The increased area of contact of the horizontal well with the reservoir is reflected by the
productivity index (PI). Typically, the PI for a horizontal well may be increased by a factor
of 4 when compared to a vertical well penetrating the same reservoir.
Heterogeneous reservoirs
When irregular reservoirs exist, the horizontal well can effectively intersect isolated
productive zones which might otherwise be missed. A horizontal well can also intersect
vertical natural fractures in a reservoir.
Reduce water/gas coning
A horizontal well provides minimum pressure drawdown, which delays the onset of
water/gas breakthrough. Even though the production per unit well length is small, the long
well length provides high production rates.
Vertical permeability
If the ratio of vertical permeability to horizontal permeability is a high, a horizontal well may
produce more economically than a vertical well.

Pressure Drop
Effect of Pressure Drop on Productivity
In many reservoir engineering calculations, the horizontal wellbore is treated as an infinite
conductivity fracture, that is the pressure drop along the well length is negligible. However, in
practice, there must be a pressure drop from the toe (tip-end) of the horizontal wellbore to the heel
(producing-end) so as to maintain fluid flow within the wellbore (see Figure 1).
Dikken (1989), Folefac (1991) and Joshi (1991) have addressed the effect of wellbore pressure
gradient on horizontal well production performance.

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Figure 7.1. Along-hole pressure gradient of a horizontal well (Joshi, 1991)

Dikken (p.502) (1990) and Folefac (p.503) (1991) contend that the assumption of constant
pressure wellbore is reasonable for single phase laminar flow but is no longer valid when turbulent
or multiphase flow occurs. Folefac (1991) showed that a typical well with the following properties:
o = 800 kg/m3; = 1.0 cp; d = 0.1968 m; and Q = 5000 RB/d gives a N RE of 4000 which is well
above the turbulence transition limit of 2000. In most practical situations, Dikken (1990) asserts
that horizontal wells will exhibit non-laminar flow. In addition, the pressure drop will be even greater
when multiphase flow exists.
Joshi (p.504) (1991), thus, asked the question: What is the magnitude of the wellbore pressure
drop as compared to pressure drop from the reservoir to the wellbore? If the wellbore pressure
drop is significant as compared to the reservoir drawdown, then the reservoir drawdown, and
consequently, the production rate along the well length will change. Thus, there is a strong
interaction between the wellbore and the reservoir. The reservoir flow and wellbore equations must
be solved simultaneously as shown in Figure 2.

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Figure 7.2. Schematic of reservoir and flow relationship (Joshi, 1991)

The coupled equations were solved by Dikken (1990) analytically by simplified boundary
conditions, notably, no inflow from the toe-end. Folefac (1991) used a Black Oil type model that
involved a finite volume technique.
Folefac (1991) concluded that the well length, wellbore diameter and perforated interval had the
most profound effect on the level of pressure drop in the wellbore. Folefac (1991) pointed out that
the wellbore pressure profile is non-linear with respect to the well length. This is because the
mixture momentum equation has a non-linear term in velocity, the friction force. This in turn will
result in an uneven drawdown in the reservoir that is otherwise considered homogenous.
Furthermore, Folefac (1991) showed that as the wellbore radius increased from 64.5 mm (2.5") to
114.3 mm (4.5"), the rate at which pressure dropped along the wellbore became nearly constant.
This is mainly due to the turbulent flow being converted to laminar flow by drilling a larger size hole.
Joshi (1991) mentions other situations where wellbore pressure drop is considerable:
High flowrates of light oil (10,000 to 30,000 RB/d)
High viscous crudes (heavy oils and tar sands)
Long well lengths
The wellbore pressure drop effects well deliverability and in turn influences well completion and
well profile design. The need to accurately calculate well flowrates and wellbore pressures is
therefore, essential.
Joshi (1991) lists a few remedies to minimize high wellbore pressure drops:
Drilling a larger diameter hole would dramatically reduce the pressure drop. The reason being
that for single phase flow, D P a 1/d5. For example, Joshi (1991), states " for a given production
rate, by increasing the well diameter twofold, the pressure drop can be reduced at least thirty-
two fold".

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Varying the shot density of a cemented hole or the slot size of a slotted liner would control
production rates and minimize pressure drop along the wellbore
Gravel packs are used in high permeability reservoirs. If the well is completed with a slotted
liner, the slots should be placed as far apart as possible. Joshi (1991) states that "this will let
the gravel pack act as a choke and facilitate maintaining minimum pressure drop across the
well length".
Therefore, by selecting the appropriate well geometry, hole size and length, wellbore pressure
drops can be minimized.

Single Phase Pressure Drop

Assuming that the horizontal wellbore can be treated as a horizontal pipe, the single phase flow
pressure drop calculation for oil flow can be written as follows:

(
p = 1.14644 10
5
) fq 2 L 5 Eq. 7.107
D
where,
p is pressure drop, psia
f is Moody's friction factor, dimensionless
fluid density, gm/cc
q is flowrate at reservoir conditions, RB/d
L is horizontal length, ft
D is internal diameter of pipe, inches
For gas flow, however, the pressure drop calculations are more complex. This is due to friction
which could change the temperature of the gas as it travels through the wellbore. Moreover,
density and viscosity are strong functions of gas pressure and temperature. This would result in a
changing pressure drop per foot length of a well along the entire well length. The Weymouth
equation for dry gas is the simplest equation to estimate pressure drop in a horizontal pipe

qg = 15320
( 2
p1 p2 D
2
) 16
3
Eq. 7.108
g TZL
where

qg is gas flowrate, scfd

p1 is pipe inlet pressure, psia

p2 is pipe outlet pressure, psia

L is pipe length, miles
T is average temperature, oR
Z is average gas compressibility factor

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D is pipe diameter, in
g gas specific gravity
Also, several multiphase correlations (Brill, 1988) are applicable for a single phase flow of either oil
or gas.

Multiphase Pressure Drop

There is very little discussion on multiphase pressure drop in horizontal wells. Folefac (1991)
studied the effect of two phase flow (hydrocarbon liquid and water are treated as one phase with
identical velocity but averaged properties). The pressure drop along the horizontal wellbore was
similar to that for single phase flow. However, the pressure drop was higher than for single phase
flow for the same volume of fluid intake.
For a horizontal pipe, numerous multiphase flow correlations have been discussed by Brill (p.500)
(1988). Slip velocities between phases make these equations more complex than single phase
flow equations. In general, Joshi (1991) states that, "different multiphase correlations may give
different values of the pressure drop". The various correlations should be compared with actual
pressure drop data. However, measuring the pressure at both ends of a horizontal well and
calibrating the data is very difficult. There is a definite need for further study on multiphase flow in
horizontal wells.

Inflow Production Profiles

Horizontal wellbore pressure drops also depend upon the type of fluid inflow profiles. Figure 3
shows some horizontal well fluid inflow profiles. On the basis of well boundary condition and
reservoir heterogeneity, several profiles are possible. Joshi (1991) examined the effect of different
fluid entry profiles on the wellbore pressure drop. Depending on the type of profile, Joshi concluded
that the total pressure drop varied from 6 psi to 14.5 psi but it was not large enough to effect the
wellhead pressure.

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Figure 7.3. Horizontal Well Inflow Profiles (Joshi, 1991)

Steady-State Productivity
The simplest form of horizontal well productivity calculations are the steady-state analytical
solutions which assume that the pressure at any point in the reservoir is constant over time.
According to Joshi (1991), even though very few reservoirs operate under steady-state conditions,
steady state solutions are widely used because:
Analytical derivation is easy.

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The concepts of expanding drainage boundary over time, effective wellbore radius and shape
factors allows the conversion to either transient or pseudo-steady state results to be quite
straightforward.
Steady-state mathematical results can be verified experimentally.
Giger (1984), Economides (1989), Mukherjee (1988) and numerous others have developed
solutions to predict steady-state productivity. Most are similar in form to the equation given by
Joshi (1988) who simplified the 3-D Laplace equation (p=0) by coupling two 2-D problems. This
was based on the assumption that a horizontal well drains an ellipsoidal volume around the
wellbore of length L as shown below.

Figure 7.4. Horizontal Well Drainage Pattern

For isotropic reservoirs kh = kv

kh h p
qh =

( )
2 2

( )
a + a ( L / 2) h h Eq. 7.109
141.2 o Bo ln + ln
L /2 L 2rw
and
0.5

( )
4

a= ( L2 ) 0.5 + 0.25+
2reh
L
Eq. 7.110

where

qh is the flowrate STB / d

a is half the major axis of the drainage ellipse ft

p is the pressure drop psi
L is the horizontal well length ft
h is reservoir height ft
rw is the wellbore radius ft

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reh is the effective drainage radius of horizontal well ft

o is the oil viscosity cp

Bo is the oil volume formation factor RB / STB

kh is the horizontal permeability mD

If the length of the horizontal well is significantly longer than the reservoir height, that is L >> h,
then the second term in the denominator of the 7.109 (p.344) equation is negligible and the
solution simplifies to

kh h p
qh =
4r eh Eq. 7.111
141.2 o Bo ln
L
Muskat (p.506) (1937) suggested a simple transformation to account for permeability anisotropy.
An effective permeability, keff , is defined as

keff = kv kh Eq. 7.112

To account for vertical anisotropy, the reservoir thickness can be modified as follows

kh
h =h Eq. 7.113
kv
In addition, the influence of well eccentricity (distance from the center of the reservoir in the vertical
plane) was also implemented. Thus, equation 7.109 (p.344) was transformed as follows

kh h p
qh =

( ( ))
2 2
a + a ( L / 2) 2 h h Eq. 7.114
141.2 o Bo ln + ln
L /2 L 2r w
where

kh
= Eq. 7.115
kv
Productivity comparisons of a horizontal well to that of a vertical well can easily be made by using
the 7.114 (p.345) equation. In converting the productivity of a horizontal well into that of an
equivalent vertical well, an effective wellbore radius can be calculated, rw,eff

rw ,eff = rw exp ( S ) Eq. 7.116

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The effective wellbore radius is defined as the theoretical well radius which will match the
production rate. Joshi (1991) assumed equal drainage volumes, reh = rev , and equal productivity
indices, J h = J v to give the following for an anisotropic reservoir

( L2 )
r
rw ,eff =
1( ) +
L
2
h
h Eq. 7.117
a 1+ L
2a rw

In this way, controlling parameters like well length, permeability and formation thickness can be
used to screen potential candidates for further simulation studies.
Renard (p.508) (1990) studied the effect of formation damage around the wellbore and modified
the steady-state equation to include skin. Renard (1990) concluded that due to the lower
productivity index per unit length in horizontal wells, the effect of skin damage is not as pronounced
as it is in vertical wells. Celier et al. (p.500) (1989) came to the same conclusion with respect to
the effect of non-Darcy flow.

Pseudo-Steady State Productivity

It is often desirable to calculate productivity from a reservoir with unique boundary conditions, such
as a gas cap or bottom water drive, finite drainage area, well location, and so on. In these
instances pseudo-steady state equations are employed. Pseudo-steady state or depletion state
begins when the pressure disturbance created by the well is felt at the boundary of the well
drainage area

Pseudo-Steady State Productivity

Dake (p.501) (1978) and Golan (p.503) (1986) describe the pseudo-steady state flow of an ideal
fluid (liquid) in a closed circular drainage area. Rearranging the equation gives the familiar vertical
well productivity
khp
qv =
2.2458 A Eq. 7.118
141.2 o Bo ln ( 2 ) + S + Sm + Dqv
CArw
where

qv is the flowrate STB / d

p is the pressure drop between the reservoir and the wellbore psi
Sm is the mechanical skin factor due to drilling and completion related well damage

S is the skin due to perforations, partial penetration and stimulation

CA is the shape factor

Dqv is the near wellbore turbulence factor or rate dependent skin

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o is the oil viscosity cp

Bo is the oil volume formation factor RB / STB

k is the formation permeability mD

h is the formation thickness ft
A is the drainage area ft
2

rw is the wellbore radius ft

reh is the drainage radius ft

The above equation can be reduced to the following single-phase pseudo-steady state equation for
oil flow (assuming S = 0, Sm = 0 and Dqv = 0),

kh p
qv =
141.2 o Bo ln ( )
reh
rw
0.75
Eq. 7.119

The equation is for a vertical well which is located in the center of a circular drainage area.
Fetkovich (p.502) (1985) wrote the shape factor in terms of an equivalent skin. This skin was
expressed by choosing a reference shape factor of a well at the center of circular drainage area

CAref
SCA = ln Eq. 7.120
CA
The horizontal well shape factor depends on the following:
drainage area shape,
well penetration.

dimensionless well length, L D =

2h( )
L kv
kh

L is the length of the horizontal well ft

h is the formation thickness ft
kv is the vertical permeability mD

kh is the horizontal permeability mD

Joshi (p.504) (1991) explains that the well performance approaches a fully penetrating infinite-
conductivity fracture when the horizontal well length is sufficiently long, i. e. L D > 10.

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Babu (p.499) (1989), Goode (p.503) (1989) and Mutalik (p.507) (1988) have developed methods
to calculate pseudo-steady state productivity for single phase flow in horizontal wells. Shape
factors were used to arbitrarily locate the well within a rectangular bounded drainage area and the
reservoir was bounded in all directions. Mutalik's model assumed the horizontal well as an infinite
conductivity well (i.e. the wellbore pressure drop is negligible). Babu's model assumed uniform-flux
boundary condition. Goode's model used an approximate infinite conductivity solution where the
constant wellbore pressure is estimated by averaging the pressure values of the uniform-flux
solution along the well length. Goode (1989) also considered the effects of completion type on
productivity. Their model allowed for cased completion, selectively perforated completion, external
casing packers to selectively isolate the wellbore and slotted liner completion with selectively
isolating zones.
Babu (1989) developed a physical model consisting of a well drilled in a box-shaped drainage
volume, parallel to the y direction (see figure 7.5 (p.348)).

Figure 7.5. Babu and Odeh physical model

The derived pseudo-steady productivity equation is

3
7.08 10 b k x k z p
qh =
o Bo ln ( )
A1
rw
+ ln CH 0.75 + SR
Eq. 7.121

where

b is extension of the drainage volume in the direction along the well axis Oy ft

SR is the skin factor due to partial penetration

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CH is the geometric shape factor defined by Babu (1989)

k x is the permeability along the x-axis mD

kz is the permeability along the z-axis mD

A1 is the drainage area in the vertical plane

2
ft

rw is wellbore radius ft

The validation rules for Babu and Odeh IPR model are:
1. Heel location (X position) must be from 0.0 to ReservoirXDim. In the original publication (see
Babu and Odeh 1989), the requirement in the x-direction for the second case considered is that
heel location (X position) must be from ReservoirXDim * 0.25 to ReservoirXDim * 0.75. While
this requirement is not enforced in this product, user should take caution when operating
outside of the requirement.
2. Heel location (Y position) + well length must be less than or equal to the reservoir Y
dimension. Also, heel location (Y position) must be greater than or equal to zero.
3. Heel location (Z position) + well radius must be less than or equal to the reservoir thickness.
Also, heel location (Z position) must be greater than or equal to well radius.
The equation 7.121 (p.348) is derived from a very complex general solution. It requires the
calculation of CH and S R . The geometric shape factor accounts effect of permeability anisotropy,
well location and relative dimensions of the drainage volume. The skin accounts for the restricted
entry associated with the well length. Babu (1989) reported an error of less than 3% when
compared to the more rigorous solution.

Solution Gas-Drive IPR

Cheng (1990), Joshi (1991) and Bendakhlia (1989) have studied the inflow performance
relationship (IPR) for solution gas-drive reservoirs. Bendakhlia followed the same approach used
by Vogel for vertical wells and developed the following equation:
2 n
q0
q0,max
= 1V ( )
pwf
pR
1V ( )
pwf
pR
Eq. 7.122

The equation can be used under the assumptions of Vogel's original IPR correlation. The
parameter V and n were correlated as a function of recovery factor.

Horizontal Gas Wells

The preceding sections have dealt with oil flow. However, horizontal wells are also appropriate for
gas reservoirs. For example, in high-permeability gas reservoirs wellbore turbulence limits the
deliverability of a vertical well. The most effective way, according to Joshi (p.504) (1991), to
reduce gas velocity around the wellbore is to reduce the amount of gas production per unit well

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length which can be accomplished by horizontal wells. Joshi (1991) describes two methods for the
relationship between pressure and flowrate.
The gas flowrate is proportional to the pressure square terms.
Al-Hussainy et al. (p.499) (1966) defined a pseudo-pressure m(p). The gas flowrate is directly
proportional to the pseudo-pressures which is defined as
p
m( p ) = p0
2 pdp
p )z ( p )
(
Eq. 7.123

A comparison of the two methods was done by Joshi (1991). Below reservoir pressures of 2500
psia, either method can be employed. However, above 2500 psia, the pseudo-pressure should be
used.

Steady state gas flow equation

The steady-state equation for gas flow is
4
7.027 10 kh h pe pwf ( 2
)
2

qh =
ZT ln ( ) reh
rw

Eq. 7.124

where

qh is the gas flowrate mmscf / d

pe is the pressure at external radius psia

pwf is the wellbore flowing pressure psia

kh is the horizontal permeability mD

h is the reservoir height ft

reh is the drainage radius ft

rw
is the effective wellbore radius ft

is the average viscosity cp

Z is the average compressibility factor
T is the reservoir temperature o
R

Pseudo steady state gas flow equation

The pseudo-steady state gas flow equation can be written as follows (Joshi, 1991)

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4
( 2
7.027 10 kh pr pwf
2
)
qh =
reh Eq. 7.125
ZT ln 0.75 + S + Sm + Sca C + Dqh
rw
where

2.222 10 ( G kah )
15

D= 2 Eq. 7.126
pwf rw h p

In equation 7.126 (p.351), the high velocity flow coefficient is given by:
10 1.1045
= 2.73 10 ka Eq. 7.127

where

qh is the gas flowrate mmscf / d

pr is the average reservoir pressure psia

pwf is the wellbore flowing pressure psia

S is the negative skin factor due to horizontal well (or well stimulation)

Sm is the mechanical skin damage

Sca is the shape related skin factor

C is the shape factor conversion constant

k is the permeability mD
h is the reservoir height ft
reh is the drainage radius ft

rw is the wellbore radius ft

is the average viscosity cp

Z is the average compressibility factor
T is the reservoir temperature o
R

pwf is the gas viscosity at well flowing conditions cp

is the high velocity flow coefficient 1 / ft

G is the gas specific gravity dimensionless

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hp is the perforated interval ft

ka is the permeability in the near wellbore region mD

The equation 7.125 (p.351) is based upon circular drainage area as a reference area. In this
equation, Dqh is the turbulence term, also called turbulence skin, or rate dependent skin factor .
(see Joshi (p.504) (1991), Brown (p.500) (1984) and Golan and Whitson (p.503) (1986)). This
term accounts for the extra pressure drop in the near wellbore region due to high gas velocity. This
term was neglected when dealing with oil flow. In addition, the term makes the solution of 7.125
(p.351) iterative.
The equation 7.127 (p.351) is given in Golan and Whitson (p.503) (1986)

Conclusions
The following can be concluded from this review:
The assumption of constant pressure drop in the wellbore is no longer valid, especially for long well
lengths and when turbulent/multiphase flow occurs.
More realistic production geometries are being used in the existing models to calculate horizontal
well productivity.
Existing models need to be verified and validated with actual field data. The absence of case
studies in the literature is indicative of the 'tight-hole' status of most horizontal well projects.

Distributed Productivity Index Method

for liquid reservoirs

Q = J (Pws Pwf ) L Eq. 7.128

for gas reservoirs

( 2
Q = J Pws Pwf L
2
) Eq. 7.129

where J is the distributed productivity index.

7.2.3 Oil / Water Relative Permeability tables

( ) (
A table of oil and water relative permeabilities as functions of water saturation (kro Swat , krw Swat ))
can be defined in conjunction with the Pseudo Steady-State (p.314) or Tranisent (p.319) liquid
IPRs for vertical completions or the Steady State (p.343) or Pseudo-Steady State (p.346) liquid
IPRs for horizontal completions.
If the reservoir water saturation is known, the water cut of the fluid flowing into the well can be
calculated:

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Qw krw (Swat ) / w
WCUT = 100 = 100 Eq. 7.130
Qo + Qw kro (Swat ) / o + krw (Swat ) / w
Alternatively, if the water cut is known, the water saturation can be found by solving the same
equation for the water saturation, Swat .
The oil and water inflows can then calculated separately using the relevant liquid IPR equation and
summed to give the liquid flow rate.

Keywords
Data is entered, in keyword mode, using the additional engine keyword feature (p.511). Use the
PERMTAB (p.585) keyword to define the table. Use the LAYER keyword to define the reservoir
water saturation, if required.
See also other IPR methods (p.308)

7.2.4 Coning
In order to simulate gas and/or water breakthrough from the reservoir, flowrate-dependent values
of GOR and watercut may be entered. In a homogeneous reservoir, analysis of the radial flow
behavior of reservoir fluids moving towards a producing well shows that the rate dependent
phenomenon of coning may be important. The effect of increasing fluid velocity and energy loss in
the vicinity of a well leads to the local distortion of a gas-oil contact or a water-oil contact. The gas
and water in the vicinity of the producing wellbore can therefore flow towards the perforation. The
relative permeability to oil in the pore spaces around the wellbore decreases as gas and water
saturation increase. The local saturations can be significantly different from the bulk average
saturations (at distances such as a few hundred meters from the wellbore). The prediction of
coning is important since it leads to decisions regarding:
Preferred initial completions
Estimation of cone arrival time at a producing well
Prediction of fluid production rates after cone arrival
Design of preferred well spacing

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7.3 Equipment
7.3.1 Chokes, Valves and Fittings
Choke
A choke is a mechanical device that limits the flow rate through the pipe. The fluid velocity
increases through the constriction and for compressible fluids can reach the sonic velocity. As the
pressure difference across the choke increases the flow velocity increases too. At the point the
velocity becomes sonic, the flow is said to be critical, and is independent of the down stream
pressure. See Brill and Mukerjee (p.506) (1999) for a detailed description of flow through chokes
and restrictions.

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Figure 7.6. Typical flow-pressure relationship for a choke

The choke is modeled by splitting the flow into two regimes:

flow is subcritical P < P

crit down < Pup q < qcrit
flow is critical 0 < P down < Pup q = qcrit

where

Pup is the upstream pressure

/ 2
psi or lbf in N /m
2

Pdown is the downstream pressure psi or lbf / in N /m

2 2

is the critical (downstream) pressure psi or lbf / in N /m

2 2
Pcrit
q is the flow rate lb / s kg / s
qcrit is the critical flow rate lb / s kg / s

The choke performance is determined by the following:

1. The choke geometry and fluid properties
2. The subcritical flow correlation
3. The critical pressure ratio
4. The critical flow correlation

Choke geometry
The main choke parameters are:

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dup upstream diameter in

dbean constriction (bean) diameter in

cv flow coefficient (used in the Ashford & Pierce (p.357) correlation)

cvL liquid flow coefficient (used in the Mechanistic (p.359) correlation)

cvG gas flow coefficient (used in the Mechanistic (p.359) correlation)

cd discharge coefficient (used for calculating the flow coefficients)

The flow coefficients can either be specified or calculated from the discharge coefficient:

cd
cv = 4
Eq. 7.131
1
where:

dbean is the diameter ratio dimensionless

=
dup

Subcritical flow correlations

There are essentially two subcritical flow models used in PIPESIM, the Mechanistic (p.359)
correlation and Ashford and Pierce (p.357) (1975) correlation . A third correlation API-14B (p.360)
is a modification of the Mechanistic correlation

Critical pressure ratio

For single phase liquids, the sonic velocity is high and flow is always subcritical. For single phase
gas flow and multiphase flow, the critical pressure is given by

Pcrit = CPR Pup Eq. 7.132

The value of the critical pressure ratio CPR can be set by the user or calculated (p.360).

Critical flow correlations

A critical flow correlation can be used to set the critical flow rate qcrit . There is a danger that this will
not match the subcritical flow at the critical pressure ratio. PIPESIM therefore adjusts the
subcritical flow correlation to ensure the flow is correct at the critical pressure. To do this it first
calculates the subcritical flow at the critical pressure:

qlim = qsub(Pup , Pdown ) evaluated at Pdown = Pcrit

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The choke downstream pressure is then calculated from the subcritical correlation using the
( )
upstream pressure and a scaled flow rate qlim/ qcrit q . This matching can be turned off, in which
case the critical flow correlation is ignored when calculating the pressure drop, although it is used
for reporting purposes.
One of twelve correlations of four distinct types can be selected for the critical flow:
1. Mechanistic (p.361), API-14B (p.361)
2. Ashford Pierce (p.361), A-P Tulsa, Poettmann-Beck (p.361)
3. Omana (p.361)
4. Achong (p.362), Baxendale (p.362), Gilbert (p.362), Pilehvari (p.362), Ros (p.362), User
defined (p.362)

Engine keywords
See Choke keyword (p.589)

Choke Subcritical Flow Correlations

Two subcritical flow correlations, Ashford-Pierce (p.357) and Mechanistic (p.359) are available. A
third, API 14B (p.360) is a version of the mechanistic correlation.

Ashford-Pierce
Ashford-Pierce (1975) (p.499) give the following equation for oil flow rate through a choke:
2
c1cv (64dbean ) (
1 + RL 1
k
)/k o + c3 G Rs + F wo w
1 Eq. 7.133
qo = Pup 1/
c2 1 + RL Bo + F wo o + c3 G R + F wo w
where

Bo is the oil formation factor volume factor bbl / STB

c1 = 3.51 is a constant

c2 = 198.6 is a constant

c3 = 0.000217 is a constant

cv is the flow coefficient

dbean is the bean diameter 1 / 64 in

1 dimensionless
k=

F wo is the upstream water to oil ratio

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Pup is the upstream pressure

Pdown is the downstream pressure

qo is the oil flow rate at standard conditions bbl / d

Rs is the upstream gas oil ratio scf / STB

R is the gas oil ratio at standard conditions scf / STB

T up Zup (R Rs ) is the upstream gas liquid ratio dimensionless

RL =
198.6 Pup

Pdown is the pressure ratio dimensionless

=
Pup

Cp is the ratio of specific heats dimensionless

=
CV

o is the upstream oil specific gravity dimensionless

G is the upstream gas specific gravity dimensionless

w is the upstream water specific gravity dimensionless

The Ashford and Pierce formula is based on the following assumptions:

polytropic expansion of gas-liquid mixture
equal gas and liquid velocities at the throat
incompressible liquid phase
liquid dispersed in a continuous gas phase
negligible friction losses

Recommended values for the flow coefficient cv are:

diameter in 1/64 in d
bean
8 0.125 1.2
12 0.1875 1.2
20 0.3125 0.976
24 0.375 0.96
32 0.5 0.95

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Mechanistic Correlation
The pressure drop across the choke is given by the weighted average of the liquid and gas phase
pressure drops:

P = L pL + G pG Eq. 7.134

The liquid phase pressure drop is given by Bernouilli's equation:

2

( )
n v
pL = Eq. 7.135
2c c Z
vL L

The gas phase pressure drop is given by Bernouilli's equation:

2

( )
n v
pG = Eq. 7.136
2c
cvG Z
G

q is the mixture velocity through ft / s m/s

v= the choke
Abean
n

q is the mass flow rate lb / s kg / s

dbean
2 is the choke area at the ft
2
m
2

Abean = constriction
4
is the no-slip density lb / ft kg / m
3 3
n = L L + G G

L and G are the liquid and gas phase

flowing fractions
are the liquid and gas phase lb / ft kg / m
3 3
L and G
densities

Z L = 1 and are the liquid and gas

compressibilities
4
0.41 + 0.35 P
ZG = 1
Pup
c is a conversion factor for c = 144 g c=1
engineering units
lb / ( ft s ) / psi
2

Total pressure drop for the two-phase system is therefore:

2
n v L G
P = + Eq. 7.137
2c 2 2
(cvL ZL ) (cvG ZG )

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API 14-B Formulation

The API 14-B formulation is similar to the mechanistic formulation, with the addition of the following
assumptions:
1. Liquid flow through the choke is incompressible. The discharge coefficient is constant with a
value of

cvL = 0.85.
2. Subcritical gas flow through the choke is adiabatic and compressible. The discharge coefficient
is constant with a value of

cvG = 0.9.

Choke Critical Pressure Ratio

The critical pressure ratio CPR is used to determine the downstream pressure when critical flow
occurs in the choke. You can set a value of CPR or it can be calculated, either from the single-
phase gas formula (used with the Mechanistic subcritical flow correlation) or using the Ashford and
Pierce formula (used with the Ashford and Pierce subcritical flow correlation).

Single phase gas critical pressure ratio

For a single phase gas flow, the critical pressure is given as a function of the specific heat ratio:

2 1
CPR = Eq. 7.138
+1

/
The value of = CP CV is calculated by the program, but can be overridden by the user. For
diatomic gases (for example air) 1.4 and CPR = 0.53

Ashford and Pierce critical pressure ratio

qo
Ashford-Pierce (1975) (p.499) give the critical flow condition = 0 at = CPR . 7.133 (p.357) for

qo and simplifying gives:

1 + RL 1 ( k
)/k
=0 Eq. 7.139
1 + RL
1/

This can be manipulated to give an equation for = CPR :

1/ 2
2 RL
(1 + RL ) =


+1
( (
1 + RL 1
k
) / k) Eq. 7.140

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Choke Critical Flow Correlations

The following choke correlations are available:

Ashford and Pierce / Sachdeva / Poetmann-Beck

The Ashford-Pierce (1975) (p.499) critical flow can be obtained by evaluating 7.133 (p.357) at
= CPR , determined from 7.140 (p.360). The stock tank critical oil flow rate takes the form:
2
c1cv (64dbean ) 1 + RL 1 ( k
)/k o + c3 g Rs + F wo w
1 Eq. 7.141
qo = Pup 1/
c2 1 + RL Bo + F wo o + c3 g R + F wo w
The Sachdeva (p.499) critical flow correlation takes a similar form:

2 RL + 0.76 1
qo = 0.858cv (64dbean ) Pup
RL + 0.56 Bo + F wo
Eq. 7.142
1
2 1
(62.4( o + c3 g R + Fwo w )) + (62.4( o + c3 g Rs + Fwo w ))
The Poetmann-Beck (p.507) critical flow correlation takes a similar form:

RL + 0.766 1 L + R L G
qo = 88992 9273.6 0.4513 Abean Pup
RL + 0.5663 5.61 L + 0.0765 G R 3 Eq. 7.143
+ R L G
2 L

Mechanistic / API14B
The critical mass flow rate can be found by inverting the 7.137 (p.359) and evaluating it at the
critical value of the pressure drop:

2 g n P
q = Abean
L G Eq. 7.144
c1 2 + 2
(cvL ZL ) (cvG ZG )
(
P = 1 CPR Pup ) Eq. 7.145

The API14B critical flow uses the mechanistic critical flow formula, with cvL = 0.85 and cvG = 0.9

Omana Correlation
The Omana (p.507) correlation gives a formula for the stock tank critical liquid flow rate:
0.657
qL = 1.953 10 L
3 1.245
L
1.545
(
1 + RL ) 1.8
dbean G
3.49 3.19
Pup Eq. 7.146

where:

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surface tension at upstream conditions (dynes/cm)

Gilbert, Ros, Baxendall, Achong, Pilehvari and User defined correlations

The equations proposed by Gilbert, Ros, Baxendall, Archong and Pilehvari (Ghassan (p.503)) for
stock tank critical liquid flow are all of the form:
c 1/e
Pup (64dbean )
qL = Eq. 7.147
b
a GLR

where
GLR - producing gas liquid ratio (scf/STB)
a, b, c - empirical coefficient given below

Correlation a b c e
Achong 3.82 0.650 1.88 1
Baxendall 9.56 0.546 1.93 1
Gilbert 10 0.546 1.89 1
Pilehvari 46.67 0.313 2.11 1
Ros 17.4 0.5 2.00 1

Users can also define their own parameters for this formula by using engine keywords (p.589). For
example:

CHOKE CCORR=USER a=0.1 b=0.546 c=1.89 e=1.0 ADJUSTSC dbean = 3

Keywords can be entered in the GUI by replacing the choke with an Engine Keyword Tool.

Flow Control Valves Mechanistic Theory

PIPESIM's mechanistic choke equation is based on the theory for subcritical flow (see Brill and
Mukherjee, 1969).

Subcritical flow
The mass flow rate is given in terms of the pressure drop as follows:

2g ns P
Qsc = 12 Abean
fL fG Eq. 7.148
2 + 2
(Z L cL ) (ZG cG )
where:

f L and f G are the liquid and gas phase fraction

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cL and cG are the liquid and gas flow coefficient

Abean is the choke cross-section

P is the pressure drop, which is given by:

P = f L P L + f G P G Eq. 7.149

and

( )
2
1 q
P L = Eq. 7.150
2 g ns (12Z L cL Abean)

( )(
2
1 q
P G = Eq. 7.151
2 g ns 12Z L cL Abean )

where

ZL = 1 is the liquid compressibility factor

ZG = ZG (k , DP , Pup ) is the gas compressibility factor

ns = f L L + f G G is the no slip density

Critical flow
The critical mass flow is given by the subcritical correlation evaluated at the critical pressure drop:

(
P crit = Pup 1 CPR ) Eq. 7.152

where CPR is the critical pressure ratio.

Fittings
The pressure drop across a fitting is given by the Crane Technical Paper 410 (p.501):
2
v
P = K Eq. 7.153
2c

K is a dimensionless friction factor or resistance

v is the fluid velocity ft / s m/s
is the fluid density lb / ft kg / m
3 3

c is a conversion factor for engineering units c = 144 g lb / ( ft s ) / psi c = 1

2

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The velocity of the fluid in the fitting depends on the internal diameter of the fitting where the
velocity is measured. If the fitting has two internal diameters, d1 and d2, the velocities are related
by:
2 2
1 d1 v1 2 d2 v2
Eq. 7.154
= =q
4 4
For incompressible fluids the density can be taken as constant and the velocities are inversely
proportional to the square of the diameters. Therefore the pressure drop can be written in terms of
either velocity:
2 2
v1 v2
Eq. 7.155
P = K 1 = K2
2c 2c
The fitting resistances are related by:
1
K2 = 4 K1 Eq. 7.156

/
and = d1 d2 is the ratio of the internal diameters.

Comparison with the choke model

The fitting can be modeled as a choke (p.354) using a mechanistic sub-critical (p.359) liquid flow
correlation. The choke diameter is taken as the minimum diameter of the fitting d1 and the flow
coefficient is calculated from the fitting resistance at d1:

1
cv = Eq. 7.157
K1

Resistance calculation
The fitting resistance K can be specified by the user. Since it is a function of the internal diameter,
d , this value must also be specified to allow the velocity to be calculated correctly.
The fitting resistance can also be calculated by PIPESIM using formulae from the Crane Technical
Paper 410 (p.501). The resistance is a function of the fitting type, the pipe nominal diameter, d N
the internal diameter, d2 and the diameter of any constriction, d1. These Crane Technical Paper
410 (p.501) formula can be written as:

K 1 = a1 f T (d N ) + a2 0.5 1 ( 2
) + a (1 )
3
2 2
Eq. 7.158

The first term a1 f T represents friction due to the shape of the pipe fitting, the second term
a2 0.5 (1 ) is the resistance due to sudden contraction through any constriction in the fitting
2

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2 2
and the third term a3 1 ( ) is the resistance due to sudden expansion after a constriction. The

constants a1, a2 and a3 depend on the fitting type and are given by:

Fitting a1 a2 a3
Check Swing Valve Conventional 100 0 0
Check Swing Valve Clearway 50 0 0
Standard 90 degree Elbow 30 0 0
Standard 45 degree Elbow 16 0 0
Standard 90 degree Short Radius Elbow 14 0 0
Standard 90 degree Long Radius Elbow 12 0 0
Tee - Flow through run 20 0 0
Tee - Flow through branch 60 0 0
Check Lift Globe Valve 600
Globe Valve Conventional 340
Angle Valve Conventional 150
Globe Valve Y-Pattern 55
Check Lift Angle Valve 55
Gate Valve < 45
o 8
1.6 sin 2.6 sin
2 2
o
Gate Valve 45 < < 180
o 8 1
sin
2
Ball Valve < 45
o 3
1.6 sin 2.6 sin
2 2
o
Ball Valve 45 < < 180
o 3 1
sin
2

The friction factor f T , depends on the nominal size of the pipe:

Nominal size d N (inch) f T

1/2 .027
3/4 .025
1 .023
1 1/4 .022
1 1/2 .021

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2 .019
2 1/12, 3 .018
4 .017
5 .016
6 .015
8 - 10 .014
12 - 16 .013
18 - 24 .012

7.3.2 Compressors, Pumps, and Expanders

Centrifugal Pumps and Compressors

Centrifugal pumps and compressors are described by curves of head and efficiency as functions of
the flow rate for a given speed:

Head (q , N c ) = Head c (q ) Eq. 7.159

(q , Nc ) = c (q ) Eq. 7.160

where:

Head is the head ft lbf / lb Nm / kg

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is the efficiency, expressed as a fraction, 0 < 1

q is the flow rate lb / s kg / s
Nc is the compressor speed for the curve

The fan laws can be used to determine the head and efficiency for speeds N that differ from the
curve speed :

( ) ( )
2
N q
Head (q , N ) = Head c Eq. 7.161
Nc N / Nc

(q , N ) = c (q
N / Nc ) Eq. 7.162

The change in pressure of the fluid and the power needed to run the pump or compressor can be
determined from the head and efficiency:

P = Pout Pin = c1 Head Eq. 7.163

c2 q Head
Power = Eq. 7.164

where

(Pin , T in ) + (Pout , T out ) is the average density lb / ft kg / m

3 3

=
2
Pin is the suction pressure
/ 2
psi or lbf in N /m
2

is the discharge pressure psi or lbf / in N /m

2 2
Pout

T in is the suction temperature o

R K

T out is the discharge temperature o

R K

Power is the power required by the hp W

pump or compressor

( )
c1 is a conversion factor for 1 in
2
engineering units
144 ft

c2 is a conversion factor for 1 hp

engineering units 550 ft lbf / s

The outlet temperature depends on how much of the pump energy is transferred to the fluid. Three
different models can be used:

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( ) )
Adiabatic Route: 1
T in Pout
T = T out T in = 1 Eq. 7.165
Pin

( ) )
Polytropic Route: n 1
Pout n
T = T out T in = T in 1 Eq. 7.166
Pin

Mollier Route (Isentropic): S ( P , T ) = S ( P , T ) Eq. 7.167

out out in in

where

(Pin , T in ) + (Pout , T out ) is the average value of

=
2
Cp is the ratio of specific heats
=
CV

n (Pin , T in ) + n (Pout , T out ) is the average value of n

n =
2
n is the polytropic coefficient
=
n1 1
S is the specific entropy BTU J
o
lb F kg K

Note that:
Only a fraction of the power is converted to head. When using the adiabatic route, the energy
that is not converted to head is assumed to be converted to fluid heat. The usual adiabatic
temperature increase is multiplied by a factor 1 / 1.
n
The polytropic route PV = constant can be used to model constant pressure (n = 0) , constant
temperature (n = 1) , constant enthalpy (n = ) and constant volume (n = ) changes as well
as intermediate routes. PIPESIM uses a value of n that is a function of the efficiency ( ) and
the specific heat ratio ( ). This value can only be used when > ( 1) / .
In the special case when the efficiency = 1, the polytropic coefficient equals the specific heat
ratio n = and the polytropic and adiabatic formulas are the same.
The Mollier Route can only be used in compositional models, the PIPESIM blackoil model does
not calculate entropy.

Engine keywords
See compressor keywords (p.595).

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Reciprocating Compressor Operation

This graph shows how the reciprocating compressor will operate for various field deliverabilities:

Note the following:

1. If the field deliverability falls below the minimum compressor flowrate, recycle mode will be
invoked. Due to the low pressure operation in this region, it may be necessary to add a reverse
block to the branch containing the compressor.
2. If the field deliverability falls below the minimum suction pressure of the compressor, no solution
is possible.

Note: This occurrence may be identified using FPT with an event conditional on the minimum
rate through the compressor. To limit the flowrate through a compressor, place a choke in the
branch upstream and specify a maximum gas constraint in FPT.

3. Always run the network model in Wells Offline mode, with no reverse blocks set.

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Expanders

Expanders are modeled in a similar way to centrifugal compressors (p.366), except they work in
reverse. Fluid flows through the expander and power is extracted. As with compressors, expanders
can be described by curves of head and efficiency as functions of the flow rate for a given speed:

Head (q , N c ) = Head c (q ) Eq. 7.168

(q , Nc ) = c (q ) Eq. 7.169

where:

Head is the head ft lbf / lb Nm / kg

is the efficiency, expressed as a fraction, 0 < 1
q is the flow rate lb / s kg / s
Nc is the expander speed for the curve

The fan laws can be used to determine the head and efficiency for speeds N that differ from the
curve speed :

( ) ( )
2
N q
Head (q , N ) = Head c Eq. 7.170
Nc N / Nc

(q , N ) = c (q
N / Nc ) Eq. 7.171

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The change in pressure of the fluid and the power needed to run the pump or compressor can be
determined from the head and efficiency:

P = Pin Pout = c1 Head Eq. 7.172

Power = c2 q Head Eq. 7.173

where

(Pin , T in ) + (Pout , T out ) is the average density lb / ft kg / m

3 3

=
2
Pin is the suction pressure
/ 2
psi or lbf in N /m
2

is the discharge pressure psi or lbf / in N /m

2 2
Pout

T in is the suction temperature o

R K

T out is the discharge temperature o

R K

Power is the power extracted by the hp W

expander

( )
c1 is a conversion factor for 1 in
2
engineering units
144 ft

c2 is a conversion factor for 1 hp

engineering units 550 ft lbf / s

The outlet temperature depends on how much of the energy is removed from the fluid. Three
different models can be used:

( ) )
Adiabatic Route: 1
Pout
T = T out T in = T in 1 Eq. 7.174
Pin

( ) )
Polytropic Route: n 1
Pout n
T = T out T in = T in 1 Eq. 7.175
Pin

Mollier Route (Isoentropic): S ( P , T ) = S ( P , T ) Eq. 7.176

out out in in

where

(Pin , T in ) + (Pout , T out ) is the average value of

=
2

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Cp is the ratio of specific heats

=
CV

n (Pin , T in ) + n (Pout , T out ) is the average value of n

n =
2
n 1 is the polytropic coefficient
=
n1 1
S is the specific entropy BTU J
o
lb F kg K

Notes:
Only a fraction of the head is converted to power. When using the adiabatic route, the energy
that is not converted to power is assumed to be converted to fluid heat. The usual adiabatic
temperature decrease is multiplied by a factor 1.
n
The polytropic route PV = constant can be used to model constant pressure ( n = 0), constant
temperature ( n = 1), constant enthalpy ( n = ) and constant volume ( n = ) changes as well
as intermediate routes. PIPESIM uses a value of n that is a function of the efficiency ( ) and
the specific heat ratio ( ). This value can only be used when < / ( 1).
In the special case when the efficiency = 1, the polytropic coefficient equals the specific heat
ratio n = and the polytropic and adiabatic formulas are the same.
The Mollier Route can only be used in compositional models; the PIPESIM blackoil model does
not calculate entropy.

Engine keywords
See expander keywords (p.599)

7.3.3 Multiphase Boosting Technology

Multiphase boosting technology (also referred to as multiphase pumping technology) for the oil and
gas industry has been in development since the early 1980s, and is now rapidly gaining
acceptance as a tool to optimize multiphase production systems (Oxley, Ward and Derks 1999).
Multiphase boosting has been recognized as a vital technology, preferable to the standard
approach of separation, gas compression, liquid pumping and the use of dual flow lines back to the
host facility. It is particularly beneficial for the development of satellite fields. Multiphase boosting
enables the full (non-separated) well stream to be boosted in a single machine, thus greatly
simplifying the production system, resulting in significant cost savings that in many scenarios, have
made the development of marginal fields, economic.

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Since 1990, thousands of multiphase boosters have been installed worldwide, with the vast
majority of the installations based onshore or offshore topsides. Over the years, the development
of multiphase boosting has led to two categories of commercial boosters:
Positive Displacement
The most common types are the Twin screw type & Progressive cavity type multiphase
boosters.
Rotodynamic
The most common type is the Helico-axial type multiphase booster.
The figure below depicts the difference between multiphase boosting technology and the more
traditional technology of separation, pumping and compression.

Traditional Multiphase Production approach

The incoming fluid is separated into its constituent
liquid and gas phases.
The separated liquids are pumped up to the required
pressure and exported via the liquid export line.
Separated gas is compressed up to the required
pressure and exported via the gas export line.

Alternative Multiphase Production approach

The incoming fluid is separated into its constituent
liquid and gas phases.
The separated liquids are pumped up to the required
pressure and separated gas is compressed up to the
required pressure.
The two phases are recombined and exported using a
multiphase export line.

Multiphase Boosting
The incoming fluid is directly boosted up to the
required pressure without separation of the gas and
liquid phases.
It is exported using a multiphase export line.

Multiphase boosters are pumps/compressors that can accommodate fluids ranging from 100%
liquid to 100% gas, and anywhere in between. Although commonly referred to as multiphase
pumps, the terminology used in this document is 'multiphase booster' to recognize the fact that
100% gas can also be handled by this equipment (albeit with some restrictions, as outlined in later
sections of this topic).

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Multiphase boosters are used primarily for the following reasons:

Production Enhancement
Multiphase boosting helps to accelerate and/or increase hydrocarbon production by
lowering backpressure on wells.
Pressure Boosting
Multiphase boosting increases fluid pressure thus enabling thetransportation of multiphase
fluids over long distances. It also helps to move fluids from low pressure systems to higher
pressure systems.
In many cases, Multiphase boosters will deliver the combined benefit of production enhancement
and pressure boosting. For example, lowering the backpressure on a well by using a multiphase
booster may increase the rate and simultaneously supply the fluid at a higher pressure at the
flowline inlet.
To demonstrate the principle of multiphase boosting, take the example of a well which is connected
using a flowline and riser to the inlet separator on the host facility, as in the following diagram.

If the Wellhead is selected as the node, the inflow would represent the P-Q (pressure-flowrate)
relationship from the reservoir up to the wellhead and the outflow would represent the P-Q
relationship downstream of the wellhead, including the multiphase booster, flowline and riser. Both
Inflow and Outflow are represented in the Systems plot. The point of intersection of the two curves
is the system operating point, for example, the flowing wellhead pressure and production rate the
system would operate at. In this example, there is no intersection point, which indicates that the
system would not produce at these conditions.

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Production system analysis: THP curve and outflow curve

For this example, you can see from the Production System Analysis graphic that the system is
incapable of producing naturally. From the THP curve, it is clear that if the back pressure on the
well could be lowered, production could be restored. Assuming that you could install a booster
directly downstream of the wellhead, that would provide a pressure 'boost' of 1000 psi to the well
fluids, the outflow curve could be lowered as shown in the figure below. The system would now
produce 134 lb/s (32,412 stb/d of liquid) at a flowing wellhead pressure of 1554 psia. In this
example, multiphase boosting has transformed a dead well to one that produces over 30, 000 stb/d
of fluid.
Production system analysis: the effect of multiphase boosting visualized

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Through the type of analysis outlined above, the effect of multiphase boosting on a production
system can be easily evaluated, and the requirements of the multiphase booster such as power
requirement, speed, etc. can be determined.

Positive Displacement Multiphase Pumps

Positive displacement type pumps work by transferring a definite amount of fluid through a
pumping chamber operating at a particular speed. As the fluid is passed from the suction side to
the discharge end, differential pressure is added hydrostatically rather than dynamically, which
results in these pumps being less sensitive to fluid density than rotodynamic type pumps. This
feature makes positive displacement type pumps more attractive for surface installations than
rotodynamic type pumps. This is primarily because fluids at surface conditions are at lower
pressures and temperatures and tend to have higher gas fractions and a greater tendency for
density change than fluids at subsea conditions (Butler 1999).
There are four (4) types of Positive displacement pumps: Twin Screw, Progressive Cavity (Single
Screw), Piston & Diaphragm, but commercial development has focused mainly on the Twin Screw
and Progressive Cavity types.
The majority of positive displacement type multiphase boosters on the market are of the Twin
screw type, and they will be the primary focus of this topic.

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Twin Screw Type

The twin screw type booster, also referred to as two-spindle screw pump, works on the basis of
fluid carried between the screw threads of two intermeshing feed screws and displaced axially as
the screws rotate and mesh. The fluid is split into two inlets on opposite sides of the pumps. This
equalizes stresses associated with slugging and better enables this type of pump to handle
fluctuating inlet conditions. The fluid passes through a chamber created by the twin interlocking
screws and moves along the length of the screws to the outlet at the top of the pump. The
volumetric rate pumped depends on the screw pitch, diameter and rotational speed.
The following figure shows an example of a twin screw type pump.

It should be noted that, unlike screw type compressors, the volume of the chambers is not reduced
from pump suction to pump discharge, for example, there is no in-built compression in the twin
screw type multiphase boosters. Pressure buildup in the twin screw type multiphase booster is
entirely based on the fact that a definite amount of fluid is delivered into the outlet system with
every revolution of the feed screws, and the pressure developed at pump discharge is solely the
result of resistance to flow in the outlet system. Additionally, as the fluid makes its way from suction
to discharge, gas is compressed and liquid slips back, resulting in a reduction in the volumetric
efficiency of the pump. This is due to the development of a pressure gradient across the moving
chambers from pump discharge to suction, which causes an internal leakage in the pumping
elements. This internal leakage/slip causes the pump net flow to be less than its theoretical
capacity, as demonstrated in the pump performance curves shown below.

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As can be seen from the typical pump performance curves above, pump flow rate is dependent on
pump differential pressure: the higher the pump differential pressure, the higher the internal
leakage, and thus the lower the pump flow rate.
The theoretical capacity of the pump, i.e. the flow rate if no internal leakage is present; is the flow
rate at zero pump differential pressure. For the pump represented in the pump performance curves
above, its theoretical capacity is 500 m3/h. The difference between the theoretical flow rate and the
actual flow rate, is the internal leakage, also called 'pump slip'. As an example, for the pump
represented in the GVF=0% pump performance curve, the actual flow rate for a pump differential
pressure of 40 bar, would be 400 m3/h, and the pump slip would be 100 m3/h (for example, 500 -
400). Given the relative insensitivity of flow rate to differential pressure, especially at higher GVFs,
the twin screw multiphase booster is sometimes referred to as a 'constant flow rate' pump. The
twin screw pump is good for handling GVFs up to 98% at suction conditions and is the preferred
technology for high viscosity fluids.

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It can be seen from the pump performance curves that pump flow rate is dependent on GVF, but
GVF has minimal impact on pump shaft power.
The pump performance curves may suggest that there is an unlimited variety of twin screw
multiphase pumps available for an unlimited number of DP-Q (differential pressure - flow
rate)combinations; however, in practice, there are several physical limitations that restrict pump
options, as below:
Pump differential pressure is typically limited to 70 bar to avoid excessive deflection of feed
screws and possible contact between rotating screws and stator housing
Pump flow rate (i.e. total volumetric flow rate at pump suction) is presently limited to
approximately 2000 m3/h per pump
Gas volume fraction at pump suction is typically limited to 95% maximum (for GVF > 95%,
some form of liquid recirculation is typically required to maintain GVF at suction at 95%
maximum)
Pump inlet pressure and outlet pressures are restricted by casing design pressure and seal
design pressure

Progressive Cavity Type

The progressive cavity type pump (also known as single-rotor screw pump) operates on the basis
of an externally threaded screw, also called rotor, turning inside an internally threaded stator. It is
the same artificial technology used in wells for production enhancement that was adapted for
surface multiphase pumping.

As with the screw type pump, as the rotor rotates within the stator, chambers are formed and filled
with fluid that progress from the suction side of the pump to the discharge side of the pump. The
continuous seal line between the rotor and the stator helix keeps the fluid moving steadily at a fixed
flow rate proportional to the pump rotational speed. Application of the progressive cavity type pump
for multiphase boosting has been less widespread than the twin screw type multiphase booster,
and flow rates and differential pressures are typically lower than those achievable with the twin
screw type (< 30,000 bbl/d total volume).
An example of a progressive cavity type pump for multiphase applications is Moyno's R&M Tri-
Phaze System, which is considered one of the largest; capable of transferring multiphase flows
up to 29,000 bbl/day (192 m3/h) at differential pressures up to 300 psi (20.7 bar). Progressive
cavity pumps can tolerate high solids content and can be adapted to deliver higher flow rates and
differential pressures by installing them in series or parallel arrangements, which increases the
complexity (Mirza 1999).

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Given the wider operating range and greater popularity of twin screw pumps in the oil and gas
industry, PIPESIM has chosen to focus its modeling capabilities in the positive
displacementcategory of multiphase boosters, on twin screw pumps.

Rotodynamic Multiphase Pumps

Rotodynamic type pumps work by adding kinetic energy to the fluid, which is then converted to
pressure, thus boosting the fluid. The actual increase in pressure is directly proportional to the
density of the pumped fluid, for example, the higher the fluid density, the higher the pressure
increase. Because of this, dynamic type pumps are more sensitive to fluid density than positive
displacement type pumps, and tend to be used in applications with lower maximum gas volume
fractions; for example, in subsea applications.
The commercial development of dynamic type multiphase boosters has been focused on the
helico-axial type, based on helico-axial hydraulics developed and licensed by Institute Franois du
Petrole (IFP). For very high gas volume fractions (GVF > 95%), the contra-rotating axial (CRA)
machine was specially developed; originally by Framo Engineering AS and Shell.
The design of the helico-axial type pump has also concentrated on its driver mechanism. For
subsea use, there are electric motor driven units as well as hydraulic turbine driven units. For
onshore or offshore topsides applications, other driver types can also be used.

Helico-Axial Type
The helico-axial type multiphase booster features a number of individual booster stages, each
consisting of an impeller mounted on a single rotating shaft, followed by a fixed diffuser. In
essence, the impeller imparts kinetic energy to the fluid, which is converted to pressure in the
diffuser. The diffuser homogenizes the fluid and redirects it to the next impeller stage. This
interstage mixing prevents separation of the gas-oil mixture, enabling stable pressure-flow
characteristics and increased overall efficiency. The impeller blades have a typical helical shape,
and the profile of the open type impeller and diffuser blade arrangement are specifically designed
to prevent the separation of the multiphase mixture inside the pump (de Marolles and de Salis,
1999).
Helico-axial pumps are able to pump large fluid volumes compared to positive displacement
pumps, which is the reason they are installed in the majority of offshore and subsea applications.
They can also handle limited amounts of sand but are more prone to stresses associated with
slugging. They are good for handling GVFs up to 95%.
The following figure shows a vertically-configured helico-axial pump and a close-up of four
individual stages.

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The boosting capabilities of the helico-axial type pump are a function of GVF at suction, suction
pressure, speed, number of impeller stages and impeller size.

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As can be seen from the above figure, the pressure boosting capability drastically reduces with
increasing GVF. Also, for lower speeds or a reduced number of stages, the pressure boosting
capability will be less than the maximum shown in the figure. For a given pump with a given
number of stages, speed and impeller diameter, pump performance curves can be provided as
shown in the figure. These curves are valid for a given GVF at suction, suction pressure and fluid
density only. New performance curves will have to be generated for conditions differing from those
represented in a specific set of performance curves.

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Practical operating limits of the helico-axial type multiphase booster are (Siep-RTS 1998):
Pump differential pressure typically limited to 70 bar
Pump flow rate (for example, total volumetric flow rate at pump suction) presently limited to
approximately 1500 m3/h per pump
Gas volume fraction at pump suction typically limited to 95% maximum
Pump inlet pressure, 3.4 bara minimum
Pump outlet pressure restricted by casing design pressure and seal design pressure

Contra-Rotating Axial Type

The CRA operates on the basis of axial compressor theory, but rather than having one rotor and a
set of stator vanes, the CRA employs two contra-rotating rotors. The inner rotor consists of several
stages mounted on the outside of an inner cylinder. The outer rotor consists of several stages on
the inside of a concentric, larger diameter cylinder.

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The exact mechanism underlying pressure buildup inside the CRA compressor is not yet fully
understood, nor are there sufficiently mature design rules available for the scale-up of CRA
performance to larger flow rates.
CRA can handle flow rates of the same order of magnitude as the helico-axial type multiphase
booster, however they can achieve significantly lower differential pressures (maximum 20 bar) and
efficiencies (approximately 25%) than conventional boosting systems.
Given the wider operating range and greater popularity of helico-axial multiphase boosters in the
oil and gas industry, PIPESIM currently focuses its modeling capabilities in the rotodynamic
category of multiphase boosters, on the helico-axial type.

Alternative Multiphase Production approach

The alternative multiphase production approach described in the figure can also be modeled in
PIPESIM. This is done using the generic booster option, which splits the fluid into liquid and gas;
and pumps the liquid and compresses the gas. Efficiency values for the compressor have been
obtained from field data and are available in the help system.

Wet Gas Compressors

Wet Gas Compressors are a special category of multiphase booster that are used for well streams
with high gas volume fractions and small amounts of liquid. Multiphase pumps operating under
these conditions are termed "wet gas compressors."
These well streams are often found in marginally economic fields where optimizing production and
minimizing cost are critical targets.
The same guidelines that are used to design a multiphase pump, apply for wet gas compression
service. But special attention must be paid to the design of the wet gas compression service, to

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ensure it can handle thermal expansion, quick temperature changes, as well as high equipment
temperature due to compression heat generated.
Wet gas compressors can handle GVF's greater than 98% and small volumes of low viscosity
fluids. The excessive heat generated by the compression of mostly gas in the well stream often
necessitates the installation of a product cooler. PIPESIM currently cannot model Wet gas
compressors, but support will provided for this option in the near future.

References
Subsea Development from Pore to Process, Oilfield Review, Volume 17, Issue 1, Publication Date:
3/1/2005, Amin Amin, Mark Riding, Randy Shepler, Eric Smedstad Schlumberger and John
Ratulowski Shell.

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Guide to Multiphase Booster Efficiencies

Tables 1 and 2 gives guidelines on the (pump and compressor) efficiencies to enter in the generic
multiphase booster module, when the generic model is needed to simulate a Helico-Axial Booster
(p.386) or Twin Screw Booster (p.386).

Helico-Axial
The following table gives guidelines on the efficiencies to enter in the generic multiphase booster
module to simulate a Helico-Axial multiphase booster.

FLUID GVF (%) APPROXIMATE PUMP APPROXIMATE COMPRESSOR

EFFICIENCY (%) EFFICIENCY (%) (see 2) (p.387)
0 (see 1) (p.387) 10 10-100
10 50 20 -100
20 40 60-100
30 40 80-100
40 30-40 80-100
50 40(50) (see 3) (p.387) 40 (20) (see 3) (p.387)
60 40(50) (see 3) (p.387) 30(20) (see 3) (p.387)
70 30 60
80 30 50
90 20 70
100 10 100
Table 7.3: Helico-Axial Multiphase Booster

Twin screw
The following table gives guidelines on the efficiencies to enter in the generic multiphase booster
module to simulate a Twin Screw multiphase booster.

FLUID GVF (%) APPROXIMATE PUMP APPROXIMATE COMPRESSOR

EFFICIENCY (%) EFFICIENCY (%) (see 2) (p.387)
0 5 20 -100
10 30 20 -100
20 30 70 -100
30 30 80 -100
40 30 90
50 40(50) (see 3) (p.387) 40(20) (see 3) (p.387)
60 40 50
70 30 70

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80 20 60
90 10 30
100 (see 4) (p.387) 10 100
Table 7.4: Twin Screw Multiphase Booster

See also the Twin screw curve format description.

Notes:
1. Helico-Axial multiphase booster not recommended for pure liquid operations.
2. When using fluids with high liquid content the compressor efficiency has little effect as long as
the compressor efficiency is within the range indicated.
3. Two sets of pump and compressor efficiencies are valid for fluids with these gas volume
fractions.
4. Twin screw multiphase booster not recommended for pure gas operations

7.3.4 Artificial Lift

Progressive Cavity Pump (PCP)
General
Progressive Cavity Pumps (PCPs) are a special type of rotary positive displacement pump
sometimes referred to as single-screw pumps. Unlike ESPs, PCP performance is based on the
volume of fluid displaced and not on the pressure increase dynamically generated through the
pump. PCPs are an increasingly common form of artificial lift for low- to moderate-rate wells,
especially onshore and for heavy (solid laden) fluids.
Invented in the late 1920s by Rene Moineau, PCPs were not used in the oilfield until the late
1970s. Their use is becoming increasingly common for low- to moderate- rate onshore wells,
particularly for heavy-oil and sand-laden fluids. (See SPE Production Engineering Handbook
(p. 0 ).)
PCP systems have several advantages over other lift methods:
Overall high energy efficiency (typically 55-75%)
Ability to handle solids
Ability to tolerate free gas
No valves or reciprocating parts
Good resistance to abrasion
Low internal shear rates (limits fluid emulsification through agitation)
Relatively lower power costs (prime mover capacity fully utilized)
Relatively simple installation and operation (low maintenance)
Low profile surface equipment and noise levels

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Limitations of PCP systems include:

Maximum production rates of approximately 5000 BPD
The maximum installation depth is about 4,500 ft.
Maximum operating temperature of approximately 300 F.
Corrosive fluids may damage elastomer and result in higher slippage
Pump stator may sustain permanent damage if run dry even for short periods
Rod sting and tubing wear can be problematic for directional and horizontal wells (though
downhole drives can be used to avoid this)

Principle of Operation
PCPs are most commonly driven by surface mounted electrical motors (Figure 7.7 (p.389)),
although downhole electric and hydraulic drive systems are available.
A PCP is comprised of two helical gears, a steel rotating gear called the rotor (internal gear) and
a stationary gear called the stator (external gear), which is commonly made of elastomer but may
be steel as well. The rotor is positioned inside the stator and rotates along the longitudinal axis
(Figure 7.7 (p.389)):

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Figure 7.7. PCP Pump Illustration

The volume between the stator and rotor forms a sealed cavity that trap the fluid and as the rotor
turns this cavity progresses the fluid from the inlet to the outlet of the pump. The volume of the
cavity and the rotational speed (N) determine the flow rate achieved by the pump.
The volume of the cavity may be calculated based on geometric parameters. The volume of the
cavity is defined by the diameter of the rotor (Dr ) times the stator pitch length (Ls ) times the
eccentricity (e). The eccentricity is defined as the distance between the centerlines of the major
and minor diameters of the rotor.
Therefore, the flow rate through the pump can be expressed as:
Q = 4eDrLsN
In field units, Ps , e and D are in feet and N in revolutions per-minute to give a rate in ft3/min.
Multiply by 256.46 to convert to BPD. (See Bellarby (p. 0 ).) The geometric parameters required
for this calculation vary considerably among vendors and are generally not published.
Hydraulic power can then be calculated by:

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Hhp = 1.7 X 10-5 PQ

Where P is the pressure differential across the pump (psi) and Q is rate (BPD).
In practice, the clearance between the rotor and stator are not perfect due mainly to deformation of
the elastomeric stator as a function of pressure, temperature, and wear. This causes some of the
fluid to slip back into preceding cavities. Slip increases with increasing pressure and number of
stages. Higher viscosity fluids exhibit less slip.
For simulation purposes, PCP performance curves are generally used. While the format of
performance curves varies by vendor, PIPESIM has adopted the format suggested by ISO 15136-1
(2009) (p. 0 ). PIPESIM provides performance curves from several vendors based on reference
conditions (generally water at standard conditions). While catalog performance curves for
rotodynamic-type pumps (such as ESPs) are generally consistent with field performance, PCP
performance curves vary considerably based on the operating conditions (pressure and
temperature) as well as the fluid properties. Therefore, the catalog curves available from within
PIPESIM should only be used for preliminary analysis. It is common for PCPs to undergo bench
tests to generate performance curves for specific pumps at intended operating conditions. It is
therefore recommended that these curves be used for more detailed simulation studies.

Viscosity Effects
PIPESIM has the option to apply a viscosity correction to reduce slippage effects for higher
viscosity fluids. The method of Karassik et al. (p. 0 ) is used.

qv 2 (1)
v1
= Eq. 7.177
qv 1 v2

Where v = the kinematic viscosity, SSU (Saybold Seconds Universal)

q = the slippage, (BPD)

The range of kinematic viscosity is 100 to 10,000 SSU for this viscosity correction. If the reference
fluid is water with kinematic viscosity of about 32 SSU, the equation reduces to:

32 (2)
qs (v 2) = q Eq. 7.178
v 2 s (curve )

Note: SSU is a viscosity unit that is equal to the measure of the time that 60 cm3 of oil takes to
flow through a calibrated tube at a controlled temperature. This should not be confused with the
dynamic (absolute) viscosity, unit of cp or Pas.

Electrical Submersible Pumps (ESP)

General
The electric submersible pump (ESP) is perhaps the most versatile of the artificial lift methods. The
ESP comprises a down hole pump, electric power cable, motor and surface controls. In a typical

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application, the down hole pump is suspended on a tubing string hung on the wellhead and is
submerged in the well fluid. The pump is close-coupled to a submersible electric motor that
receives power through the power cable and surface controls.
ESPs are used to produce a variety of fluids and the gas, chemicals and contaminants commonly
found in these fluids. Aggressive fluids can be produced with special materials and coatings. Sand
and similar abrasive contaminants can be produced with acceptable pump life by using modified
pumps and operation procedures.
ESPs usually do not require storage enclosures, foundation pads, or guard fences. An ESP can be
operated in a deviated or directionally drilled well, although the recommended operating position is
in a vertical section of the well.
The ESP has the broadest producing range of any artificial lift method ranging from 100 b/d of total
fluid up to 90,000 b/d.
ESPs are currently operated in wells with bottom hole temperatures up to 350 degree Fahrenheit.
Operation at elevated ambient temperatures require special components in the motor and power
cables of sustained operation at high temperatures, and have efficiently lifted fluids in wells deeper
than 12,000 ft. System efficiency ranges from 18 to 68%, depending on fluid volume, net lift and
pump type.

ESP System Components: Motor

The ESP system's prime mover is the submersible motor. The motor is a two-pole, three-phase,
squirrel-cage induction type. Motors run at a nominal speed of 3,500 rev/min in 60-Hz operation.
Motors are filled with a highly refined mineral oil that provides dielectrical strength, bearing
lubrication and thermal conductivity. The design and operation voltage of these motors can be as
low as 230 volt or as high as 4,000 volt. Amperage requirement may be from 17 to 110 amps. The
required horsepower is achieved by simply increasing the length of the motor section. The motor is
made up of rotors, usually about 12 to 18 inches (300-460 mm) in length that are mounted on a
shaft and located in the electrical field (stator) mounted within the steel housing. The larger single
motor assemblies will approach 33 feet (10 m) in length and will be rated up to 400 horsepower,
while tandem motors will approach 90 feet (27.5 m) in length and will have a rating up to 750
horsepower. The rotor is also composed of a group of electromagnets in a cylinder with the poles
facing the stator poles. The speed at which the stator field rotates is the synchronous speed, and
can be computed from the equation:
120 f
v= Eq. 7.179
M
Where: v is speed in rev/min, f is frequency in cycles/sec and M is number of magnetic poles.
The number of poles the stator contains is determined by the manufacturer. Therefore to change
the speed of the stator magnetic field, the frequency will have to change.
Heat generated by the motor is transferred to the well fluid as it flows past the motor housing.
Because the motor relies on the flow of well fluid for cooling, a standard ESP should never be set
at or below the well perforations or producing interval, unless the motor is shrouded.
Motors are manufactured in four different diameters (series) 3.75, 4.56, 5.40 and 7.8 in. Thus
motors can be used in casing as small as 4.5 in. 60-Hz horsepower capabilities range from a low of
7.5 hp in 3.75-in series to a high of 1,000 hp in the 7.38-in series.

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Motor construction may be single section or several "tandems" bolted together to reach a specific
horsepower. Motors are selected on the basis of the maximum diameter that can be run easily in a
given casing size.

ESP System Components: Pumps

The ESP is a multistage centrifugal pump. Each stage of a submersible pump consists of a rotating
impeller and a stationary diffuser. The pressure-energy change is accomplished as the liquid being
pumped surrounds the impeller. As the impeller rotates it imparts two rotating motion components
to the liquid: one is in a radial direction outward from the center of the impeller (centrifugal force),
the other motion moves in a direction tangential to the outside diameter of the impeller. The
resultant of these two components is the actual direction of flow. The type of stage used
determines the rate of fluid production. The number of stages determines the total design head
generated and the motor horsepower required. The design falls into one of two general categories:
the smaller flow pumps are generally of radial flow design. As the pumps reach design flows of
approximately 1,900 B/D,the design change to a mixed flow.
The impellers are of a fully enclosed curved vane design, whose maximum efficiency is a function
of the impeller design and type and whose operating efficiency is a function of the percent of
design capacity at which the pump is operated. The mathematical relationship between head,
capacity, efficiency and brake horse power is expressed as:

qv H
Power = Eq. 7.180

Where: qv is the volume flow rate, H is the head, is the fluid specific gravity and is the pump
efficiency
The discharge rate of a submersible centrifugal pump depends on the rotational speed (rpm), size
of the impeller, impeller design, number of stages, the dynamic head against which the pump is
operating and the physical properties of the fluid being pumped. The total dynamic head of the
pump is the product of the number of stages and the head generated by each stage.
"Bolt-on" design makes it possible to vary the capacity and total head of a pump by using more
than one pump section. However, large-capacity pumps typically have integrated head and bases.

Pump Selection
Select Artificial Lift ESP ESP Design and use the Pump Selection tab . The tab has two
sections, Pump Design Data and Pump Parameters. Select a pump based on certain design
criteria.

Pump Design data

Design Production rate
Desired flowrate through the pump in stock-tank units. The actual flowing quantity will be
computed.
Design Outlet Pressure
the required outlet pressure of the PIPESIM model when the pump is installed. It is
recommended to only model the well, and no associated flowline or riser, while designing
the ESP system. In this case the outlet pressure would then be the wellhead pressure

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Static Reservoir Pressure

If you entered a value previously, that value is preserved. However, if this field is empty,
the value is taken from the PIPESIM model.
Water cut
If you entered a value previously, that value is preserved. However, if this field is empty,
the value is taken from the PIPESIM model.
GOR (or GLR)
If you entered a value previously, that value is preserved. However, if this field is empty,
the value is taken from the PIPESIM model.
Pump Depth
The depth at which the pump is to be installed. This is taken from the PIPESIM model if a
pump is already installed or can be entered.
Casing ID
The casing size that the pump has to fit into. Usually 3.38 to 11.25 in.
Design Frequency
The frequency/speed that the pump is expected to run at.
Gas Separator Efficiency
The efficiency of the gas separator if installed.
Head factor
Allows the pump efficiency to be factored (default = 1).
Viscosity Correction
All pump performance curves are based on water systems, this option will correct for oil
viscosity.
Select Pump
Will use the available data to select suitable pumps from the database. The pump intake
conditions will first be computed. The resulting pump list can be sorted by efficiency or
Maximum flowrate by selecting the column header. The Manufactures to select from can
be filtered. Errors in the simulation (p.397).

Pump parameters
Calculate
Calculate pump performance at the conditions specified. Errors in the simulation (p.397)
Stage-by-stage
Perform the stage calculations on a stage-by-stage basis. Default = stage-by-stage.
Selected Pump
The pump selected, by the user, from the design data
No. of Stages required
The computed number of stages for this pump under these conditions.

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Pump efficiency @ Design rate

The efficiency of the pump at the design production rate
Pump power required
The power required for this pump to deliver the required flowrate.
Pump intake pressure
The computed pump intake pressure.
Pump discharge pressure
The computed pump discharge pressure.
Head required
The computed pump head required
Liquid density
The computed liquid density at the pump intake
Free gas fraction at inlet conditions
The computed gas fraction.
Pump performance plot
plot performance curves at different speeds
Pump curves
plot standard performance curves
Install pump
Install the pump into the tubing of model. This will replace any existing ESP but not gas lift
valves.
See also: Select a Motor (p.391), Select a Cable (p.396)

Motor Selection
This can only be performed after a pump has been selected.
Select Artificial Lift ESP ESP Design and use the Motor/Cable Selection tab.
Name of the selected Pump
Selected from the Pump tab.
No. of stages
Computed.
Pump efficiency
Computed
Pump power required
Computed.
Select Motor
The resulting motor list can be sorted by power, voltage, current, etc. by selecting the
column header. Errors (p.390).

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Various parameters associated with the motor will be computed and displayed at both 60Hz and
the initially entered Design Frequency.
NP [Name Plate] Power
NP [Name Plate] Voltage
NP [Name Plate] Current
See also: Select a Pump (p.392), Select a Cable (p.396)

ESP Database
To simulate an ESP, PIPESIM maintains a database of manufacturers and models from which the
user can select. For each model the diameter, minimum and maximum flowrate and base speed
are provided. A plot of the ESP's performance is also available. If the required ESP is not in the
database, you can easily enter the basic data required for it into the database using Data New
ESP/Pump/Compressor. See Data/NewESP-Pump-Compressor.

Selection
When modeling an ESP, it is important that the correct size (expected design flowrate and physical
size) ESP is used. A search facility is available, based on these two parameters, to select the
appropriate ESP from the database. The search can, if required, be restricted to a particular
manufacturer. Pumps that meet the design criteria will be listed.

Stage-by-stage modeling
Stage-by-stage modeling is selected by selecting the checkbox next to the calculate button.
Alternatively by inserting Engine Keywords (PUMP STAGECALCS) (p.617) into the model, using
the EKT.

Install a Pump
Once the ESP manufacturer and model (p.391) has been selected from the database of common
ESP's (p.395) some parameters can be altered. The performance curves for each model are
(normally) based on a Speed of 60Hz and 1 stage.

Design data
Speed
The actual operating speed of the ESP
Stages
The actual number of stages of the ESP
Head factor
Allows the efficiency to be factored (default = 1)

Calculation Options
Viscosity Correction
Allow a viscosity correction factor to be applied to take account of changes to the fluid
viscosity by the pressure and temperature.

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Gas Separator present

Allow a gas separator to be added (automatically) with an efficiency: Separator efficiency -
efficiency of an installed gas separator (default = 100% if installed)
Performance table
The data used to predict the performance of the ESP
Standard Curves
The standard performance curves for the ESP - can be printed/exported
Variable Speed Curves
Variable speed curves at 30 - 90 Hz.- can be printed/exported

ESP Design
The ESP option is selected from the Artificial Lift menu. To design an ESP the following stages are
required:
Select a Pump (p.392)
Select a Motor (p.391)
Select a Cable (p.396)
The ESP should then be installed, added into the tubing, at the required depth. This can either be
performed manually or by using the Install button. Installing automatically removes any existing
ESPs in the tubing. However, any gas lift values or injections points are not removed.
See also: ESP [Reda] web site

ESP System Components: Cable

Cable Selection can be determined after a Pump and motor have been selected.
1. Motor/Cable Selection tab
2. Cable Selection
3. Select Cable
Cable Length
The length of the cable, can be modified
NP Current @ Design Frequency
The [Name Plate] Current at the design frequency. Cannot be changed.
Computed values

Selected Cable
Cable length
Voltage drop
Downhole voltage
Surface voltage

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Total System KVA

Design Report
Display a report that details all the selected components of the ESP system.

Errors
Occasionally a pump may not be able to be determined and a Convergence error will be reported.
There could be a number of reasons for such an error and the user is advised to view the output
report.
Common problems:
1. The system cannot reach the outlet pressure specified. Try increasing the outlet pressure.

Assumptions of the Alhanati model

The model assumes:
Constant pressure at the gas injection manifold, which is upstream of the surface injection
choke
Adiabatic flow through the choke.
In the unified criteria, two sets of criteria were defined, namely C1 and C2, and both must be
greater than zero for stable gas lift operation.

C2 = F 1 ( )

+

Fc
Eq. 7.181

where

(q fo + qGo) At Pco
F3 = Eq. 7.182
( p f pG ) g q fo
(ZT )c
ch = Eq. 7.183
(ZT )m
Nomenclature

At Cross sectional area of tubing in

2

g Acceleration due to gravity ft / s

2

Pco Steady state casing pressure psia

Pg

Pf

q fo Steady state reservoir fluids flow rate stbd

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qGo Steady state injected gas flow rate mmscf

Gas expansion factor

T Temperature F
Z gas compressibility factor

subscripts

gas lift valve

ch gas injection choke
t tubing
c casing
m manifold

7.4 Heat Transfer Models

7.4.1 Energy Equation for Steady-State Flow
PIPESIM uses the first law of thermodynamics to perform a rigorous heat transfer balance on
each pipe segment. The first law of thermodynamics is the mathematical formulation of the
principle of conservation of energy applied to a process occurring in a closed system (a system of
constant mass m). It equates the total energy change of the system to the sum of the heat added
to the system and the work done by the system. For steady-state flow, it connects the change in
properties between the streams flowing into and out of an arbitrary control volume (pipe segment)
with the heat and work quantities across the boundaries of the control volume (pipe segment). For
a multiphase fluid in steady-state flow, the energy equation is given by:

H+ ( 1 2
)
v + gz dm = Q W s
2 m
Eq. 7.184

where the specific enthalpy:

H = U + PV Eq. 7.185
is a state property of the system since the internal energy U the pressure P and the volume V are
state properties of the system.
It is clear from the left-hand side of equation 7.184 (p.398), that the change in total energy is the
sum of the change in enthalpy energy,
H dm = (U + PV )dm Eq. 7.186
the change in gravitational potential energy:
EP = ( gz )dm Eq. 7.187

and the change in total kinetic energy (based on the mixture velocity vm)

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E K = ( 12 v )dm 0
2
m
Eq. 7.188

which is assumed to be negligible.

On the right-hand side of equation 7.184 (p.398), Q includes all the heat transferred to the
control volume (pipe segment) and W s represents the shaft work, that is work transmitted across
the boundaries of the control volume (pipe segment) by a rotating or reciprocating shaft.

7.4.2 Overall Heat Transfer Coefficient

Steady state heat transfer between the fluid inside a pipe (flowline, riser or tubing) and its
surroundings occurs due to the difference between the bulk fluid temperature T b and the ambient
temperature T a. In the case of a flowline or riser, the ambient temperature is the temperature of the
ambient fluid (air or water) moving above the mud line. In the case of a tubing, the ambient
temperature is the ground temperature at a distance far from the well, given by the geothermal
gradient at the tubing depth. The rate at which heat is transferred depends on various thermal
resistances such as:
Inside fluid film (which is used to model heat transfer between a moving fluid and the pipe wall)
Wax layers on the inside of the pipe wall
Pipe wall and surrounding layers (for example coatings, fluid-filled annuli)
Ground and surrounding medium (air or sea)
The heat transfer Q per unit length of pipe can be expressed as:

Q = UA(T b T a) Eq. 7.189

where A = Do is a reference area based on the pipe outside diameter and U is the overall heat
transfer coefficient. The overall heat transfer coefficient can be calculated from the heat transfer
coefficients for each resistance, which in turn can be found from theoretical heat transfer models.
The method of calculation depends on whether the resistances are in series, parallel, or both.

Resistances in series
For resistances in series, (for example pipe coatings, see Fig 7.8 (p.400)) the temperature
difference can be written as the sum of the temperature differences across each resistance:

T a T b = T i Eq. 7.190
i

Therefore
1 A 1
= T i = Eq. 7.191
U Q i i hi

Here h i is the heat transfer coefficient for resistance i given by:

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1 A
= T i Eq. 7.192
hi Q

Figure 7.8. Pipeline and Layers

Resistances in parallel
For resistances in parallel, (for example partially buried pipes, see Fig 7.9 (p.401)) the overall heat
transfer can be written as the sum of the heat transfer through each resistance:

Q = Qi = U i A(T b T a) Eq. 7.193

i i

Therefore the overall heat transfer coefficient can be found by summing the heat transfer
coefficients for each resistance in parallel:

U = Ui Eq. 7.194
i

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Figure 7.9. Burial configurations

Heat transfer models

Heat transfer models are required for:
radial heat transfer between a moving fluid and the pipe wall, see Inside film coefficient (p.402).
radial heat transfer through a conductive layer (p.408), such as internal wax layers, the pipe
wall and insulation.
radial heat transfer through a convective layer (p.410), such as a fluid-filled annulus.
heat transfer through the ground
between the pipe and the surface for buried and partially buried horizontal flowlines (p.412)
radially, between the pipe and the far field geothermal temperature gradient for vertical wells
(p.416)
heat transfer through the ambient fluid
between the ground and the ambient fluid for buried and partially buried horizontal flowlines
between the pipe and the ambient fluid for partially buried and fully exposed horizontal
flowlines
between the pipe and the ambient fluid for fully exposed vertical risers

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Reference diameter for Overall Heat Transfer Coefficient

By default in PIPESIM, all Heat Transfer Coefficients (including local Inside, Outside, and Wall
Coefficients, as well as the Overall Heat Transfer Coefficient) are referenced to the pipe outside
diameter (and outside area), in keeping with one industry standard for heat exchanger design.
However, the HEAT HTCRD keyword can be used from PIPESIMs EKT to override that default
basis with a different user-specified diameter (effectively imposing a different reference area for all
reported Heat Transfer Coefficients). This can be useful for direct comparison with Heat Transfer
Coefficients which are reported by some other flow assurance software on an inside diameter and
area basis (for example, OLGA, PIPEFLO).

7.4.3 Inside Fluid Film Heat Transfer Coefficient

This inside film heat transfer coefficient accounts for resistance to heat flow between the bulk of
the fluid and the inside of the pipe wall. For the most common PIPESIM cases where forced
convection dominates internal heat transfer, a Nusselt number correlation is selected depending on
whether that forced flow is laminar, turbulent or in the transition region.
For the less common PIPESIM case where inside natural convection may dominate internal heat
transfer, a Natural Convection Nusselt number is also computed. In such cases, a check of these
two competing Forced Convection and Natural Convection mechanisms is performed. PIPESIM
then sets its Inside Fluid Film Heat Transfer Coefficient to the higher of these values.

Inside Forced Convection

A number of inside film coefficient (IFC) correlations were added over time to the legacy PIPESIM
engine. Several of those legacy correlations are no longer commonly used for new models.
However, these may still be used for compatibility with historic work, through the HEAT keyword.
The following document PIPESIM's two primary methods for computation of the Inside Forced
Convective Heat Transfer Coefficient:
Kreith Method (p.402) (default, with mixed multiphase properties)
Kaminsky Method (p.405) (noted for special consideration of Inside Fluid Film Heat Transfer
Coefficients in cases with a stratified multiphase flow regime)

Kreith
This is the default method in PIPESIM.
Kreith (averaged) mixture properties
For cases with multiphase flow, the Kreith method uses mixture properties for a pseudo single-
phase, based on the local (slip-flow) liquid holdup. These properties are calculated as follows.

First, liquid and gas Reynolds numbers are calculated based on the superficial velocities vSL and
vSG :

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L vSL D
ReSL = Eq. 7.195
L

G vSG D
ReSG = Eq. 7.196
G
where is the density, the viscosity, D the pipe diameter and the subscripts L and G refer to
the liquid and gas phase properties.
A total Reynolds number is then obtained:

ReTOTAL = ReSL + ReSG Eq. 7.197

A Prandtl number is then calculated using fluid mixture properties:

mc p
m Eq. 7.198
Prm =
km

where c p is the specific heat capacity, k the thermal conductivity, and the viscosity, and the
subscript m refers to the mixture.
The mixture thermal conductivity is given by:
1
km =
HL (1 H L ) Eq. 7.199
+
kL kg
and the mixture heat capacity:
Cp = H L Cp
m L
( )
+ 1 H L Cp
G
Eq. 7.200

where H is the holdup.

Kreith Single-Phase Nusselt Number relations

In both single-phase and multiphase cases, PIPESIM's Kreith inside fluid film coefficient is based
on the following methods for prediction of the inside film Nusselt Number.

For turbulent flow (ReTOTAL 6000 ):

Kreith recommends the McAdams enhancement to the respected Dittus-Boelter equation for
turbulent inside Nusselt Number (Nu). McAdams fixes the Pr exponent at 0.33 - in agreement with
the other respected Sieder-Tate equation for turbulent inside Nu. McAdams also applies a 'short-
pipe' entrance effect (D/L) multiplier to Dittus-Boelter's turbulent inside Nu method, similar to the
entrance effects found in all laminar forced-flow Nu methods.

Nu 1P
Turb
= 0.023ReTOTAL
0.8
Pr
0.33
(
1+ ( )
D
L
0.7
) Eq. 7.201

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{
For laminar flow (ReTOTAL 2000 ):

SD
Nu 1P 0.25ReTOTAL Pr
( )(D
L
ln 1
Pr
0.167
2.645
ReTOTAL Pr (
D
L ))
; L
D
10

Nu 1P = MD
D
L
10 ( SD ) ( LD 10) LD
L
10 < Eq. 7.202
30
Lam Nu 1P Nu 1P + Nu 1P ; D
1 30 10
30 10
1
LD
Nu 1P 1.86 ReTOTAL Pr
D
L ( ) 3
;
L
D
> 30

where the superscripts SD, MD and LD stand for short duct, medium duct and long duct,
respectively.

For transition flow (2000 ReTOTAL 6000 ):

( ) ( )
( )
ln Nu 1 P ln Nu 1 P
Turb Lam
ReTOTAL (
ln Remax ) (
ln Remin ) Eq. 7.203
Nu 1P = Nu 1P
Lam 2000

Note: As the Reynolds number decreases, the laminar flow Nusselt number is approaches 4. So if
the Reynolds number is less than 2000, then PIPESIM limits the Reynolds number to a minimum
of 4.

Reference: Kreith (p.505)

Kreith Multiphase Inside Fluid Film Coefficient

If the flow is multiphase then the void fraction is given by

AvG
= Eq. 7.204
AvG + AvL
where the cross-sectional area of the pipe:
2
D
A= Eq. 7.205
4
The gas-weighted two phase fluid thermal conductivity is defined as:

k2P = k G + (1 )k L Eq. 7.206

The two phase inside film coefficient for the correlations below (unless otherwise stated) is defined
as:

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Nu 2P k2P
hi = Eq. 7.207
2P D

Note: Nu2P in this equation is computed by applying the Kreith (averaged) mixture properties to
the Kreith Single-Phase Nusselt Number relations.

Kaminsky

The Kaminsky method may give enhanced prediction for cases where multiphase stratified-flow
heat transfer effects will strongly affect the Overall Heat Transfer Coefficient (as one of its largest
series resistances).

Kaminsky (regime-dependent) Film Phase and Dimensionless Parameters

If the flow regime is mist, single gas phase or froth then the Kaminsky method's fluid film at the
inside wall is considered to be a single-phase gas and the base superficial Reynolds number is:

G vSG D
ReS = ReSG = Eq. 7.208
G
and the Prandtl number is:

G c p
G Eq. 7.209
Pr = PrG =
kG

where is the density, the viscosity, v the velocity, c p the specific heat capacity, k the thermal
conductivity, D the pipe diameter and the subscript SG refers to the superficial gas phase
properties.
For all other flow regimes, the Kaminsky method's fluid film at the inside wall is considered to be a
single-phase liquid and the base superficial Reynolds number is:

L vSL D
ReS = ReSL = Eq. 7.210
L
and the Prandtl number is:

L cp
L Eq. 7.211
Pr = Pr L =
kL
where the subscript SL refers to the superficial liquid phase properties.
The following minimum and maximum superficial Reynolds numbers are defined as boundaries of
the laminar-turbulent transition region:

ReS = 2000 Eq. 7.212

min

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ReS = 6000 Eq. 7.213

max

Kaminsky base Single-Phase Film Nusselt Number

The following minimum and maximum superficial Reynolds numbers are defined as boundaries of
the laminar-turbulent transition region: ReS min = 2000

ReS max = 6000

The Kaminsky method bases its single-phase Nusselt Number on the Sieder and Tate equations
for turbulent and laminar flows of the film phase, as follows.

For turbulent Kaminsky Film Phase (ReS > ReS ):

max

( )
0.14
4/5 1/3
Nu 1PTurb = 0.023ReS Pr Eq. 7.214
W

For laminar Kaminsky Film Phase (Re ReS ):

max
1

( ) ( )
0.14
D 3
Nu 1PLam = 1.86ReS Pr Eq. 7.215
L W

where L is the length of the pipe and the subscript W refers to wall properties. The viscosity is
either the liquid or gas viscosity depending on the flow regime (as described above).

Throughout the transition region (2000 Re 6000 ), PIPESIM prorates the Kaminsky u 1 P by
applying

Nu 1PTurb Eq. 7.216

from Kaminsky Film Equation 1081.16 and

Nu 1PLam Eq. 7.217

from Kaminsky Film Equation 1081.17 to the same

Nu 1P Eq. 7.218

Interpolation Method listed above as Kreith Equation 1081.9.

Reference: Sieder and Tate (p.509)

Kaminsky Single-Phase Inside Fluid Film Coefficient

If the flow regime is mist, single gas phase or froth, this PIPESIM method regards the entire inside
bulk fluid as a single-phase gas and the Inside Film Coefficient is:

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kG Nu 1P
hi = Eq. 7.219
1P D
Similarly, for the case of a single-phase bulk liquid flow the inside film coefficient reduces to:

k L Nu 1P
hi = Eq. 7.220
1P D
Kaminsky Multiphase Inside Fluid Film Coefficient
For all other (multiphase) flow regimes, with a turbulent liquid film (Re 2300 ):

P2Pf
hi = hi S Eq. 7.221
2P 1 P SL P1 Pf
Its required input of the single-phase turbulent heat transfer film coefficient h 1, must first be
computed by the Sieder-Tate correlation. This Multiphase Pressure-Drop/Heat-Transfer Analogy
Method also implicitly requires that both the Superficial Liquid Pressure Drop and the Multiphase
Pressure Drop be pre-calculated as additional inputs, before its h 1 can be computed.

For horizontal (for example, if the pipe angle | | < swap ) stratified flow, the wetting of the pipe
wall is calculated from
S = D Eq. 7.222
where is the wetted wall fraction given by Grolman's correlation (p.503) :

{ }
2 0.8

( ) { }
0.15 0.25
W G L uLS D uGS
1
= 0 + Eq. 7.223
+ G cos( ) 2
L (1 H L ) gD
in which the minimum wetted wall fraction 0 is approximated by:
0.374
0 0.624H L Eq. 7.224

For all other types of flow, heat transfer it is reasonable to assume that heat transfer is
circumferentially uniform (i.e. S = 1).
For laminar flow (Re < 2300 ):

(2 H L )h i 1PSL
hi = 2 Eq. 7.225
2P
3
HL
The single-phase laminar heat transfer is estimated by the Sieder-Tate correlation.
Reference: Kaminsky (p.504)

Inside Natural Convection

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As described for Annulus and Outside Convective Heat Transfer Coefficients, Natural Convection
Heat Transfer inside a pipe is also a function of the Grashof Number (Eq. 1081.3).
Whenever fluid temperature may be significantly influenced by Natural Convection heat transfer,
PIPESIM checks for the possible influence of Natural Convection inside the pipe.

Inside Natural Convection Nusselt Number

PIPESIM computes an Inside Natural Convection Nusselt Number as follows:

This equation captures the Natural Convective Effect whenever significant, in a simple, compute-
inexpensive, and numerically stable way. Its 'floor' is set to Nu = 3.66 - the Conduction-Only
Limiting Minimum Nu for a Circular Pipe.
PIPESIM computes this NuNC for every Laminar case, to check if this Natural Convection Nu
would dominate.
Further, PIPESIM also computes this NuNC for Transition and Turbulent (Forced Convection)
cases if: Re < 10000 (transition Re)

Maximum Nu Method for Competing Natural and Forced Convection

Whenever it is computed (for Laminar cases, or for Transition and Turbulent cases within the
Gr/Re or Re range described above), this Inside Natural Convection Nu is compared with
PIPESIM's Inside Forced Convection Nu, and the larger Nu value is used to compute PIPESIM's
Inside Fluid Film Coefficient, as: Nu = max(NuNC, NuFC)
where, NC denotes this Natural Convection Nu, and FC denotes the Forced Convection Nu.
This numerical method approximates a physical reality. One or the other of Natural or Forced
Convection will suppress the other as buoyant density differences, flowrates, and turbulence are
increased or decreased in different cases. This method models that competition, while maintaining
a continuous trend of Inside Fluid Film Nusselt Number for parametric studies with differing
flowrates, insulation levels, ambient temperatures, etc.
Reference: VDI, Incropera, Scandpower (p.504)

7.4.4 Conductive Heat Transfer Coefficients

Brill and Mukherjee (p.500) give a formula for radial heat transfer Q per unit length of pipe through
a conductive layer:

Q ln (ro / ri )
T = T o T i = Eq. 7.226
2 k
where
k is the conductivity of the layer.

ri is the inner radius of the layer

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ro is the outer radius of the layer

T i is the temperatures at the inside edge of the layer

T o is the temperatures at outside edge of the layer

This equation can be used to calculate the heat transfer coefficient for a conductive layer:
1 A A ln (ro / ri ) Eq. 7.227
= T =
h Q 2 k
where

A Do is the radius of the reference area (normally the pipe outside radius)
=
2 2

Wax Heat Transfer Coefficient

7.227 (p.409) can be used for heat transfer through a wax layer on the inside wall of the pipe,
where

k = kwax is the conductivity of the wax layer.

Di is the inner radius of the wax layer (equal to the pipe inner radius minus the wax
ri = rwax thickness)
2

Di is the outer radius of the wax layer (equal to the pipe inner radius)
ro =
2

Pipe wall heat transfer coefficient

7.227 (p.409) can be used for heat transfer through the pipe wall, where

k = k pipe is the conductivity of the pipe wall.

Di is the inner radius of the pipe

ri =
2

Do is the outer radius of the pipe

ro =
2

Conductive layer heat transfer coefficient

7.227 (p.409) can be used for heat transfer through conductive layers, such as foam insulation or
cement, where

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PIPESIM User Guide

k = kn is the conductivity of the n th layer

Dni is the inner radius of the n th layer

ri =
2

Dno is the outer radius of the n th layer

ro =
2

7.4.5 Annulus and Outside Convective Heat Transfer Coefficients

Convective heat transfer can occur in a number of places in a well and surface network, across a
fluid filled annulus; between a pipe or surface and the air or sea. Free (or natural) convection
occurs when the bulk fluid is at rest and convection is driven by buoyancy effects alone. Forced
convection occurs when the fluid is moving, which will increase the rate at which heat is
transferred.
The heat transfer coefficient for free convection at a wall is given in terms of the Nusselt number
( Nu ), the fluid conductivity (k ) and a length scale ( L ):
k Nu
h = Eq. 7.228
L
The Nusselt number can be found experimentally, depending on the geometry of the convective
surfaces. It also depends on the fluid properties, which are encapsulated in two dimensionless
numbers, the Prandtl number (Pr ) representing the ratio of velocity and temperature gradients:
cp
Pr = Eq. 7.229
k
and the Grashof number representing the ratio of buoyancy to viscous forces:
3 2
L g T
Gr = 2
Eq. 7.230

Fluid thermal expansion coefficient K 1

Fluid dynamic viscosity kg m

1
s
1

Fluid density kg m
3

c p Fluid heat capacity

1
W kg
k Fluid thermal conductivity W m
1
s
1

Fluid properties are calculated at a film temperature T film half way between the wall temperature
and the bulk fluid temperature:

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T film = (T wall + T f ) / 2 Eq. 7.231

The wall temperature and bulk fluid temperature are used to calculate the temperature difference in
the formula for the Grashof number:

T = |Tf T wall | Eq. 7.232

Because the fluid properties and Grashof numbers are functions of the wall temperatures, the heat
transfer coefficient is also a function of the wall temperatures. The heat loss calculation therefore
needs to be solved iteratively.

Convection in a fluid filled vertical annulus

PIPESIM can model the heat transfer in a fluid filled annulus by free convection. The heat transfer
coefficient can be determined from the heat transfer coefficients at the inner and outer walls:
1 1 1
= + Eq. 7.233
h annulus h inner h outer
For vertical pipes (angle 45 ), the Nusselt number is given by Eckert and Jackson (1950)
(p.502) (quoted in Kreith and Bohn(1997) (p.505)) in terms of the Rayleigh number ( Ra):
0.25 9
Nu = 0.555Ra for Ra 10 Eq. 7.234
0.4 9
Nu = 0.021Ra for Ra > 10 Eq. 7.235

where
Ra = Pr Gr Eq. 7.236
The bulk fluid temperature is assumed to be the average of the annulus wall temperatures:

T f = (T inner + T outer ) / 2 Eq. 7.237

Convective Heat transfer through fluid-filled annuli can be modeled by the use of the EKT. Refer to
the Expert Mode Keyword Reference section on fluid coats (p.628).

Convection in a fluid-filled horizontal annulus

PIPESIM uses the same equations to calculate the heat transfer for a horizontal fluid annulus as
for a vertical annulus. except that the Nuuslet number is given by:
0.25
Nu = 0.53Ra Eq. 7.238

Fully exposed pipe

For a flowline or riser exposed to the sea or the air, the ambient heat transfer coefficient can be
calculated by summing the free and forced convection heat transfer coefficients:

h a = h forced + h free Eq. 7.239

For forced convection, the heat transfer coefficient depends on the Reynolds number of the flow

Nu forced = (0.4Re )Pr0.4

0.5 0.67
+ 0.06Re Eq. 7.240

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7.4.6 Heat Transfer Between a Horizontal Flowline and the Ground

Surface
Fully Buried Ground Heat Transfer Coefficient
The fully buried heat transfer coefficient for a flowline is evaluated by determining a conduction
shape factor to account for the geometrical and thermal effects of the burial configuration. Once
the shape factor is known, the ground heat transfer coefficient is calculated from:

kg S
hg = Eq. 7.241
R
where R is a chosen reference length. By default, in PIPESIM, this is the outer radius of the pipe.
The shape factor used differs depending on the partial burial option that is selected.
A pseudo film coefficient is then added in series in order to model the ambient fluid moving above
ground level:
1 1 1
= + Eq. 7.242
h ext hg ha

2009 Method
The conduction shape factor is obtained from a solution to the steady-state heat conduction
equation (the Laplace equation) with convective boundary conditions on the pipe inside wall and
ground surfaces:

B p abur
S=

( ) ( )
2 2 1
Bp Bp 2 Eq. 7.243
cosh 0 B p abur 0 + 1+
Bg Bg

where
0 = cosh
1
( ZR ) Eq. 7.244

is a auxiliary geometrical quantity and

( ) 1
2
Z
abur = sinh 0 = Eq. 7.245
R
is a scale factor for bicylindrical coordinates and
U ipc R
Bp = Eq. 7.246
kg
is the Biot number of the pipe and
h aR
Bg = Eq. 7.247
kg

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is the Biot number of the ground. U ipc is the combined heat transfer coefficient of the inside film,
pipe, coatings (and wax)
1 1 1 1
= + + Eq. 7.248
U ipc hi h wax h pipe &layers
Equation 7.243 (p.412) is not valid when the pipe&layers surface is just touching the ground
surface (Z/R=1). In such a case, the shape factor is calculated from the following asymptotic
expression

Bp
S

( )( )
1
Bp 2 Eq. 7.249
1+ 1 + 2Bp
Bg

We obtain the ground heat transfer coefficient from:

kg S
hg = Eq. 7.250
R

Note: This is the default method in PIPESIM. The shape factor above is accurate to within 2.5% of
the numerical simulation studies given by Schneider (p.509). For information about how the results
of the 2009 method compare to Schneiders, see Ovuworie (p.507).

1983 & 2000 Methods

The conduction shape factor is obtained from a solution to the steady-state heat conduction
equation (the Laplace equation) with isothermal boundary conditions on the pipe inside wall and
ground surfaces:
2
S=
cosh
1
( Z
R pipe &layers ) Eq. 7.251

Reference: Kreith (p.505)

Partially Buried Ground Heat Transfer Coefficient

To calculate the overall heat transfer coefficient for a partially buried pipeline, buried and exposed
heat transfer coefficients must be calculated and combined in parallel . The method of combination
and the ground conduction shape factors used differ depending on the partial burial option that is
selected.

2009 Method
1. A fully exposed pseudo pipe of the same diameter is created and an overall heat transfer
coefficient (U exp ) is calculated using the methods described in the sections above.

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{
2. A partially buried conduction shape factor is calculated using the methods described in the
sections above. The shape factor is computed from

(
2 B p apart tan
-1
1 Apart
1 + Apart
) 1 < Apart < 1

( )
;
Bp 2
1+ 1 Apart
Bg
B p apart

( )
;
S= Bp Apart = 1 Eq. 7.252
1+
Bg

( )
2 B p apart tanh
-1
Apart 1
Apart + 1
Apart > 1

( )
;
Bp 2
1+ Apart 1
Bg
where

( )( ( ) )
1
Bp Bp
Apart = 1 + cos 0 + B p apart + 0 Eq. 7.253
Bg Bg

is an auxiliary geometrical quantity and

( ZR )
2
apart = sin 0 = 1 Eq. 7.254

is a scale factor for bicylindrical coordinates.

3. The fully buried and fully exposed heat transfer coefficients are then combined in parallel
(according to the fraction of pipe exposed and the fraction of pipe buried) using equation 7.255
(p.415) to give the overall heat transfer coefficient:

Note: This is the default method in PIPESIM. For more information, see Ovuworie (p.507).

2000 Method
1. A fully exposed pseudo pipe of the same diameter is created and an overall heat transfer
coefficient (U bur ) is calculated using the methods described in the sections above.
2. A fully buried pseudo pipe (Z=+R) of the same diameter is created and an overall heat transfer
coefficient (U exp ) is calculated using the methods described in the sections above.

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3. The fully buried and fully exposed heat transfer coefficients are then combined in parallel
(according to the fraction of pipe exposed and buried) to give the overall heat transfer
coefficient:

U = 1+( 0

)
U exp
0
U
bur
Eq. 7.255

where the negative of half of the angle of the exposed arc:

0 = cos
-1
( ZR ) Eq. 7.256

1983 Method
1. A fully exposed pseudo pipe with diameter corresponding to the exposed surface area is
created and an overall heat transfer coefficient (U exp ) is calculated using the methods
described in the sections above.
2. A fully buried pseudo pipe with diameter corresponding to the buried surface area is created
and an overall heat transfer coefficient (U bur ) is calculated using the methods described in the
sections above.
3. The fully buried and fully exposed heat transfer coefficients are then combined in parallel
(according to the surface areas of pipe exposed and buried) to give the overall heat transfer
coefficient:

Aexp Abur
U = U exp + U Eq. 7.257
A A bur
where the total surface area of the buried pipe:
A = 2 R Eq. 7.258
The surface area of the exposed portion of the pipe is:

Aexp = R 1 ( bur
2
) Eq. 7.259

where the angle of the buried arc:

bur = sin
-1
( ZR ) Eq. 7.260

The surface area of the buried portion of the pipe is:

Abur = A Aexp Eq. 7.261

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7.4.7 Heat Transfer Between a Vertical Well and the Surrounding Rock
Ramey Model
Heat transfer between a well and its surroundings varies with time: the well exchanges energy with
the formation, heating it up (or cooling it down), until the formation is at the same temperature as
the well.
The Ramey (1962) (p.508) model is an analytical method for determining the ground heat transfer
coefficient, hg , given the length of time t a well has been operating. The model assumes that heat
transfer in the wellbore is steady-state, whilst heat transfer to the formation is by transient radial
conduction. In his paper, Ramey quotes various solutions for different boundary conditions. He
observed that the solutions eventually converge after about a week. He concluded that a line
source with constant heat flux gives a good asymptotic solution for long times (times greater than
one week).
The wellbore (ground) heat transfer coefficient is given by:

2k g
hg = Eq. 7.262
D f (t )
where the time function:

1
f (t ) = E1
2
D
4 T
( ) ( )
exp
D
4 T
2 2
Eq. 7.263

The exponential integral is given by:

D2

E1 ( )
D
4 t
2

= 0
4 T 1 exp ( r )
r
( )
d r ln
D
2

4 t

Eq. 7.264

For large values of time t, Ramey uses a series expansion for the exponential integral, which to
leading order gives:

f (t ) ln ( ) 4 t
Dco


2
Eq. 7.265

kg ground thermal resistance Wm K

1 1

D outside diameter of pipe m

Dco outside diameter of pipe and thermal coatings m

kg ground thermal diffusivity m s

2 1

=
g cg

cg ground specific heat capacity J kg K

1 1

g ground density kgm

3

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r radial distance from the centre of the well m

0.577 Euler-Mascheroni gamma constant dimensionless

In the case of a tubing we see that:

1 1
= Eq. 7.266
h ext hg
and the ambient temperature used in equation 7.262 (p.416) is given by the geothermal
temperature at some radial distance far from the centre of the well.

Note: To compute a geothermal gradient and hence a geothermal temperature at a particular well
depth,, PIPESIM requires knowledge of at least two ambient temperatures at two corresponding
measured depths (MD) or true vertical depth (TVD) usually these are the ambient temperatures
at top and bottom of the tubing.

Reference: "Wellbore Heat Transmission", H.J. Ramey (p.508)

7.5 Fluid Models

A number of fluid and solid phases may be present in oil and gas pipeline. These include:
Fluids
Vapour hydrocarbon and water (gas)
Liquid hydrocarbon (oil)
Liquid water
Other liquids (e.g. liquid CO2)
Solids
Hydrate I
Hydrate II
Wax
Asphaltene
Ice
Scale
PIPESIM simulates flow of only three fluid phases, oil, gas and water. In fact some flow models
only consider two phases, liquid and gas. Liquid properties are determined by combining the oil
and water properties.
PIPESIM can be used to model wax precipitation and deposition. Other solid phases cannot be
modelled, although the appearance of hydrates, asphaltene and ice can be predicted. PIPESIM
can model scale prediction.
Fluid models are used to determine the phase state (e.g. single phase oil, single phase gas, two
phase oil and gas etc) and the phase thermodynamic and transport properties needed for

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simulation (e.g. density, enthalpy and viscosity). PIPESIM allows three different types of fluid
description:
Black oil (p.419) Three phases are allowed, oil, gas and water. The hydrocarbon fluid is made
up of oil and gas. Simple correlations are used to determine how much gas can dissolve in oil
and the phase properties.
Compositional (p.449) The number of phases allowed depends on the flash package. Fluid is
made up of components, such as methane, ethane, water etc. Phase state is determined by
minimizing Gibbs energy of the system (the flash). This can be a complicated calculation and is
therefore significantly slower than black oil. PIPESIM can use a number of different flash
packages.
Fluid Property Table Files (p.469) Two phase (liquid and gas) properties can be output from
compositional packages in a tabular form that PIPESIM can read.

7.5.1 Steam Modelling

For steam systems (production and injection) PIPESIM uses ASTEM97 - IAPWS IF97 Properties
of Water and Steam for Industrial Use," Copyright Edward D. Throm (C) 2005.
When modeling steam systems the pressure and quality or temperature are required. If the quality
is not provided, superheated (quality =100%) or sub-cooled (quality=0%) then the temperature is
required.
Steam systems can be modeled in both single branch and network models using engine
keywords. These can be specified from the Pipesim GUI as described below. However:

Notes:
Because the GUI does not understand steam as a fluid model choice, it will require you to
specify a valid fluid model, either as Black Oil, or Compositional. The steam keywords will
override this, so the choice is not really relevant when the model is working.
PIPESIM requires a Fluid Model defined and mapped to each source. The current configuration
recognize either a Black Oil or Compositional Fluid and the same is linked to validation
mechanism. For a special case of Steam Modelling which the underlying PIPESIM Engine is
capable a handle, user must present the Steam definition using keywords as detailed above
and ensure there is no other fluid (Black Oil or Compositional) is present. This can only be done
by skipping the validation mechanism.

A steam case has been configured under PIPESIM Case Study folder for your reference.

Single branch steam

1. To model steam in a single branch PIPESIM model, go to Setup Simulation Advanced
tab in the single branch view of the steam source branch, and specify the following keywords,
for example:

STEAM
INLET QUALITY = 0.5

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The inlet steam quality needs to be specified, if not, the engine will assume it to be either 0.0 or 1.0
depending on the pressure and temperature at the inlet.
2. Make sure you have a black oil fluid specified, with a GLR of zero and a watercut of
100%.correctly.
3. Mass flow rates must be used with steam. Any operation that specifies a flowrate, or sets a
flowrate limit, must do so with a mass rate, not a gas or liquid rate.
When steam quality is provided, it will be used with the lnlet pressure to calculate the resulting
steam temperature and enthalpy; Any inlet temperature you specify will be ignored.
If quality is not provided, enthalpy will be used instead. If Enthalpy is not provided, the system will
be flashed at the specified inlet pressure and temperature, and as a result will be 100% liquid or
100% vapour at the system inlet.

Network model steam

1. To model steam sources in a network model, go to Setup Simulation Advanced tab in the
network view, and enter the following data for example in the lower section of the window:

SETUP COMP = STEAM

SOURCE NAME = SS1 QUALITY = 0.8

2. Enter the quality for all the steam sources. If the quality is not entered, it will be determined from
the temperature and pressure given for that source. If it is entered the source will be considered
saturated at that pressure and the temperature will be adjusted accordingly.

Note: Steam is considered as a third thermodynamic model (after blackoil and compositional). At
present only one thermodynamic model is allowed per network, so steam systems have to be
modeled as a separate network from the hydrocarbon production or injection networks.

7.5.2 Black Oil Fluid Modeling

Black oil fluids are modelled as three phases, oil, gas and water. The amount of each phase is
defined at stock tank conditions, by specifying two ratios, typically the gas oil ratio (GOR) and the
water cut (WCUT). Properties at pressures and temperatures other than stock tank are determined
by correlations (p.421). Water is assumed to remain in the water phase. The key property for
determining the phase behaviour of the hydrocarbons is the solution gasoil ratio (p.422),
Rs (P , T ), which is used to calculate the amount of the gas dissolved in the oil at a given pressure
and temperature:

Stock tank volume of gas dissolved in oil: R V

s O

Stock tank volume of free gas: V G = (GOR R s ) V O

At stock tank conditions Rs = 0. The bubble point pressure (p.426) Pb(T ) can be found by
calculating the pressure at which all the gas is dissolved in the oil Rs ( Pb, T ) = GOR

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For pressures below the bubble point the oil is saturated (no more gas can dissolve in it at that
pressure and temperature). For pressures above the bubble point, there is no vapour phase and
the oil is undersaturated, since more gas could be dissolved in it if it were available. Above stock
tank pressure P > Ps the oil contains dissolved gas, and is known as live oil. Oil at stock tank
pressure (or oil with GOR=0) is known as dead oil. Different correlations apply for dead oil,
saturated live oil, and unsaturated live oil properties.
Correlations (p.421) are needed for the fluid properties needed for simulation:
the oil formation volume factor (p.427) (which is used to determine oil density),
the gas compressibility (p.436) (to determine the gas density)
the water density
the oil viscosity (p.429)
the gas viscosity (p.439)
the water viscosity
the fluid enthalpy (p.441)
the oil-gas surface tension (p.440)
the water-gas surface tension (p.440)
Liquid properties (p.470) are calculated by combining the oil and water properties.

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Black oil Correlations

The following black oil correlations are available:

Solution gas (p.422) and bubble point Lasater (p.425), Standing (p.425), Vasquez and
pressure (p.426) Beggs (p.426), Kartoatmodjo and Schmidt (p.424),
Glas (p.424), De Ghetto et al (p.423) or Petrosky
and Farshad (p.425).
Oil formation volume factor of saturated Standing (p.428), Vasquez and Beggs (p.428),
systems Kartoatmodjo and Schmidt (p.428)
Oil formation volume factor of Vasquez and Beggs (p.428)
undersaturated systems
Dead oil viscosity (p.430) Beggs and Robinson, Glas, Kartoatmodjo, De
Ghetto, Hossain, Petrosky, Elsharkawy or Users data.
Live oil viscosity of saturated systems Chew and Connally, Kartoatmodjo, Khan, De Ghetto,
(p.432) Hossain, Petrosky, Elsharkawy, or Beggs and
Robinson.
Live oil viscosity of undersaturated Vasquez and Beggs, Kouzel, Kartoatmodjo, Khan, De
systems (p.434) Ghetto, Hossain, Petrosky, Elsharkawy, Bergman or
None.
Viscosity of oil/water mixtures (p.470) Inversion, Volume Ratio, or Woelflin.
Gas viscosity (p.439) Lee et al.
Gas compressibility (p.436) Standing, Hall and Yarborough, or Robinson et al.
Oil-gas surface tension (p.440)
Water-gas surface tension (p.440)

Correlation data
The data points spanned the following ranges :

Lasater (p.505) Standing (p.509) Vasquez and Beggs

(p.428)
Data Correlation was Correlation was based Correlations use data
developed in 1958 on 105 experimentally from more than 600 oil
from 158 determined bubble systems. Approximately
experimental data point pressure of 6,000 measured data
points California oil systems. points were collected.

Pb bubble point 48 to 5,780 130 to 7,000 50 to 5,250

pressure (psia)
T temperature (F) 82 to 272 100 to 258 70 to 295
API API gravity 17.9 to 51.1 16.5 to 63.8 16 to 58
( API)

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G gas specific 0.574 to 1.223 0.59 to 0.95 0.56 to 1.18

gravity

Rsb solution gas at 3 to 2,905 20 to 1,425 20 to 2,070

bubble point
pressure (scf/
STB)

Beggs and Robinson Chew and Connally

Data Data from 600 oil systems were used Data from 457 oil systems
to develop correlations for dead and was used to develop
live oil viscosity. 460 dead oil correlation for live oil
observations and 2,073 live oil viscosity
observations were used.

Pb bubble point pressure 50 to 5,250 132 to 5,645

(psia)
T temperature (F) 70 to 295 72 to 292
API API gravity ( API) 16 to 58

G gas specific gravity

Rsb solution gas at bubble 20 to 2,070 51 to 3,544

point pressure (scf/
STB)

Glas (p.503) developed PVT correlations from analysis of crude oil from the following North Sea
Fields:- Ekofisk Stratfjord Forties Valhall COD 30/7-2A.

Solution Gas-oil Ratio

The solution gas-oil ratio, Rs (scf/STB), can be determined using one of a number of correlations:
De Ghetto et al (p.423)
Glas (p.424)
Kartoatmodjo and Schmidt (p.424)
Lasater (p.425)
Petrosky and Farshad (p.425)
Standing (p.425)
Vasquez and Beggs (p.426)
The correlations depend on:

P pressure (psia)
T temperature (F)
API API gravity ( API)

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G gas specific gravity

De Ghetto et al.
De Ghetto et al. give different correlations for the solution gas-oil ratio and the bubble point
pressure. In PIPESIM it is important to use related formula for these two properties to ensure
consistency. The PIPESIM implementation of the solution gas-oil ratio is therefore derived from the
De Ghetto et al equations for the bubble point pressure.

Extra heavy oil, API < 10

For extra heavy oil the De Ghetto formula is a modified version of the Standing (p.425) formula:
1.1128
P
Rs (P , T ) = C G Eq. 7.267
10.7025 A(T )
Here A is a function of the fluid temperature and the oil API density:

log 10 A = 0.002 T 0.0142 API Eq. 7.268

C is a calibration (p.426) constant.

Heavy oil, 10 < API < 22.3
For heavy oil the De Ghetto formula is a modified version of the Standing (p.425) formula:
1/0.7885
P
Rs (P , T ) = C G Eq. 7.269
15.7286 A(T )
Here A is a function of the fluid temperature and the oil API density:

log 10 A = 0.002 T 0.0142 API Eq. 7.270

C is a calibration (p.426) constant.

Medium oil, 22.3 < API < 31.1
For medium oil the De Ghetto formula is a modified version of the Kartoatmojdo and Schmidt
(p.424) formula:
C2 C4
Rs = C C 1 G (1 + gcorr ) A(T ) P Eq. 7.271

Here A is a function of the fluid temperature and the oil API density:
API
log 10 A = C3 Eq. 7.272
T + 460
If the separator pressure and temperatures are known then a non-zero gas specific gravity
correction factor is used:

gcorr = 0.1595 API

0.4078
T sep
0.2466
log 10 ( )
Psep
114.7
Eq. 7.273

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C is a calibration (p.426) constant.

The constants C1, C2, C3 and C4 :

C1 C2 C3 C4
0.10084 0.2556 7.4576 0.9868

Light oil, 31.1 < API

For light oil the De Ghetto formula is a modified version of the Standing (p.425) formula:
1/0.7885
P
Rs (P , T ) = C G Eq. 7.274
31.7648 A(T )
Here A is a function of the fluid temperature and the oil API density:

log 10 A = 0.0009 T 0.0148 API Eq. 7.275

C is a calibration (p.426) constant.

Glas
The Glas formula for the solution gas-oil ratio is:
1.22549 1.212009 0.210784
Rs = G f (P ) API T Eq. 7.276

Here:

log10 f (P ) = 2.887 1 1 0.397 log10 P C ( ) Eq. 7.277

C is a calibration (p.426) constant.

Kartoatmodjo and Schmidt
The Kartoatmodjo and Schmidt formula for the solution gas-oil ratio:
C2 C4
Rs = C C 1 G (1 + gcorr ) A(T ) P Eq. 7.278

Here A is a function of the fluid temperature and the oil API density:
API
log 10 A = C3 Eq. 7.279
T + 460
If the separator pressure and temperatures are known then a non-zero gas specific gravity
correction factor is used:

gcorr = 0.1595 API

0.4078
T sep
0.2466
log 10 ( ) Psep
114.7
Eq. 7.280

C is a calibration (p.426) constant.

The constants C1, C2, C3 and C4 depend on the oil API density:

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C1 C2 C3 C4
API < 30 0.05958 0.7972 13.1405 1.0014
API > 30 0.0315 0.7587 11.2895 1.0937

Lasater
The Lasater formula for the solution gas-oil ratio:

YG O
Rs (P , T ) = C 132755 Eq. 7.281
(1 Y G ) MW O

Y G = 0.08729793 + 0.37912718 ln ( P G
T + 460
+ 0.769066 ) Eq. 7.282

The oil molecular weight is given by

2 3
MW O = 677.3893 13.2161 API + 0.024775 API + 0.00067851 API Eq. 7.283

The oil specific gravity is given by

141.5
O = Eq. 7.284
API + 131.5
C is a calibration (p.426) constant.
Petrosky and Farshad
The Petrosky and Farshad formula for the solution gas-oil ratio is
1
0.8439
G 0.5774

Rs (P , T ) = C ( 112.727
P
+ 12.34)
A(T )
Eq. 7.285

Here A is a function of the fluid temperature and the oil API density:
5 1.3911 4 1.541
A(T ) = 4.561 10 T 7.916 10 API Eq. 7.286

C is a calibration (p.426) constant.

Standing
The Standing formula for the solution gas-oil ratio used in PIPESIM is:
1/0.83
P
Rs (P , T ) = C G Eq. 7.287
A(T ) 18
Here A is a function of the fluid temperature and the oil API density:

log 10 A = 0.00091 T 0.0125 API Eq. 7.288

C is a calibration (p.426) constant.

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Vasquez and Beggs

The Vasquez and Beggs formula for the solution gas-oil ratio used in PIPESIM is:
C C
Rs (P , T ) = g (P 14.7) 2 A(T ) Eq. 7.289
C1
Here A is a function of the fluid temperature and the oil API density:

C3 API
log 10 A = Eq. 7.290
T + 460
C is a calibration (p.426) constant.
The constants C1, C2 and C3 depend on the oil API density:

C1 C2 C3
API < 30 11.172 1.0937 11.172
API > 30 10.393 1.187 10.393

Calibration

( )
If a calibration data point is provided, Rscal = R Pcal , T cal , then the calibration term C is
s
calculated to ensure the calibration point is a solution of the relevant solution gas-oil ratio equation.
For example, for the Vasquez and Beggs (p.426) equation, the calibration term will be given by
C C
Rscal = g ( Pcal 14.7) 2 A(T cal ) Eq. 7.291
C1
Hence the Vasquez and Beggs (p.426) equation for the solution gas oil ratio can be re-written as:

Rs (P , T ) = Rscal
( P 14.7
Pcal 14.7 )
C2

A( T )
A(T cal )
Eq. 7.292

It is assumed that the calibration point is a bubble point (p.426), although this will in fact only be
the case if the calibration solution gas-oil ratio Rscal is equal to the fluid GOR.

If no calibration data is provided, PIPESIM uses C = 1.

Bubble point pressure

The bubble point pressure Pb(T ) is the pressure at which all the free gas is dissolved, i.e. when the
solution gas-oil ratio is equal to the fluid GOR:

Rs (Pb, T ) = Rsb Eq. 7.293

The bubble point can therefore be determined by solving the relevant solution gas-oil ratio (p.422)
equation.

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Oil Formation Volume Factor

The oil formation volume factor (FVF) is the ratio of the oil volume (at a given pressure and
temperature) to the stock tank oil volume. As pressure increases, two competing processes take
place: gas is dissolved in oil which increases the volume, and the oil is compressed, which
decreases the volume. Below the bubble point, the effect of gas dissolving in oil dominates and the
saturated oil FVF increases with pressure. However at the bubble point pressure, all the available
gas has dissolved in the oil. Therefore above the bubble point pressure the only effect is
compressibility and the undersaturated oil FVF increases with pressure.

Separate correlations are available for the saturated oil FVF (p.427) and undersaturated oil FVF
(p.428).

Related links:
Calibration Properties (p.154)

Oil Formation Volume Factor for Saturated Systems

For saturated systems P < Pb the oil formation volume factor Bob (bbl/STB) depends on the
solution gas-oil ratio Rs and the temperature T .

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Standing
The saturated oil formation volume factor is given by:
1.175
Bob = 0.972 + 0.000147F Eq. 7.294

where the correlating factor is calculated using :

( )
0.5
g
F = Rs + 1.25T Eq. 7.295
o

Data used to develop correlation (p.421)

Vasquez and Beggs

The saturated oil formation volume factor is given by:
Bob = 1 + C1Rs + C2(T 60)
( )API
G
+ C3 Rs (T 60)
API
G( ) Eq. 7.296

C1 C2 C3
API < 30 4.677 104 1.751 105 -1.81 108

API > 30 4.67 104 1.100 10

5
1.337 10
9

Data used to develop correlation (p.421)

Kartoatmodjo and Schmidt

The saturated oil formation volume factor is given by:
1.50
Bob = 0.98496 + 0.0001F Eq. 7.297

Where the correlating factor

0.755 0.25 1.50
F = RS g o + 0.45T Eq. 7.298

Oil Formation Volume Factor for Undersaturated Systems

The oil formation volume factor Bo (bbl/STB) for pressures above the bubble point is given by a
simple compressibility law:

Bo = Bob(Rsb) exp Z o ( pb p ) Eq. 7.299

where Zo is the oil compressibility and is a calibration factor (used in mixing different fluids).

Vasquez and Beggs

The Vasquez and Beggs correlation for the oil compressibility is

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5 Rsb + 17.2 T 1180 G + 12.61 API 1433

Zo = 10
5 Eq. 7.300
P
Data used to develop correlation (p.421)

TURZO Method
The performance of a rotodynamic (centrifugal or vertical) pump on a viscous liquid differs from the
performance on water, which is the basis for most published curves. Typically, head and rate of
flow decrease as viscosity increases, while power and the net positive suction head required
(NPSHR) increases. Starting torque could be affected.
The following formula is the TURZO equation for viscosity correction:
Q H
Power = Eq. 7.301
E
where
P is power.
Q is the rate.
H is the head.
E is the efficiency.

Qv = Q f Q Eq. 7.302
Hv = H f H Eq. 7.303
Ev = E f E Eq. 7.304

where the value of each equation is less than 1.

The viscosity correction is calculated as follows:
Pv fQ fH
= Eq. 7.305
P fE

Oil Viscosity
As pressure increases, two competing processes take place: gas is dissolved in oil which lightens
the oil, reducing its viscosity, and the oil is compressed, which increases the viscosity. Below the
bubble point, the effect of gas dissolving in oil dominates and the saturated viscosity decreases
with pressure. However at the bubble point pressure, all the available gas has dissolved in the oil.
Therefore above the bubble point pressure the only effect is compressibility and the
undersaturated viscosity decreases with pressure.

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Three sets of correlations are used to determine the oil viscosity:

1. At stock tank pressure the oil viscosity is given by dead oil viscosity correlations (p.430) as a
function of the flowing fluid temperature o ( Ps , T ) = od (T ).
2. At pressures below the bubble point the oil viscosity is given by live oil viscosity correlations
(p.432) as a function of the dead oil viscosity and the solution gas-oil ratio
o (P , T ) = ob( od , Rs ).
3. At pressures above the bubble point the oil viscosity is given by undersaturated oil viscosity
correlations (p.434), as a function of the bubble point viscosity and the pressure
o (P , T ) = ou ( ob, P ).

Dead Oil Viscosity

The correlations available for calculating dead oil viscosity are:

Beggs and Robinson

Dead oil viscosity is calculated as follows :
x
od = 10 1 Eq. 7.306
1.163
where x = yT

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z
and y = 10 and z = 3.0324 0.02023 g API
Data used to develop correlation (p.421)

Glas
Dead oil viscosity is calculated as follows :
d
od = c log 10(gAPI ) Eq. 7.307

where
10 3.444
c = 3.141 10 T and d = 10.313 log 10(T ) 36.447

Kartoatmodjo and Schmidt

Dead oil viscosity is calculated as follows :
d
od = c log 10(gAPI ) Eq. 7.308

where
8 2.8177
c = 16 10 T and d = 5.7526 log 10(T ) 26.9718

De Ghetto et al
De Ghetto et al. use a combination of four correlations to compute the dead oil viscosity depending
on the value of the API.
For API < 10 (extra heavy oils) the following correlation is used:
x
od = 10 1 Eq. 7.309
y
where x = 10 and y = 1.90296 0.012619 g API 0.61748 log10 (T )
For 10 < API < 22.3 (heavy oils) the following correlation is used:
x
od = 10 1 Eq. 7.310
y
where x = 10 and y = 2.06492 0.0179 g API 0.70226 log 10(T )
For 22.3 < API < 31.1 (medium oils) the following correlation is used:
d
od = c log 10(gAPI ) Eq. 7.311

9 3.556
where c = 220.15 10 T and d = 12.5428 log 10(T ) 45.7874
For API > 31.1 (light oils) the following correlation is used
x
od = 10 1 Eq. 7.312
y
where x = 10 and y = 1.67083 0.017628 g API 0.61304 log 10(T )

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Petrosky and Farshad

Dead oil viscosity is calculated as follows:
d
od = c log 10(gAPI ) Eq. 7.313

7 2.10255
where c = 2.3511 10 T and d = 4.59388 log 10(T ) 22.82792

Hossain et al
Hossain et al. correlation for dead oil viscosity is only valid for heavy oils (10 < API < 22.3) and it is
given as follows:
A B
od = 10 T Eq. 7.314

where A = 0.71523 g API + 22.13766 and B = 0.269024 g API 8.268047

Elsharkawy and Alikhan

Elsharkawy and Alikhan dead oil viscosity is only valid in the API range 20-48 and is calculated as
follows:
x
od = 10 1 Eq. 7.315
y
where x = 10 and y = 2.16924 0.02525 g API 0.68875 log 10(T )

User's data
If user's data is selected for the dead oil viscosity method, then a curve is fitted through the two
( ) ( )
supplied data points 1, T 1 and 2, T 2 of the following form:

( )
log od = log ( B ) C log (T ) Eq. 7.316

where

C=
log ( ) 1
2

( )
Eq. 7.317
T2
log
T1
and
C C
B = 1T 1 = 2T 2 Eq. 7.318

Live Oil Viscosity Correlations

Many of the correlations available for calculating live oil viscosity are of the form
B
ob = A od Eq. 7.319

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where A and B are functions of the Solution gas-oil ratio Rs :

Correlation A B
Chew and
Connally
Data used
to develop
correlation
0.2 +
( 10
0.8
0.000852 Rs ) 0.482 +
( 10
0.518
0.000777 Rs )
(p.421)
Beggs and Data used 0.515 0.338
Robinson to develop (
10.715 Rs + 100 ) (
5.44 Rs + 150 )
correlation
(p.421)
Elsharkawy 1.12410 1.06622
and Alikhan (
1241.932 Rs + 641.026 ) (
1768.841 Rs + 1180.335 )
Hossain et al 1 1.7188311 10
3
Rs + 1 2.052461 10
3
Rs +

6 2 6 2
+1.58031 10 Rs +3.47559 10 Rs

Petrosky and 4 Rs 3 Rs
Farshad 0.1651 + 0.6165 0.9886 10 0.5131 + 0.5109 0.9973 10

Other authors use more complicated formulas:

Kartoatmodjo and Schmidt

Live oil viscosity is calculated as follows:
2
ob = 0.06821 + 0.9824F + 0.0004034F Eq. 7.320

where
0.43+0.5165 B
F = A od Eq. 7.321

and
0.000845 Rs
A = 0.2001 + 0.8428 10 Eq. 7.322

and
0.00081 Rs
B = 10 Eq. 7.323

Khan

Live oil viscosity calculated by Khan is a function of the gas and oil specific gravities ( G , O ), the
solution gas-oil ratio ( Rs ), the bubble pressure ( Pb), and the flowing pressure ( P ). It is given as
follows:

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y
ob = A e Eq. 7.324

where

y = ln (0.09) + 0.5 ln ( G )
1
3
( )
ln Rs 4.5 ln
T
460( )
3 ln 1 O ( ) Eq. 7.325

and

( )
0.14
P 2.5104( P Pb)
A= e Eq. 7.326
Pb

De Ghetto et al
De Ghetto et al. expression of the live oil viscosity is a combination of 4 correlations depending on
the value of oil API.

F A B
For API ob = 2.3945 + 0.8927F +
0.5798+0.3432 B 0.0335 + 0.00081 Rs
< 10 A od 10
(extra 2 0.000845 Rs
heavy +0.01567 F +1.0875 10
oils)
For 10 < = 0.6311 + 1.078 F 0.4731+0.5664 B 0.2478 + 0.00081 Rs
API < ob A od 10
22.3 2 0.000845 R s
(heavy 0.003653 F +0.6114 10
oils)
For 22.3 = 0.0132 + 0.9821 F 0.3855+0.5664 B 0.2038 + 0.00081 Rs
< API < ob A od 10
31.1 2 0.000845 Rs
(medium 0.005215 F +0.8591 10
oils)
For API B 0.6487 0
> 31.1 ob = A od (
25.1921 Rs + 100 ) (
2.7516 Rs + 150 )
(light
oils)

Undersaturated Oil Viscosity

The correlations available for calculating undersaturated oil viscosity are:

Vasquez and Beggs

Undersaturated oil viscosity is calculated as follows:

( )
A
p
ou = ob Eq. 7.327
pb

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where A = 2.6 p
1.187
(
exp 8.98 10 p 11.513
5
)
Data used to develop correlation (p.421)

Kouzel
Undersaturated oil viscosity is derived from the equation:
F ( p)
10
ou = ob Eq. 7.328
F ( pb)
10
p 14.7
F ( p) =
(
1000 A + B od
0.278
) Eq. 7.329

Where A and B are parameters entered by the user. Suggested values for A and B are 0.0239 and
0.01638 respectively.

Kartoatmodjo and Schmidt

Undersaturated oil viscosity is calculated as follows:

ou = 1.00081 ob + 0.001127 A( p pb) Eq. 7.330

A = 0.006517 ob ( 1.8148
) + 0.038( ) ob
1.59

Khan
Undersaturated oil viscosity is calculated as follows:

ou = obexp 9.65e
5
( p pb) Eq. 7.331

De Ghetto et al
De Ghetto et al. expression of the undersaturated oil viscosity is a combination of 3 correlations
depending on the value of oil API.
For API < 10 (extra heavy oils) the following correlation is used:

ou = ob 1
( p
pb )( A
B ) Eq. 7.332

where A = 10
2.19
( od
1.055
)( p b
0.3132
) and B = 10( 0.0099 g API )
For 10 < API < 22.3 (heavy oils) the following correlation is used:

ou = 0.9886 ob + 0.002763 A( p pb) Eq. 7.333

where A = 0.01153 ob ( 1.7933

) + 0.03610( ob
1.5939
)
For API > 22.3 ( medium and light oils) the following correlation is used:

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(
ou = ob 1
p A
pb B ) Eq. 7.334

where A = 10
2.19
( oD
1.055
)( p
b ) and B = 10(
0.3132 0.00288 g API )

Hossain et al
Undersaturated oil viscosity is calculated as follows:

ou = ob + 0.004481( p pb)( A B ) Eq. 7.335

where A = 0.555955 ob ( 1.068099

) and B = 0.527737( ob
1.063547
)
Petrosky and Farshad
Undersaturated oil viscosity is calculated as follows:

ou = ob + 1.3449E
3
( p pb)(10 A) Eq. 7.336
2
where A = 1.0146 + 1.3322 X 0.4876 X 1.15036 X and X = log10 ob
3
( )
Elsharkawy and Alikhan
Undersaturated oil viscosity is calculated as follows:

ou = ob + A 10
2.0771
( p pb) Eq. 7.337
1.19279 0.40712 0.7941
where A = od ob pb

Bergman and Sutton

Undersaturated oil viscosity is calculated as follows:
B
ou = obexp A( p pb) Eq. 7.338

4 5 7 2
where A = 2.278877 10 1.48211 10 X + 6.5698 10 X ,
B = 0.873204 + 2.24623 10 X and X = log 10( ob)
2

Disabling the calculation of undersaturated oil viscosity

If you select None as the undersaturated oil viscosity method, then the undersaturated oil viscosity
is assumed to be the same as the saturated live oil viscosity at the same temperature and
pressure.

Gas Compressibility
The real gas law is given by pV = ZRT where

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p pressure
V volume
R universal gas constant
T absolute temperature
Z gas compressibility factor

Numerous equations of state have been proposed to predict this Z-factor. Standing and Katz
presented a generalized Z-factor chart for predicting the volumetric behavior of natural gases. To
employ this chart, we require knowledge of the critical properties of the gas (namely, critical
pressure and critical temperature) as a function of the specific gravity. These are given in the black
oil model by Standing (1977) for natural gas and gas-condensate systems:

Gas Systems
2
T c = 168 + 325 G 12.5 G Eq. 7.339

Gas-Condensate Systems
2
T c = 187 + 330 G 71.5 G Eq. 7.340

2
pc = 706 51.7 G 11.1 G Eq. 7.341

where

T c critical temperature

pc critical pressure

G specific gravity of the gas mixture

This allows us to calculate the reduced temperature and reduced pressure, defined respectively
as:
T
Tc = Eq. 7.342
Tc
p
pc = Eq. 7.343
pc
Various correlations have been proposed for curve fitting this reduced pressure-reduced
temperature Z-factor chart and are available in PIPESIM:
Hall-Yarborough Z-Factor Correlation (p.438)
Standing Z-Factor Correlation (p.438)
Robinson et al. Z-Factor Correlation (p.439)

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Hall-Yarborough Z-Factor Correlation

Gas compressibility (Z-factor) is calculated as follows:

( )
2
0.06125 pR T R (
x 1.2 1T R ) Eq. 7.344
Z= e
R
where the reduced density is a root of the following equation:

2 ( + + )
R R
2
R
3
R
4

F ( R ) = 0.06125 pr T R 1.2(1 T R ) +
((1 ) ((14.67T ) 9.76T 4.85T ) ) Eq. 7.345
3 2 3 2

R R R R R
(
+ 90.7T R 242.2T R
2
+ 42.4T )
R
3
R
2.18+2.82T R
=0

where

where R reduced density

pR reduced pressure

TR reciprocal of the reduced temperature

The method is not recommended for use within a pressure range pR = 0, 1 .

Standing Z-Factor Correlation

Gas compressibility (Z-factor) is calculated as follows:
A + (1 A)
Z= G
x Eq. 7.346
e B + FP r

where the coefficients A to G are given by:

0.5
A = 1.39(T r 0.92) 0.36T R 0.101
6
0.32 pR
0.666 2
B = (0.62 0.23T r ) pR + 0.037 pR +
(T r 0.86) 10 (
9 T R 1 )

C = (0.132 0.32log (T R ))
2

D = 10 ( 0.30160.49T R +0.1824T R
)
The method is not valid for T R < 0.92.

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Robinson et al. Z-Factor Correlation

Gas compressibility (Z-factor) is calculated as follows:

Z = 1 + A1 +
( )( )
A2
TR
+
A3

TR
3 R + A4 +
2
( )
A5
TD
2
R +
A5 A6
R
DR
5

Eq. 7.347
A7
( ) ( )
2 2 x A8 R
+ 3 R 1 + A8 R e
Tr

where

0.27 pR
D=
TR

A1 = 0.310506237

A2 = 1.4067099

A3 = 0.57832729

A4 = 0.53530771

A5 = 0.61232032

A6 = 0.10488813

A7 = 0.68157001

A8 = 0.68446549

The method is valid within a temperature and pressure range of T r = 1.05, 3.0 and
pr = 0.2, 3.0 .

Gas Viscosity
Gas viscosity is calculated using the Lee et al (p.505) correlation as follows:
Y
g = K exp X g Eq. 7.348

where

(7.77 + 0.183 G ) (T + 460)1.5 4

K= 10
(122.4 + 373.6 G + T + 460)

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1914.5
X = 2.57 + + 0.275 g
T
Y = 1.11 + 0.04 X

g is the gas viscosity (cp)

g is the gas specific gravity

g is the gas density (g/cc)

T is the temperature ( oF )

Related links:
Calibration Properties (p.154)

Surface Tension
Oil-gas Surface Tension
The oil-gas surface tension is given by Baker and Swerdloff (p.499):

O = 37.7 0.05 (T 100) 0.26 API

Eq. 7.349
4 7 2 11 3
1 7.1 10 P + 2.1 10 P + 2.37 10 P

O is the surface tension between the oil and the gas (dynes/cm)

P is the pressure (psia)

T is the temperature o
( F)

API is the oil API gravity

Water-gas Surface Tension

The water-gas surface tension is given by Katz:

W = 70 0.1 (T 74) 0.002 P Eq. 7.350

W is the surface tension between the water and the gas (dynes/cm)

P is the pressure (psia)

T is the temperature o
( F)

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Black Oil Enthalpy

Black Oil Fluid Enthalpy Model
The black oil fluid model makes some approximations in the entropy balance based upon the
thermodynamic behavior of typical hydrocarbon fluids. The black oil model is suitable for light,
medium and heavy oil based fluids, particularly if significant quantities of water are present. The
black oil model is fast, simple to use and easy to calibrate. It is also suitable for gas and gas/
condensate screening studies.
There are currently two black oil enthalpy calculation methods available in PIPESIM.

2009 Method
The enthalpy of the gas phase is given by:

H g = c p T g c P + H vap Eq. 7.351

g pg

The enthalpy of the oil phase is given by:

H o = c p T o c P Eq. 7.352
o po

The enthalpy of the water phase is given by:

H w = c p T w c P Eq. 7.353
w pw

where the gas, oil and water Joule Thomson coefficients are approximated by (Ref: Alves, Alhanati
and Shoham (p.499):

/
1 T Z
g = 5.40395
Z T Eq. 7.354
g c
pg

/
1
o = 5.40395
Eq. 7.355
o c
po

/
1
w = 5.40395
Eq. 7.356
w c
pw

The total enthalpy of the fluid is given by:

H = H g wg + H o wo + H w ww Eq. 7.357

where:

H is the specific enthalpy BTU / lb

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T is the flowing temperature o

F
P is the flowing pressure psia
cp is the specific heat capacity at constant pressure BTU lb oF
/
is the Joule Thomson coefficient F / psia
o

is the flowing density lb / ft

3

Z is the gas compressibility factor dimensionless

w is the flowing mass fraction dimensionless

H vap is the latent heat of vaporization BTU / lb

/ 3
1 BTU ft = 5.40395 psia

1983 Method
The enthalpy of the gas phase is given by:

H g = c p T + P (1.619 10 )P 0.02734
10 6
P + 1.412 10 Eq. 7.358
g
The enthalpy of the oil phase is given by:
3
H o = c p T + 3.36449 10 P Eq. 7.359
o
The enthalpy of the water phase is given by:

( )
3
2.9641 10
H w = cp T + P Eq. 7.360
w w
The total enthalpy of the fluid is given by:

H = H g mg + H o mo + H w mw Eq. 7.361

where:

m is the stock tank mass fraction dimensionless

is the stock tank specific gravity dimensionless

Black Oil Mixing

Introduction
Mixing occurs in network models, when two or more streams meet at a junction and in single
branch models where injected fluid, or fluids from multiple completions mix with fluid already in the
branch. The fluid properties of the mixed stream need to be determined.

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Stock Tank Oil Properties

Phase ratios (Gas Oil Ratio / Water cut)

The phase ratios for a mixed stream are calculated by adding the individual phase rates of each
stream and then calculating the ratio of the phases. The calculations are at stock tank conditions.

Qvg ,mix
GOR mix = Eq. 7.362
Qvo ,mix
Qvw ,mix
WCUT mix = Eq. 7.363
Qvw ,mix + Q
vo ,mix
Here:

GOR mix is the gas oil ratio of the mixture

WCUT mix is the water cut of the mixture

n is the stock tank oil volume rate of the combined stream

Qvo ,mix = Qvo ,i
i =1
n is the stock tank water volume rate of the mixture
Qvw ,mix = Qvw ,i
i =1
n is the stock tank gas volume rate of the mixture
Qvg ,mix = Qvg ,i
i =1

Qvo ,i = QvL ,i ( )
1 WCUT i is the stock tank oil volume rate of stream i

Qvw ,i = QvL WCUT i is the water volume rate of stream i

,i

Qvg ,i = QvL GOR i is the stock tank gas volume rate of stream i
,i

QvL = Qvo ,i + Qvw ,i is the stock tank liquid volume rate of stream i
,i

WCUT i is the water cut of stream i

GOR i is the gas oil ratio of stream i

n is the number of streams in the mixture

Phase densities
The phase densities (and specific gravities) are determined as a volumetric average of the input
stream densities:

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DOD i Qvo ,i
DOD mix = Eq. 7.364
Qvo ,mix
GSG i Qvg ,i
GSG mix = Eq. 7.365
Qvg ,mix
WSG i Qvw ,i
WSG mix = Eq. 7.366
Qvw ,mix
Here:

DOD mix is the dead oil density of the mixture

GSG mix is the gas specific gravity of the mixture

WSG mix is the water specific gravity of the mixture

DOD i is the dead oil density of stream i

GSG i is the gas specific gravity of stream i

WSG i is the water specific gravity of stream i

Contaminants
The mole fractions of contaminants for the mixed stream is determined using a gas phase
volumetric average of the individual stream mole fractions:

Z j ,i Qvg ,i
Z j ,mix = Eq. 7.367
Qvg ,mix
Here:

Z j ,mix is the mole fraction of contaminant j in the mixture

Z j ,i is the mole fraction of contaminant j in stream i

Thermal Data (Heat Capacity and thermal conductivity)

The phase thermal properties of mixed streams are calculated using mass averages of the phase
properties of the input streams:

CP ,i Q ,i
CP ,mix = Eq. 7.368
Q ,mix

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K ,i Q ,i
K ,mix = Eq. 7.369
Q ,mix
H vap ,i Qg ,i
H vap ,mix = Eq. 7.370
Qg ,mix
Here:

is the phase, oil = O , vapor (gas) = G , or water = W

CP ,mix is the heat capacity of phase in the mixture

K ,mix is the thermal conductivity of phase in the mixture

H vap ,mix is the latent heat of vaporization of the gaseous phase g in the mixture

CP ,i is the heat capacity of phase in stream i

K ,i is the thermal conductivity of phase in stream i

H vap ,i is the latent heat of vaporization of the gaseous phase g in stream i

n is the mass flow rate of phase of the mixture

Q ,mix = Q ,i
i =1

Q ,i is the mass flow rate of phase of stream i

Correlations
Unlike other properties, the choice of correlations used for the combined fluid can not be decided
by averaging. Instead, the selected correlation for the mixed stream is chosen as the one which
has the highest flow rate associated with it for the relevant phase. For example the correlation for
mixture Oil Viscosity is set to be the correlation that has maximum stock tank rate associated with
it.
While deciding the correlation for the mixed stream, we have to consider following rules:
All properties are independent of each other. For example the. choice for mixture dead Oil
viscosity correlation has nothing to do with mixture live Oil viscosity
Resultant mixture correlation is decided based on associated phase rate (for example, oil if we
are deciding Oil property) ; not based on number of streams using that correlation
Stock tank flow rates are used at the point of mixing.

Example 1
For an example assume we are mixing 7 flow streams which have different sets of correlations as
tabulated below:

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Stream Flow rate (STB/ Dead Oil Viscosity Live Oil Viscosity Under-saturated Oil
day) Viscosity
1 5000 Hossain Kartoatmodjo Vasquez and Beggs
2 2000 Glasso Khan Kouzel
3 4000 Petrosky-Farshad Chew and Connally Kouzel
4 3000 Beggs and Robinson Khan Kouzel
5 6000 Beggs and Robinson Kartoatmodjo Bergman and Sutton
6 8000 Glasso Hossain Bergman and Sutton
7 2000 Beggs and Robinson Elsharkawy Kouzel

The total oil flow for each correlation, and the correlations selected for the combined fluid are
tabulated below:

Stream Flow rate (STB/day) Dead Oil Viscosity

4,5,7 11000 Beggs and Robinson
2,6 10000 Glasso
1 5000 Hossain
3 4000 Petrosky-Farshad
combined 30000 Beggs and Robinson

Stream Flow rate (STB/day) Live Oil Viscosity

1,5 11000 Kartoatmodjo
6 8000 Hossain
2,4 5000 Khan
3 4000 Chew and Connally
7 2000 Elsharkawy
combined 30000 Kartoatmodjo

Stream Flow rate (STB/day) Under-saturated Oil Viscosity

5,6 14000 Bergman and Sutton
2,3,4,7 11000 Kouzel
1 5000 Vasquez and Beggs
combined 30000 Bergman and Sutton

Example 2
Mixing of fluids that use different correlations may produce unexpected results. In the above
example, a 51%-49% mixture of streams 1 and 2 will use the same correlations as stream 1, but a
49%-51% mixture will use the same correlations as stream 2. So, even though these to mixtures

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are similar, their properties may be modelled completely differently. Therefore it is important to
select compatible correlations when modelling networks.

Calibration data
A number of correlations are calibrated using user supplied data. This section describes how
streams with different calibration data are mixed.

Dead oil viscosity

Dead oil viscosity (p.430) can be specified using no calibration data; 2point {(T 1, 1), (T 2, 2)}
calibration data; or as a User Supplied Table with multipoint calibration data
{(T 1, 1), ( )}
, T n , n . If none of the streams in a mixture use calibration data, then the mixing
is done by simply determining the mixture correlation, as outlined in Correlations (p.445). If
however, at least one of the input streams uses dead oil viscosity with calibration data then a User
Supplied Table is used for the mixture deadoil viscosity. The table entries are calculated in three
steps:

{ }
1. The number and value of the temperature points T x in the table are determined:
If the inlet streams use multipoint calibration, then the mixed stream will use multipoint
calibration. PIPESIM will try to include all the input temperatures in the mixture table, up to a
maximum of 40 points.
If the inlet streams only use 2point calibration data, then the mixed stream will use only two
points. The Temperature will be set to the minimum and maximum temperatures of the input
stream calibration temperatures.

( )
2. The viscosity of each inlet stream i T x is calculated at each temperature in the mixed stream
table.
3. The mixture viscosity is calculated at each point in the stream using the Kendall and Monroe
cubic mixing rule:

( )
3
n Qvo ,i 1/3
comb(T x ) = ( ( ))
i T x Eq. 7.371
i =1 Qvo ,mix

Example 3
Streams 13, defined in the table below, mix at a junction. All streams use dead oil correlations
without data, so the mixed stream, stream 4, uses the dead oil correlation with the biggest flow, in
this case Beggs and Robinson. Stream 4 then mixes with stream 5 at another junction. Stream 5
uses a correlation with calibration data. Even though stream 5 has less flow than stream 4, the
mixture, stream 6, will use a User Supplied Table to define its dead oil correlation.

Stream Flow rate (STB/day) Dead Oil Viscosity

1 2000 Beggs and Robinson
2 2500 Chew and Connally

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3 1000 Beggs and Robinson

4= 1+2+3 5500 Beggs and Robinson
5 2500 Any correlation with 2point data, or a User Supplied Table
6 = 4+5 8000 User Supplied Table

Solution Gas Rs

( )
If one or more of the input streams has a single point calibration data, Rsi Pref ,i , T ref ,i , then the
mixed stream solution gas will also be calibrated using a single point:
1. Determine the correlation (p.445) for the mixed stream.

( )
2. Determine reference pressure and temperature values Pref ,mix , T ref ,mix for calibrating the
mixed stream viscosity. These are calculated as the mass flow rate average of the input stream
reference pressures and temperatures for those input streams with calibration data.
3. Determine the solution gas of each stream at the reference pressure and temperature for the
( )
mixed stream Rsi Pref ,mix , T ref ,mix . For those streams that are undersaturated at
(Pref ,mix , T ref ,mix ) the potential solution gas is determined by extrapolation.

4. The solution gas for the mixed stream is determined as a volume average of all the input
stream solution gas (or potential solution gas) values.

Live oil viscosity

A number of steps are needed to determine the live oil viscosity of a mixture:
1. Determine the correlation (p.445) for the mixed stream.

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(
2. Determine reference pressure and temperature values Pref ,mix , T ref ,mix for calibrating the )
mixed stream viscosity. These are calculated as the mass flow rate average of the input stream
reference pressures and temperatures, for those input streams with calibration data. If the
mixed stream is not saturated at the calculated reference pressure and temperature, the
reference pressure is reduced to the saturation pressure
n Qo ,i
T ref ,mix = T ref ,i
1=1 Qo ,mix
n Qo ,i
Pref ,mix = MIN Pref ,i , Psat ,mix (T ref ,mix )
1=1 Qo ,mix
3. Determine the input stream viscosities at the mixture reference pressure and temperature
o ,i (Pref ,mix , T ref ,mix ). If an input stream is undersaturated at (Pref ,mix , T ref ,mix ) then its
viscosity is calculated by first adding more gas so that the stream is saturated. The added gas
has a specific gravity equal to that of the mixture.

( )
4. The live oil viscosity of the mixture is calculated at Pref ,mix , T ref ,mix using the 7.371 (p.447)
equation.

5. The live oil correlation can then be calibrated using o ,mix Pref ,mix , T ref ,mix ( )
7.5.3 Compositional Fluid Modeling
In compositional fluid models the user can specify a number of components that make up the fluid.
These can be real molecules, such as methane, ethane or water, known as library components or
pseudo components that represent the properties of several molecules, known as petroleum

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fractions. The phase behaviour and thermodynamic properties are determined by an equation of
state (EOS). This equation of state is either a cubic equation (p.450) (this is a modified form of the
Van der Waals equation) or a non-cubic equation (p.454). The number of phases that can be
modelled depends on the flash package:
Two phase flash. Water is removed from the fluid and the remaining hydrocarbons are flashed
to determine the amount of oil and vapour. This method is used for most compositional flash
packages (and for black oil models). This means that water only appears in the water phase
and does not appear in the vapour phase.
Three phase flash. If the Multiflash compositional package is used, then a three phase flash is
performed. This means that there is a possibility that water will appear in the vapour phase, and
some components (e.g. water, methanoll) will appear in the aqueous phase.
The three phase flash gives a more accurate model of water behaviour than the two phase
flash. However, there can be problems when the flash produces two non-aqueous liquids
one of these may be mis-identified as water.
Multiphase flash. The Multiflash compositional standalone package can be used to model
vapour and three liquid phases as well as solid phases. Within PIPESIM flow simulations,
Multiflash is only ever used to model two liquid phases. However, it can be used within
PIPESIM to plot phase envelopes and to predict whether solid phases (asphaltene, hydrates,
wax and ice) would be present.

Cubic Equations of State

Equations of state (EoS) describe the pressure, volume and temperature (PVT) behavior of pure
components and mixtures. The phase state and most thermodynamic properties (e.g. density,
enthalpy, entropy) are derived from the equation of state. Separate models are used for transport
properties, such as Viscosity (p.429), thermal conductivity and surface tension. PIPESIM can use
both cubic and non-cubic (p.454) Equations of State.
Volume shift (three-parameter) and acentric factor corrections, if available, are recommended for
the cubic equations of state.
The cubic equation of state can be written as:
nRT a
P= + Eq. 7.372
V b (V + m b) (V + m b)
1 2

Where:

P is the pressure of the fluid

V is the total volume of the container containing the fluid
a is a measure of the attraction between particles
b is the volume excluded from V by a particle
n is the number of moles
T is the temperature
R is the gas constant

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m1, m2 constants:
( )
for the Peng-Robinson EOS m1, m2 = (1 + 2, 1 2)

(
for the Soave RedlichKwong EOS m1, m2 = (1, 0) )
The EoS is a cubic equation for the volume, as a function of the pressure, temperature and EoS
parameters. It is often written in terms of the compressibility:
PV
Z= Eq. 7.373
nRT
( )
In the special case m1, m2 = (0, 0) the cubic EoS reduces to van der Waals equation, and in the
special case when a = b = 0 the cubic EoS reduces to the ideal gas equation.
The parameters a and b are in fact functions of the pressure, temperature, composition,
component properties and the mixing rules. If there is more than one phase present, the
composition of each phase differs and hence each phase has different equation of state
parameters. Assuming a quadratic mixing rule for a and a linear mixing rule for b the parameters
for phase are given by
2 2 2
n R T 1/2
a = ( Ai A j ) (1 ij ) x i x j Eq. 7.374
P
nRT
b = Bi x i Eq. 7.375
P
Where:

x i is the mole fraction of component i in phase

Ai is a function of the temperature T , the component critical pressure Pci , critical temperature
T ci and acentric factor i

Bi is a function of the component critical pressure Pci and critical temperature T ci

ij is the Binary Interaction Parameter between component i and component j

Thermodynamic properties
Thermodynamic properties can be calculated from the equation of state. The method may vary
between flash packages. The following equations are used in E300 flash.

The fugacity coefficient i for each component in each phase is used to determine the phase
state and phase split. It is given by:

ln i =
RT
1
V
RT
V

( )
P
ni T ,V ,n j
d V ln
PV
RT Eq. 7.376

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The phase density can be found from the phase volume. For a two parameter Equation of State,
this is found by solving the cubic equation. However, this can give poor prediction of the liquid
density. For a three parameter Equation of State, the phase volume is modified by subtracting a
volume shift term:
eos
V = V x i V si Eq. 7.377
o
The phase enthalpy H is calculated from the ideal gas enthalpy: H :

H =
o
H V
T ( TP )V
P d V RT + PV Eq. 7.378

o
The phase entropy S is calculated from the ideal gas entropy: S :

S =
o
S ( TP )
V V

R
V
d V + R ln
PV
RT
Eq. 7.379

o
The ideal gas enthalpy and entropy are determined from the ideal gas specific heat C p :
T
o
H = T ref
o
C p dT Eq. 7.380

T o
C p
=
P
R ( x i ln x i )
o
S dT R ln Eq. 7.381
T ref T P ref
The ideal gas specific heat is calculated by summing the component specific heats
o o
C p = C pi x i Eq. 7.382
o
For library components, the component specific heat C pi is a known functions of temperature. For
user defined petroleum fractions, the component specific heat is calculated as a function of
temperature and the component molecular weight MW i , boiling point temperature T Bi , specific
gravity i and acentric factor i .

E300 Flash

The ECLIPSE version of the Peng Robinson EoS has an option correction for the Ai term for large
acentric factors (ECLIPSE PRCORR keyword).

E300 flash name Peneloux Volume Shift Correction Peng Robinson 1978 Acentric Factor
Correction
Peng-Robinson
Peng-Robinson Yes
Peng-Robinson Yes
Peng-Robinson Yes Yes

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SRK Yes
SRK

Multiflash
The Multiflash Implemnetation in PIPESIM has the cubic Equations of State, Peng-Robinson and
RKS, along with the Cubic Plus Association (CPA) model, which is an extension of the RKS
(advanced) cubic EoS to handle polar and hydrogen bonding components. The Multiflash
implementation also includes non-cubic EoS (p.454).
EoS names differ from those in the Multiflash GUI.

Peng Robinson
Peneloux Volume
PIPESIM GUI name Multiflash GUI name 1978 Acentric
Shift Correction
Factor Correction
Peng-Robinson PR (Advanced) Yes
NOT CURRENTLY
PR78 (Advanced) Yes
AVAILABLE
SRK RKS (Advanced) Yes
Association (CPA-
Association (CPA) Yes
Infochem)

Versions of the Peng-Robinson and SRK equations of state without the volume shift correction are
available, but are not recommended. Liquid densities predicted by these equations of state can be
poor. In particular the liquid water density is out by about 15%. This causes problems in PIPESIM,
since it can predict water being lighter than oil. This particular problem does not arise in two phase
flashes, where the water properties are not determined by the equation of state. It does occur in 3
phase flashes, such as Multiflash.

Peng Robinson 1978

Multiflash GUI Volume Shift
PIPESIM GUI name Acentric Factor
name Correction
Correction
Standard Peng-Robinson PR
NOT CURRENTLY AVAILABLE PR78 Yes
Standard SRK RKS

DBR flash

The DBR flash has both the Peng Robinson and the Soave RedlichKwong equations of state,
with both two and three parameter (volume shift) options:

DBR flash Volume Shift Correction

Peng-Robinson
Peng-Robinson Yes
SRK

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SRK Yes

Non-cubic Equations of State

Equations of state (EoS) describe the pressure, volume and temperature (PVT) behavior of pure
components and mixtures. The phase state and most thermodynamic properties (e.g. density,
enthalpy, entropy) are derived from the equation of state. Separate models are used for transport
properties, such as viscosity, conductivity and surface tension.
PIPESIM can use both cubic (p.450) and non-cubic and Equations of State.

Multiflash

BWRS
The BWRS is an 11-parameter non-cubic equation. The BWRS equation gives much more
accurate volumetric and thermal property predictions for light gases and hydrocarbons. It should
give reasonable vapor-liquid phase equilibrium predictions, but owing to its complexity, it requires
more computing time than the cubic EOS (e.g SRK or Peng-Robinson). The EoS is similar to a
virial expansion in density:

( ) ( )
2 2
RT B C D C
P= n+ + 2 + 5 + 5 1 + 2 exp Eq. 7.383
V V V V V V V
2

The BWRS EoS can be used with most of the components that can be used with the cubic EoS.
(p.459)

Note: It does not work with the Hydrogen component or with aqueous components.

CSMA
CSMA is the Multiflash multi-reference fluid corresponding states model. The CSMA model is
based on a collection of very accurate equations of state for a number of common substances. The
density, thermal properties and VLE of each substance are generally reproduced to within the
accuracy of experimental measurements. The properties of mixtures can be estimated from a
model that reduces to the (accurate) pure component values as the mixture composition
approaches each pure component limit.
An important application is mixtures containing CO2, H2S and light hydrocarbons. It can only be
used with a limited selection of components (p.464).

Note: It can only be used via an MFL file.

CPA
The CPA (cubic-plus-association) model extends the capabilities of industry-standard cubic
equations of state to polar and hydrogen-bonding components. It is applicable to a wide variety of
systems of importance to the upstream oil industry such as hydrocarbons, gases, water and
hydrate inhibitors (alcohols and glycols).

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The Multiflash CPA model is based on the Infochem RKSA (advanced Redlich-Kwong-Soave)
equation of state. It has the advantage for non-polar substances, because it reduces the RKSA eos
so that all the characterization methods and parameters for standard oil and gas mixtures can be
used. Extra terms in the equation describe polar and associating compounds. The main application
in Multiflash is representing the fluid phases when modeling hydrates and hydrate inhibition. CPA
shows improvements over standard cubic eos for other systems such as acid gases and water.

Note: Salt components are not supported.

The CPA model is the subject of an active research program that is extending its applicability to
many other systems of industrial importance.

Reference Fluid Thermodynamic and Transport Properties REFPROP

REFPROP is an acronym for REFerence fluid PROPerties. The flash package provides
thermodynamic and transport properties of industrially important fluids and their mixtures with an
emphasis on refrigerants and hydrocarbons, especially natural gas systems. It is developed by the
National Institute of Standards and Technology (NIST).
REFPROP is based on highly accurate single component and mixture models based on the
Helmholtz energy.

NIST recommendation for pure fluids / mixture

For single components, REFPROP has a recommended set of equations of state explicit in
Helmholtz energy. That is, for each single component, a specific equation of state explicit in
Helmholtz energy is chosen. e.g. for carbon dioxide this is Span and Wagner (1996) (p.509) .
Mixture calculations employ a model that applies mixing rules to the Helmholtz energy of the
mixture components; it uses a departure function to account for the departure from ideal mixing.

GERG

Introduction
GERG is an acronym for Groupe Europen de Recherches Gazires, which is supported by the
European natural-gas companies. The European natural-gas companies include E.ON Ruhrgas
(Germany), Enags (Spain), Gasunie (The Netherlands), Gaz de France (France), Snam Rete Gas
(Italy) and Statoil (Norway).
The flash package, developed at Ruhr-Universitat Bochum, provides thermodynamic and transport
properties of industrially important gases and other mixtures with an emphasis on hydrocarbons
and further components. Lehrstuhl fuer Thermodynamik (Department of Thermodynamics) of Ruhr-
Universitat Bochum, Germany have developed a wide-range equation of state (EOS) for natural
gases and other mixtures that meets the requirements of standard and advanced natural gas
applications.
The first published equation of state by Ruhr-Universitat Bochum covers mixtures consisting of up
to 18 components as listed below:

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Annotations:
Yellow natural gas main components
Red further hydrocarbons
Blue further components

In 2004, the new equation of state was evaluated by the GERG group and then adopted under the
name GERG-2004 equation of state (or GERG-2004 for short) as an international reference
equation of state for natural gases and similar mixtures (GERG standard).

GERG-2008
In 2008, Ruhr-Universitat Bochum further extended GERG-2004 by including three additional
components n-nonane, n-decane and hydrogen sulfide, making its component list up to 21
components. This expanded equation of state was called GERG-2004 XT08, where "XT08" meant
"eXTension 2008". In 2010, upon the request of the ISO Working Group (ISO TC193 SC1 WG13),
Ruhr-Universitat Bochum simplified the name of GERG-2004 XT08 to GERG-2008, the current
version of GERG.
The GERG-2008 equation of state is under consideration to be adopted as an ISO Standard (ISO
20765-2 and ISO 20765-3) for natural gases. The ISO group ISO TC 193/SC 1/WG 13 is working
on this matter.

Description

Structure
The GERG equation of state is based on a multi-fluid approximation, which is explicit in the
reduced Helmholtz energy = a/(RT) [ = Alpha in the figures] dependent on the density , the
temperature T and the composition x (mole fractions) of the mixture. The structure of the equations
of state is shown in the following figure:

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Figure 7.10. The basic structure of the equations of state GERG-2004 (N = 18) and GERG-2008
(N = 21) for natural gases and other mixtures.

Three elements are necessary to set up a multi-fluid approximation:

Pure substance equations of state for all components
Reducing functions for density and temperature
Departure function
The reducing functions as well as the departure function were developed to describe the behaviour
of the mixture and contain substance and mixture specific parameters. From the reducing
functions, the reducing values r and Tr for the density and the temperature of the mixture are
calculated. They only depend on the mixture composition and turn into the critical properties c
and Tc, respectively, for the pure components. The departure function depends on the reduced
density , the inversely reduced temperature ( = Tau in the figures) , and the composition x of
the mixture. It contains the sum of binary specific and generalized departure functions, which can
be developed for single binary mixtures (binary specific) or for a group of binary mixtures
(generalized). The following equation illustrates this summation:

Figure 7.11. The departure function for the mixture in a multi-fluid approximation as a double
summation over all binary specific and generalized departure functions developed for the binary
subsystems; GERG-2004: N = 18; GERG-2008: N = 21.

The mathematical structure of the part of the binary specific and generalized departure functions
that depends on and is similar to the structure of pure substance equations of state and is
determined by our method for optimizing the structure of equations of state. Furthermore, the

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departure functions contain a factor that only depends on the composition of the mixture. For
further details, see the references given at the end of this description.
In order to obtain a reference equation of state that yields accurate results for various types of
natural gases and other multi-component mixtures over wide ranges of composition, the reducing
and departure functions were developed using only data for binary mixtures. The 18 pure
components covered by GERG-2004 form 153 different binary mixtures, and the 21 pure
components covered by GERG-2008 result in 210 possible binary mixture combinations. Departure
functions rij(,, x) were developed only for such binary mixtures for which accurate
experimental data existed. For binary mixtures with limited or poor data, no departure functions
were developed, and only the parameters of the reducing functions r(x) und Tr(x) were fitted; in
case of very poor data, simplified reducing functions without any fitting were used.
The multi-fluid approximation used enables a simple inclusion of additional components in future
developments. This means that, for example, fitted parameters of the existing equation of state do
not have to be refitted when incorporating new components. This also holds for the departure
function with its optimized structure, which remains unchanged when expanding the model.

Range of Validity and Accuracy

The entire range of validity of GERG-2008 covers the following temperatures and pressures:
Normal range: 90 K T 450 K, p 35 MPa
Extended range: 60 K T 700 K, p 70 MPa
Moreover, the equation can be reasonably extrapolated beyond the extended range, and each
component can basically cover the entire composition range, i.e. (0-100)%.
GERG-2008 represents most of the experimental data, including the most accurate measurements
available, to within their uncertainties. The uncertainty values given in the following correspond to
the uncertainties of the most accurate experimental data.
In the gas region, the uncertainties in density and speed of sound are 0.1%, in enthalpy differences
(0.2-0.5)% and in heat capacities (1-2)%. In the liquid region, the uncertainty in density is
(0.1-0.5)%, in enthalpy differences (0.5-1)% and in heat capacities (1-2)%. In the two-phase
region, vapour pressures are calculated with a total uncertainty of (1-3)%, which corresponds to
the uncertainties of the experimental VLE data. For mixtures with limited or poor data, the
uncertainty values stated above can be somewhat higher.
These accuracy statements are based on the fact that GERG-2008 represents the corresponding
experimental data to within their experimental uncertainties (with very few exceptions).

References
The comprehensive descriptions of GERG (with the entire numerical information, experimental
data used, quality, range of validity, etc.) are retrievable from the following reference:
Kunz, O., Klimeck, R., Wagner, W., Jaeschke, M. The GERG-2004 wide-range equation of state
for natural gases and other mixtures. GERG TM15 2007. Fortschr.-Ber. VDI, Reihe 6, Nr. 557, VDI
Verlag, Dsseldorf, 2007; also available as GERG Technical Monograph 15 (2007).
Kunz, O., Wagner, W. The GERG-2008 wide-range equation of state for natural gases and other
mixtures: An expansion of GERG-2004. To be submitted to J. Chem. Eng. Data (2011).

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Note: This GERG Monograph is available for downloaded from the website of GERG - http://
www.gerg.eu/publications/tm.htm

Components for Cubic Equations of State

For the cubic equations of state (p.450), non-aqueous components can either be selected from a
library (p.459), or user-defined components (petroleum fractions (p.463)) can be selected by
defining their properties.
For two phase flashes, water can be selected, but it is treated differently from the other
components. It is removed from the flash calculations, and the water phase properties are
calculated separately. For three phase flashes (Multiflash), aqueous components (p.463) can be
selected from the component library. User-defined aqueous components are not allowed.

Non-aqueous library components

Different library components are available for each package. When converting from one package
to another, if a library component is not available in the new package, it will be converted into a
petroleum fraction (p.463). Default molecular weight and boiling point temperature are used to
define the petroleum fraction data for pure components are taken from Poling et al (p.508).
The non-aqueous library components can be divided into three types
1. Pure hydrocarbon components (p.459)
2. Non-hydrocarbon components (p.461)
3. Pseudo-components (p.462)

Pure hydrocarbon components

The following pure library components can be selected:

Formula Multiflash E300 flash DBR 2phase flash MW (g/gmol) Tbp (K)
CH4 Methane C1 C1 16.043 111.66
C2H4 Ethylene Ethylene 28.054 169.42
C2H6 Ethane C2 C2 30.070 184.55
C3H4 Propadiene 40.065 238.77
C3H6 Propylene 42.081 225.46
C3H6 Cyclo-C3 42.081 240.34
C3H8 Propane C3 C3 44.097 231.02
C4H6 1,3-Butadiene 54.092 268.62
C4H6 1,2-Butadiene 54.092 269.00
C4H8 iso-Butene 56.108 266.24
C4H8 1-Butene 56.108 266.92
C4H8 tr2-Butene 56.108 274.03

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C4H8 cis2-Butene 56.108 276.87

C4H10 Isobutane IC4 i-C4 58.123 261.34
C4H10 N-Butane NC4 n-C4 58.123 272.66
C5H10 1-Pentene 70.134 322.38
C5H10 Cyclopentane Cyclo-C5 70.134 303.11
C5H12 2,2-Dimethylpropane 72.150 282.65
C5H12 Isopentane i-C5 72.150 300.99
C5H12 N-Pentane n-C5 72.150 309.22
C6H6 Benzene BEN Benzene 78.114 353.24
C6H12 1-Hexene 84.161 336.63
C6H12 Methylcyclopentane Mcyclo-C5 84.161 344.98
C6H12 Cyclohexane Cyclo-C6 84.161 353.93
C6H14 N-Hexane n-C6 86.177 341.88
C7H8 Toluene TOL Toluene 92.141 383.79
C7H14 1Heptene 98.188 366.79
C7H14 Methylcyclohexane Mcyclo-C6 98.188 374.09
C7H16 3-Methyl Hexane 100.204 365.00
C7H16 N-Heptane n-C7 100.204 371.57
C7H16 3-Methyl Hexane 100.204 365.00
C8H10 Ethylbenzene C2-Benzene 106.167 409.36
C8H10 P-Xylene p-Xylene 106.167 411.53
C8H10 M-Xylene m-Xylene 106.167 412.34
C8H10 O-Xylene o-Xylene 106.167 417.59
C8H16 1Octene 112.215 394.44
C8H16 Ethylcyclohexane 112.215 404.00
C8H18 N-Octane n-C8 114.231 398.82
C9H12 124MBenzene 120.194 442.49
C9H12 Cumene 120.194 425.52
C9H20 N-Nonane n-C9 128.258 423.97
C10H14 1,2-Diethylbenzene 134.22 456
C10H22 N-Decane n-C10 142.285 447.30
C11H24 N-Undecane 156.312 469.08
C12H26 N-Dodecane 170.338 489.48
C13H28 N-Tridecane 184.365 508.63
C14H10 Phenanthrene 178.233 611.55

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C14H30 N-Tetradecane 198.392 526.76

C15H32 N-Pentadecane 212.419 543.83
C16H34 N-Hexadecane 226.446 559.98
C17H36 N-Heptadecane 240.473 574.56
C18H38 N-Octadecane 254.500 588.30
C19H40 N-Nonadecane 268.527 602.34
C20H42 N-Eicosane 282.554 616.84
C21H44 N-Heneicosane
C22H46 N-Docosane
C23H48 N-Tricosane
C24H50 N-Tetracosane
C25H52 N-Pentacosane
C26H54 N-Hexacosane
C28H58 N-Octacosane
C29H60 N-Nonacosane
C30H62 N-Triacontane
C32H66 N-Dotriacontan
C36H74 N-Hexatriacontane

Non-hydrocarbons
The following pure library components can be selected:

Formula Multiflash E300 flash DBR 2phase flash MW (g/gmol) Tbp (K)
H2 Hydrogen H2 H2 2.016 20.38
He Helium Helium 4.003 4.30
N2 Nitrogen N2 N2 28.014 77.35
O2 Oxygen O2 31.999 90.17
Ar Argon Argon 39.948 87.27
Kr Krypton 83.800 119.74
Xe Xenon 131.290 165.01
NH3 Ammonia NH3 17.031 239.81
H2S Hydrogen Sulphide H2S H2S 34.082 212.84
CO Carbon Monoxide CO CO 28.010 81.66
CO2 Carbon Dioxide CO2 CO2 44.010
SF6 SF6 146.06 209.00

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Pseudo-hydrocarbon components
Some packages contain pseudo components, essentially pre-defined petroleum fractions (p.463),
that can be used to represent the heavy end of the oil.

Formula Multiflash E300 flash DBR 2phase flash MW (g/gmol) Tbp (K)
C4 58.124 268.9
C5 72.151 305.9
C6 C6 84.00 341.9
C7 C7 96.00 371.6
C8H10 m&p-Xylene 106.167 411.9
C8 C8 107.00 398.8
C9 C9 121.00 424.0
C10 C10 134.00 447.0
C11 C11 147.00 469.0
C12 C12 161.00 489.0
C13 C13 175.00 508.0
C14 C14 190.00 527.0
C15 C15 206.00 544.0
C16 C16 222.0 560.0
C17 C17 237.00 575.0
C18 C18 251.00 589.0
C19 C19 263.00 603.0
C20 C20
C21 C21
C22 C22
C23 C23
C24 C24
C25 C25
C26 C26
C27 C27
C28 C28
C29 C29
C30 C30
C31 C31
C32 C32
C33 C33

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C34 C34
C35
C36
C37
C38
C39
C40
C41
C42
C43
C44
C45
Bitumen 544.00 773.2

Aqueous library components

Aqueous components are defined as those that will distribute mainly in the second liquid phase.
These are water and the hydrate suppressants methanol, ethylene glycol, diethylene glycol and
triethylene glycol. The calculation in of the amount of aqueous components to add corresponds to
an agreed definition. The water phase is added as a proportion of the DRY gas at stock tank
conditions (15 degrees C, 1bar). The discrepancy between hand calculations and software is
because the software makes a correction for the amount of aqueous components that will partition
to the gas phase. That is, it aims to add the amount of aqueous components requested as a
separate aqueous phase. There will also be some loss to the hydrocarbon liquid phase but this will
not be significant unless the aqueous phase contains a lot of methanol. The amount lost to the
vapor phase will be significant if there is a large amount of gas present relative to other phases.

Formula Multiflash
H2O Water
CH3OH Methanol
C2H5OH Ethanol
C2H6O2 Ethylene Glycol (MEG)
C4H10O3 Diethylene Glycol (DEG)
C6H14O4 Triethylene Glycol (TEG)
NaCl Salt Component

Petroleum fractions

User-defined components can be created by defining key properties: molecular weight MW i ,

critical pressure Pci , critical temperature T ci , boiling point temperature T Bi , specific gravity i and

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acentric factor i . It is not always necessary to supply values for all these properties the flash
packages can use correlations to determine unspecified properties from those that are specified.
Minimum data required is shown in the table below:

Multiflash E300 flash / DBR flash

MW i , i yes

MW i , T Bi yes

T Bi , i yes

MW i yes

Pci , T ci , i . yes

Note: The Multiflash routines that calculate the petroleum fraction properties assume the molecular
weight of petroleum fractions exceed 72.

Components for Non-Cubic Equations of State

Only library components can be used for the CSMA, NIST recommendation for pure fluid/mixture
and GERG-2008 non-cubic equations of states (p.454).

Formula Multiflash (CSMA) REFPROP (NIST recommendation GERG-2008 (GERG-2008)

for pure fluid/mixture)
CH4 Methane methane Methane
C2H6 Ethane ethane Ethane
C3H8 Propane propane Propane
i-C4H10 Isobutane isobutane Isobutane
n-C4H10 Butane butane n-Butane
i-C5H12 Isopentane isopentane Isopentane
n-C5H12 Pentane pentane n-Pentane
n-C6H14 Hexane hexane n-Hexane
n-C7H16 Heptane heptane n-Heptane
n-C8H18 Octane octane n-Octane
n-C9H20 nonane n-Nonane
n-C10H22 decane n-Decane
C2H2 Ethylene
C6H12 Cyclohexane
C7H8 Toluene

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H2 Hydrogen hydrogen (normal) Hydrogen

He Helium helium Helium
N2 Nitrogen nitrogen Nitrogen
O2 Oxygen oxygen Oxygen
Ar Argon argon Argon
H2S Hydrogen Sulphide hydrogen sulfide Hydrogen sulphide
CO Carbon Monoxide carbon monoxide Carbon monoxide
CO2 Carbon Dioxide carbon dioxide Carbon dioxide
NH3 Ammonia

Multiflash is a 3phase flash and allows aqueous components. REFPROP and GERG-2008 allow
water, but are two phase flashes. The water component is therefore removed before the flash
calculation, and water properties are calculated outside the flash.

Formula Multiflash (CSMA) NIST-REFPROP GERG-2008

H2O Water water Water
C2H5OH Ethanol

Viscosity Models for Compositional Fluids

Select Setup Compositional, then on the Property Models tab, select one of the following
models for determining viscosity:
Pedersen (the default)
LBC (Lohrenz-Bray-Clark)
Aasberg-Petersen (only available for E300 and DBR)
NIST recommendation for pure fluids / mixture (only available for REFPROP and GERG-2008)
Preliminary testing has shown the Pedersen method to be the most widely applicable and accurate
for oil and gas viscosity predictions. Multiflash uses the Pedersen method as the default viscosity
model, though an option is available to choose the LBC model for backward compatibility. The
Pedersen method has been adopted as the default in response to the deficiencies of the LBC
method. The Pedersen method is based on the corresponding state theory, as is the LBC method.
The results for different components are as follows:
Lower Alkanes
Predicted liquid viscosities using LBC and Pedersen methods have been compared to
experimental data for Methane and Octane as a function of both temperature and pressure
and for Pentane as a function of temperature. For both Methane and Pentane the
Pedersen method predictions show close agreement with experimental data. For Octane,
the Pedersen and LBC methods give comparable results. For the aromatic compound,
Ethyl Benzene, the Pedersen method is not as good as LBC.

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Higher Alkanes
The results for higher alkanes Eicosane and Triacontane are mixed: the Pedersen method
is adequate for Eicosane whereas LBC is slightly better than Pedersen for Triacontane.
For Triacontane both the LBC and Pedersen methods are inadequate. However, in the
majority of cases the higher hydrocarbons should be treated as petroleum fractions rather
than as single named components.
Petroleum Fractions
The LBC method describes viscosity as a function of the fluid critical parameters, acentric
factor and density. The LBC model is therefore very sensitive to both density and the
characterization of the petroleum fractions.
Water
The Pedersen method suffers the same drawback as LBC in that it is unable to predict the
temperature dependence of water, a polar molecule. To overcome this problem, the
Pedersen method has been modified especially for water so that it now accurately models
the viscosity of water in the liquid phase. This was achieved by the introduction of a
temperature-dependent correction factor. However the prediction of the viscosity of the
gas phase is also affected, though in only a minor way.
Methanol
Neither the LBC nor Pedersen method can deal with polar components, with the Pedersen
method slightly worse than LBC. This is not surprising, as both methods were developed
for non-polar components and mixtures. The Pedersen method works best with light
alkanes and petroleum mixtures in the liquid phase. It performs as well or better than the
LBC method in nearly all situations.
The choice of the equation of state has a large effect on the viscosities predicted by both methods.
The LBC method is more sensitive to the equation of state effects than is the Pedersen method.
See also: Package, Binary Interaction Parameters, Emulsions (p.470), Equation of State (p.450)

Solid Precipitation
Asphaltene Prediction
ONLY AVAILABLE WITH MFL FILES
Asphaltene formation line is displayed automatically on the phase envelope to enable the
determination of the conditions (temperature and pressure) at which asphaltene appears

Hydrates
Only available with Multifllash.
Requires additional licensing option.
Hydrate lines are displayed automatically on the phase envelope if water is in the component list
and hydrates will form. The amount of water may influence the results of the calculations,
particularly when inhibitors or water-soluble gases are present.

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Background
Natural gas hydrates are solid ice-like compounds of water and light components of natural gas.
The phase behavior of the systems involving hydrates can be very complex because up to six
phases must normally be considered. The behavior is particularly complex if there is significant
mutual solubility between phases.
The Multiflash hydrate model uses a modification of the SRK equation of state for the fluid phases
plus the van der Waals and Platteeuw model for the hydrate phases. The model can explicitly
represent all the effects of the presence of inhibitors.

Hydrate Inhibitors
Hydrate inhibitors decrease the hydrate formation temperature or increase the hydrate formation
pressure in a given gas mixture. The model includes parameters for the commonly used inhibitors
such as Methanol, and the glycols MEG, DEG and TEG.
A new mixing rule has been developed for the SRK equation of state to model the inhibitors' effects
on the fluid phases. The treatment of hydrate inhibition has the following features. The model can
represent explicitly all the effects of inhibitors, including the depression of hydrate formation
temperature, the depression of the freezing point of water, the reduction in the vapor pressure of
water (i.e. the dehydrating effect) and the partitioning of water and inhibitor into the oil, gas and
aqueous phases. The model has been developed using all available data for mixtures of water with
Methanol, MEG, DEG and TEG. This involves simultaneously representing hydrate dissociation
temperatures, depression of freezing point data and vapor-liquid equilibrium data. The solubilities
of hydrocarbons and light gases in water/inhibitor mixtures have also been represented. There is
no fundamental difference between calculations with and without inhibitors. To investigate the
effect of an inhibitor it must be added to the list of components in the mixture and the amount must
be specified just as for any other component. It is not possible to specify the amount of inhibitor in
a particular phase, only the total amount in the mixture. This is because the inhibitor will be split
among the different phases present at equilibrium with the amount in a particular phase depending
on the ambient conditions and the amounts of other components present in that phase This is
exactly what happens in reality. The amount of inhibitor typically needed would be approximately
35% by mass of inhibitor relative to water.

Model features
The main features of the model are:
The description of the hydrate phase behavior uses a thermodynamically consistent set of
models for all phases.
The vapor pressures of pure water are reproduced. The following natural gas hydrate formers
are included: METHANE, ETHANE, PROPANE, ISOBUTANE, BUTANE, NITROGEN, CO2
AND H2S.
The thermal properties (enthalpies and entropies) of the hydrates are included, permitting
flashes involving these phases.
The properties of the hydrates have been fixed by investigating data for natural gas
components in both simple and mixed hydrates to obtain reliable predictions of both structure I
and structure II hydrates.
The properties of the empty hydrate lattices have been investigated and the most reliable
recent values have been adopted.

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Proper allowance has been made for the solubilities of the gases in water so that the model
parameters are not distorted by this effect. This is particularly important for Carbon Dioxide and
Hydrogen Sulphide, which are relatively soluble in water.
Correct thermodynamic calculations of the most stable hydrate structure have been made. The
model has been tested on a wide selection of open literature and proprietary experimental data.
In most cases the hydrate dissociation temperature is predicted to within 1 degree Kelvin.
To ensure that reliable results are obtained, it is particularly important to use the correct set of
models and phase descriptors. The hydrates model set contains a complete set of model and
phase specifications.

Hydrate Model Details

The hydrate model set has the following definitions:
FLUID PHASE MODEL
The recommended fluid phase model is the advanced SRK equation of state with the a
parameter fitted to the pure component vapor pressure, the Peneloux density correction
and the INFOCHEM mixing rule. The required binary interaction parameters (BIP) for
hydrocarbons, light gases, water and inhibitors are available from the OILGAS2 BIP data
set.
HYDRATE MODELS
The hydrate model consists of lattice parameters for the empty hydrate and parameters
interaction of gas molecules with water in the hydrate. There are different parameter
values for each hydrate structure, HYDRATE I and II. In addition, the hydrate must be
associated with a liquid phase model that is used to obtain the properties of water. It is
important that this is the same model that is used for water as a fluid phase.
PHASES
In most cases, six phase descriptors are required: gas, hydrocarbon liquid, aqueous liquid,
hydrate I, hydrate II and ice. At high pressures and/or low temperatures the `gas' phase
may become liquid-like and a second non-aqueous liquid PD is needed. This is also the
case if there is a significant amount of CO2 or H2S present. In most practical cases, the
gas contains propane and has a hydrate II stable hydrate structure. Key components are
defined to distinguish between the hydrocarbon and aqueous liquid phases. In principle,
hydrate calculations and phase envelope plotting with Multiflash are no different from flash
calculations and envelope plotting for the fluid phases alone. Multiflash treats fluid and
solid phases the same. It can carry out a full range of flashes for streams with hydrates.

Ice Prediction
Only available with Multiflash Flash.
Ice is treated as a pure solid phase. The ice formation line is displayed automatically on the phase
envelope if water is in the component list and ice will form.

Wax Prediction
ONLY AVAILABLE WITH MFL FILES
Waxes are complex mixtures of solid hydrocarbons that freeze (solidify) out of crude oils if the
temperature is low enough - below the critical wax deposition temperature. They are mainly formed

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from normal paraffins or if isoparaffins and naphthenes are present. The wax formation line is
displayed automatically on the phase envelope to enable the determination of the conditions
(temperature and pressure) at which wax could deposit.
Wax deposition (p.670) can also be modelled.

7.5.4 Fluid Property Table Files

Fluid properties can be pre-calculated for a range of pressure and temperature values and stored
in a table. PIPESIM reads the table and can interpolate it to get properties for any pressure and
temperature. Tables in a format that can be read by PIPESIM can be generated by a range of
Compositional Fluid Packages, including PIPESIM itself. Table files representing different fluids
cannot be mixed. They are therefore useful in single branch models, but less so in network models,
unless the entire network contains only a single fluid.
The tables contain liquid and gas properties:

Property
Pressure psia kPa
Temperature F K
Liquid Volume Fraction % %
Water cut % %
Liquid Density lb / ft kg / m
3 3

Gas Density lb / ft kg / m
3 3

Gas Compressibility
Gas Molecular Weight lb / lbmol kg / kgmol
Liquid Viscosity cP cP
Gas Viscosity cP cP
Total Enthalpy BTU / lbmol kJ / kgmol
Total Entropy BTU / (lbmol F ) kJ / (kgmol K )
Liquid Heat Capacity BTU / (lbmol F ) kJ / (kgmol K )
Gas Heat Capacity BTU / (lbmol F ) kJ / (kgmol K )
Liquid Surface Tension dyne / cm dyne / cm
Gas Thermal Conductivity BTU / (hr ft F ) W / (m K )
Oil Thermal Conductivity BTU / (hr ft F ) W / (m K )
Water Thermal Conductivity BTU / (hr ft F ) W / (m K )

The number of phases and the phase volume fractions, can be determined from the liquid fraction
and water cut. However, since only liquid and gas properties are available, these tables are only
suitable for use with two-phase flow models.

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The table files also contain the total molecular weight of the fluid, which is independent of the
pressure and temperature. This allows PIPESIM to calculate the liquid molecular weight from the
other table properties. The total molecular weight, liquid molecular weight and gas molecular
weight are then used to convert the molar quantities (enthalpy, entropy and heat capacities) to
mass based quantities.
Table files may also contain compositional data. In this case the table data may be ignored and
PIPESIM may use normal compositional flashing.

Internal fluid property tables

PIPESIM can also use property tables to store fluid data in compositional runs. Properties are
interpolated from the table properties and as the simulation progresses, tables values are filled in
when necessary. This can speed up compositional simulations, although it requires more memory
to store the data. These tables can be used in network simulations with multiple fluids a new
mixture can be created by mixing the fluid components and a new internal table created for the
new fluid.

7.5.5 Liquid mixture properties

Two phase flow correlations model flow of a liquid and a gas phase. When there are two liquid
phases, such as oil and water, the two liquid phases need to be combined and modelled as a
single liquid phase. The oil and water will flow at the same velocity. The liquid density can be
simply averaged. However more complicated models are used for liquid viscosity (p.470) and
liquid-gas surface tension (p.477).

Liquid Viscosity and Oil/Water Emulsions

An emulsion is a mixture of two immiscible liquid phases. One phase (the dispersed phase) is
carried as droplets in the other (the continuous phase). In Oil/Water systems at low watercuts, oil is
usually the continuous phase. As watercut is increased there comes a point where phase
inversion occurs, and water becomes the continuous phase. This is the Critical Watercut of
Phase Inversion, otherwise called the cutoff. It occurs typically between 55% and 70% watercut.
The viscosity of the mixture is usually highest at and just below the cutoff. Emulsion viscosities can
be many times higher than the viscosity of either phase alone.

Related links:
Viscosity Properties (p.150)
Viscosity Properties (p.150)

Correlations and methods

The methods available for calculating the oil/water mixture viscosity are:
Inversion
Volume Ratio
User-supplied Table
In addition a number of emulsion correlations are available:

Technical Description
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Woelflin
Brinkman
Vand
Richardson
Leviton and Leighton
The cutoff can be entered as a watercut, or calculated using the Brauner and Ullman correlation.
The cutoff is used by all the emulsion correlations and methods, except for the Volume ratio
method.

Figure 7.12. Viscosity of oil/water mixtures

Related links:
Viscosity Properties (p.150)
Viscosity Properties (p.150)

Inversion
The inversion method sets the liquid viscosity to the viscosity of the continuous phase. This means
that, at a watercut below or equal to the cutoff, water droplets are carried by a continuous oil
phase, and the mixture assumes the viscosity of the oil. At a watercut above the cut-off value, oil
droplets are carried by a continuous water phase, and the mixture assumes the viscosity of the
water.

Technical Description
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Related links:
Viscosity Properties (p.150)
Viscosity Properties (p.150)

Volume ratio
The Volume ratio method calculates mixture viscosity as follows:

m = o o + w w Eq. 7.384

where

o is oil viscosity

o is the volume fraction of oil

w is the water viscosity

w is the volume fraction of water

Related links:
Viscosity Properties (p.150)
Viscosity Properties (p.150)

User-Supplied Table
This method uses a user-supplied table of viscosities or viscosity multipliers against flowing (in
situ) watercut. The table is entered in the dialog revealed by pressing the Setup emulsion table
button. The first watercut value in the table must be zero. The viscosity value at zero watercut is
used to divide into all the others to yield multipliers. Therefore, the viscosity table can be populated
with absolute viscosity values, or with multipliers.
The table is applied to watercuts from zero up to the supplied watercut cutoff value; above this, the
liquid viscosity is set to the water viscosity using a transition region.

Related links:
Viscosity Properties (p.150)
Viscosity Properties (p.150)

Woelflin
The Woelflin correlations assume that the continuous phase changes from oil to water at a given
watercut cutoff point. This means that, at a watercut below or equal to the cutoff value, a water-in-
oil emulsion forms, and the emulsion viscosity is given by the Woelflin correlation. At a watercut
above the cutoff value, oil droplets are carried by a continuous water phase, and the mixture
assumes the viscosity of the water, using a transition region.

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In his 1942 paper, Woelflin described 3 types of water-in-oil emulsions, which he labeled loose,
medium and tight. The paper provides tables of viscosity multiplication factors as a function of
watercut for the 3 types, and a chart showing curves to fit the data. The PIPESIM implementation
is a digitization of the curves.
The viscosity of all 3 emulsion types increases with watercut up to the specified cutoff value, above
which it falls and assumes the value of the water viscosity. It should be noted that all 3 emulsion
types can yield emulsion viscosities many times greater than the oil viscosity. In the case of
the tight emulsion, multiplier values in the region of 100 are readily obtained. In his experiments on
tight emulsions, Woelflin reported that the viscosity of a 60% watercut emulsion could not be
determined, because the mixture was too viscous to flow through the viscometer.
Versions of PIPESIM prior to the 2007.1 release implemented only the loose emulsion correlation,
using a curve-fit as follows:

(
m = o 1 + 0.00123V W
2.2
) Eq. 7.385

where o is oil viscosity, and w is volume fraction of water. This option is retained for backwards
compatibility and is called Pipesim Original Woelflin. It gives very similar answers to the new
loose emulsion option up to a watercut of 60%, but diverges above this.

Related links:
Viscosity Properties (p.150)
Viscosity Properties (p.150)

Brinkman
The Brinkman correlation calculates elevated emulsion viscosities on either side of the cutoff, using
the formula
2.5
L = c (1 d ) Eq. 7.386

where c is the viscosity of the continuous phase and d is the volume fraction of the
discontinuous phase.

Related links:
Viscosity Properties (p.150)
Viscosity Properties (p.150)

Vand
The Vand correlations calculate elevated emulsion viscosities on either side of the cutoff, using the
formula

(k1 d )
Eq. 7.387
L = c e (1k2 d )

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where c is the viscosity of the continuous phase,

d is the volume fraction of the discontinuous phase,

and the coefficients k1 and k2 are selected as follows. The Vand coefficients are 2.5 and 0.609;
Barnea and Mizrahi are 2.66 and 1.0; the user-supplied coefficients are entered in the
accompanying data entry boxes.

Related links:
Viscosity Properties (p.150)
Viscosity Properties (p.150)

Richardson
The Richardson correlation calculates elevated emulsion viscosities on either side of the cutoff,
using the formula
e
L = c (k d ) Eq. 7.388

where c is the viscosity of the continuous phase,

d is the volume fraction of the discontinuous phase,

and k is a user-supplied constant. Separate values of k can be provided for oil-in-water and water-
in-oil conditions, the default values are 3.8 and 6.6.

Related links:
Viscosity Properties (p.150)
Viscosity Properties (p.150)

Leviton and Leighton

The Leviton and Leighton correlation calculates elevated emulsion viscosities either side of the
cutoff, using the formula
e
(
2.5 d + 0.4 c )
L = c
(
d )(
+ c d + d
1.66
+ d
3.66
) Eq. 7.389

where d and c are the viscosities of the discontinuous and continuous phases, and d is the
volume fraction of the discontinuous phase.

Related links:
Viscosity Properties (p.150)

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Viscosity Properties (p.150)

Brauner and Ullman

The Brauner and Ullman correlation can be used to calculate the watercut cutoff value. It uses the
formula

(( ))
0.6 0.4
t t
c=1 0.4
Eq. 7.390
0.6
1 + t t

where

c is the cutoff/100

o
t =
w

o is the oil viscosity (in cP)

w is the water viscosity (in cP)

o
t =
w

o is the oil density (in lb/ft3)

w is the water density (in lb/ft3)

See also: Inversion (p.471) and Volume Ratio (p.472).

Related links:
Viscosity Properties (p.150)
Viscosity Properties (p.150)

Limits and Safety factors

Emulsion correlations and methods have the potential to cause difficulty for the calculation engine.
Extremely large viscosities can be predicted, this can cause convergence failure. The
discontinuous behavior around the inversion point (cutoff) can also cause problems, particularly in
a network model. As a result, a number of limits and safety factors have been introduced, as
described below. All of these are properties of the model: only one value is held, and it is applied
to all fluids in the model.

Related links:
Viscosity Properties (p.150)

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Viscosity Properties (p.150)

Maximum cutoff
A typical value for the cutoff is between 55% to 70%, and the default is 60%. The Woelflin
correlations are particularly sensitive to high cutoff values, so there is a maximum limit of 70%,
which will be applied silently. The limit may be extended using the keyword MAXCUTOFF=
(p.525).

Related links:
Viscosity Properties (p.150)
Viscosity Properties (p.150)

Transition region above the cutoff

The Woelflin and user-supplied table methods exhibit pronounced discontinuity about the cutoff.
For these methods therefore, the discontinuity about the cutoff is smoothed with a transition region,
extending from the cutoff value in the direction of increasing watercut. By default this is 5% wide.
Predicted viscosities in this region are interpolated between the value predicted at the cutoff (the
maximum emulsion viscosity point, with oil the continuous phase) and the value at cutoff plus
transition region width (the viscosity predicted from a continuous water phase). The size of the
transition region can be controlled with the keyword SMOOTHCUTOFF (p.525) =.

Related links:
Viscosity Properties (p.150)
Viscosity Properties (p.150)

Maximum Emulsion Table Multiplier

The user-supplied and Woelflin correlations are subject to a maximum multiplier limit, default value
100. This can be controlled with the keyword MAXEMULSION (p.525) =.

Related links:
Viscosity Properties (p.150)
Viscosity Properties (p.150)

Maximum liquid viscosity

As viscosity increases, the resistance to fluid flow also increases. There comes a point where
viscosity is so high that the term 'fluid' ceases to be appropriate, and the prediction of pressure
drops due to fluid flow can be regarded as non physical. The maximum liquid viscosity is by default
1.0E+7 (ten million) cP, this can be controlled by the keyword MAXLIQVISC (p.525) =.

Related links:
Viscosity Properties (p.150)
Viscosity Properties (p.150)

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Liquid-gas Surface Tension

The surface tension between the liquid and gas phase is used in two phase flow correlations, for
example to calculate bubble velocity. If there are two liquid phases present, the surface tension will
depend on the oil-gas surface tension, the water-gas surface tension, and the water cut.
In black oil models, when there is sufficient oil, it is assumed that the liquid is segregated with the
water below the oil. The gas in therefore only in contact with the oil, and the surface tension is
given by:

L = O WCUT < 60

If water dominates the liquid then the surface tension is taken as an average of the oil-gas and
water-gas surface tensions:

L = O 1 ( WCUT
100 )
+ O
WCUT WCUT > 60
100

L is the surface tension between the oil and the gas (dynes/cm)

O is the surface tension between the oil and the gas (dynes/cm)

W is the surface tension between the water and the gas (dynes/cm)

WCUT is the water cut (%)

7.6 Typical and Default Data

7.6.1 Limits
The following limitations apply to the PIPESIM modules.

General
Maximum number of components in a stream: 50

Pipeline and facilities

Maximum number of sources: 1
Maximum number of sinks: 1
Maximum number of pipe coatings: 4
Maximum number of nodes for a pipeline or riser: 101

Well Performance
Maximum number of completions: 10

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Maximum number of sinks: 1

Maximum number tubing coatings (using Expert mode) : 10
Maximum number of nodes for a tubing: 100
Maximum number of geothermal survey points: 100
Maximum number of tubing strings: Detailed model = 20, Simple model = 4

Network
Maximum number of wells / branches: Unlimited.
Maximum number of nodes: Unlimited.
Maximum number of PVT files: 500
Maximum number of compositions: 1,000
Maximum number of Black Oil compositions: 1,024
Maximum number of PQ data points: 30

Note: Although the maximum number of wells, and so on, is unlimited practical limits may apply
depending upon the configuration of the PC used. The limiting factors [for large models] will be
memory and processor speed. Please see the License and Installation Guide for your version of
PIPESIM for recommendations on memory.

7.6.2 Tubing and Pipeline Tables

Tubing/Casing Tables

Nominal Weight OD ID in WT
Bore lb/ft in in
1 1/4in 3.02 1.660 1.278 0.191
1 1/4in 2.3 1.660 1.379 0.140 H-40,J-55,C-75,L-80,N-80,C-90 Tubing
1 1/4in 2.33 1.660 1.379 0.140
1 1/4in 2.4 1.660 1.379 0.140 H-40,J-55,C-75,L-80,N-80,C-90 Tubing
1 1/4in 2.1 1.660 1.410 0.125
2 3/8in 7.7 2.375 1.703 0.336
2 3/8in 6.2 2.375 1.853 0.261
2 3/8in 5.8 2.375 1.867 0.254 C-75,L-80,N-80,C-90,P-105 Tubing
2 3/8in 5.95 2.375 1.867 0.254 C-75,L-80,N-80,C-90,P-105 Tubing
2 3/8in 5.3 2.375 1.939 0.218
2 3/8in 4.6 2.375 1.995 0.190 H-40,J-55,C-75,L-80,N-80,C-90,P-105 Tubing
2 3/8in 4.7 2.375 1.995 0.190 H-40,J-55,C-75,L-80,N-80,C-90,P-105 Tubing

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2 3/8in 4 2.375 2.041 0.167 H-40,J-55,C-75,L-80,N-80,C-90 Tubing

2 7/8in 11 2.875 2.065 0.405
2 7/8in 10.7 2.875 2.091 0.392
2 7/8in 9.5 2.875 2.195 0.340
2 7/8in 8.6 2.875 2.259 0.308 C-75,L-80,N-80,C-90,P-105 Tubing
2 7/8in 8.7 2.875 2.259 0.308 C-75,L-80,N-80,C-90,P-106 Tubing
2 7/8in 7.8 2.875 2.323 0.276 C-75,L-80,N-80,C-90,P-105 Tubing
2 7/8in 7.9 2.875 2.323 0.276 C-75,L-80,N-80,C-90,P-106 Tubing
2 7/8in 6.4 2.875 2.441 0.217 H-40,J-55,C-75,L-80,N-80,C-90,P-105 Tubing
2 7/8in 6.5 2.875 2.441 0.217 H-40,J-55,C-75,L-80,N-80,C-90,P-105 Tubing
3 1/2in 16.7 3.500 2.480 0.510
3 1/2in 15.8 3.500 2.548 0.476
3 1/2in 12.7 3.500 2.750 0.375 C-75,L-80,N-80,C-90,P-105 Tubing
3 1/2in 12.95 3.500 2.750 0.375 C-75,L-80,N-80,C-90,P-106 Tubing
3 1/2in 12.8 3.500 2.764 0.368
3 1/2in 9.2 3.500 2.992 0.254 H-40,J-55,C-75,L-80,N-80,C-90,P-105 Tubing
3 1/2in 9.3 3.500 2.992 0.254 H-40,J-55,C-75,L-80,N-80,C-90,P-105 Tubing
3 1/2in 10.2 3.500 2.992 0.254 H-40,J-55,C-75,L-80,N-80,C-90 Tubing
3 1/2in 7.7 3.500 3.068 0.216 H-40,J-55,C-75,L-80,N-80,C-90 Tubing
4 in 13.4 4.000 3.340 0.330
4 in 11.6 4.000 3.428 0.286
4 in 11 4.000 3.476 0.262 H-40,J-55,C-75,L-80,N-80,C-90 Tubing
4 in 9.5 4.000 3.548 0.226 H-40,J-55,C-75,L-80,N-80,C-90 Tubing
4 1/2 in 19.2 4.500 3.640 0.430
4 1/2 in 19.1 4.500 3.626 0.437 Q-125*,V-150* Casing
4 1/2 in 16.6 4.500 3.750 0.375 Q-125*,V-150* Casing
4 1/2 in 15.1 4.500 3.826 0.337 HC-95*,P-110,Q-125,V-150* Casing
4 1/2 in 15.5 4.500 3.826 0.337
4 1/2 in 13.5 4.500 3.920 0.290 J-55,K-55,C-75,L-80,N-80,C-90,C-95,HC-95*,P110
4 1/2 in 12.6 4.500 3.958 0.271 H-40,J-55,C-75,L-80,N-80,C-90 Tubing
4 1/2 in 12.75 4.500 3.958 0.271 H-40,J-55,C-75,L-80,N-80,C-90 Tubing
4 1/2 in 11.6 4.500 4.000 0.250 J-55,K-55,C-75,L-80,N-80,C-90,C-95,HC-95*,P110 Casing
4 1/2 in 10.5 4.500 4.052 0.224 J-55,K-55 Casing
4 1/2 in 9.5 4.500 4.090 0.205 H-40,J-55,K-55 Casing
5 in 24.2 5.000 4.000 0.500 C-75,L-80,N-80,C-90,C-95,P110,Q125 Casing

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5 in 23.2 5.000 4.044 0.478 C-75,L-80,N-80,C-90,C-95,HC-95*,P110,Q125,V150* Casing

5 in 21.4 5.000 4.126 0.437 C-75,L-80,N-80,C-90,C-95,P110 Casing
5 in 20.8 5.000 4.156 0.422
5 in 20.3 5.000 4.184 0.408
5 in 18 5.000 4.276 0.362 C-75,L-80,N-80,C-90,C-95,HC-95*,P110,Q125,V150* Casing
5 in 15 5.000 4.408 0.296 J-55,K-55,C-75,L-80,N-80,C-90,C-95,HC-95*, Casing
P110,Q125,V150*
5 in 13 5.000 4.494 0.253 J-55,K-55 Casing
5 in 11.5 5.000 4.560 0.220 J-55,K-55 Casing
5 1/2in 35 5.500 4.200 0.650 C-90 Casing
5 1/2in 26.8 5.500 4.500 0.500 Q-125*,V-150* Casing
5 1/2in 26 5.500 4.548 0.476 C-90 Casing
5 1/2in 23 5.500 4.670 0.415 C-75,L-80,N-80,C-90,C-95,HC-95*,P110,Q125,V150* Casing
5 1/2in 20 5.500 4.778 0.361 C-75,L-80,N-80,C-90,C-95,HC-95*,P110,Q125*,V150* Casing
5 1/2in 17 5.500 4.892 0.304 J-55,K-55,C-75,L-80,N-80,C-90,C-95,HC-95*,P110,Q125* Casing
5 1/2in 15.5 5.500 4.950 0.275 J-55,K-55 Casing
5 1/2in 14 5.500 5.012 0.244 H-40,J-55,K-55 Casing
5 1/2in 13 5.500 5.044 0.228
6 in 26 6.000 5.132 0.434
6 in 23 6.000 5.240 0.380
6 in 20 6.000 5.352 0.324
6 in 18 6.000 5.424 0.288
6 in 15 6.000 5.675 0.163
6 5/8 in 32 6.625 5.524 0.550 C-75,L-80,N-80,C-90,C-95,P110,Q125*,V150* Casing
6 5/8 in 28 6.625 5.791 0.417 C-75,L-80,N-80,C-90,C-95,P110,Q125*,V150* Casing
6 5/8 in 24 6.625 5.921 0.352 J-55,K-55,C-75,L-80,N-80,C-90,C-95,P110,Q125*,V150* Casing
6 5/8 in 20 6.625 6.049 0.288 H-40,J-55,K-55 Casing
6 5/8 in 17 6.625 6.135 0.245
7 in 42.7 7.000 5.750 0.625 Q125*,V150* Casing
7 in 38 7.000 5.920 0.540 C-75,L-80,N-80,C-90,C-95,HC-95*,P110,Q125,V150* Casing
7 in 35 7.000 6.004 0.498 C-75,L-80,N-80,C-90,C-95,HC-95*,P110,Q125,V150* Casing
7 in 32 7.000 6.094 0.453 C-75,L-80,N-80,C-90,C-95,HC-95*,P110,Q125*,V150* Casing
7 in 29 7.000 6.184 0.408 C-75,L-80,N-80,C-90,C-95,HC-95*,P110,Q125*,V150* Casing
7 in 26 7.000 6.276 0.362 J-55,K-55,C-75,L-80,N-80,C-90,C-95,HC-95*,P110 Casing
7 in 23 7.000 6.366 0.317 J-55,K-55,C-75,L-80,N-80,C-90,C-95,HC-95* Casing

Technical Description
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7 in 20 7.000 6.456 0.272 H-40,J-55,K-55 Casing

7 in 17 7.000 6.538 0.231 H-40 Casing
7 5/8 in 47.1 7.625 6.375 0.625 C-75,L-80,N-80,C-90,C-95,P110,Q125 Casing
7 5/8 in 45.3 7.625 6.435 0.595 C-75,L-80,N-80,C-90,C-95,HC-95*,P110,Q125,V150* Casing
7 5/8 in 39 7.625 6.625 0.500 C-75,L-80,N-80,C-90,C-95,HC-95*,P110,Q125,V150* Casing
7 5/8 in 33.7 7.625 6.765 0.430 C-75,L-80,N-80,C-90,C-95,HC-95*,P110,Q125*,V150* Casing
7 5/8 in 29.7 7.625 6.875 0.375 C-75,L-80,N-80,C-90,C-95,HC-95*,P110,Q125*,V150* Casing
7 5/8 in 26.4 7.625 6.969 0.328 J-55,K-55,C-75,L-80,N-80,C-90,C-95,HC-95* Casing
7 5/8 in 24 7.625 7.025 0.300 H40 Casing
7 5/8 in 20 7.625 7.125 0.250
8 5/8 in 49 8.625 7.511 0.557 C-75,L-80,N-80,C-90,C-95,HC-95*,P110,Q125,V150* Casing
8 5/8 in 44 8.625 7.625 0.500 C-75,L-80,N-80,C-90,C-95,HC-95*,P110,Q125*,V150* Casing
8 5/8 in 40 8.625 7.725 0.450 C-75,L-80,N-80,C-90,C-95,HC-95*,P110,Q125* Casing
8 5/8 in 36 8.625 7.825 0.400 J-55,K-55,C-75,L-80,N-80,C-90,C-95,HC-95* Casing
8 5/8 in 32 8.625 7.921 0.352 H-40,J-55,K-55 Casing
8 5/8 in 28 8.625 8.017 0.304 H-40 Casing
8 5/8 in 24 8.625 8.097 0.264 J-55,K-55 Casing
9 5/8 in 71.8 9.625 8.125 0.750
9 5/8 in 70.3 9.625 8.157 0.734 V150* Casing
9 5/8 in 61.1 9.625 8.375 0.625 HC-95*,Q125*,V150* Casing
9 5/8 in 58.4 9.625 8.435 0.595 HC-95*,Q125*,V150* Casing
9 5/8 in 53.5 9.625 8.535 0.545 C-75,L-80,N-80,C-90,C-95,HC-95*,P110,Q125,V150* Casing
9 5/8 in 47 9.625 8.681 0.472 C-75,L-80,N-80,C-90,C-95,HC-95*,P110,Q125 Casing
9 5/8 in 43.5 9.625 8.755 0.435 C-75,L-80,N-80,C-90,C-95,HC-95*,P110 Casing
9 5/8 in 40 9.625 8.835 0.395 J-55,K-55,C-75,L-80,N-80,C-90,C-95,HC-95* Casing
9 5/8 in 36 9.625 8.921 0.352 H-40,J-55,K-55 Casing
9 5/8 in 32.3 9.625 9.001 0.312 H-40 Casing
9 5/8 in 29.3 9.625 9.063 0.281
10 3/4 in 79.2 10.75 9.282 0.734 Q125*,V150* Casing
0
10 3/4 in 73.2 10.75 9.406 0.672 Q125*,V150* Casing
0
10 3/4 in 71.1 10.75 9.450 0.650 HC-95*,Q125*,V150* Casing
0
10 3/4 in 65.7 10.75 9.560 0.595 HC-95*,P-110,Q125,V150* Casing
0

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10 3/4 in 60.7 10.75 9.660 0.545 HC-95*,P-110,Q125,V150 Casing

0
10 3/4 in 55.5 10.75 9.760 0.495 L-80,N-80,C-90,C-95,HC-95*,P-110,Q125* Casing
0
10 3/4 in 51 10.75 9.850 0.450 J-55,K-55,C-75,L-80,N-80,C-90,C-95,HC-95*,P-110 Casing
0
10 3/4 in 45.5 10.75 9.950 0.400 H-40,J-55,K-54 Casing
0
10 3/4 in 40.5 10.75 10.05 0.350 H-40,J-55,K-55 Casing
0 0
10 3/4 in 32.75 10.75 10.19 0.279 H-40 Casing
0 2
11 3/4 in 66.7 3.915 11.75 10.65 Q-125*,V-150* Casing
0 6
11 3/4 in 60 3.522 11.75 10.77 J-55,K-55,C-75,L-80,N-80,C-90,C-95,HC-95*,P-110,Q-12 Casing
0 2 5
11 3/4 in 54 11.75 10.88 0.435 J-55,K-55 Casing
0 0
11 3/4 in 47 11.75 11.00 0.375 J-55,K-55 Casing
0 0
11 3/4 in 42 11.75 11.08 0.333 H-40 Casing
0 4
11 3/4 in 38 11.75 11.15 0.300
0 0
13 3/8 in 100.3 13.37 11.90 0.734 V-150* Casing
5 7
13 3/8 in 98 13.37 11.93 0.719
5 7
13 3/8 in 92.5 13.37 12.03 0.672 Q-125* Casing
5 1
13 3/8 in 86 13.37 12.12 0.625 HC-95* Casing
5 5
13 3/8 in 85 13.37 12.15 0.608
5 9
13 3/8 in 77 13.37 12.27 0.550
5 5
13 3/8 in 71 13.37 12.28 0.547 Q-125* Casing
5 1
13 3/8 in 72 13.37 12.34 0.514 C-75,L-80,N-80,C-90,C-95,HC-95*,P-110,Q-125 Casing
5 7

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13 3/8 in 68 13.37 12.41 0.480 J-55,K-55,C-75,L-80,N-80,C-90,C-95,P-110 Casing

5 5
13 3/8 in 61 13.37 12.51 0.430 J-55,K-55 Casing
5 5
13 3/8 in 54.5 13.37 12.61 0.380 J-55,K-55 Casing
5 5
13 3/8 in 48 13.37 12.71 0.330 H-40 Casing
5 5
16 in 109 16.00 14.68 0.656
0 8
16 in 84 16.00 15.01 0.495 J-55,K-55 Casing
0 0
16 in 75 16.00 15.21 0.393 J-55,K-55 Casing
0 4
16 in 65 16.00 15.25 0.375 H-40 Casing
0 0
16 in 55 16.00 15.37 0.312
0 6
18 5/8 in 87.5 18.62 17.75 0.435 H-40,J-55,K-55 Casing
5 5
20 in 133 20.00 18.73 0.635 J-55,K-55 Casing
0 0
20 in 106.5 20.00 19.00 0.500 J-55,K-55 Casing
0 0
20 in 94 20.00 19.12 0.438 H-40,J-55,K-55 Casing
0 4

Pipeline tables

Nominal Bore Schedule OD in ID in Wall Thickness in

1/8in Sch 80 0.406 0.217 0.094
1/8in Sch 40 0.406 0.268 0.069
1/4in Sch 80 0.539 0.303 0.118
1/4in Sch 40 0.539 0.362 0.089
3/8in Sch 80 0.673 0.421 0.126
3/8in Sch 40 0.673 0.492 0.091
1/2in XXS 0.839 0.252 0.293
1/2in Sch 160 0.839 0.461 0.189
1/2in Sch 80 0.839 0.543 0.148

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1/2in Sch 40 0.839 0.622 0.108

3/4in XXS 1.051 0.437 0.307
3/4in Sch 160 1.051 0.614 0.219
3/4in Sch 80 1.051 0.744 0.154
3/4in Sch 40 1.051 0.827 0.112
1in XXS 1.315 0.599 0.358
1in Sch 160 1.315 0.815 0.250
1in Sch 80 1.315 0.957 0.179
1in Sch 40 1.315 1.049 0.133
1 1/4in XXS 1.661 0.898 0.382
1 1/4in Sch 160 1.661 1.161 0.250
1 1/4in Sch 80 1.661 1.280 0.191
1 1/4in Sch 40 1.661 1.382 0.140
1 1/2in XXS 1.902 1.102 0.400
1 1/2in Sch 160 1.902 1.339 0.281
1 1/2in Sch 80 1.902 1.500 0.201
1 1/2in Sch 40 1.902 1.610 0.146
2in XXS 2.375 1.503 0.436
2in Sch 160 2.375 1.687 0.344
2in Sch 80 2.375 1.939 0.218
2in Sch 40 2.375 2.067 0.154
2 1/2in XXS 2.874 1.772 0.551
2 1/2in Sch 160 2.874 2.469 0.374
2 1/2in Sch 80 2.874 2.323 0.276
2 1/2in Sch 40 2.874 2.126 0.203
3in XXS 3.500 2.300 0.600
3in Sch 160 3.500 2.624 0.438
3in Sch 80 3.500 2.900 0.300
3in Sch 40 3.500 3.068 0.216
4in XXS 4.500 2.728 0.886
4in Sch 160 4.500 3.438 0.531
4in Sch 120 4.500 3.622 0.439
4in Sch 80 4.500 3.826 0.337
4in Sch 40 4.500 4.026 0.237
5in XXS 5.563 4.063 0.750

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5in Sch 160 5.563 4.311 0.626

5in Sch 120 5.563 4.563 0.500
5in Sch 80 5.563 4.815 0.374
5in Sch 40 5.563 5.047 0.258
6in XXS 6.625 4.897 0.864
6in Sch 160 6.625 5.187 0.719
6in Sch 120 6.625 5.504 0.561
6in Sch 80 6.625 5.761 0.432
6in Sch 40 6.625 6.211 0.280
8in Sch 160 8.626 6.815 0.906
8in XXS 8.626 6.878 0.874
8in Sch 140 8.626 7.004 0.811
8in Sch 120 8.626 7.189 0.719
8in Sch 100 8.626 7.437 0.594
8in Sch 80 8.626 7.626 0.500
8in Sch 60 8.626 7.815 0.406
8in Sch 40 8.626 7.980 0.323
8in Sch 30 8.626 8.071 0.278
8in Sch 20 8.626 8.126 0.250
10in Sch 160 10.748 8.496 1.126
10in Sch 140 10.748 8.748 1.000
10in Sch 120 10.748 9.059 0.844
10in Sch 100 10.748 9.311 0.719
10in Sch 80 10.748 9.559 0.594
10in Sch 60 10.748 9.748 0.500
10in Sch 40 10.748 10.020 0.364
10in Sch 30 10.748 10.134 0.307
10in Sch 20 10.748 10.248 0.250
12in Sch 160 12.752 10.126 1.313
12in Sch 140 12.752 10.500 1.126
12in Sch 120 12.752 10.752 1.000
12in Sch 100 12.752 11.063 0.844
12in Sch 80 12.752 11.378 0.687
12in Sch 60 12.752 11.630 0.561
12in Sch 40 12.752 11.941 0.406

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12in Sch 30 12.752 12.091 0.331

12in Sch 20 12.752 12.252 0.250
14in Sch 160 14.000 11.189 1.406
14in Sch 140 14.000 11.500 1.250
14in Sch 120 14.000 11.811 1.094
14in Sch 100 14.000 12.126 0.937
14in Sch 80 14.000 12.500 0.750
14in Sch 60 14.000 12.811 0.594
14in Sch 40 14.000 13.122 0.439
14in Sch 30 14.000 13.252 0.374
14in Sch 20 14.000 13.378 0.311
14in Sch 10 14.000 13.500 0.250
16in Sch 160 16.000 12.811 1.594
16in Sch 140 16.000 13.126 1.437
16in Sch 120 16.000 13.563 1.219
16in Sch 100 16.000 13.937 1.031
16in Sch 80 16.000 14.311 0.844
16in Sch 60 16.000 14.689 0.656
16in Sch 40 16.000 15.000 0.500
16in Sch 30 16.000 15.252 0.374
16in Sch 20 16.000 15.378 0.311
16in Sch 10 16.000 15.500 0.250
18in Sch 160 18.000 14.437 1.781
18in Sch 140 18.000 14.874 1.563
18in Sch 120 18.000 15.252 1.374
18in Sch 100 18.000 15.689 1.156
18in Sch 80 18.000 16.126 0.937
18in Sch 60 18.000 16.500 0.750
18in Sch 40 18.000 16.878 0.561
18in Sch 30 18.000 17.122 0.439
18in Sch 20 18.000 17.378 0.311
18in Sch 10 18.000 17.500 0.250
20in Sch 160 20.000 16.063 1.969
20in Sch 140 20.000 16.500 1.750
20in Sch 120 20.000 17.000 1.500

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20in Sch 100 20.000 16.650 1.675

20in Sch 80 20.000 17.937 1.031
20in Sch 60 20.000 18.378 0.811
20in Sch 40 20.000 18.811 0.594
20in Sch 30 20.000 19.000 0.500
20in Sch 20 20.000 19.252 0.374
20in Sch 10 20.000 19.500 0.250
24in Sch 160 24.000 19.311 2.344
24in Sch 140 24.000 19.874 2.063
24in Sch 120 24.000 20.378 1.811
24in Sch 100 24.000 20.937 1.531
24in Sch 80 24.000 21.563 1.219
24in Sch 60 24.000 22.063 0.969
24in Sch 40 24.000 22.622 0.689
24in Sch 30 24.000 22.878 0.561
24in Sch 20 24.000 23.252 0.374
24in Sch 10 24.000 23.500 0.250
30in Sch 30 30.000 28.748 0.626
30in Sch 20 30.000 29.000 0.500
30in Sch 10 30.000 29.378 0.311

7.6.3 Typical Values

Fluid Properties
The table below gives typical values for properties, in Engineering units and data for various oil
locations worldwide.

Default Min Max North North South Middle Far Australia

Sea America America East East
Black Oil
Properties
Water cut 0 0 100
GOR required 340 -1,100 600-20,000
Gas s.g. 0.64 0.64 - 0.81 0.65 - 0.8
Water s.g. 1.02 1.01 - 1.03 1.01 - 1.05
API 30 38 13 - 56 7-45 32-44 34

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Solution Gas Lasater Glaso Lasater

Correlation
Viscosity
Data
Dead Oil Beggs Beggs and
viscosity and Robinson
Robinson
Viscosity @ 2.247 0.4 -11 5 - 10,000
200F
Viscosity @ 117.8 3.8 - 120 -
60F 82,000 10,000
Heat
capacities
Oil (p.642) 0.45
Gas (p.642) 0.55
Water 1.0
(p.642)

Default values can be changed - click the relevant link.

Roughness

Material ft. in
Drawn tubing (brass, lead, glass, and the like) 0.000005 0.00006
Commercial steel or wrought iron 0.00015 0.0018
Asphalted cast iron 0.0004 0.0048
Galvanized iron 0.0005 0.006
Cast iron 0.00085 0.010
Wood stave 0.0006-0.003 0.0072-0.036
Concrete 0.001-0.01 0.012-0.12
Riveted steel 0.003-0.03 0.036-0.36

Thermal Conductivities

Material Density Thermal Conductivity Thermal Conductivity

(kg/m3) Btu/hr/ft/F (W/m/K)
Anhydrite 0.75
Carbon Steel 7900 28.9 50
Concrete Weight Coat 2000 - 3000 0.81 - 1.15 1.4 - 2.0

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Corrosion Coat (Bitumen) - 0.19 0.33

Corrosion Coat (Epoxy) - 0.17 0.30
Corrosion Coat (Polyurathane) - 0.12 0.20
Dolomite 1.0
Ground (Earth) 0.37 - 1.5
Gypsum 0.75
Halite 2.8
Ice 900 1.27 2.2
Lignite 2.0
Limestone 0.54
Line pipe 27 46.7
Mild Steel tubing 26 45
Mud 1500 0.75 - 1.5 1.3 - 2.6
Neoprene Rubber - 0.17 0.3
Plastic coated pipe 20 34.6
Plastic coated tubing 20 34.6
Polyurathane Foam (dry) 30 - 100 0.011 - 0.023 0.02 - 0.04
Polyurathane Foam (wet) - 0.023 - 0.034 0.4 - 0.6
PVC Foam (dry) 100 - 340 0.023 - 0.025 0.040 - 0.044
Sandstone 1.06
Shale 0.7
Stainless Steel - 8.67 15
Stainless steel (13%) 18 31.14
Stainless steel (15%) 15 26
Syntactic Foam (dry) 500 0.052 0.09
Syntactic foam (wet) - 0.17 0.3
Volcanics 1.6
Wet Sand 1600 1.04 - 1.44 1.8 - 2.5

Thermal Conductivities in W/m/K (Liquids and Gases)

Fluid Default Temperature Temperature Temperature Temperature

5oC 20oC 100oC 200oC
Air 0.024 0.026 0.030 0.037
Crude Oil (p.631) (30 API) 0.138 0.14 0.14 0.12 0.10
Glycol (DEG) 0.26 0.25 0.20 0.14

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Natural Gas (p.631) (P=1 0.035 0.030 0.032 0.045 0.062

bara)
Natural Gas (p.631) 0.045 0.045 0.052 0.070
(P=100 bara)
Natural Gas (p.631) 0.071 0.067 0.064 0.074
(P=200 bara)
Natural Gas (p.631) 0.090 0.085 0.076 0.083
(P=300 bara)
Water (p.631) 0.605 0.56 0.59 0.68 0.68

Default values can be changed - click the relevant link.

Permeability
For a gas well, this is gas permeability. For an oil well, this is total liquid permeability.
Typical values are:
< 1 md : Very low
1 - 10 md: Low
10 - 50 md: Mediocre
50 - 200 md: Average
200 - 500 md: Good
> 500 md: Excellent

Drainage Radius
Common drainage radii are:
40 acres 745 ft (227 m)
80 acres 1053 ft (321 m)
160 acres 1490 ft (454 m)
640 acres 2980 ft (908 m)

Fittings
Model fittings
Fittings (elbows, values and tees) are modeled by the standard practice of utilizing equivalent
length. From the fittings table determine the extra length of pipe that needs to be added to the
model to exert the same pressure drop as the required fitting.

Valves - Equivalent lengths of 100% open valves in feet

Model as a pipe with the required ID and set the equivalent length as indicated in the table below.
For example to model a 3/4 inch angle value add a pipe section of ID 3/4 and a length of 12 feet.

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Pipe Size Gate Valve Globe Valve Angle Valve

(Inches) (feet) (feet) (feet)
1/2 .35 17 8
3/4 .50 22 12
1 .6 27 14
1 1/4 .8 38 18
1 1/2 1.0 44 22
2 1.2 53 28
2 1/2 1.4 68 33
3 1.7 80 42
4 2.3 120 53
5 2.8 140 70
6 3.5 170 84
8 4.5 220 120
10 5.7 280 140
12 9 400 190
14 10 450 210
16 11 500 240
18 12 550 280
20 14 650 300
22 15 688 335
24 16 750 370

Elbows: Equivalent length of elbows in feet

Model as a pipe with the required ID and set the equivalent length as indicated in the table below.
For example to model a 3/4 standard elbow add a pipe section of ID 3/4 and a length of 2.2 feet.

Pipe Size: St'd elbow Med. sweep elbow Long sweep elbow
Inches feet feet feet
1/2 1.5 1.3 1
3/4 2.2 1.8 1.3
1 2.7 2.3 1.7
1 1/4 3.6 3 2.3
1 1/2 4.5 3.6 2.8
2 5.2 4.6 3.5
2 1/2 6.5 5.5 4.3

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3 8 7 5.2
4 11 9 7
5 14 12 9
6 16 14 11
8 21 18 14
10 26 22 17

Tees: Equivalent length of Tees in feet

Model as a pipe with the required ID and set the equivalent length as indicated in the table below.
For example to model a 3/4 inch Tee (straight through) add a pipe section of ID 3/4 and a length of
1.3 feet

Pipe Size: Tee (straight through) Tee (rt. angle flow)

Inches feet feet
1/2 1 3.2
3/4 1.3 4.5
1 1.7 5.7
1 1/4 2.3 7.5
1 1/2 2.8 9
2 3.5 12
2 1/2 4.3 14
3 5.2 16
4 7 22
5 9 27
6 11 33
8 14 43
10 17 53

7.7 Glossary
The PIPESIM help uses the following symbols:

7.7.1 Roman Letters

a is the major axis of ft m
the drainage ellipse

D
2 is the pipe cross- ft
2
m
2

A= sectional area
4

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hR is the Biot number dimensionless dimensionless

B=
k

Bo is the oil formation bbl / STBO

volume factor

c, C is the specific heat BTU / lb F J / kg K

o
capacity

d, D is the pipe diameter ft m

E is the specific total BTU / lb J / kg
energy

f is the friction factor dimensionless dimensionless

is the frequency Hz Hz
F, R is the gas/oil ratio dimensionless dimensionless

g is the acceleration
due to gravity
= 32.17 ft s / 2
= 9.81m s / 2

L g T is the Grashof dimensionless dimensionless

3 2

Gr = number
2

h is the local heat BTU / h ft F W /m K

2 o 2
transfer coefficient

H = U + PV is the specific BTU / lb J / kg

enthalpy

HL is the liquid holdup dimensionless dimensionless

Head is the head ft lb f / lb N m / kg

J is the productivity
index

k is the thermal BTU / h ft F W /m K

o
conductivity 2
2 m
is the absolute ft
permeability

L is the pipe length ft m

is the horizontal well
length

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m is the mass lb kg
M is the molecular lb / mol kg / kmol
weight
dimensionless dimensionless
is the number of
magnetic poles in an
ESP

n is the polytropic dimensionless dimensionless

coefficient mol mol
is the number of
moles

N is the compressor
speed

hL is the Nusselt number dimensionless dimensionless

Nu =
k
p, P is the pressure
/
psi or lbf in
2
N /m
2

Power is the power hp W

c p is the Prandtl number dimensionless dimensionless

Pr =
k
q is the mass flow rate lb / s kg / s
Q is the heat transfer BTU / h W
rate
is the average liquid
rate

r is the radial distance ft m

from the centre of
well

rw is the wellbore radius ft m

reh is the is the drainage ft m

radius of a horizontal
well

R is the pipe radius ft m

is the gas constant
/
= 1545.35lb f ft lb mol R = 8.314 J / K mol
o

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Ra = Pr Gr is the Rayleigh dimensionless dimensionless

number

Re is the Reynolds dimensionless dimensionless

number

S is the specific entropy BTU J

Q is the pipe burial o
lb F kg K
S= shape factor
2 k T dimensionless
dimensionless
is the skin

t is the well operating h s

time

T is the temperature o
F, R
o K

U is the specific internal BTU / lb J / kg

energy
BTU / h ft F W /m K
2 o 2
is the overall heat
transfer coefficient

v is the fluid velocity ft / s m/s

is the ESP speed rev / min rev / s
V is the volume ft
3 J / kg

wt is the pipe wall ft m

thickness

Ws is the shaft work BTU J

z is the vertical ft m
displacement above
a gravitational datum
level

Z is the compressibility
ft m
is the pipe burial
depth

7.7.2 Greek Letters

is the angle of the pipe to the horizontal

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bur = sin
-1
( ZR ) is the angle of the buried arc of a
partially buried pipe

k is the thermal diffusivity ft / s /s

2 2
= m
c p

=
1
( )
is the volumetric thermal expansion
coefficient
1 / oF , 1 / oR 1/K
T H

Cp is the ratio of specific heats dimensionless dimensionless

= is the specific gravity (relative density) dimensionless dimensionless
CV

dbean is the choke diameter ratio dimensionless dimensionless

=
dup

is the pipe roughness ft m

is the efficiency, expressed as a
fraction, 0 < 1

AvG is the void fraction dimensionless dimensionless

=
AvG + AvL

is the fluid dynamic viscosity cp = 10 Pa s Pa s = kg / m s

3

is the density lb / ft kg / m
3 3

ns = L L + G G is the no-slip density lb / ft kg / m

3 3

is the flowing fraction dimensionless dimensionless

is the interfacial (surface) tension dynes / cm N /m

7.7.3 Subscripts
b bubble point
bulk

c critical

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G gas phase
L liquid phase
m mixture
o oil
r reduced

R reservoir
s gas/oil ratio, solution
slip or slippage

v vaporization or vapor phase

volume or volumetric

w water

7.8 Conversion Factors

Common conversion factors used in PIPESIM are tabulated below.

7.8.1 Length
1 ft = 0.3048 m 1 m = 3.28084 ft

1 ft = 12 in

7.8.2 Volume
3 3 3 3
1 ft = 0.02832 m 1 m = 35.31467 ft

3 3
1 barrel = 5.61458 ft 1 ft = 0.17811 barrel

3 3
1 barrel = 0.15899 m 1 m = 6.28981 barrel

7.8.3 Mass
1 lb = 0.4536 kg 1 kg = 2.2046 kg

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7.8.4 Time
1 hour = 3600 s

1 day = 86400 s

7.8.5 Gravity
2 2
g = 32.18 ft s g = 9.81 m s

g = 1 / 144 psi ft lb
2 1

7.8.6 Pressure
The engineering units of pressure psi, needs to be treated with care. One psi is one pound-force
per square inch, or 144 pound force per square foot. A pound force is the force exerted by one
2
pound weight, which is one pound times the acceleration due to gravity g = 32.18 ft s .

lbf ft 1
1 psi = 144 2 = 144 g lb 2 2
ft s ft
5
1 bar = 10 Pa 1 bar = 14.504 psi

1 Atm = 1.01325 bar 1 Atm = 14.70 psi

7.8.7 Energy
1 BTU = 1.055056 kJ 1 kJ = 0.947817 BTU
3 3
1 kJ = 10 Pa m

7.8.8 Power
2
1 hp = 550 g ft lb s
3 1 hp = 0.7457 kW

7.8.9 Dynamic viscosity

3
1 cP = 10 Pa s

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7.8.10 Permeability
10 Pa 2
1 mD = 10 m
Atm

7.9 References

Adames, P.E. "Analysis and comparison of three comprehensive mechanistic

hydrodynamic models for vertical upward and deviated gas-liquid
flow through pipes". MSc thesis, University of Calgary, 2009.

Aggour "Hydrodynamics and Heat Transfer in Two-Phase Two-Component

Flow", PhD thesis, University of Manitoba, Winnepeg, Canada
(1978).

Al-Hussainy, R., Ramey Jr., "The Flow of Real Gases Through Porous Media", JPT (1966)
H. J. and Crawford, P. B. 624-636.

Alhanati, F. J. S., Schmidt, "Continuous Gas-Lift Instability: Diagnosis, Criteria, and Solutions",
Z., Doty, D. R. and Lagerlef, SPE 26554 (1993)
D. D.

Alves,I.N., Alhanati, F. J. S. "A Unified Model for Predicting Flowing Temperature Distribution in
and Shoham,O. Wellbores and Pipelines", SPE 20632 (1992)

Ashford, F.E. and Pierce, "Determining Multiphase Pressure Drops and Flow capacities in
P.E. Down-Hole Safety Valves", Journal of Petroleum Technology,
Paper No. SPE-5161, (September, 1975).

Aziz, K., Govier, G. W. and "Pressure Drop in Wells Producing Oil and Gas," J. Cdn. Pet.
Forgasi, M. Tech. (July-Sept. 1972) 38-48.

Babu, D. K. and Odeh, A. S. "Productivity of a Horizontal Well", SPE Reservoir Engineering

(November 1989) 417-421.

Baker, A., Nielsen, K., and "Pressure Loss, Liquid-Holdup Calculations Developed,"
Gabb, A. Technology, Oil & Gas Journal (Mar. 14, 1988).

Baker, O. and Swerdloff, W. "Calculation of Surface Tension - 3";, Oil & Gas Journal (Dec. 5,
1955) 141.

Beal, C. "The Viscosity of Air, Water, Natural Gas, Crude Oil and its
Associated Gases at Oil Temperatures and Pressures", Trans.
AIME (1946) 94.

Beggs, H. D. "Gas Processing Operations", OCGI Publications, (1984), ISBN

0-930972-06-6

Technical Description
499
PIPESIM User Guide

Beggs, H. D., and Brill, J. P. "A Study of Two Phase Flow in Inclined Pipes", J. Pet. Tech. (May
1973) 607-617.

Beggs, H. D. and Robinson, "Estimating the Viscosity of Crude Oil Systems", J. Pet. Tech.
J. R. (Sept. 1975) 1140-1.

Bellarby, Jonathan Well Completion Design, Chapter 6, Elsevier, 2009.

Bendakhlia, H. and Aziz, K. "Inflow Performance Relationships for Solution-Gas Drive

Horizontal Wells", SPE paper 19823 presented at the Annual
Technical Conference and Exhibition, San Antonio, (October
1989).

Bendiksen et al. The Dynamic Two-Fluid Model OLGA: Theory and Application,
SPE Production Engineering, 171-180, May 1991.

Bergman, D. F. and Sutton, "Undersaturated Oil Viscosity Correlation for Adverse Conditions",
R. P. SPE 103144 (2006).

Bhatti and Shah "Turbulent and Transition Flow Convective Heat Transfer in Ducts",
Handbook of Single-Phase Convective Heat Transfer, ed. Kakac,
Shah, Aung Wiley Interscience, NY (1987)

Brauner, N. and Ullmann, A. Modeling of Phase Inversion Phenomenon in Two-Phase Pipe

Flows, Int. J. Multiphase Flow, 28, 1177, 2002.

Brill, J. P. et al. "Analysis of Two-Phase Tests in Large Diameter Flow Lines in

Prudhoe Bay Field", SPEJ (June 1981).

Brill, J. P. and Beggs, D. H. "Two-Phase Flow in Pipes", 6th Edition, University of Tulsa, Tulsa,
Oklahoma, (December 1988).

Brill, J.P. and Mukherjee, H. "Multiphase Flow in Wells", SPE Monograph 17, (1999)

Brons, F. and Marting,V. E. "The Effect of Restricted Fluid Entry on Well Productivity", Trans.,
AIME (1961) 222, 1972.

Brown, T.S., Niesen, V.G., "Measurement and Predition of Kinectics of Paraffin Deposition",
And Erickson, D.P. SPE 26548, 68th Annua Technical Conference and Exhibition of
SPE Houston, TX, 3-6 October, 1993.

Brown, K.E. "The Technology of Artificial Methods", Penwell Publishing

Company, Tulsa, Oklahoma, 1984.

Butler, B. "Success grows in pumping high-gas-fraction multiphase fluids",

Petroleum Engineer International, July 1999.

Celier, G. C. M. R., Jouault, "Zuidwal: A Gas Field Development With Horizontal Wells", SPE
P. and de Montigny, O. A. M. paper 19826 presented at the Annual Technical Conference and
C. Exhibition in San Antonio, October 1989.

Technical Description
500
PIPESIM User Guide

Cheng, A.M. "Inflow Performance Relationships for Solution-Gas-Drive Slanted/

Horizontal Wells", SPE paper 20720 presented at the Annual
Technical Conference and Exhibition, New Orleans, September
1990.

Chew, J. and Conally, C. A. "A Viscosity Correlation for Gas Saturated Crude Oils", Trans.,
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Chu and Jones "Convective Heat Transfer Coefficient Studies in Upward and
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Cinco, H., Miller, F.G.,and "Unsteady-State Pressure Distribution created By a Directionally

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Cinco, H., Samaniego, V., "Transient Pressure Behavior for a Well With a Finite-Conductivity
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Cinco-Ley, H., and "Transient Pressure Analysis for Fractured Wells", JPT, 1749 -
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Cinco-Ley, H., and "Transient Pressure Analysis: Finite Conductivity Fracture Case
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Colburn "A Method of Correlating Forced Convection Heat Transfer Data

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Cooper, R.E., and Troncoso, "An Overview of Horizontal Well Completion Technology", SPE
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Technical Description
501
PIPESIM User Guide

Dikken, B.J. "Pressure Drop in Horizontal Wells and its Effect on Production
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Technical Description
503
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Hausen "Neue Gleichungen fur die Warmeubertragung bei frieier oder

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Kunz, Klimeck The GERG-2004 wide-range equation of state for natural gases
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Lockhart, R. W. and "Proposed Correlation of Data for Isothermal Two-phase, Two-

Martinelli, R. C. Component Flow in Pipes", Chem. Eng. Prog. (January 1949) 45,
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PIPESIM User Guide

Martin and Sims "Forced Convection Heat Transfer to Water with Air Injection in a
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McCain, William D. Jr. "Petroleum Fluids", edition 2.

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Manhane, J. M., Gregory, G. "A Flow Pattern Map for Gas-Liquid Flow Pattern in Horizontal
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Martinelli "Heat Transfer to Molten Metals", Trans. ASME, 69, 947 (1947).

Minami, K. and Brill, J. P. "Liquid Holdup in Wet Gas Pipelines", SPE J. Prod. Eng. (May
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Mirza, K. Z. "Progressing cavity multiphase pumping systems: expanding the

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Moody, L. "An approximate Formula for Pipe Friction Factors", Transactions

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Mukherjee, H. and Brill, J. P. "Liquid Holdup Correlations for Inclined Two-Phase Flow", JPT
(May 1983) 1003-1008.

Mukherjee, H. and "A Parametric Comparison of Horizontal and Vertical Well

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Muskat, M. "The Flow of Homogeneous Fluids Through Porous Media",

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PIPESIM User Guide

Mutalik, P. N., Godbole, S. P. "Effect of Drainage Area Shapes on Horizontal Well Productivity",
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Norris, L. "Correlation of Prudhoe Bay Liquid Slug Lengths and Holdups

Including 1981 Large Diameter Flowlines Tests", Internal Report
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Nunner "Warmeubergang und Druckabfall in Rauhen Rohren", VDI-

Forschungsheft 445, ser B, 22, 5 (1956) or 786-Atomic Energy
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Oliemans, R. V. A. "Two-Phase Flow in Gas-Transmission Pipeline", ASME paper 76-

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Oliver and Wright "Pressure Drop and Heat Transfer in Gas-Liquid Slug Flow in
Horizontal Tubes", Bri. Chem. Eng., vol. 9, no. 9, p 590-596 (1964)

Omana, R. et al. "Multiphase Flow Through Chokes", SPE 2682, 1969

Orkiszewski, J. "Predicting Two-Phase Pressure Drops in Vertical Pipes", J. Pet.

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Ovuworie, Chukwuemeka "Steady-State Heat Transfer Models For Fully And Partially Buried
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Oxley, K. C., Ward, J.M. and "How multiphase pumping can make you money", presented at
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Poettman, F. H. and Beck, R. "New Charts Developed to Predict Gas-Liquid Flow Through
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Prandtl, L. "Furhrrer durch die Stomungslehre", Vieweg, Braunschweig, p 359

(1944)

Petrosky, G.E. Jr. and "Pressure-Volume-Temperature Correlations for Gulf of Mexico

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Petukhov and Gnielinski Int. Chem. Eng., 16-2, p 359, (1976)

Petukhov and Kirillov "Heat Transfer and Friction in Turbulent Pipe Flow with Variable
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Pots, B. F. M., Bromilow, I. "Severe Slug Flow on Offshore Flowline/Riser Systems", SPE
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Prats, M. "Effect of Vertical Fractures on Reservoir Behavior-Incompressible

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Ramey, H.J. "Wellbore Heat Transmission", JPT 435 Trans AIME, No. 225 (April
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Ravipudi and Godbold "The Effect of Mass Transfer on Heat Transfer Rates for Two-
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Rezkallah and Sims "An Examination of Correlations of Mean Heat Transfer

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Sandall et al. "A New Theoretical Formula for Turbulent Heat and Mass Transfer
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Scandpower PT Tech Note "TN-11: Heat Transfer Calculations", Scandpower PT, Oslo
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Technical Description
508
PIPESIM User Guide

Shell report SIEP 98-5463 "Satellite multiphase boosting - Multiphase boosting study", Siep-
RTS, ABB Lummus Global

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SPE Production Engineering Volume IV, Chapter 15, Society of Petroleum Engineers, 2007.
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Venkatesan, R. "The Deposition and Rheology of Organic Gels", U. of Michigan,

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Webb "A Critical Evaluation of Analytical Solutions and Reynolds Analogy

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Technical Description
510
PIPESIM User Guide

8
Keyword Index
Input Files and Input Data Conventions (p.515)
General Data (p.522)
Compositional Data (p.645)
Blackoil Data (p.633)
Heat Transfer Data (p.623)
Flow Correlation Data (p.554)
System and Equipment Data (p.588)
Well Performance Modeling (p.566)
PIPESIM Operations (p.654)
PIPESIM-Net Keywords (p.675)

8.1 Keyword List

A (p.511) B (p.511) C (p.512) D (p.512) E (p.512) F (p.512) G (p.512) H (p.513) I
(p.513) J (p.513) K (p.513) L (p.513) M (p.513) N (p.514) O (p.514) P (p.514) Q
(p.514) R (p.514) S (p.514) T (p.515) U (p.515) V (p.515) W (p.515) X (p.515) Y
(p.515) Z (p.515)

8.1.1 A
ASSIGN (p.667)

8.1.2 B
BACKPRES (p.580)
BEGIN (p.550)
BLACKOIL (p.633)
BRANCH (p.678)

Keyword Index
511
PIPESIM User Guide

8.1.3 C
CASE (p.524)
CALIBRATE (p.643)
CHOKE (p.589)
COAT (p.626)
COMP (p.648)
COMPCRV (p.593)
COMPLETION (p.567)
COMPRESSOR (p.595)
CONETAB (p.579)
CONFIG (p.631)
CONTAMINANTS (p.644)
CORROSION (p.555)
CPFLUID (p.642)

8.1.4 DE
END (p.550)
ENDCASE (p.550)
ENDJOB (p.550)
EROSION (p.555)
EQUIPMENT (p.354)
ESP (p.617)
EXPANDER (p.599)

8.1.5 F
FETKOVICH (p.570)
FITTING (p.600)
FLOWLINE (p.567)
FMPUMP (p.602)
FORCHHEIMER (p.586)
FRACTURE (p.586)
FRAMO2009 (p.602)

8.1.6 G
GASLIFT (p.603)

Keyword Index
512
PIPESIM User Guide

8.1.7 H
HCORR (p.561)
HEATER (p.603)
HEADER (p.523)
HEAT (p.623)
HORWELL (p.580)
HVOGEL (p.586)

8.1.8 I
IFPPSSE (p.571)
IFPTAB (p.578)
IFPCRV (p.576)
INLET (p.539)
INJGAS (p.609)
INJFLUID (p.609)
INJPORT (p.607)
IPRCRV (p.576)
ITERN (p.537)

8.1.9 J
JOB (p.523)
JONES (p.571)
JUNCTION (p.685)

8.1.10 K
KCOAT (p.628)

8.1.11 L
LAYER (p.582)
LVIS (p.637)

8.1.12 M
MPBOOSTER (p.611)
MPUMP (p.612)
MULTICASE (p.659)

Keyword Index
513
PIPESIM User Guide

8.1.13 N
NAPLOT (p.655)
NAPOINT (p.659)
NODE (p.614)
NOPRINT (p.550)
NSEPARATOR (p.685)

8.1.14 O
OPTIONS (p.525)
OPTIMIZE (p.668)

8.1.15 P
PCP (p.617)
PERMCRV (p.584)
PERMTAB (p.585)
PETROFRAC (p.653)
PIPE (p.615)
PLOT (p.547)
PRINT (p.539)
PROP (p.635)
PUMP (p.617)
PUMPCRV (p.593)
PUSH (p.552)

8.1.16 Q R
RATE - Compositional (p.654)
RATE - Blackoil (p.535)
REINJECTOR (p.620)
RISER (p.567)

8.1.17 S
SEPARATOR (p.621)
SETUP (p.40)
SINK (p.683)
SLUG (p.556)

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SOURCE (p.680)
SPHASE (p.564)

8.1.18 T
TABLE (p.666)
TCOAT (p.627)
TIME (p.670)
TPRINT - Compositional (p.654)
TPRINT - Blackoil (p.642)
TRANSIENT (p.587)
TUBING (p.567)

8.1.19 U
UNITS (p.524)
USERDLL - Flow Correlations (p.566)
USERDLL - Equipment (p.554)

8.1.20 V
VCORR (p.557)
VOGEL (p.570)

8.1.21 W
Wax Deposition (p.670)
WELLHEAD (p.622)
WELLPI (p.569)
WCOPTION (p.573)
WPCURVE (p.570)

8.1.22 XYZ

8.2 Input Files and Input Data Conventions

8.2.1 General
The PIPESIM engine input processor accepts data under a system of main-code and sub-code
keywords. The entire input data file is checked for syntax errors before program execution begins;
if any input errors are detected, diagnostics are written to the terminal (for interactive jobs) and to
the Input Data Echo in the main job output, and program execution is halted.

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8.2.2 Statements
Data is entered in statements. Each statement must begin with a main-code keyword (unless it is a
comment card or a blank line), and is followed by sub-code keywords and equated values
appropriate to the maincode. Statements are usually entered one per line in the file; but if desired,
a statement can be split across multiple lines, or multiple statements can be provided on one line.
In all cases there is a limit of 256 characters per statement, and per line, including spaces.
Statements are composed of printable text characters. Valid characters are those in the 7- or 8-bit
ASCII set between decimal values 32 (space, [ ]) and 126 (tilde, [~]). Some computers or
installations will generate characters outside this range, due to differences in national language
alphabets and punctuation. Usually this will not cause any problems but this cannot be guaranteed.
(Files containing ASCII codes greater than 128 or less than 32 are often created using a word-
processing program, because these characters are used as formatting instructions to produce a
correctly formatted printed page. For PIPESIM however they are not required and will sometimes
cause the program to generate large numbers of syntax errors. Use of such programs for preparing
input files is best avoided, you should use a text editor instead; alternatively acceptable results
may be obtained by requesting the word-processor to produce ASCII text files as output.)
Upper and lower case can be freely mixed, except where doing so would cause the computer
system to assign a different meaning to the data. All Maincodes and Subcodes described in this
document are case-insensitive, but for example some computer systems are case-sensitive in
filenames, so where these are specified care must be taken to provide the correct case.

8.2.3 Delimiters
There are a number of characters reserved for use as delimiters. In general these can only be
used for the purpose described, however if a reserved delimiter character is required for use in a
character string, the string can be quoted with apostrophes or double quotes. The delimiters (with
ASCII decimal codes) are:
[ ] One or more blanks or spaces can be used to delimit main-code and sub-code entries, and
to improve readability in conjunction with other delimiter characters. (ASCII 32)
[,] A comma (with or without one or more blanks) can also be used to delimit main-code and
subcode entries, but its main use is to delimit data items when a multiple set of values is
provided with parentheses (see below). (ASCII 46)
[=] An equal's sign is used to separate each subcode from its associated numeric or character
data. Additional spaces may be inserted either side of the equals to improve readability. Some
subcodes do not require values; if no value is provided the equals must be omitted. (ASCII 61)
['] Apostrophes (also known as closing single quotes) can be used in matching pairs to delimit
character data which itself contains delimiter characters, e.g. embedded blanks. (Do not
confuse apostrophe with the opening single quote[`], and do not attempt to match opening and
closing single quotes with one another.) (ASCII 39)
["] Double quotes can be used in matching pairs as an alternative to apostrophes in delimiting
character data. This is useful when the character string contains one or more single quotes.
(Note that double quote is itself a single character or keystroke, and is not equivalent to two
single quotes.) (ASCII 34)

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[$] or [!] Either a dollar sign or an exclamation point is used to delimit end-of-line comments
from input data. All characters on the line between the comment delimiter and end-of-line will be
ignored. (ASCII 36 and 33)
[(] [)] Parentheses are used to enclose Multiple Value Data Sets when 2 or more values are
provided for a subcode. Supplied data values should be separated with commas. (Additional
separators are valid in multiple data sets, see below.) (ASCII 40 and 41)
[&] The ampersand is used to continue a statement across two or more lines. It is placed as the
last character on a line to specify that the statement continues on the next line. There is no limit
to the number of continuation lines, but the complete statement cannot span more than 256
characters, including spaces. The ampersand should appear between subcodes. Continued
lines can be separated with blank lines, but not with comment lines. (ASCII 38)
[;] The semicolon is used to separate multiple statements provided on a single line. (ASCII 59)

Examples
RATE LIQUID = 6000 GLR = 400 WCUT = 20
RATE, LIQ=6000, GLR=400, WCUT=20
MULTICASE LIQ = ( 200, 250, 300 ) GLR = ( 95, 105 )
HEADER PROJECT=TEST, USER=J. BLOGGS
HEADER PROJECT=TEST, USER='JOE BLOGGS'
$ This line is a comment and will be ignored
! This line is also a comment
MULTICASE LIQ=(200.250,300) GLR=(95,105) ! This is an end-of-line comment
RATE, LIQ=6000, GLR=400, WCUT=20 $ This is also an end-of-line comment
MULTICASE LIQ=(200.250,300) & ! This statement is continued on the next line
GLR=(95,105)
! the next line contains two statements
RATE, LIQ=6000, GLR=400, WCUT=20 ; MULTICASE
LIQ=(200,250,300) GLR=(95,105)

8.2.4 Abbreviations
Main-code and sub-code keywords can be abbreviated down to the minimum number of letters
required to make them unique in their context. For maincodes the context is all other main-codes;
thus for example the GASLIFT maincode can be abbreviated to G because no other maincode
starts with G, but COMP is an illegal abbreviated maincode because it matches COMPRESSOR,
COMPLETION and COMPOSITION. The context for subcodes is restricted to the set of legal
subcodes for the maincode concerned. If the keyword is abbreviated too much, the input processor
will generate a syntax error and processing will terminate.

Example
For example the following 2 lines are equivalent:

OPTIONS SEGMENTS=10
OPT S=10

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8.2.5 Numeric data

Except where noted, all numeric data must be equated to a preceding subcode with an equals sign
[=]. Decimal points are optional, if provided only one is allowed and it must be the period or full
stop character, [.] (ASCII 46). Large and small values may carry an exponent, for example,
1200000 may be written as 1.2e6 (or 0.12E7, .12e7, 1.2+6, 1.2e+6, 1.2D6, and so on). For
example 0.000034 may be written as 3.4e-5 (or 0.34e-6, and so on). Do not embed spaces or
commas in numeric data; they will be interpreted as delimiters signaling the end of the data item,
and the remaining digits will then cause a syntax error.
Some main-codes allow data to be provided without keywords, in a strict positional order. Usually
this is to allow easy entry of tabular data. Examples are PERMTAB (p.585), CONETAB (p.579),
IFPTAB (p.578).

Example
In the following example, all lines are equivalent:

RATE MASS=224.0
RATE MASS=.224e+3
RATE MASS=224

8.2.6 Units Description

A Units Description String can accompany numeric data. Such strings are the best way to provide
data in units different to the defaults established with the UNITS statement. The string must contain
no embedded blanks or other recognized delimiters. It can appear after the data to which it refers,
or between the keyword and the equals. For example:

RATE LIQ = 3000 bbl/day WCUT = 55 % GOR = 300 scf/bbl

RATE LIQ bbl/day = 3000 wcut % = 55 GOR scf/bbl =
300

Multiple value data sets equated to non-symbolic subcodes can also accept unit's description
strings placed outside the parentheses, for example:

PUMPCRV head = (300, 250,200,150,100,50) kj/kg

Symbolic subcodes (eg ?ALPHA, ?BETA on Multicase) will not allow units description strings.
Instead, the description can be placed on the line where the symbol is used, for example:

MULTICASE ?ALPHA=(20,30,40)
PUMP DP = ?ALPHA kg/cm2

8.2.7 Character Input

Character data should be enclosed in a single or double quotes if it contains reserved delimiter
characters (for example embedded blanks). It must be equated to a sub-code with an [=] sign.

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Example
For example:

HCORR PLOSS = BJA HOLOUP = BJA MAP = TD

NODE dist=0 elev = 0 t=100 u=0.8 label = "Station Z' to
J2"

8.2.8 Comment Statements and Blank Lines

Any information to the right of a comment delimiter [$ or !] is ignored. Lines beginning with a
comment delimiter sign will be ignored completely and can be entered at any location in the input
data file.
Blank lines are also ignored and so may be used to improve layout and readability.

Example
$ ~---- THIS LINE WILL BE IGNORED -----
RATE, MASS=224 $ THIS IS AN IN-LINE COMMENT

8.2.9 Multiple Value Data Sets

Some subcodes accept more than one value, and for these an explicit syntax is available using
parentheses. At its simplest the Multiple Value Data Set is a 2 or more values, separated by
commas, and enclosed by parentheses. For example:

MULTICASE LIQ=(200,250,300) GLR=(95,105)

CHOKE dbean = 0.5 ccorr = (pratio, sonicup, flowrate)
DOVCORR uovcorr=table temps=(80,100,120,140)
viscs=(6.5,5,2,1.5)
PRINT CUSTOM=(g3,h3,i3,k1,l1,m4,g4,f4,h11,i11,j11,m11)
PLOT CASE=(+,f7,g7,h7)

Multiple value sets can become very long, and care should be taken to avoid the maximum
statement limit of 256 characters.
A range of data values can be specified for numeric data, this is a convenient alternative to
entering long strings of explicit values. The syntax is ( start : finish ; iop increment), which specifies
a Starting value, a Finishing value, an Increment Operator, and an Increment Value. The special
characters used are:
colon [:] separates the starting value from the finishing value

semicolon [;] separates the finishing value from the increment operator

plus [+] the addition operator

minus [-] the subtraction operator

asterisk [*] the multiplication operator

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hash/sharp/number sign the enumeration operator.

[#]
Note: On computers outside the USA, the hash character will
sometimes display as the national currency symbol. The required
ASCII code is 35 decimal.

Examples
Some examples:

Example 1
To specify values from 10 to 100 by repeated addition of 5:

(10:100;+5).

Example 2
To specify values from 10 to 100 in 50 equal-sized steps:

(10:100;#50)

Example 3
To specify values from 10 to 100 by repeated multiplication by 1.5:

(10:100;*1.5)

Example 4
To specify values from 100 to 10 by repeated subtraction of 7:

(100:10;-7)

Example 5
The range syntax can appear many times and be combined with other values, E.g.:

MULTICASE GLR=( 0, 1:1000;*1.5, 1200, 1600, 2000:10000;+1000 )

8.2.10 Input Files

General
The input data may appear in more than one file. At least one file is required, this may contain
explicit references to further files if desired. In addition certain other files, if they exist, will be
automatically read and processed in addition to your main input file.

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The main input ('.PSM' or '.PST') file

Conventionally, the main input file has a filename with an extension of '.PSM'. It is specified on the
engine command line or in answer to the engine prompt 'INPUT FILE NAME:'. In fact however any
extension can be chosen, and will be used as specified. Beware however that word-processing
programs can generate files with embedded formatting characters (that the engine will not
recognize) if certain extensions are used, for example .TXT, .DOC. You are advised to use .PSM
as the extension for all PIPESIM keyword main input files.

Note: The PIPESIM Graphical User Interface (GUI) program generates temporary engine keyword
files with the extension .PST. All such files are assumed by it to be volatile, so if you choose to
create files with a .PST extension, they are likely to be overwritten with no warning. Use .PSM
instead.

Included files and the INCLUDE statement

Input data can be explicitly split among 2 or more files by use of the INCLUDE statement.
INCLUDE has no subcodes, and the only value allowed is the name of the file to be included. The
contents of the included file will be processed as though it appeared in the input file instead of the
INCLUDE statement. For example if the file 'oil23.inc' contains the following:

UNITS in=eng
BLACKOIL
PROP gassg=.68 watersg=1.05 api=37.6
PROP psat=600 psia tsat=120 F GSAT=370
RATE wcut=20 GOR=320

This file can be referenced from the main input file by use of an INCLUDE at the appropriate point,
for example:

INCLUDE oil23.inc

The Included file is assumed to reside in the same directory as the main input file; if this is not the
case a path can be provided, such as:

include ..\..\proj-45\common\oil23.inc

Filenames containing spaces and other delimiter characters must be quoted, for example:

INCLUDE "k:\my special projects\pipesim files\my common

files\proj-45\common\oil type 23c.inc"

Included files can themselves contain INCLUDE statements, and such nested includes can go to a
maximum of 10 levels. Take care to ensure such an include nest does not attempt to include a file
that has already been included.
All Included files should specify a UNITS statement before any numeric data is supplied. Failure to
do this is not an error, but the interpretation of the contents of the included file will then depend on
the units in force in the main input file at the point of the INCLUDE statement. This is an unsafe
situation, and can lead to unforeseen errors, which do not necessarily manifest themselves
immediately. Any UNITS statement in an included file will only affect data in that file, and will not be

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remembered when processing returns to the main input file. Thus an included file cannot be used
to alter units settings in the main input file.

AUTOEXEC.PSM
This is a special include file that, if it exists in the same directory as the main input file, is
automatically included for processing as though an INCLUDE statement referenced it. The file is
named after the MS-DOS control file AUTOEXEC.BAT because of the obvious parallels between
them. Note however that, while AUTOEXEC.BAT must reside in the root directory of a DOS boot
disk to do its job, AUTOEXEC.PSM must instead reside in the same directory as the engine main
input file. It is therefore possible to have many different autoexec.psm files in different directories of
a computer's file system.

modelname.U2P or branchname.U2P
The .U2P file is a file whose contents are defined identically to AUTOEXEC.PSM, but whose
applicability is limited to just one main input file name. This is specified by matching the rootnames
of the files. For example if the main input file is called fred.psm, the matching .u2p file is fred.u2p.

8.3 General Data

HEADER (p.523) Job Accounting Header
JOB (p.523) Job Title
CASE (p.524) Case Title
UNITS (p.524) Input and Output Units
OPTIONS (p.525) Calculation Procedure Options
RATE (p.535) Fluid Flow Rate Data
ITERN (p.537) Iteration Data (Optional)
INLET (p.539) System Inlet Data
PRINT (p.539) Output Printing Options
NOPRINT (p.550) Output Print Suppression Options
PLOT (p.547) Output Plotting Options
BEGIN, END (p.550) Block delimiters
PUSH (p.552) Remote action editing
PLOT FILE DATA (p.553)
EXECUTE (p.553)
USERDLL (p.554) Equipment

8.3.1 Changing Parameters within the System Profile

One of the features of PIPESIM which gives a great deal of flexibility is the ability to change any
parameter, for example, flow rate or fluid property, at any point (node) in the system. In fact, almost
any main-code can be inserted at any point in the System Profile, that is the cards between the first

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NODE card and the ENDCASE card. There are one or two exceptions where the main-code must
appear before the first NODE card (for example ITERN main-code) and these are documented in
the relevant sections. This feature allows changes of pipe diameter, fluid inflow and outflow, and so
on, to be easily modeled.
The main-code to change parameters within the System Profile should be inserted after the NODE
card at which it is to take effect. There is no limit to the number of parameters which can be
changed at a particular node.

Example
Example:
A pressure control valve is located at a position 2000' down a flowline and sets the downstream
pressure to 800 psia. There is a change of pipe diameter (to 6"), and another flowline from a
similar well joins thus doubling the flow rate.

Multiple Cases
If multiple cases are to be considered, where the same feature within the profile is to be repeated
but with a different value assigned to it, then the user has a choice. Either the whole profile may be
repeated or an ASSIGN (p.667) card may be used to avoid repetition of the profile.

Note: The MULTICASE (p.659) card provides a convenient alternative to the use of repeated
ENDCASE cards.

8.3.2 HEADER - Job Accounting Header (Required)

Main-code: HEADER
The HEADER card must be the first card in a job and must contain both a PROJECT and USER
sub-code.

PROJECT= Project name (12 characters maximum) which should be entered in quotes if the
string contains delimiters (such as blanks or commas).

USER= User name (12 characters maximum) which should be entered in quotes if the
string contains delimiters (such as blanks or commas).

PASSWORD= Password (12 characters maximum) which should be entered in quotes if the
string contains delimiters (such as blanks or commas).

Example
HEADER PROJ=TEST USER='JOE BLOGGS'

8.3.3 JOB - Job Title (Optional)

Main-code: JOB

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JOB Job title (70 characters maximum). Quotes are not required even if the title string includes
delimiters.

8.3.4 CASE - Case Title (Optional)

Main-code: CASE

CASE Case title (70 characters maximum). Quotes are not required even if the title string
includes delimiters.

8.3.5 UNITS - Input and Output Units (Optional)

Main-code: UNITS

INPUT= Specifies the units in the input file

SI Input data in SI units (default).

ENG Input data in engineering units

OUTPUT= Specifies the units in the output file

SI Output data in SI units (default).

ENG Output data in engineering units

ALL= Specifies the units in both the input and output files.

SI Input data in SI units (default).

ENG Input data in engineering units

The UNITS statement should appear before the input data to which it relates and is therefore
usually placed at the top of the input file after the HEADER statement.
If input data is provided in additional files, viz. AUTOEXEC.PSM, (p.515) branchname .U2P, or
files specified on INCLUDE statements, each file should commence with its own UNITS statement
to ensure the units in the file are not dependent on the position in the main input file where it is
processed. A UNITS statement in an additional file does not affect the units already established for
the main input file.
The UNITS statement may appear many times in the input file, to ensure the subsequent data has
the desired units system. Please note however it is preferable for each data item to be qualified
with its own units description string.

Example
UNITS INPUT=SI OUTPUT=ENG

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8.3.6 OPTIONS Calculation Procedure Options (Optional)

Main-code: OPTIONS

SEGMENTS= The number of segments in each pipe or tubing section. The pipeline is
divided into sections by entering distance and elevation data (or TVD/MD)
on NODE statements. Each section is then sub-divided by the program
into a number of segments for calculation purposes. The default number
of segments is 4; allowable range is 1 to 500. The intermediate segment
data will only be printed if PRINT (p.539) sub-code SEGMENT is
selected. The MAXSEGLEN= subcode (below) can also be used to
subdivide sections. The EOFS= setting may add 2 additional short
segments to the section, see below.

MAXSEGLEN= The maximum segment length to be used by the program (ft or m). The
number of segments in each section is computed by dividing the section
length by the specified MAXSEGLEN= length. The final number of
segments used is the maximum of this calculation, rounded up, and the
number specified by the SEGMENTS= subcode. above. The default for
MAXSEGLEN= is infinite. The EOFS= setting may add 2 additional short
segments to the section, see below.

MINSECTLEN or The minimum length of any section of pipe that the PIPESIM engine will
DUPENODELEN compute properties such as pressure, temperature, etc. for. Any node
which is closer than this length from the previous node will be ignored and
removed from the system profile.

EOFS= Extra One-Foot Segments. Pipe sections between NODE statements

are divided into segments for calculation purposes, under the control of
the SEGMENTS= and MAXSEGLEN= subcodes above. In addition, extra
short segments are added to the start and end of the section to ensure
the reported fluid properties and flowrates are calculated at an almost
identical temperature and pressure as that reported at the node. In fact,
the fluid properties are calculated at segment average pressure and
temperature. With EOFS enabled, the discrepancies caused by this
mismatch are minimized; however, it does have some effect of the
runtime. Can be set to ON or OFF. Default is ON.

SEC= Controls the calculation of pressure losses due to Sudden Expansions

and Contractions (SEC) of pipe diameter. Can be set to ON or OFF. The
default is ON.

SECLIM= The lower limit for printing of SEC pressure losses. Any SEC DP less than
this value will not be reported. DPs are reported with a one-line message
in the primary output page. Default is 10 psi.

GRIDPRES=(...) Values of pressure to be used in the P/T grid for compositional

interpolated flash calculations. Psia or bara. Exclusive with
NUMGRIDPRES=.

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GRIDTEMP=(...) Values of temperature to be used in the P/T grid for compositional

interpolated flash calculations. F or C. Exclusive with NUMGRIDTEMP=.

NUMGRIDPRES= The number of grid pressure points desired in the P/T grid for
compositional interpolated flash calculations. A number between 60 and
100, default 60. If this subcode is specified, the actual values of grid
pressure will be generated internally using an arithmetic increment
algorithm, between atmospheric pressure and approximately. 40,000 psi.
Exclusive with GRIDPRES=.

NUMGRIDTEMP= The number of grid temperature points desired in the P/T grid for
compositional interpolated flash calculations. A number between 60 and
100, default 60. If this subcode is specified, the actual values of grid
temperature will be generated internally using a linear increment
algorithm, between -60 and +300 F. Exclusive with GRIDTEMP=.

2010GRID Reverts from the current 60x60 compositional table pressure-temperature

grid size to the 21x21 grid size present in PIPESIM 2010.1 and earlier
releases. Can be specified either as 2010GRID or 2010GRID=ON

HTCRD= Heat Transfer Coefficient Reference Diameter. All HTCs printed on the
Heat Transfer Output pages will normally use a reference diameter equal
to the local pipe outside diameter. However, if a value is provided for
HTCRD=, the supplied reference diameter will be used instead. This is
useful when sensitizing on pipe diameter, or when different pipe
diameters are present in the system, because it allows HTCs to be
compared without the need to convert for different diameters. Units are In.
or mm.

GTGRADIENT= Controls geothermal gradient assumptions in Pipe objects. When a

temperature profile is provided for a well tubing with TEMP= on the
various NODE statements, the values are assumed to specify measured
points on a geothermal gradient, so temperatures are interpolated
between them based on the true vertical Depth. However, when
temperatures are provided for flowlines and risers, they are assumed to
be specifications that exhibit a step-change at the nodes. This subcode
can be set to ON, OFF or AUTO. ON makes all pipe objects, notably
flowlines and risers, interpolate the temperatures according to the
elevation or depth (NB, not distance). OFF prevents all pipe objects,
notably well tubing and horizontal completions, from interpolating. AUTO
is the default setting, which allows well tubing pipes to interpolate, but
prevents flowlines and risers.

PPMETHOD= Compositional Flashing method (p.9) for determination of fluid transport

properties. Can be set to 1, 2, or 3. The default is 1. The meaning of
these is:

1: Interpolate (fastest). This option uses interpolation between physical

properties from flash results in a predefined grid of temperature and

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pressure points. This grid can be modified using the GRIDPRES= and
GRIDTEMP= subcodes above.

2: Hybrid when close to the Phase Envelope, interpolation elsewhere.

This is a compromise between speed and accuracy, which assumes that
properties will change more rapidly when close to a phase boundary.
Interpolation is performed whenever the grid points comprising a
rectangle all show the presence of the same phases. For example. if all 4
points in the rectangle have some oil, some gas, and no water, then we
assume the rectangle lies entirely within the 2-phase region of the
hydrocarbon phase envelope, so interpolation is appropriate. If however
one, two or three of the points have no oil, then clearly the hydrocarbon
dew point line crosses the rectangle, so a rigorous flash is required.

3: Rigorous (slowest). Interpolation never occurs: properties are obtained

by flashing at the required pressure and temperature. This is the most
accurate method, but it is also the slowest.

THMETHOD= Compositional Flashing method (p.9) for Temperature/enthalpy balance

calculation. In most simulations, for every PP flash that is performed,
there are about 5 to 10 TH flashes, so these have the greatest effect on
speed and run-time. The inaccuracies of TH interpolated flashes are
usually minimal. Can be set to 1, 2, or 3, as for PPMETHOD=.

IFP= This is a way to switch off all existing completion options in the model.
Should only be used by another program controlling the engine as a sub-
task. Can be set to ON or OFF. The default is ON.

ACTIVELAYER= In a multi-layer well, specifies that only one of the reservoir layers is to be
active. Must be set to a number between 1 and the number of reservoir
layers in the well. Layers are numbered starting with 1 for the deepest.

COMPLETION= or Controls the way temperature and enthalpy changes are handled when
COMPHBAL= modelling the pressure drop calculations across a completion. may be set
to:
ADIABATIC or ISENTHALPIC: The pressure change will be at constant
enthalpy, so the fluid will undergo a temperature change according to it's
Joule-Thomson coefficient. For Liquids this will result in a temperature
increase; for gases, temperature will usually decrease, but in high-
pressure reservoirs it may increase.
ISOTHERMAL: The pressure change will be at constant temperature. The
fluid temperature will not change, so a consequent enthalpy change will
occur,

MAXEMULSION= Maximum value for the multiplier as interpolated or extrapolated from the
emulsion viscosity table for user-supplied and Woleflin emulsion
correlations (p.637). Default 100. The limit will be applied silently. This
is a global (model-wide) option.

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MAXCUTOFF= Maximum value for the BOUNDARY= and CUTOFF= (p.637) keywords
on the LVIS statement, default 70. Limit will be applied silently. This is a
global (model-wide) option.

MAXLIQVISC= Maximum liquid viscosity the engine will allow. If any correlation predicts
values greater than this they will be limited to it. Default 1e7 cP. Limit will
be applied with warnings. This is a global (model-wide) option.

SMOOTHCUTOFF= Size of the transition region that is used to interpolate the viscosity
multiplier when watercut is above the cutoff value. Default 5%. This is a
global (model-wide) option.

EMUL3PHASE= Method for assigning priority between Emulsion options and a 3-phase
flow correlation. This is a PIPE component level option. May be set to one
of the following values:

EMULSION: Emulsion option will take priority. Any fluid with an emulsion
viscosity will override a 3-phase correlation. Oil and water phase
Viscosities and densities will be set to the emulsion liquid phase values
before calling the correlation.

3PHASE: 3 phase correlation will take priority. Separate oil and water
phase densities and viscosities will be passed to it, and its answers will be
used as-is. The liquid phase emulsion viscosity will be ignored. This is the
default setting, chosen for backward compatibility with previous versions
of the engine.

HYBRID: The 3 phase correlation will be called as for the 3PHASE option,
and its prediction of the mixing status of the liquid phase will be
examined. If it predicts separate, unmixed oil and water phases, the
answers will be used as-is. If however it predicts mixed oil and water, and
the fluid has an emulsion viscosity, then the answers will be discarded,
and a further call made in the EMULSION mode as described above.

Note: The test for "the fluid has an emulsion viscosity" is that the mixed
liquid viscosity has to be at least 1% greater than the maximum of the oil
and water phase viscosities. The test will therefore give a positive result
for any emulsion option, that is, it is not restricted to Woleflin and user-
supplied-table options

HYDRATECALC= Controls calculation of Hydrate Formation Temperature (HFT) in

compositional models. HFT optionally appears in the profile plot file, but
calculating it results in a large increase in CPU time required, hence it is
not enabled by default. Can be set to OFF or ON.

WAXCALC= Controls calculation of Wax Formation Temperature (WFT or Cloud Point)

in compositional models. WFT optionally appears in the profile plot file,

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but calculating it results in a large increase in CPU time required, hence it

is not enabled by default. Can be set to OFF or ON.

ASPHALTCALC= Controls calculation of Asphaltene Formation Temperature (AFT) in

compositional models. AFT optionally appears in the profile plot file, but
calculating it results in a large increase in CPU time required, hence it is
not enabled by default. Can be set to OFF or ON.

ALHANATI= Controls calculation of Alhanati Gas Lift Instability (GLI) criteria. GLI
criteria can be calculated for wells that have gas lift, but the calculation
requires a number of additional data items that are not needed for any
other purpose. Can be set to ON or OFF, default OFF.

ON: GLI criteria calculation is requested. If the additional data items are
available, the calculated criteria values will be written to the system plot
file; otherwise, diagnostic message(s) will be issued to enumerate the
missing data. To remove the messages, you can either supply the
missing data, or switch the calculation OFF.

OFF: GLI criteria will not be calculated, and diagnostic messages will not
appear.

GLMAXMASS= Specifies a maximum gas lift rate limit, in mass ratio terms. Unlimited gas
lift in a network branch can lead to the existence of multiple network
solutions, so the network may converge to an unwanted solution, where a
well produces nothing but lift gas. This subcode specifies the maximum
mass rate of gas that can be injected, as a ratio with the current
production mass flow rate. Its purpose is to prevent the well from
converging at the unwanted solution. It is only applied in a network model.
The default value is 0.2, thus the gas lift mass rate will be limited to 20%
of the current production mass flowrate in a network model.

GLMAXGLR= Specifies a maximum gas lift rate limit as a GLR. Unlimited gas lift in a
network branch can lead to the existence of multiple network solutions, so
the network may converge to an unwanted solution, where a well
produces nothing but lift gas. This subcode specifies the maximum rate of
gas that can be injected, as a volume ratio with the current production
stock-tank liquid flow rate. Its purpose is to prevent the well from
converging at the unwanted solution. The default value is infinite. A
sensible value for this limit is in the range 1000 to 2000 scf/sbbl. Units are
scf/sbbl or sm3/sm3.

FMMINTEMP= Specifies the minimum temperature used in fluid property flash

calculations. Units are F or C. The default value is 0K (absolute zero).
However some flash packages will refuse to produce results at
temperatures higher than this. For example, NIST Refprop requires
temperature to be above -100F. This keyword can be used to limit the
temperature range for the iterative PH flash algorithm when calculating
temperature from enthalpy. If the temperature is out of the flash package
range, you get an error message stating this. Only the minimum

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temperature the package will allow is reported. Use this keyword to set
the equivalent minimum temperature. A similar keyword FMMAXTEMP=
is used for the maximum temperature.

SYSTEMTYPE= Specifies if the branch or model represents a production well or an

injection well. Usually there is no ambiguity between these and it is
unnecessary for this to be explicitly stated by the user. However
sometimes the model is open to interpretation either way. If it makes a
difference, the user can supply an override value here. One example
where this can be important is the production of VFP tables for a flowline
branch. If there is no elevation difference between the branch start and
end, then the system type is moot. However, VFP tables must be written
with VFPPROD for a production branch and VFPINJ for an injection
branch. Also, a VFPPROD allows sensitivity on GLR, Watercut and
Artificial lift, and these must be provided in the table. Can be set to
PRODUCER or INJECTOR. If omitted, PIPESIM will determine the
system type, based on overall branch elevation change and the
location(s) and numbers of completions it contains.

LAYERINJECT= Controls the ability for reservoir layers to operate in injection mode. By
default layers are able to accept fluid injection if the tubing pressure
exceeds the layer pressure. Setting this option to NO makes all layers to
refuse to allow injection; if the tubing pressure exceeds the layer
pressure, the layer's flowrate will be zero. Can be set to YES or NO,
default is YES.

ELIQLOADING=, Specifies the correction factor to be applied to Turner's general equation

LLE= in liquid loading (p.307) calculations. Minimum is 0.1, maximum is 10.0
and the default is 1.2.

LLVELOCITY= Controls which Gas Velocity is used in liquid loading (p.307) calculations
to get the Critical Gas Rate (CGR). Choices are: VSG, VM, VG, and EQN,
whose meanings are:

VSG: The Superficial Gas Velocity is used. This yields a result that is
closest to that obtained by a hand calculation (from which it differs
because the fluid phase behaviour is predicted by the selected fluid PVT
package). However it is insensitive to Liquid Volume Fraction (LVF), and
under some conditions can predict a CGR that reduces when LVF
increases. This is the default.

VM: The fluid Mean Velocity is used (i.e. the average of the gas and liquid
phase velocities, the velocity at no-slip conditions). This yields a
conservative result, i.e. a CGR somewhat higher than that obtained with
VSG. Its main advantage is that the CGR it calculates should increase
with VFL.

VG: The Actual Gas Velocity is used. VG is calculated by the selected

multiphase flow correlation, thus in principle it ought to be the most
accurate choice. The CGR it calculates is generally the largest, or most

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conservative. However it will always be considerably larger than a hand

calculated result, and will be strongly affected by the choice of multiphase
flow correlation.

EQN: The gas velocity is calculated from the Stock-tank gas flowrate
using the equation: Vg = Qgas* (T+460) * Z / (3.067 * P * A) . This allows
the resulting CGR to be verified by hand calculation. However, it takes no
account of the fluid PVT behaviour.

LLANGLEMIN= or Maximum pipe angle for liquid loading calculations. The Turner equation
ALIQLOADING= assumes vertical or near vertical uphill flow. As deviation increases, so
the equation becomes less applicable; so it makes sense to restrict it to
pipe sections where the local deviation angle is a reasonable
approximation to the vertical. By default the limit is 45 degrees. It can be
set to any vertical deviation angle between 0.1 and 90 degrees. When the
Pipe is deviated greater than this, the calculation is not performed.

LLFRNLIQMAX= Maximum Liquid Volume Fraction (LVF) for liquid loading calculations.
The Turner equation assumes a continuous gas phase with small
dispersed liquid droplets entrained in it. As LVF increases, so the
equation becomes less applicable, and it makes sense to restrict it to pipe
segments where the LVF is consistent with the description liquid droplets
in a continuous gas phase. By default the limit is 0.1. It can be set to any
value between 0 and 1. When the LVF is greater than this, the calculation
is not performed.

RAMEYTIME= Specifies the length of time a well has been operating when HEAT
(p.623) subcode RAMEYMETHOD is invoked for a piece of tubing.
Minimum is 0 hour and default is 168 hours. The minimum recommended
value for RAMEYMETHOD=LARGETIME is 168 hours.

UFACTOR= Specifies a multiplier for all supplied (not calculated) U-values in heat loss
calculations. U-values are entered on the numerous NODE statements
that specify the geometry of the pipe and tubing of the branch. This
multiplier is applied to all of these before they are used in calculation of
heat transfer and temperature change of the fluid. This is useful if you
want to sensitize on the overall effective U-value for the branch. Note it is
NOT used if the U-value is calculated. Default is 1, allowed range is 0 to
1e10.

SEPMASSCALC= Method for calculating the flowrate of fluid separated when a

compositional fluid passes through a separator. Can be set to TABLE or
FLASH, default TABLE.

MPBOOSTROUTE= Specifies an override thermodynamic route to adjust the fluid temperature

and enthalpy at the discharge of any multiphase booster. Can be set to
ISENTHALPIC, ISOTHERMAL, or NONE.

FCVSHUTMODE= Shut-in behaviour for Flow Control Valves (FCVs). An FCV can be
specified with a table of fixed bean areas, and a flowrate limit. PIPESIM

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enforces the flowrate limit by selecting the largest area that results in a
flowrate at or below the limit. However, it may happen that the smallest
bean area in the table is too large to enforce the limit. In this case the
value specified on this subcode is used to select a mode of behaviour.
Can be set to OPEN, SHUT, or EXACT, whose meanings are:

OPEN: The smallest non-zero bean area is used, so the flowrate will
exceed the specified limit.

SHUT: The valve will be set to the closed position, so the flowrate will be
zero.

EXACT: The flowrate will be set to the limit, and the required bean area
will be calculated and reported.

RETAINHEEL= Can be set to YES or NO. If YES, selects the Multiple Completion
algorithm for the well's iterative solution, regardless of the number of
completions the well may contain. The default is NO.

IFC= An override on the state of the IFC= subcode on the HEAT statement.
Can be set to INPUT or CALC; if set to CALC, this overrides any
subsequent HEAT statement that may set it to INPUT.

SLUGREGIME= Specifies the Flow Regimes that allow slug length calculations.

NOSLUGREGIME= Specifies the Flow Regimes that do not allow slug length calculations.

MINSEGLEN= The minimum segment length to be used when pipe sections are
subdiivided. (ft or m).

OPPOINTS= Controls the explicit generation of Operating Points in the Nodal Analysis
operation. Can be set to YES, to generate them, or NO, to omit them.
This subcode is also available on the NAPLOT (p.655) statement; it is
duplicated here so that it can be used without the additional effects that
occur when NAPLOT is used.

DOWNHILLPREC= Downhill Pressure Recovery method. When a two-phase fluid flows in a

pipe that is angled downhill, the liquid phase usually flows faster than the
gas. Sometimes the liquid flows downhill at its terminal, or critical,
velocity, whereby its speed is limited by friction against the pipe walls, and
there is no net pressure gain due to the elevation change. This is often
called slack flow conditions. The multiphase flow correlations will not
usually model slack flow, so this keyword allows a choice of methods for
simulating how pressure recovery is modelled in downhill pipe sections,
and will affect the value for Elevation Pressure gradient:

CORR or NORMAL: Downhill pressure recovery is modelled by the

selected multiphase flow correlation. The exact calculations performed
will depend on the selected correlation. Typically, they use some mixture

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fluid density based on the calculated liquid holdup. This is the default
method.

GAS: Downhill pressure recovery is calculated using the density of the

gas phase alone. This option assumes the liquid will segregate into a
stream at the bottom of the pipe and flow at its terminal velocity, similar to
open-channell flow. N.B. This option is applied only when the in-situ liquid
volume fraction is less than 0.8; at higher values, the CORR method is
used.

NONE: Downhill Pressure Recovery is disabled. The elevation pressure

gradient is set to zero in downhill pipe sections.

SSMETHOD= Segment Solution Method. The pipe and tubing objects (for example,
flowlines, risers, tubing strings, and distributed completions) are divided
into computational elements called segments. Each segment is simulated
one after another in a so-called marching algorithm. This subcode allows
a choice of segment length selection and solution method. (Note: To
activate this subcode requires a specific debug flag. To get the debug
flag, please contact Schlumberger.) Currently, the following choices are
available:

1: This is the Original method, which uses predefined, fixed segment

lengths. The segment length is defined using the SEGMENTS= and
MAXSEGLEN= keywords. (See above.) All pressure drop, heat transfer,
and fluid inflow calculations are based on this segment length. If the
segment convergence algorithm fails, then the entire section (NB, not just
the current segment) is subdivided into double the previous number of
segments and the calculation is restarted from the start of the section.

2: This is the Gradient method, which uses values of gradients to select a

suitable segment length at the position in the system being simulated.
The gradients considered are Pressure, Temperature, Enthalpy, and
Reservoir Fluid Inflow. These are expressed as a change in the quantity
per unit length of pipe. For example, pressure gradient is expressed as
psi/ft or bar/m, temperature gradient is expressed as F/ft or C/m, and so
on. Each gradient is evaluated at the segment boundaries. For each
gradient, a user-specifyable tolerance exists which, when divided by the
gradient, yields a segment length. The minimum of these segment lengths
is used as the length of the next segment in the simulation. (For reasons
of backwards-compatability, the values of SEGMENTS= and
MAXSEGLEN= keywords are also honoured in this method.) If the
segment convergence algorithm fails, the segment length is halved and
the calculation is restarted. This is known as a "chop". NB, unlike the
original method, the chop applies only to the current segment and not to
the entire section.

DPRTOL= Delta Pressure Relative Tolerance is a tolerance used by the Gradient

method. This is a unitless ratio of pressure expressed as (PIN-POUT)/

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PIN, where PIN is the segment inlet pressure, and POUT is the segment
outlet pressure. The segment length for the next segment is calculated as
DPRTOL*PIN/PGRAD, where PGRAD is the pressure gradient (DP per
length) from the previous segment. The default is 0.04. Smaller values will
result in smaller, and therefore more, segments.

DPATOL= Delta Pressure Absolute Tolerance is a tolerance used by the Gradient

method. This is a value of Delta Pressure (DP) in units of psi or Bar. The
segment length for the next segment is calculated as DPATOL/PGRAD,
where PGRAD is the pressure gradient (DP per length) from the previous
segment. The default is 1 psi. Smaller values will result in smaller, and
therefore more, segments.

DTATOL= Delta Temperature Absolute Tolerance is a tolerance used by the

Gradient method. This is a value of Delta Temperature (DT) in units of
Farenheit or Celcius. The segment length for the next segment is
calculated as DTATOL/TGRAD, where TGRAD is the temperature
gradient (DT per length) from the previous segment. This ensures that the
temperature change across any segment is never more than DTATOL.
The default is 5 F. Smaller values will result in smaller, and therefore
more, segments.

DHATOL= Delta Enhtalpy Absolute Tolerance is a tolerance used by the Gradient

method. This is a value of Delta Enthalpy in units of BTU/lb or KJ/Kg. The
segment length for the next segment is calculated as DHATOL/HGRAD,
where HGRAD is the enthalpy gradient (DH per length) from the previous
segment. This ensures that the enthalpy change across any segment is
never more than DHATOL. The default is 10 btu/lb. Smaller values will
result in smaller, and therefore more, segments.

DPGTOL= Delta Pressure Gradient Tolerance is a tolerance used by the Gradient

method. This is a unitless ratio of pressure gradients that is used to
validate the results of the current segment's DP calculation. The pressure
gradient in the current segment is compared to the previous segment. If
the difference is greater than this tolerance, the segment is "chopped", or
divided into two smaller segments. This allows the algorithm to identify
and recover from a pressure gradient discontinuity, such as what is often
encountered in multiphase flow correlations. The default value is 0.05.
Smaller values will result in smaller, and therefore more, segments.

DTGTOL= Delta Temperature Gradient Tolerance is a tolerance used by the

Gradient method. This is a unitless ratio of temperature gradients that is
used to validate the results of the current segment's DT calculation. The
temperature gradient in the current segment is compared to the previous
segment. If the difference is greater than this tolerance, the segment is
"chopped", or divided into two smaller segments. This allows the
algorithm to identify and recover from a temperature gradient
discontinuity, such as what is caused step-changes in ambient

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temperature. The default value is 0.25. Smaller values will result in

smaller, and therefore more, segments.

DQGTOL= Delta Flowrate Gradient Tolerance is a tolerance used by the Gradient

method. This is a unitless ratio of flowrates and/or flowrate gradients. It is
relevant only in distributed completions and horizontal wells. It is used in
the following ways:

The segment length for the next segment is calculated as DQGTOL/

QGRAD. QGRAD is the inflow rate gradient that is calculated from
QI/QP/Segl, where QI is segment inflow rate (the rate entering the
segment from the reservoir), QP is segment production rate (the rate
entering at the segment inlet), and Segl is segment length. These
values are all from the previous segment. This ensures the flowrate
change across any segment, when expressed as a ratio, is never
more than DQATOL.
Used to validate the results of the current segment's Delta Flowrate
(DQ) calculation. The inflow gradient in the current segment is
compared to the previous segment. If the difference is greater than
this tolerance, then the segment is "chopped", or divided into two
smaller segments. This allows the algorithm to identify and recover
from an inflow gradient discontinuity, such as what is caused by step-
changes in reservoir properties ( for example, pressure, and step-
changes in reservoir fluid properties.)
The default value is 0.2 .Smaller values will result in smaller, and
therefore more, segments.

MEMCHOPFACTOR= Memory Chop factor is a factor used by the Gradient method. When a
previous segment length was set as a result of a "chop" (see above), it is
desirable to restrict the speed at which subsequent segments are allowed
to grow. The maximum segment length for the current segment is limited
to the length of the previous segment multiplied by this factor. The default
value is 2.

8.3.7 RATE: Fluid Flow Rate Data

Main-code: RATE
RATE allows flow rate to be defined for all fluid types.
For both Blackoil and Compositional fluids, a flow rate may be defined in volumetric terms using
the GAS= or LIQ= subcodes, or in mass terms using MASS=. A mass rate refers to the total
stream without regard for which phases may exist. A volumetric rate refers only to the phase it
specifies, and is always measured at stock-tank conditions. The other phase may or may not be
present at stock-tank conditions, depending on the fluid definition, but it is never included in the
specified flowrate.
Stock tank conditions are 1.013 bara and 15.6 oC, or 14.696 psia and 60 oF.

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LIQ= Gross liquid flow rate at stock tank conditions (sm 3/d or STB/D). The liquid phase
includes both hydrocarbon and aqueous phases (oil and water), but not gas.

GAS= Gas flow rate at stock tank conditions (MMsm 3/d or MMscf/d).

MASS= The total mass flow rate (kg/s or lb/s). Note this defines the mass flow rate of the
total stream, in contrast to LIQ= and GAS=, which defines a flow rate for one
phase only.

MULTIPLIER= Factor to mix or split a previously defined flow rate by a fixed ratio. Supplied value
must be greater than zero. Valid only within the system profile, that is after the
PROFILE or the first NODE statement.

ADDLIQ= Quantity to be added to a previously defined stock-tank liquid flow rate. Supplied
value may be greater or less than zero. (sm 3/d or STB/D). Valid only within the
system profile, that is after the PROFILE or the first NODE statement. See also
the INJFLUID. (p.609) statement.

ADDGAS= Quantity to be added to a previously defined stock-tank gas flow rate. Supplied
value may be greater or less than zero. (MMsm 3/d or MMscf/d). Valid only within
the system profile, that is after the PROFILE or the first NODE statement.. See
also the INJFLUID and INJGAS. (p.609) statements.

ADDMASS= Quantity to be added to a previously defined total mass flow rate. Supplied value
may be greater or less than zero. (kg/s or lb/s). Valid only within the system
profile, that is after the PROFILE or the first NODE statement.. See also the
INJFLUID. (p.609) statement.

ADDER= Quantity to be added to a previously defined flow rate (may be greater or less than
zero). Note The units of ADDER= are inferred from the type of flowrate as
originally defined, viz. Gas, Liquid or Mass, and the system of unit conversions
currently in force, that is Engineering or SI. ). Valid only within the system profile,
that is after the PROFILE or first NODE statement.

WCUT= Obsolete: see the BLACKOIL. (p.633) statement.

GWR= Obsolete: see the BLACKOIL. (p.633) statement.

WGR= Obsolete: see the BLACKOIL. (p.633) statement.

GLR= Obsolete: see the BLACKOIL. (p.633) statement.

GOR= Obsolete: see the BLACKOIL. (p.633) statement.

LGR= Obsolete: see the BLACKOIL. (p.633) statement.

OGR= Obsolete: see the BLACKOIL. (p.633) statement.

A Blackoil fluid must define its stock-tank volume phase split on the BLACKOIL statement, using
the subcodes: GLR=, GOR=, OGR=, or LGR=, and WCUT=, WGR= or GWR=. For historical

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reasons these subcodes are also available on the RATE statement. However, since RATE applies
to all types of fluid (Compositional and Steam in addition to Blackoil), it is natural to assume that
GLR= and so on behave similarly. Alas they do not, they apply to black oil fluids only. You are
strongly encouraged to refrain from using these subcodes on RATE; use them on the BLACKOIL
or COMPOSITION. (p.648) statement instead.

8.3.8 ITERN Iteration Data (Optional)

Allows the System Outlet Pressure to be specified.
Because PIPESIM performs a heat balance simultaneously with the pressure loss calculations, it is
necessary for the calculation procedure to begin at the pipeline source and proceed in the direction
of flow. A problem with a fixed delivery pressure therefore requires an iterative solution. The
program will iterate on the user's specified Control variable, which can be System Inlet Pressure,
Flow Rate, or a user-defined variable, as specified with the TYPE subcode.
The ITERN main-code should appear in the initial part of the input file, i.e. before the PROFILE or
NODE statements.
Main-code: ITERN

POUT= The required System Outlet Pressure (psia or Bara).

TYPE= Specifies the identity of the Control variable ('guess') to be changed ('guessed') in
order to match the specified outlet pressure. May be one of:

PRESSURE or IPRESSURE: The system inlet pressure.

GFLOW: The system gas flow rate.

LFLOW: The system liquid flow rate.

MFLOW: The system mass flow rate.

PGEN+: A User-specified variable, as defined with the special symbol ?XITERN.

See note 1 below. Outlet pressure is expected to increase as ?XITERN
increases.

PGEN-: A User-specified variable, as defined with the special symbol ?XITERN.

See note 1 below. Outlet pressure is expected to decrease as ?XITERN
increases.

XEST= Initial Estimate of the Control Variable ('guess') to be changed ('guessed') in

order to match the specified outlet pressure. The units for this is dependent on
the TYPE. For example: = Estimated inlet pressure (bara or psia) if TYPE=PRES.
= Estimated mass flow rate (kg/s or lb/s) if TYPE=MFLOW. = Estimated gas flow
rate (kg/s or lb/s) if TYPE=GFLOW.= Estimated liquid flow rate (kg/s or lb/s) if
TYPE=LFLOW

PTOL= Allows control over the Outlet Pressure Tolerance. The program will iterate until
the difference between the calculated outlet pressure and the pressure specified
in the POUT sub-code is less than outlet pressure tolerance. The user can

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specify the required tolerance, as a percentage, by use of the PTOL sub-code. If

PTOL is not specified, the program will use a value of 1% or 1 psi, whichever is
the smaller.

XTOL= Allows control over the Control Variable ('guess') Tolerance. This is important if
the system being simulated is prone to becoming 'ill-conditioned' (i.e., when a
small change in guess results in a disproportionately large change in outlet
pressure). Under such conditions it may take the iterative procedure many more
iterations than usual to calculate a solution to within the outlet pressure tolerance
(if it can manage it at all). Also, the user may not be interested in such accuracy,
because for example, s/he may only be able to control the guess to within fairly
coarse limits. XTOL exists to stop the program performing numerous
unnecessarry iterations, by terminating the iterative procedure when two
successive guesses fall within the specified tolerance. The user can control the
value of this tolerance, as a percentage, with the XTOL sub-code. The default
value for XTOL is 1.0E-4 %.

XMIN= Specifies a lower bound for the Control variable. If the iterative procedure
attempts to guess below this limit, the guess will be reset to the limit. If this shows
the required answer lies below the limit, the iterative procedure will terminate with
a suitable diagnostic, and case output will be written.

XMAX= Specifies an upper bound for the Control variable. If the iterative procedure
attempts to guess above this limit, the guess will be reset to the limit. If this
shows the required answer lies above the limit, the iterative procedure will
terminate with a suitable diagnostic, and case output will be written.

LIMIT= Specifies the maximum allowed number of iterations. The default value is 40 and
the maximum is 100. If a solution has not been obtained within this number of
iterations, the iterative procedure will be terminated, and results printed for this
case with the current (i.e. last guessed) value of input pressure or flow rate.

SCREEN Gives node by node output on the user's terminal for each iteration. If this sub-
code is omitted, the only output that appears on the terminal during the iteration
procedure is one line for each iteration, summarizing the iteration progress so far.
Note this sub-code has no effect if PIPESIM is running in batch mode.

OPWI Enables OPWI ("Output Printing While Iterating") mode. Node-by-node output for
the system profile is written to the output files during every iteration. Normally,
this output would be suppressed until the iterative procedure has converged. This
is useful for debugging the iterative procedure.

LASTANSWER Using this sub-code, the guess from the previous case is used as an estimate for
the next case. Thus the value which you have set for XEST will only be used in
the first case.

CFCMODE= Controls the iteration routine's interaction with a system containing a Choke in
critical flow. Can be set to ON or OFF, default is ON. In the ON state, a choke in
critical flow will terminate the iterative procedure early. Thus is usually beneficial,
since the converged solution is likely to require the choke to be in critical flow.

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However when TYPE=PGEN, and the Control variable is applied downstream of

the choke, an early iterative termination will prevent correct convergence, so the
OFF state is preferable.

CFCSOLN= Controls the post-convergence behavior when a case has converged with a
choke in critical flow. Can be set to ON or OFF, default ON. In the ON state, a
further round of iteration is performed, to converge on the pressure downstream
of the choke that allows the specified system outlet pressure to be achieved. In
the OFF state, this further round is omitted, thus the system outlet pressure will
be higher that the one specified.

TITLE= Specifies the title to be used for the Control variable in the system and profile plot
files.
TITLE keyword is working only when TYPE = PGEN+ or PGEN-.

Note: When TYPE=PGEN+ or PGEN- is used, the iterations will guess the value of a user-defined
variable in order to achieve the specified outlet pressure. The variable is called ?XITERN, and the
user must arrange that this name appears at a suitable point in the input file as the value of a
subcode that will have an effect on the system outlet pressure. This is how PIPESIM implements
its user variable feature. PGEN is an acronym for "Pseudo-GENeral iterative mode" (it is not truly
general since it converges only on outlet pressure).

8.3.9 INLET System Inlet Data

Main-code: INLET
The INLET statement is optional. It is useful if the system contains no reservoir completions, and is
typically used to define a Generic Source at the start of a surface pipeline model. If supplied, must
appear before the PROFILE or first NODE statement.

TEMPERATURE= The temperature of the fluid entering the system at the System inlet. (oC or
oF). If omitted, the inlet fluid is assumed to enter the system at the ambient

temperature as defined on the first NODE statement.

PRESSURE= The System inlet pressure (bara or psia). Not required if the inlet pressure is
to be determined using the iteration option (see the ITERN main-code), or if
the reservoir pressure is supplied with a well inflow performance option .

ENTHALPY= or H= As an alternative to temperature, the inlet fluid enthalpy can be supplied;

PIPESIM will then calculate its temperature. (btu/lb or Kj/kg)

QUALITY= As an alternative to Temperature or Enthalpy, and only if the fluid is specified

as Steam, the inlet steam quality can be supplied. Quality is the steam mass
fraction vapour: must be in the range 0 to 1.

8.3.10 PRINT Output Printing Options (Optional)

Main-code: PRINT

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PIPESIM offers a wide choice as to the amount of printed output. The PRINT maincode controls
most of the available options, which can be divided into 4 behavioral categories:
Per-case Output pages
Subcodes such as PRIMARY and AUXILIARY control the production of complete pages
which are repeated for as many cases as desired (as specified on CASES=). Pages are
typically 132 characters wide and usually have (at least) one line for every node in the
system, or otherwise have about 60 lines of relevant data. These page selections should
be made at the start of the job or between cases.
Attributes
Subcodes such as SEC and TITLES affect the way data appears on output pages, e.g. by
adding something to an existing page or changing the representation of the data on the
page. Page attributes are best selected at the start of the job and not changed thereafter.
Point reports
Subcodes such as SPOT and PHASE SPLIT control the production of localized reports
dedicated to an aspect of the system at a chosen position, or to a piece of equipment
within it. Reports are requested by supplying the PRINT statement, with the required
subcode, at the position within the system profile where the information is required. They
are written to one of the selected output pages (as specified on REPORTS=) and appear
for as many cases, and as many positions, as desired.
One-off Output pages
Subcodes such as SYNTAX, ECHO and NARESULT control the production of single page
reports that appear only once per job. These page selections should be made at the start
of the job.
Except where noted, the options can appear without a value, in which state a value of ON will be
assumed. Values of OFF or ON can be provided if desired

Per-case output page options

The per-case output page options are as follows:

Default

PRIMARY The primary output page consists of a line for each node, containing ON
node distance and elevation, pipe angle, fluid pressure, temperature
and mean velocity, friction and elevation pressure drop, phase
flowrates, phase densities, and Flow Regime pattern.

AUXILIARY The Auxiliary output page consists of a line for each node, containing ON
node distance and elevation, , phase superficial velocities, mass flow
rates and viscosities, overall Reynolds number, Liquid volume fraction,
Liquid Holdup fraction, Flowing Liquid Watercut, total enthalpy, Erosion
velocity, Erosion rate, Corrosion rate, Hydrate sub-cooling Delta
Temperature, Liquid loading Velocity ratio, and segment iteration
counters. For compositional fluids 3 additional columns hold table
interpolation diagnostics.

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HORWELL The Horizontal Well output page consists of a line for each node, OFF
containing: node distance and elevation; Reservoir and Wellbore
Pressure; Reservoir, Inflow, and Wellbore temperature; Inflow Joule-
Thomson Coefficient; Distributed Productivity Index; Wellbore flowrate;
Specific inflow (i.e., flowrate between wellbore and reservoir, per unit
length); Friction Gradient; Reservoir and Wellbore GLR and Watercut;
and Liquid Viscosities for Reservoir, Inflow and Wellbore. The Horwell
output is restricted to the portion of the system that is defined to be a
distributed completion (see the COMPLETION (p.567) statement).

FLUID The Input Fluid data page shows the definition of the Blackoil or ON
Compositional fluids used as input to the case (fluid definitions resulting
from mixing or separation can be obtained with the SPOT=FLUIDSPEC
subcode, see below). A compositional fluid is specified mostly by its
component list and their respective molar flowrates, along with other
data controlling the attributes of the selected PVT package and table
interpolation control data. A blackoil fluid is specified by a number of
correlation choices and tunable values. This page also specifies fluid
input flowrates.

PROFILE The profile and Flow Correlations output page consists of a line for ON
each node, containing node distance and elevation, pipe section
length, cumulative length, ambient temperature, input U-value, node
TVD and MD, and fluid definition detail. In addition the selected
Horizontal, Vertical, and Single Phase flow correlation choices will be
echoed, along with pertinent options currently in force.

ITERATION The case-level iteration progress log page. This page will only appear if ON
the case is iterative, i.e. the Outlet Pressure has been specified. Data is
one line per iteration plus information on how each iteration's guess is
computed. Errors encountered during iteration will also appear on this
page.

INFLOW Details of the selected Inflow Performance Relationship (IPR) appear OFF
on this page. Data includes relevant input values and all derived or
computed values and answers. If the model contains multiple
completions, each will have its own section on this page.

HINPUT The heat Transfer Input data page has a line for each node showing OFF
the input data for detailed heat transfer calculations across multiple
layers of pipe and coatings. Values are: node distance, wax pipe and
coatings thicknesses, wax pipe and coatings conductivities, burial
depth, ambient fluid velocity, and ambient temperature.

HOUTPUT The Heat Transfer Output page has a line for each node showing the OFF
results of heat transfer calculations. Values are: Node distance, fluid
temperature and enthalpy, Overall Heat Transfer Coefficient (HTC),
Fluid film HTC, wax pipe and coatings HTCs, soil/ambient HTC, and
text description of burial configuration. (All HTCs are referenced to the

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Pipe (Note: not coatings) outside diameter, this can be changed with
the HTCRD= subcode of HEAT (p.623) ).

SLUG The Slug output page has a line for every node showing the results of OFF
slugging calculations. Values are: node distance and elevation, mean
slug length and frequency, 1 in a thousand slug length and frequency,
1 in a hundred slug length and frequency, 1 in ten slug length and
frequency, PI-SS, and flow regime pattern.

GLINPUT The gas Lift Input data page has a line for every gas lift valve in the OFF
system, showing the input data supplied for it.

Note: The lines in this page appear in order of depth from the
wellhead, i.e. shallowest at the top of the page, deepest at the bottom;
this is the opposite to the direction of fluid flow in a gas lifted well, so
this page will usually be in reverse order when compared with all other
pages.

Values are: Valve TVD and MD, valve port diameter, Cv, test rack
pressure, Ap/Ab, Throttling factor, valve type, and valve operation
mode. (To request this page be produced in the same direction as the
rest of the output pages specify GLINPUT=*FWD). N.B. The values in
this page are only useful when MODE=SIMULATE has been specified
on a GASLIFT (p.603) statement.

GLOUTPUT The Gas Lift Output page has a line for every gas lift valve in the OFF
system, showing all calculated values for the valve. The lines are
ordered shallowest first as for the GLINPUT page (see above). Values
are: valve MD, test rack dome pressure, valve operating temperature at
depth, dome pressure at depth, casing and tubing pressure at depth,
valve opening and closing pressures, DP across valve, Orifice gas
flowrate, throttled gas flowrate, actual gas flowrate, and text description
of valve operating status. (To request this page be produced in the
same direction as the rest of the output pages specify
GLOUTPUT=*FWD). N.B. The values in this page are only useful when
MODE=SIMULATE has been specified on a GASLIFT (p.603)
statement.

3PHASE For Shell clients only, this page has a line for every node showing three OFF
phase flow values as calculated by the SRTCA 3-phase flow
correlation. The 3-phase SRTCA (p.561) correlation must be the
selected multiphase flow correlation for this page to appear.

ARTSLUG For Shell clients only, this page has a line for every node showing the OFF
results of Artificial Slug calculations. The Artificial Slug SRTCA
(p.561) correlation must be the selected multiphase flow correlation
for this page to appear.

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WAX this page has a line for every node showing Wax Deposition input data, OFF
calculations and results.

CUSTOM=(x,x,x) The Custom output page allows you to create your own page of output OFF
organized one node per line. Values appear in columns on the page
and are chosen from the set of Profile Plot variables. Identifiers are
provided as a multiple value set (p.515). An up-to-date list of the
available identifiers can be obtained using the SYNTAX subcode of
PLOT (p.548). Each column will be 10 characters wide plus one
space, so 11 columns will conveniently fit on a standard width page. If
desired you can specify up to 40 identifiers, but be aware this will give
an output page that is 440 characters wide.

INDATA This is a combination of PROFILE and FLUID. ON

EXTRA= The Extra output page allows installation-specific data to be printed. OFF
This subcode requires an equated value. If the value TGRAD is
provided, the result is a page containing a line for each node with
temperature Gradient information from heat transfer calculations. Other
values are installation-specific..

Attributes
The Attributes are:

Default

TITLES Print case titles on job summary output ON

SEGMENTS Print segment data. The pipe or tubing section between each node is OFF
sub-divided for computation purposes into a number of segments (as
controlled by OPTIONS SEG= (p.525) and MAXSEGLEN= (p.525) , and
the accuracy needs of the calculation at each point). With this subcode
selected, each segment will have its own line of output in all the per-case
output pages; without it, the output will be restricted to each node.

SEC Print details of pressure drops caused by Sudden Expansion and ON

Contraction. When Pipe ID changes, the junctions between the non-
matching diameters are assumed to be straight-edged, and to cause
pressure reduction due to turbulence effects. With this subcode enabled
a one-line message will be written to the primary output where SEC
losses are greater than a specified threshold value (as defined with
OPTIONS SECLIM=).

CASES= Specifies the number of cases to print. This subcode requires a numeric 1
value. The selected per-case output pages will appear for as many
cases as are specified. In Nodal Analysis jobs, the value applies to both
the inflow and the outflow cases, thus the actual number of cases printed
will be double.

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REPORTS= Specifies the name of the per-case output page to receive point report PRIMARY
output. Any of the per-case page names can be provided to direct the
point reports to the specified page. In addition the value DEDICATED
specifies that an additional page be created to hold them instead.

Point report subcodes

The point report subcodes must appear on a PRINT statement, positioned within the system
profile, at the position where the values are required. If multiple reports are required at any point a
separate PRINTstatement must be used for each report. Each report is written to the output page
chosen with the REPORTS= subcode above. Reports vary in length between 6 and 200 lines.
They are:

SPOT=STPROPS Fluid Stock-tank properties: phase flowrates and physical properties are
reported at stock-tank conditions, viz. 14.696 psia, 60 F.

SPOT=FLPROPS Fluid flowing properties: phase flowrates and physical properties are
reported at the current pressure and temperature

SPOT=MPFLOW Multiphase Flow values: Fluid properties, pipe dimensions, and calculated
values with particular relevance to multi-phase flow calculations. See note
1.

SPOT=SLUG Slug flow values: fluid properties and calculated values with relevance to
slug size calculations. See note 1.

SPOT=SGLV Sphere-Generated Liquid Volume values: input data and results from
SGLV calculations. See note 1.

SPOT=HTINPUT Heat Transfer Input values: fluid properties, pipe and coatings thicknesses
and conductivities etc. as used in heat transfer calculations. See note 1.

SPOT=HTOUTPUT Heat transfer output and calculated values: heat transfer coefficients,
coating layer temperatures, film coefficients and dimensionless groups.
See note 1.

SPOT=FLUIDSPEC Fluid specification values. The complete set of values that define the fluid.
A compositional fluid is specified mostly by its component list and their
respective molar flowrates, along with other data controlling the attributes
of the selected PVT package and table interpolation control data. A
blackoil fluid is specified by a number of correlation choices and tunable
values.

SPOT=ACVALUES 'Accululated' values. These are values that accumulate over the length of
the system, for example total liquid holdup, total friction DP, total pipeline
volume, etc.

SPOT=SHELL Shell clients only, a report specific to the SRTCA slugging and 3-phase
flow correlation. See note 1.

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SPOT=COMPLETION Distributed or multipoint completion values: reservoir inflow, drawdown,

Distributed P.I., Skin values, relevant pipe dimensions, fluid phase
flowrates and physical properties. See note 1.

USPOT=(x,x,x) Custom spot report: allows you to create a report of values of your choice.
Values are chosen from the set of Profile Plot variables. Identifiers are
provided as a multiple value set (p.515). An up-to-date list of the available
identifiers can be obtained using the SYNTAX subcode of PLOT. (p.547)

MAP Print the flow regime map at the current position. A flow regime map is
specific to each choice of multiphase flow correlation, and is affected by
fluid properties, pipe dimensions, and (critically) pipe angle. Since the map
must be requested at a node position, please note that the pipe angle (and
perhaps other dimensions) may change across the selected node. The
dimensions and angle used to generate the map are those of the
Upstream pipe section. The fluid properties used are those at the current
pressure and temperature. If the map is requested at the start of the
profile, pipe dimensions and angle are taken from the first pipe section.

PHASESPLIT Print a Phase Split report, for compositional fluids only. This lists the molar
flowrates of all components in the feed stream and in the phases that exist
at that pressure and temperature. Additional phase properties such as
density, viscosity etc. are also printed.

PRESSURE= Pressure value for use with PHASESPLIT; if provided, will be used instead
of the system current pressure. (psia or Bara)

TEMPERATURE= Temperature value for use with PHASESPLIT; if provided, will be used
instead of the system current temperature. (F or C)

PHASENV= Produce a plot file containing the Phase Envelope (and other lines) for the
current compositional fluid. Note this option produces no printed output;
instead, a plot file will be created, named with an 8-character code known
as the handle, and with an extension of .ENV. This file can be processed
by the plotting post-processor PSPLOT to display the phase envelope.

N.B., you do not need to know the name of the file to plot the phase
envelope. From the GUI, select Profile Plot, then select Series, and
choose axes of pressure and temperature. The phase envelope file(s) will
be automatically processed along with the model's profile plot data, so you
should see the phase envelope and other available line(s) along with the
pipeline system's pressure-temperature traverse.

By default the phase envelope file will contain a number of lines,

depending on the phase behaviour of the fluid, the capabilities of the
selected PVT package, and the PVT feature licenses you have available.
The lines can be selected by supplying a list of line types as a multiple
value set. (p.519) Available line types are:

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HYDROCARBON: the hydrocarbon phase envelope, consisting of a

bubble point line and a dew point line

CRITICALPOINT: the Hydrocarbon critical point

WATERDEW: the water dew point line

HYDRATE1: Hydrate type 1 line

HYDRATE2: Hydrate type 2 line

WATERICE: the water ice line

WAX: the wax appearance, or cloud point, line

ASPHALTENE: the asphaltene appearance line

If you do not supply a list of line types, the file will contain as many lines
as the PVT package is capable of generating for the fluid, and for which
you have a valid license.

QUALITY= Values of Quality for use with PHASENV. If present, must be equated to a
multiple value set (p.519) of quality values, each in the range 0 to 1. The
resulting plot file will contain a hydrocarbon quality line for each value.

Note: The values in this report are calculated during the simulation of a piece of pipe, and
therefore refer to the pipe segment immediately upstream of the statement's position.

One-off output pages

The One-off output pages are:

Default

NARESULT Nodal Analysis result page. Lists the pressure, temperature and ON
flowrate at the Nodal Analysis point for all cases in each inflow and
outflow curve. Will only appear in Nodal Analysis jobs.

SUMFILE Controls the generation of the summary output file. This file is named ON
from the model file's root name with an extension of .SUM, and
contains a line for each labelled node for every case that was run in
the job. Data values are: Stock-tank watercut, Stock-tank liquid flow
rate, flowing free gas flow rate, pressure, temperature, friction
elevation and total pressure losses, mixture velocity, liquid holdup
fraction, liquid holdup volume, and flow regime pattern.

SUMMARY Requests that the summary file be copied to the end of the main ON
output file at the end of the job. Requires that SUMFILE be set to ON.

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WAXRESULT For Shell clients only, this page has one line per case or per reporting OFF
interval showing the history of wax deposition in the system.

ECHO Writes a line-numbered copy of the input data file at the start of the ON
job. All included files will be expanded in-line, and any syntax errors
generated will appear after the line that caused them.

SYNTAX Print formatted table of valid keyword input data. This extends over OFF
about 20 pages and lists the available maincodes, subcodes, value
types they can be equated to, conversion factors, maximum and
minimum limits for numeric data, and allowable character values. This
report is generated from the engine code used to read and validate the
input data file. It is useful when up-to-date documentation is not to
hand or appears to be incorrect.

NEWINPUTDATA Writes a copy of the input data file, but with the numeric data OFF
converted to the units system specified for output (with UNITS OUT=).

8.3.11 PLOT Output Plotting Options (Optional)

Main-code: PLOT (or NOPLOT to switch off)
The PLOT statement requests the production of plot files, and controls various aspects of program
behavior with relevance to plotting. Plot files are post-processed with the BJA plotting program
PSPLOT, or your chosen plotting program (for example Microsoft EXCEL). When driven using the
PIPESIM GUI, plots will normally appear concurrently with running the engine.

CASE or PROFILE Requests the production of the Profile Plot File, which contains data that
is organized to be plotted against position in the pipeline system. For
example a pressure profile for a flowline shows pressure on the Y-axis
against total distance on the X-axis; A temperature profile shows
temperature against total distance. For a well the axes may be reversed,
and/or the Y-axis might be elevation or depth. The profile plot file will
contain many quantities that can sensibly be plotted against distance,
elevation, or total length. (They may also be plotted against one another,
with varying degrees of usefulness.) By default, each NODE (p.614) in
the system will produce a point on the plot, and each case (p.659) will
produce a separate line on the plot. The SEGMENT subcode (see below)
will increase the number of plot points on each line.

CASE= or PROFILE= As above, and if a value is provided, it specifies the data that is to appear
in the plot file. Identifiers are provided as a multiple value set (p.519). An
up-to-date list of the available identifiers can be obtained using the
SYNTAX subcode (see below). If no value is supplied a default set of plot
file data will be written. If your supplied value starts with a plus sign [+],
your identifiers will be added to the default set instead of replacing it.

JOB or SYSTEM Requests the production of the System Plot File, which contains data that
is organized to be plotted against sensitivity variables. For example a job

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that sensitizes on flowline ID could produce a plot of ID on the X-axis

against flowrate on the Y-axis (or ID against holdup, or flowrate against
holdup, etc...). The plot file will contain many values, and you can plot
anything against anything, with varying degrees of usefulness. Each
case will produce one point on the plot, and separate lines on the plot are
produced by combinations of sensitivity variables as specified by
MULTICASE or NAPLOT statements.

JOB= or SYSTEM= As above, and if a value is provided, it specifies the data that is to appear
in the plot file. Identifiers are provided as a multiple value set. An up-to-
date list of the available identifiers can be obtained using the SYNTAX
subcode (see below). If no value is supplied a default set of plot file data
will be written. If your supplied value starts with a plus sign [+], your
identifiers will be added to the default set instead of replacing it.

SEGMENT Requests that profile plot data be written for every segment. By default a
point is written only for each node, but the pipe between each node is
usually sub-divided into a number of segments for calculation purposes.
With this subcode you can plot the intermediate segment data as well.

HERE= Requests that specified profile plot variables be added to the existing
system plot file at the current profile position. This can be used for
example to obtain fluid properties at any point, so they can be plotted
against sensitivity variables. This subcode is only valid within the system
profile. Identifiers are provided as a multiple value set (p.519). chosen
from the profile plot variables list (see SYNTAX below).

SYNTAX Will create a list (in the standard output file) in two columns of available
plot file variables and their identifiers (for example A, B, Y2, etc.) These
identifiers can be provided to the JOB=, CASE= or HERE= subcodes
(see above), and to SPOT= and CUSTOM= subcodes of PRINT (p.539).

EQUIPJOB= Controls the addition of equipment plot variables to the system plot file.
Each item of equipment (for example, pumps, chokes, heaters, and so
on) placed in the profile will, by default, result in additional plot variables
being added to the system plot file. For each equipment item, between 6
and 20 additional variables will be added, the exact number and
selection being specific to the equipment concerned. Can be set to ON or
OFF, default ON.

PVTDATA= Presence of this subcode triggers production of a fluid calibration plot file,
similar to that produced when one of the PLOT buttons in the Black oil
dialog advanced calibration tab is pressed. If a value is provided it must
be a multiple value set of identifiers specifying the fluid properties to be
written to the plot file. The file created is named from the model or branch
root file name with an extension of .PEX.

FORMAT= The overall textual layout of the plot files. Can be set to:

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BJA: Write the plot files in BJA (i.e., original PIPESIM) format. This is the
default option. BJA format plot files are composed of printable ASCII
characters, arranged in lines of less than 200 columns. Header
information is present at the start of the file. This is the option to use if
you intend to read the file with PSPLOT.

LOTUS: Write the plot files in LOTUS '.PRN' file format. Files will be
named with the extension .PRN. The Lotus 123 spreadsheet program will
recognize .PRN files and will often read them without further user
intervention.

NEUTRAL: Write the plot files in NEUTRAL format. NEUTRAL format

consists entirely of lines of numeric data arranged in columns. No header
information is written.

CSV: Write plot files in Comma Separated Value format. Files will be
named with the extension .CSV. The EXCEL spreadsheet program will
recognize .CSV files and will usually read them without further user
intervention.

PACKEDCSV: As for CSV above, but the data is written in a compressed

form that occupies less space, thus using less disk space; however, it
takes more run-time to produce.

GOAL: Write files in GOAL-compatible format. This is a combination of

revision B (see below) and BJA.

XYJOB= For the System plot file, specifies the identifiers to be used as the X and
Y axes when the plotfile is first opened by PSPLOT. Identifiers are
provided as a multiple value set.

XYCASE= For the Profile plot file, specifies the identifiers to be used as the X and Y
axes when the plotfile is first opened by PSPLOT. Identifiers are provided
as a multiple value set.

VERSION= or Specifies the revision standard that the plot file is to be written to
REVISION= conform to. May be set to B or C, whose meanings are:

B: Revision B plot files conform to an older standard that contains some

fixed-format data and hence is not forward compatible. Some older
programs that read plot files, notably GOAL, can only process revision B
plot files.

C: Revision C plot files contain additional information, and are written

using textual Tags at the start of every line. This allows a measure of
forward compatibility, thus additional features may be present in the file,
and these can be silently ignored by an older reading program, without
causing an error.

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COMPOSITIONS= Controls the addition of composition records to the system plot file.
Composition records specify the fluid definition at the system outlet, and
are important in .PWH files created for use in PIPESIM.net's Wells Off-
line mode. With composition records present, a PWH file can be used to
replace a well definition in a network run, resulting in considerable
speedup of the network solution. Can be set to YEs (the default) or NO.

CASEFILENAME= or Specifies the name of the profile plot file. By default this will be created at
PROFILEFILENAME= run-time from the root name of the branch or model input file name, with
an extension of .PLC.

JOBFILENAME= or Specifies the name of the system plot file. By default this will be created
SYSTEMFILENAME= at run-time from the root name of the branch or model input file name,
with an extension of .PLT.

PVTFILENAME= Specifies the name of the Fluid calibration plot file produced with the
PVTDATA= subcode. By default this will be created at run-time from the
root name of the branch or model input file name, with an extension
of .PEX.

ALHANATI= Controls the calculation of Alhanati gas lift Instability criteria. The
Alhanati criteria are required by GOAL, so production of GOAL-format
files will enable this option. If it is enabled, but some of the data it
requires is missing, warning messages will be produced: these will list
the nature of the required missing data. This subcode allows the
calculation to be controlled explicitly, thus the messages can be
suppressed if the calculation is not required. Can be set to YES or NO,
default being dependent on model input data.

A PLOT statement should appear before the first NODE card in a case, to specify the required
SYSTEM and PROFILE plot options. Additional PLOT HERE statements can appear anywhere in
the profile.

8.3.12 NOPRINT Output Print Suppression Options (Optional)

Main-code: NOPRINT
The NOPRINT card has the opposite effect to PRINT (p.539) and suppresses printing of the
specified data. The same sub-codes as specified under PRINT are valid (with the exception of
MAP). This card is often used to suppress output in the second and subsequent cases of a job.

8.3.13 BEGIN , END - Block delimiters

Main-codes: BEGIN, END
The BEGIN and END statements delimit a block of one or more further statements that collectively
define an entity, and give it a name which can be referred to later. There are two types of entity
that can be defined, a CURVE, or a FLUID. The input file can contain as many BEGIN..END blocks
as are needed to define as many fluids or curves as desired.

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FLUID Specifies that the block defines a fluid. A Blackoil or Compositional fluid can be
specified with as many delimited statements as are necessary, and the resulting fluid
can be referred to on subsequent main-codes (such as . LAYER, INJGAS, INJFLUID,
GASLIFT, BLACKOIL, COMPOSITION) to specify the injected or reservoir layer fluids

CURVE Specifies that the block defines a curve. Curve definitions are used in 2 situations:
Inflow performance : a reservoir or layer can be characterized by a curve of Bottom hole
pressure against flowrate. Also, variation of GLR and Watercut can be specified as a
coning relationship. Pumps and compressors: these devices can be specified with
curves of flowrate against head, power and efficiency

NAME The name of the entity being defined.

INHERIT Optional, for FLUID blocks only. Controls inheritance of black oil fluid properties from
the 'current' fluid. By default, each new fluid starts off with nothing defined. However the
fluid already defined and currently in use can he inherited as the basis for a new fluid if
desired. This is useful in legacy .PSM files which define only one black oil fluid and do
not give it a name, and when additional fluids are being defined in additional input files.
(p.520)

Example
The subcodes can appear on either maincode. Blocks cannot be nested, but it is possible to refer
to an earlier block when defining a subsequent block.
For example:

begin fluid name=oil1

BLACKOIL
PROP API = 33 GASSG=0.65 PSAT=4000 TSAT=250
GSAT=320
LVIS T1=250 VIS1=0.6 T2=60 VIS2=20
RATE GOR=320 WCUT=30
end fluid

begin
BLACKOIL
PROP API = 45 GASSG=0.6 PSAT=3770 TSAT=240
GSAT=350
LVIS T1=250 VIS1=0.63 T2=60 VIS2=22
RATE GOR=300 WCUT=10
end fluid name=oil2

begin fluid name=oil3

BLACKOIL USE = oil1
RATE GOR=600 WCUT=12
end

BLACKOIL use = oil2

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8.3.14 PUSH - Remote Action Editing (optional)

The PUSH statement is provided primarily to allow other computer programs to exert control over a
PIPESIM engine run, without the need to modify an existing input file. For a human, almost
everything that is possible with the PUSH statement can be accomplished far more easily by
editing the main input ('.psm') file with a text editor. However, designing a computer program to
reliably interpret and correctly modify a .PSM file without human help is surprisingly difficult. PUSH
is best viewed a replacement for a text editor and a human. Nevertheless, humans can sometimes
find PUSH statements useful as an alternative way to organize input data. (Beware however that
a .psm file containing PUSH statements may not behave as expected if it is itself the subject of
control by another program using PUSH.)
The PUSH statements are generally supplied in an additional input file (p.520) but this is not a
requirement.
PUSH allows an editing action (the action ) to be performed on a subsequent statement (the
target). The target is specified by its maincode and label The action can be: the addition of extra
text on the end of the target statement; addition of an extra statement before or after the target; or
the removal of the target statement.
Main-code: PUSH

MAINCODE= Required: Specifies the target maincode.

LABEL= or Specifies the label of the target statement. Serves to distinguish the required
OBJECT= target statement when multiple statements having the same maincode are
present. To specify that the target has no label (and thus prevent an earlier
statement that does have a label from being the target), supply
LABEL=*NONE.

TEXT= Text to be appended to the target statement. The text should be enclosed in
quotes since it will usually contain spaces, and equated pairs of keywords and
values. The supplied text must conform to the syntax necessary for the target
maincode, otherwise a syntax error will occur and processing will terminate.

ETEXT= Exclusive text to be appended to the target statement. When 2 or more PUSH
operations append text to the same target, the appended text will normally
grow as each push is actioned; however if ETEXT= is specified the current text
will replace any existing text resulting from earlier push(es).

LINE= OR Text to be added as a separate line after the target statement.

LINEAFTER=

LINEBEFORE= Text to be added as a separate line before the target statement.

REMOVE Results in the target statement being removed from the input. (This is actually
achieved by transforming it into a comment by prepending the comment
character '!'.)

ERROR= Sets the severity of the action when errors occur. The most common error is
that the position or target was not found, so the action did not occur. May be
set to one of the following:

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FATAL: Errors will be fatal, i.e. processing will terminate. A diagnostic

message will be issued to the screen and the output file. This is the default
behavior.

WARNING: Errors will result in a diagnostic message on the output file and a
message box on the screen, but processing will continue.

NOTE: Errors will result in a diagnostic message on the output file, processing
will continue.

SILENT: Errors will be silently ignored.

GLOBAL Specifies that this push statement is to be applied to all matching statements.
If GLOBAL is not specified, the first statement that matches the specified
maincode and label will be the only target.

Notes:
Multiple PUSH statements may be present in the input file or additional files.
If many PUSHes specify the same target, the order in which the actions occur is the order in
which they appear in the file. However the result may turn out to be reversed from that expected
by the user. For example, if 2 pushes each add a line after the same target (the LINE=
subcode), the second push will insert its new line immediately after the target thus displacing
the one added by the first push. For the TEXT= and LINEBEFORE= subcodes this does not
cause a problem, because the definition of the action corresponds to what the user expects. If
one push specifies REMOVE=, then all subsequent pushes will not find the target, so position
this push last.
The text added with TEXT=, LINE= etc can be any text valid for the specified position in the file.
Multiple statements can be provided by separating them with a semicolon (':'). Remember to
enclose the text in quotes ('"') or apostrophes ('''). If the text you are adding itself contains
quotes , enclose it in apostrophes, and vice-versa.
The subcodes TEXT=, ETEXT=, LINE=, LINEBOFORE= and REMOVE are mutually exclusive.
Any statement that has a label starting with an exclamation point ('!') will be excluded from
being selected as a PUSH target. This is useful to prevent a line that was previously inserted
with one push from being modified or removed by a subsequent push.

8.3.15 PLOTFILEDATA
Main-code: PLOTFILEDATA

8.3.16 EXECUTE - deferred execution of a statement

Main-code: EXECUTE
The EXECUTE statement allows some other statement to be positioned within the system profile,
to be executed during system simulation. Normally, any statement in the profile is processed by the
input processor, and is used to build the system model. The system model consists of a set of

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global values, (for example fluid properties, options, inlet pressure, and so on.) and a set of
connected equipment items (for example pipes, pumps, chokes, flowlines, and so on). When the
system model is simulated, the global values cannot normally be changed, but use of the
EXECUTE statement makes some values available for control.
EXECUTE has no subcodes: instead, any text supplied on it will be stored, and interpreted as a
statement by the input processor when the system is simulated.
The EXECUTE statement should appear within the profile, that is after the PROFILE statement.

EXECUTE text comprising an otherwise complete and valid statement

8.3.17 USERDLL - Equipment

The API for the inclusion of user-defined 32-bit equipment DLL's is provided by Schlumberger.
See User Equipment DLL Case Study - User Pump
Main-code: USERDLL

FILENAME= The name of the DLL.

EPNAME= The entry point of the DLL - the actual name of the routine as exported
from the DLL

PSNAME= The internal PIPESIM name of the routine. The psname's must be unique
- the user should check that other DLLs specified in the userdll.dat file
(located in C:\Program Files\Schlumberger\PIPESIM\data for a standard
installation of PIPESIM - look for ep_ident) do not use the same
psname's.

LINKTYPE= 24 The DLL linkage type. Note that it must be 24

EPTYPE= The type entry point for the DLL. Note that it must be equipment to
EQUIPMENT distinguish it from flow correlations.

TITLE= The title text describing the DLL.

OPTIONS= The string that will be sent as the first argument to the routine. (This is a
global option, perhaps specified by the author of the DLL).

SDESCRIPTION=

LDESCRIPTION=

8.4 FLOW CORRELATION DATA

VCORR (p.557) Vertical Flow Correlation Options
HCORR (p.561) Horizontal Flow Correlation Options
Single Phase Flow Options (p.564)
User Defined DLL (p.566)

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8.4.1 CORROSION
Maincode: CORROSION
Subcodes:
This maincode allows corrosion rate to be calculated.
METHOD= or Specifies the correlation to be used. Choices are:
MODEL=

DEWAARD Uses the de Waard model.

NONE disables corrosion calculations

PHACT= Optional: Specifies the actual pH of the fluid system. If not

supplied the value will be calculated internally.

CC= or The multiplier Cc to correct for inhibitor efficiency or to match

EFFICIENCY= field data

8.4.2 EROSION Erosion Rate and Velocity (Optional)

Maincode: EROSION
This maincode allows erosion rate and erosional velocity to be calculated.
METHOD= Specifies the correlation method to be used. Available methods are:

API14E: The API 14 E method. This calculates erosional velocity assuming

solids-free production. Erosion rate is not calculated. The only other
subcode this method recognizes is K=, all others are ignored

SALAMA The SALAMA 2000 method.

K= or KEROS= The desired constant in the API 14 E equation. Default value is 100 in
engineering units. A value of 100 specified when SI units are being used
will be in SI units: this translates to approximately 82 in engineering units.
The value may be qualified with the units descriptor 'ENG' or 'SI' to specify
which units system to use when interpreting it.

H= or EROSRATE= The acceptable erosion rate. Used to calculate erosional velocity. Units are
in/1e3/year or mm/year, default 0.1 mm/year.

SANDRATIO= The rate of sand production, specified as a ratio with liquid rate. Units are
Parts Per Million , by volume, against stock-tank liquid rate. (The
equations in Salama's paper use a sand rate in Kg/day. This is obtained
from the supplied volume ratio using Salama's 'typical value' for sand
density, 2650 kg/m3.) If sand production ratio is zero, erosion rate will not
be calculated

W= or SANDRATE= The absolute rate of sand production, kg/day or lb/day. Use of this subcode
is not recommended unless the model also fixes the system flowrate. Sand

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production rate is better specified as a ratio with liquid rate, using the
SANDRATIO= subcode (see above).

SM= or S= This is the Geometry constant Sm in the Salama method, default 5.5.

CE= or Multiplier to match field data, default 1.

EFFICIENCY=

D= or SANDSIZE= The mean size of the sand grains. Units are in/1e3 or mm. Default 0.25 mm

SANDDENSITY= Density of the sand grains. Units are lb/ft3or kg/m3. Default 2650 kg/m3.

SANDSG= Specific gravity of the sand grains relative to water. Default 2.650

8.4.3 SLUG Slug Calculation Options (Optional)

Main-code: SLUG
The SLUG main-code allows the selection of slug behavior correlations. At present three slug
correlations are available: the severe-slugging group PI-SS proposed by Pots (p.508) , and the
slug sizing correlations of Norris (p.507) and of Scott, Shoham and Brill (p.509) .

PISS= ON Start calculation of PI-SS

OFF End calculation of PI-SS

SIZE= SSB Switch on Scott, Shohan and Brill slug size correlation.

NORRIS Switch on Norris slug size correlation.

OFF Switch off slug size correlation.

BP= ON Use BP Slug method. To see the results of this the following should also be
used: print custom = (b,o,a24, b24, c24, d24, e24,f24,g24,h24,i24)

Note: The SIZE and PISS sub-codes are not related, and can be set independently of one another.

The PI-SS routine is based upon a correlation developed at Koninklijke Shell Laboratory. PI-SS is
a dimensionless number that is a means of quantifying the likelihood of severe riser-slugging.
Normally one would turn the PI-SS calculation on after the first node of the flowline and switch it off
at the downstream riser base. If the value of PI-SS is less than one at the riser base and the flow
regime (as predicted by the Taitel-Dukler correlation) is stratified, then severe riser slugging is
possible. Conversely, PI-SS values significantly greater than one indicate that severe riser slugging
is not likely. The PI-SS number can also be used to estimate slug size. As a rule of thumb the slug
length will be approximately equal to the riser height divided by PI-SS, that is PI-SS values less
than unity imply slug lengths greater than the riser height. PI-SS is calculated at each node in the
flowline (while PISS=ON) using averaged holdup data, etc., but it is only the value recorded at the
downstream riser base which is of any real significance. PI-SS is printed as part of the PRIMARY
output (see the PRINT (p.539) main code).

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The SIZE sub-code enables the user to specify a slug sizing correlation. At present two
correlations are available, NORRIS and SSB. The NORRIS correlation was developed from
Prudhoe Bay operational data and gives slug size as a function of pipe diameter. The SSB
correlation was developed by Scott, Shohan and Brill and published in SPE paper 15103 in April
1986. The correlation takes account of slug growth. Normally one would switch the SIZE option on
at the start of the profile and slug sizes will be automatically estimated whenever the flow regime
(as predicted by the chosen correlation) is one that will support slugs. It should be noted that the
slug size data output is only printed if SLUG is specified on the PRINT main code.

Slug catcher size

The following comments may help to determine the size of a slug catcher.
The slug output pages should be switched on from the Define Output dialog.
The size of a slug catcher is determined by one of the following parameters.
1. The amount of liquid generated by pigging the lines.
2. The amount of liquid generated by changing the flowrate in the flowline. At low flowrates there
will be a large holdup of liquid in the pipeline and at high flowrates there will be a small holdup
of liquid in the line. As the flowrate is increased you get a surge of liquid from the pipeline. The
flowrate increase can be calculated using Cunliffe's method (p.303).
3. Dealing with slugs created by severe riser slugging. The likelihood of severe riser slugging is
determined by the PI-SS correlation. Slugging will occur if there is a segregated flow regime
and a PI-SS number less than one. The size of the slug is determined by using the following
formula. Slug Size = Riser Volume/PI-SS number.
4. Dealing with hydrodynamic Slugging. This is determined by use of the SSB or Norris
Correlations. You need a slugging flow regime for this to occur such as intermittent. The slug
size and frequency is taken from the slug length and frequency table in the output. It is normal
that the slug catcher is sized for the 1 in 1000 slug. These two correlations can predict huge
slug sizes with volumes greater than the holdup in the pipeline. Therefore one must be careful
to check the holdup as the slug cannot be bigger than the total amount of liquid in the pipeline.
5. Dealing with terrain slugging. PIPESIM cannot accurately predict slugging. If the holdup
increases as the pipeline goes over successive humps - this may indicate a propensity for
terrain slugging.

8.4.4 VCORR Vertical Flow Correlation Options

See also: SPHASE Single Phase Flow Options (p.564)
Main-code: VCORR

PLOSS= Pressure loss correlation (refer to the Summary of Valid Vertical Flow
Correlation Combinations (p.558)).

HOLDUP= Holdup correlation (refer to the Summary of Valid Vertical Flow Correlation
Combinations (p.558)).

MAP= Flow regime map (refer to the Summary of Valid Vertical Flow Correlation
Combinations (p.558)).

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ANGLE= Angle above which vertical flow correlations are used (default = 45 o)

TYPE= This sub-code allows the commonly recommended combinations of flow

regime maps, holdup, and pressure loss correlations to be specified with one
sub-code instead of separate MAP=, HOLDUP=, and PLOSS= sub-codes.
Please refer to the table next page.

FFACTOR= Correlating or matching factor to be applied (as a multiplier) to the calculated

friction pressure gradient (default = 1.0). This subcode can be used to adjust
('tune') the friction pressure drop values calculated by the correlation to match
measured data.

HFACTOR= Correlating or matching factor to be applied (as a multiplier) to the calculated

liquid holdup fraction (default = 1.0). This subcode can be used to adjust
('tune') the liquid holdup (and hence elevation pressure drop) values calculated
by the correlation to match measured data.

SOURCE=

OVERRIDE=

ACCELL=

SWITCHES=

ENTRAINMENT=

OPTIONS=

Summary of Valid Vertical Flow Correlation Combinations

The following table summarizes the valid combinations of pressure loss, holdup and flow pattern
map available for vertical flow. Entering non-valid combinations will result in an input data error.
For details on the vertical flow correlation abbreviations, refer to Vertical Flow Correlations -
Abbreviations (p.559).

PLOSS HOLDUP MAP TYPE

DR DR DR/TD DR

BBO BBO BB/TD BBO

BBR BBR BB/TD BBR

ORK ORK ORK ORKISZEWSKI

GA GA GA

HB HB BB/DR/BJA HBR

HBO HBO BB/DR/BJA

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BJA BJA1/BJA2 TD BJA

MB MB MB

Any BRIMIN1 Any

Any BRIMIN2 Any

NOSLIP NOSLIP NOSLIP NOSLIP

GRAY GRAY TD GRAY

Vertical Flow Correlations - Abbreviations

The abbreviations for vertical flow correlations is different for each source. This topic covers the
BJA and TULSA sources. For OpenLink users and for flow correlations like OLGAS,LEDA, TUFFP
defined in the userdll.dat file, the source is the identifier (IDENT) for the flow correlation, while the
abbreviation is the entry point identifier (ep_ident) for the selection that the user wants to use.

BJA
The abbreviations for BJA are as follows:
ANSARI
Ansari Vertical Flow Correlation
BBO
Beggs & Brill Original
BBR.
Beggs & Brill Revised
BJA
BJA correlation
BJA1
Original BJA holdup correlation
BJA2
Revised BJA holdup correlation
BRIMIN 1 or 2
Brill & Minami Holdup Correlation
DR
Duns and Ros
GA
Govier and Aziz and Forgassi
GRAY
Gray Vertical Flow Correlation

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GRAYM
Gray (modified)
GRAYO
Gray (original)
HB
Hagedorn and Brown (Revised)
HBO
Hagedorn & Brown (Original)
HBR
Hagedorn & Brown
HBRDR
Hagedorn & Brown, Duns & Ros map
LEDA
LEDA steady-state correlation
MB
Mukherjee and Brill
NOSLIP
No Slip Assumption
OLGA
OLGA-S steady-state correlation
ORK
Orkiszewski
TD
Taitel Dukler
TU2P
TUFFP Unified 2-phase v2007.1

TULSA
The abbreviations for Tulsa are as follows:
TBB
Beggs & Brill
TDR
Duns & Ros
TGA
Govier, Aziz
THB
Hagedorn & Brown (Original)

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THBR
Hagedorn & Brown (Revised)
TMB
Mukherjee & Brill
TORK
Orkiszewski

8.4.5 HCORR Horizontal Flow Correlation Options

See also: SPHASE Single Phase Flow Options (p.564)
Main-code: HCORR

PLOSS= Pressure loss correlation (refer to the Summary of Valid Horizontal Flow
Correlation Combinations (p.562)).

HOLDUP= Holdup correlation (refer to the Summary of Valid Horizontal Flow Correlation
Combinations (p.562)).

MAP= Flow regime map (refer to the Summary of Valid Horizontal Flow Correlation
Combinations (p.562)).

TYPE= This sub-code allows the commonly recommended combinations of flow

regime maps, holdup, and pressure loss correlations to be specified with one
sub-code instead of the separate MAP=, HOLDUP=, and PLOSS= sub-codes.
Please refer to the table next page.

FFACTOR= Correlating or matching factor to be applied (as a multiplier) to the calculated

friction pressure gradient (default = 1.0). This subcode can be used to adjust
('tune') the friction pressure drop values calculated by the correlation to match
measured data.

HFACTOR= Correlating or matching factor to be applied (as a multiplier) to the calculated

liquid holdup fraction (default = 1.0). This subcode can be used to adjust
('tune') the Liquid holdup (and hence elevation pressure drop) values
calculated by the correlation to match measured data.

SOURCE=

ANGLE=

OVERRIDE=

ACCELL=

SWITCHES=

ENTRAINMENT=

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Summary of Valid Horizontal Flow Correlation Combinations

The following summarizes the valid combinations of pressure loss, holdup and flow pattern map
available for horizontal or inclined flow. Entering non-valid combinations will result in an input data
error. For details on the horizontal flow correlation abbreviations, refer to Horizontal Flow
Correlations - Abbreviations (p.559).

PLOSS HOLDUP MAP TYPE

DR DR/BJA DR/TD DR

DKAGAF DKAGA TD

DKAGAF EATON TD DKAGAF

BBO BBO/BJA1/BJA2 BB/TD BBO

BBR BBR/BJA1/BJA2 BB/TD BBR

BJA BJA1/BJA2/EATON TD BJA

BJA1 BJA1/BJA2/EATON TD

MB MB MB

HB HB BB/DR/BJA HBR

HBO HBO BB/DR/TD

OLI BJA1/BJA2/EATON TD OLIEMANS

MB MB MB

Any BRIMIN1 Any

Any BRIMIN2 Any

NOSLIP NOSLIP NOSLIP NOSLIP

Horizontal Flow Correlations - Abbreviations

The abbreviations for vertical flow correlations is different for each source. This topic covers the
BJA and TULSA sources. For OpenLink users and for flow correlations like OLGAS,LEDA, TUFFP
defined in the userdll.dat file, the source is the identifier (IDENT) for the flow correlation, while the
abbreviation is the entry point identifier (ep_ident) for the selection that the user wants to use.

BJA
The abbreviations for BJA are as follows:
BBR
Beggs and Brill (Revised)

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BBO
Beggs and Brill (Original)
BBOTD
Beggs & Brill, Taitel Dukler map
BJA
Baker Jardine Revised
BJA1
BJA correlation
BJA2
Revised BJA holdup correlation
BRIMIN 1or 2
Brill and Minami Holdup Correlation
DKAGA
Dukler (AGA)
DKAGAD
Dukler, AGA & Flanagan
DKAGAF
Dukler, AGA & Flanagan (Eaton Holdup)
DR
Duns and Ros
HB
Hagedorn and Brown Revised
HBO
Hagedorn and Brown Original
LEDA
LEDA steady-state correlation
LOCKMAR
Lockhart & Martinelli
LOCKMARTD
Lockhart & Martinelli
MB
Mukherjee and Brill
NOSLIP
No Slip Assumption
OLIEMANS
Oliemans

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OLGA
OLGA-S Steady-State Correlation
OLI
Oliemans Correlation
TD
Taitel Dukler
TU2P
TUFFP Unified 2-phase v2007.1
XIAO
Xiao horizontal mechanistic model

TULSA
The abbreviations for TULSA are as follows:
TBB
Beggs & Brill
TDUK
Dukler
TMB
Mukherjee & Brill

8.4.6 SPHASE Single Phase Flow Options (Optional)

See also: Single Phase Flow Correlations (p.296), Horizontal Flow Correlation Options (p.283),
Vertical Flow Correlation Options (p.288)
PIPESIM will automatically select either the specified two-phase or single-phase correlation
depending on the phase behavior at the particular section in the pipeline. The single phase
correlation is set by default to the MOODY correlation. If no single-phase correlation is
specified but single-phase flow is encountered in the pipeline, the program automatically
switches to the MOODY correlation.
In addition, when the specified phase correlation is the Moody correlation or the Cullender-Smith
correlation, PIPESIM will calculate the Moody friction factor using either an iterative implicit method
(Colebrook-White equation (Moody chart)), an explicit method (see the Sonnad and Goudar paper
(p.509)) or a fast explicit or approximate method (see the Moody paper (p.506)) . The default
calculation method for the friction factor is the explicit method. The Moody friction factor calculation
method will also have an impact on the horizontal and vertical flow correlations as the friction factor
used to compute the pressure gradient in the flow correlations will be evaluated based on the
method specified by the Moody friction factor calculation method.
Main-code: SPHASE

CORRELATION= Single-phase flow correlation.

AGA Use the AGA dry gas equation for single phase flow.

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MOODY At Reynolds numbers greater than 2000, use the

method specified by the MOODYCALC option and at
Reynolds numbers less than 2000, assume laminar
flow (f=64/Re) (default).

PANA

PANB

WEYMOUTH

HAZENWILL

CULLSMITH Uses the Cullender and Smith Correlation for Gas with
a Moody friction factor calculated using the method
specified by the MOODYCALC option.

DRAGFACTOR= The AGA drag factor (default = 0.98).

LFMIN= The liquid volume fraction below which single phase

gas flow is assumed to exist (default = 0.00001).

LFMAX= The liquid volume fraction above which single phase

liquid flow is assumed to exist (default = 0.99).

TRMIN=

TRMAX=

TRMETHOD=

INTERPOLATE

CUTOFF

MAXIMUM

CUTOFF

COMPARE=

ON

OFF

C= Hazen-Williams C parameter

LFPROP=

MOODYCALC EXPLICIT or SONNAD Sonnad 2007 linear approximation (default)

APPROXIMATE or Moody 1947 approximation

MOODY

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IMPLICIT or Colebrook-White equation (Moody chart)

ITERATIVE

8.4.7 USERDLL - Flow Correlations

The API for user-defined multiphase flow correlation plug-in is provided by Schlumberger.
For a standard installation of PIPESIM, example Fortran source code is provided in the following
directory (assuming the default installation location):

C:\Program Files\Schlumberger\PIPESIM\Developer Tools\User Flow Correlations

\Fortran_code

. Two files are included, UFC2P_Demo.f90 for 2-phase correlations and UFC3P_Demo.f90 for
3-phase correlations. These files are self-documenting templates that will compile as is (using
Beggs-Brill as an example) and can be modified to interface with your own correlation and
compiled into a dll that is called directly by the PIPESIM engine. Configuration of the flow
correlations and related options is contained within the USERDLL.dat file which may be edited by
selecting Setup Preferences Choose Paths.

8.5 WELL PERFORMANCE MODELING

INTRODUCTION (p.567)
WELLPI (p.569) Well Productivity Index
VOGEL (p.570) Data for the Vogel Equation
FETKOVICH (p.570) Data for the Fetkovich Equation
JONES (p.571) Data for the Jones Equation
IFPPSSE (p.571) Data for the Pseudo-steady state inflow equation
WCOPTION (p.573) Well Completion Data
IPRCRV or IFPCRV (p.576) Well performance and/or coning relationship tabulation
IFPTAB (p.578) Inflow Performance Tabulation (obsolete)
CONETAB (p.579) Coning relationship Tabulation (obsolete)
BACKPRES (p.580) Backpressure Equation (BPE)
NAPOINT (p.659) System Analysis Point
NAPLOT (p.655) System Analysis
HORWELL (p.580) Horizontal Well Inflow Performance
LAYER (p.582) Reservoir Layer properties
PERMTAB (p.585) Permeability Saturation Relationship Tabulation
HVOGEL (p.586)
FORCHHEIMER (p.586) Data for the Forchheimer Equation
FRACTURE Data for the Hydraulic Fracture IPR

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TRANSIENT (p.587) Data for the Transient inflow equation.

8.5.1 INTRODUCTION
Several options for well performance modeling have been introduced. A number of basic options
are presently available and are summarized below with application limits:
1. Well Productivity Index (p.569). Oil and gas reservoirs. Black oil and compositional.
2. Vogel's Equation (p.570). Oil reservoirs. Black oil only.
3. Fetkovich's Equation (p.570). Oil reservoirs. Black oil only.
4. Jones' Equation (p.571) . Oil and gas reservoirs. Black oil and compositional.
5. Pseudo Steady State Equation (p.571) . Oil and gas reservoirs. Black oil and single phase
compositional.
6. Well Completion Options (p.573) (such as perforation and gravel steady state pack models)
are available in association with the pseudo equation..
7. Inflow Performance Tabulation (p.578). Oil and gas reservoirs. Black oil and compositional.
Options 1 to 7 are mutually exclusive (except the Well Completion options, which must be used in
combination with the Pseudo-Steady-State Equation). If more than one option is entered, the last
one entered will be invoked. Normally inflow performance data would be entered after the INLET
statement, and must appear before the first NODE card in a case. However, if injection wells are
modeled, the system profile should describe the well geometry in the direction of flow, that is
ending at the bottom hole. The appropriate inflow performance data should appear after the bottom
hole and before the ENDCASE.
Printing Inflow Performance Data
A comprehensive printout of the well inflow performance data can be obtained by invoking
the PRINT INFLOW option (Ref. Section 1.6).
Definition of Reservoir Type
For black oil cases, PIPESIM will interpret the reservoir type (oil or gas) from the way in
which the flow rate is defined under the RATE or ITERN statement as follows:
If the rate is defined on the basis of liquid flow plus a gas/liquid ratio (that is LIQ plus
GLR sub-codes) then an "oil" reservoir is assumed.
If the rate is defined on the basis of gas flow plus a liquid/gas ratio (that is . GAS plus
LGR sub-codes) then a "gas" reservoir is assumed.

8.5.2 COMPLETION Completion Profile Delimiter

Main-code: COMPLETION
The profile delimiters (supercodes) are used by PIPESIM as required flags if the model contains
horizontal wells or if you wish to perform system analysis anywhere in the system profile. The
presence of the COMPLETION delimiter informs PIPESIM that subsequent wellbore sections form
a "completion," or "productive interval." The program will therefore model the flow of reservoir fluid
into the wellbore.

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INLINE= If this sub code is present, the entire profile is modeled as a single unit. If it is absent,
the completion is modeled separately from the rest of the system profile.

EFFLENG= The effective length of the horizontal completion (m or ft). This allows you to specify
a completion length which is less than the actual length supplied with subsequent
NODE maincodes. Thus, sensitivities on length can be performed using the NAPLOT
maincode.

IPRPOINT=

DPRETIO=

TOL=

LABEL=

TYPE=

For datum reset feature, please refer to Node (p.614) .

Supercode
The supercodes are:
TUBING
Tubing Profile Delimiter
FLOWLINE
Flowline Profile Delimiter
RISER
Riser Profile Delimiter
Main-code: TUBING, FLOWLINE, RISER
The profile delimiters (supercodes) are used by PIPESIM as required flags if the model contains
horizontal wells or if you wish to perform system analysis anywhere in the system profile. The
portions of profile so delimited are sometimes be described as objects.
When any of these are encountered after the COMPLETION delimiter, the inflow modeling is
switched off, and the resulting flowrate is used for the remainder of the system profile.
Other modes of program behavior depend on the current delimiter, and the junctions of different
delimiters. For example, Heat Transfer data implying that a pipe is buried, will not be applied to a
riser; the junction of a flowline and an upward-going riser is identified as a riser-base and triggers
checks on slugging parameters; the junction of tubing and flowline triggers actions relevant to the
wellhead.

LABE L= or The name of the profile object. This is used to print on the output file, and for
NAME= object identification with the PUSH (p.552) statement.

RESETDATUM= Can be set to YES (the default) or NO. The NODE statements on either side of
a supercode are, by default, assumed to be coincident. This allows the last

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node of (for example) a previous flowline to specify the same position as the
first node of the next flowline, with no intermediate length of pipe joining them,
regardless of the values of distance and elevation these 2 nodes may specify.
This behavior can be reversed with RESETDATUM=NO, which will model a
pipe section between the 2 nodes in the same way as between any other 2
nodes in the same object.

INHERIT= Can be set to YES (the default) or NO. Controls the application of Upstream
Inheritance. Pipe object dimensions (for example Pipe ID, wall thickness,
coatings thickness and conductivity, burial configuration, and so on.) are by
default inherited from upstream objects. This allows each subsequent object to
be specified with a minimum of input data, as the only required values are
those that change between objects. However, mistakes in the specification of
data can easily occur with this mode of behavior, particularly when complex
pipe coatings and burial configurations are being specified, as unwanted data
from previous objects can be mistakenly inherited by the current object.
Specification of INHERIT=NO will ensure that each new object inherits nothing
from its upstream neighbor.

8.5.3 WELLPI Well Productivity Index (Optional)

Main-code: WELLPI
The WELLPI statement allows the Productivity Index (p.309) to be specified for a point-type
completion or a distributed completion. Exactly one of the subcodes LPI=, GPI=, MIPI=, MCPI=,
LDPI=, GDPI=, MIDPI=, or MCDPI= should be provided.

Subcodes
PWSTATIC= Static bottom hole pressure (bara or psia). This is the bottom hole pressure at zero
flow rate.

LPI= Liquid Productivity Index (bbl/day/psi or sm 3/day/bar)

GPI= Gas Productivity Index (MMscf/day/psi/psi or MMsm 3/day/bar/bar) Note: Under

normal circumstances, a gas well PI is much smaller than the typical liquid well PI.
Typical gas well PIs are between 1E-3 and 1E-6 mmscf/day/psi 2. Oil well PIs
usually vary between 1 and 40 STB/D/psi.

MIPI= Mass Incompressible Productivity Index (lb/sec/psi or kg/s/bar)

MCPI= Mass Compressible Productivity Index, (lb/sec/psi/psi or kg/s/bar/bar)

LDPI= Liquid Distributed Productivity Index (bbl/day/psi/ft or sm 3/day/bar/m)

GDPI= Gas Distributed Productivity Index (MMscf/day/psi/psi/ft or MMsm 3/day/bar/bar/m)

MIDPI= Mass Incompressible Distributed Productivity Index (lb/sec/psi/ft or kg/s/bar/m)

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MCDPI= Mass Compressible Distributed Productivity Index, (lb/sec/psi/psi/ft or

kg/s/bar/bar/m)

BPCORR= Allows a correction to the straight-line PI to allow for gas breakout when the fluid
goes below its bubble point pressure: can be set to ON or OFF (default OFF). If
enabled, the portion of the IPR below the bubble point is modelled with a Vogel
relationship.

PICOEF= Specifies the PI coefficient for the Vogel equation used if BPCORR= is enabled.
(default 0.8)

8.5.4 WPCURVE (Optional)

Main-code: WPCURVE
This statement is obsolete, please do not use it.

8.5.5 VOGEL Vogel Equation (Optional)

Main-code: VOGEL
This keyword is used to specify data for Vogel's Equation (p.310).

Subcodes
PWSTATIC= Static bottom hole pressure (bara or psia). This is the bottom hole pressure at zero
flow rate.

AOFP= Absolute Open Flow Potential of the well (sm 3/d or STB/D). This is a hypothetical
liquid flow rate when bottom hole pressure is set to 0.0 psia

PICOEF= The PI-coefficient used in Vogel's equation to adjust the degree of curvature of the
inflow performance curve. Curvature increases with increasing PICOEF. A straight
line is produced when PICOEF=0. (Default = 0.8).

8.5.6 FETKOVICH Fetkovich Equation (Optional)

Main-code: FETKOVICH
This keyword is used to specify data for Fetkovitch's Equation (p.311).

Subcodes
PWSTATIC= Static bottom hole pressure (bara or psia). This is the bottom hole pressure at zero
flow rate.

AOFP= Absolute Open Flow Potential of the well (sm 3/d or STB/D). This is a hypothetical
liquid flow rate when bottom hole pressure is set at 0.0 psia.

EXP= Exponent used in the Fetkovich equation to adjust the degree of curvature of the
inflow performance curve. Unlike the Vogel equation it is not possible to produce a

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linear well inflow characteristic as a special case of the Fetkovich equation. The
default is 1.0.

8.5.7 JONES Jones Equation (Optional)

Main-code: JONES or FORCHHEIMER
This keyword is used to specify data for the Jones Equation (p.312).

Subcodes
PWSTATIC= Static bottom hole pressure (bara or psia). This is the bottom hole pressure at
a flow rate of zero.

A= Turbulent flow coefficient. (Use TYPE= to define fluid type.)

B= Laminar flow coefficient. (Use TYPE= to define fluid type.)

TYPE= Used to define the type of fluid.

LIQ Liquid

GAS Gas

LA= Liquid turbulent flow coefficient. (psi /MMscf 2/d 2 or bar/m 6/d 2)

LB= Liquid laminar flow coefficient. (psi/MMscf/d or bar/m 3/d)

GA= Gas turbulent flow coefficient. (psi 2/MMscf 2/d 2 or bar 2/m 6/d 2)

GB= Gas laminar flow coefficient. (psi 2/MMscf/d or bar 2/m 3/d)

8.5.8 IFPPSSE : Data for the Pseudo Steady State Equation (Optional)
Main-code: IFPPSSE
The Pseudo Steady-state equation employs a radial reservoir model. The equation takes into
account both the effects of laminar and turbulent flows on pressure drawdown.

PWSTATIC= Static bottom hole pressure (bara or psia). This is the

bottom hole pressure at zero flow rate.

PERM= Average formation permeability (md).

THICKNESS= Average formation thickness (metres or feet).

RADE= Radius of external boundary of drainage area (metres or

feet). Default = 609.6 m or 2000 ft.

SKIN= Dimensionless skin factor (mechanical). Default = 0.

DIAMWELL= Wellbore diameter.

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IPRTYPE= Inflow performance relationship model

PSS Pseudo steady-state model

JONES Jones mode;

BASIS= or FLOWTYPE=

LIQUID

GAS

2PHASE

GASMETHOD=

PSEUDO Use pseudo pressure

SQUARED Use pressure squared

GA=

GB=

SOURCE=

ST Use the stock tank flow formulation of the pseudo steady

equation (default)

RES Use the reservoir flow formulation of the pseudo steady

equation

BPCORRECTION= Controls whether to apply the Vogel correction below the

bubble point

YES

NO

PICOEFF= Vogel coefficient for Vogel correction. Default = 0.8

DSKINLIQUID= Dynamic skin for liquid phase. Default = 0.

DSKINGAS= Dynamic skin for gas phase. Default = 0.

RESAREA= Reservoir area. (If entered, reservoir radius is calculated)

SHAPEFACTOR= Reservoir shape factor. (If entered, reservoir radius is

calculated) Default = 31.62

DRAINAGESKIN= Reservoir drainage skin.

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RESMOBILITY= Reservoir mobility. Should only be used for injection

systems (1/cp).

Note: If the skin is entered with the IFPPSSE main-code, any skin associated with the Well
Completion options (see Section 7.6) will be overwritten by this value.

8.5.9 WCOPTION Well Completion Data (Optional)

Main-code: WCOPTION
Well Completion Options (WCOPTION) allow the mechanical and dynamic skin factors to be
calculated from the details of the well completion configuration. Note: The well completion options
are only valid when used in conjunction with the Pseudo-Steady-State or Transient equations (as
defined under the IFPPSSE and TRANSIENT main-codes).
The WCOPTION maincode is an alternative to the FRACTURE maincode, and is exclusive with it.
TYPE= Specifies the type of well completion

OPENHOLE Openhole completion option. The program calculates

the skin factors assuming the well is not cemented. The
required data are DDAMAGE, PDAMAGE, INTERVAL,
PVERT and DEVIATION. All other sub-codes will be
ignored.

OPENGRAVEL Openhole gravel pack completion option. The required

data are DDAMAGE, PDAMAGE, INTERVAL, PVERT,
DEVIATION, PGRAV and DSCREEN. All other sub-
codes will be ignored.

PERFORATED Perforated completion option. The program calculates

the skin factors using the McLeod (p.331) or Karakas/
Tariq model. The required sub-codes are; DDAMAGE,
PDAMAGE, INTERVAL, PVERT, DEVIATION,
PERFSNMTHD, SHOTS, LPERF, DPERF,
PHASEANGLE, DCOMP, PCOMP. All other sub-codes
will be ignored.

GRAVELPACKED Gravel-packed and perforated completion Option. The

required sub-codes are; DDAMAGE, PDAMAGE,
INTERVAL, PVERT, DEVIATION, PERFSNMTHD,
SHOTS, LPERF, DPERF, PHASEANGLE, DCOMP,
PCOMP, PGRAV, DSCREEN, CASINGID and
LTUNNEL. All other sub-codes will be ignored.

FRACPACK Fracpack completion option. (i.e. a gravel packed

hydraulic fracture model). The required sub-codes are;
INTERVAL, PVERT, DEVIATION, SHOTS, DPERF,
PGRAV, DSCREEN, CASINGID, LTUNNEL,

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FPHLFRAC, FPWFRAC, FPPPERM, FPDDEPTH,

FPDPERM, FPCLEN, FPCPERM. All other sub-codes
will be ignored

INTERVAL= Completion interval length (metres or feet). Default =

formation thickness, as defined previously under the
IFPPSSE (p.571) main-code.

PDAMAGEDZONE= Permeability of the damaged zone around well bore

(md). The formation data should be given under the
IFPPSSE (p.571) main-code. Default = formation
permeability.

DDAMAGEDZONE= Diameter of the damaged zone around well bore (mm

or inches). Default = well bore radius (i.e., damaged
zone does not exist).

LPERFORATION= Length of perforation into the formation (mm or inches).

Default = infinity (which will result in a zero skin due to
perforation).

SHOTS= Shot density (shots/m or shots/ft). Default = 13.12

shots/m or 4 shots/ft.

PCOMPACTEDZO= Permeability of the compacted zone (or crushed zone)

around the perforation. Default = permeability of the
damaged If neither the damaged zone nor compacted
zone permeability is defined, the default value for
compacted zone permeability will be the formation
permeability specified under IFPPSSE. zone.

PVERTICAL= Permeability in the vertical direction (md). Default =

formation permeability, as defined previously under the
IFPPSSE (p.571) main-code.

DPERFORATION= Diameter of perforation (mm or inches). Default = 12.7

mm or 0.5 inches.

DCOMPACTEDZO= Diameter of the compacted zone (or crushed zone)

around the perforation. Default = diameter of the
perforation (i.e., compacted zone does not exist).

PGRAVEL= Permeability of gravel pack (md). Default = estimated

according to sieve size input.

SIEVESIZE=

LTUNNEL= Length of tunnel; which is usually the sum of the

thicknesses of cement, casing and annulus (mm or
inches). Default = 0.0.

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DSCREEN= Gravel pack screen ID (mm or inches).

PHASEANGLE= Perforation phase angle (degrees).

DEVIATION= Well deviation (degrees).

CASINGID= Casing ID (mm or inches).

FPDDEPTH= Fracture damage depth (mm or inches). For fracture

face skin term.

FPDPERM= Fracture face damage permeability (md). For fracture

face skin term.

FPPPERM = Fracture proppant permeability (md). Frac pack

proppant permeability.

FPCLEN = Frac pack choke length (mm or inches). Choke length

for choke fracture skin term.

FPCPERM= Frac pack choke permeability (md). Choke permeability

for choke fracture skin term.

FPWFRAC= Fracture width (mm or inches). Frac pack fracture

width.

FPHLFRAC= Fracture half length (ft or m). Frac pack fracture half
length.

PERFSKNMETHOD= Method for calculation of perforation skin.

0 McLeod (p.331) model

1 Karakas / Tariq model

DZSKINCALC=

GPSKINCALC=

PFSKINCALC=

PPDSKINCALC=

FPSKINCALC=

FACESKINCALC=

CHOKESKINCALC=

Note: The well completion options are only valid when used in conjunction with either the Pseudo-
Steady-State equation or the Transient equation (as defined under the IFPPSSE (p.571) and

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TRANSIENT (p.587) maincodes). All data entered under the WCOPTION main-code will be
ignored if the IFPPSSE or TRANSIENT main-codes are not also specified.

8.5.10 IPRCRV or IFPCRV: Inflow Performance Curve

The IPRCRV statement is a generalized replacement for IFPTAB, GIFPTAB, and CONETAB. It
allows a tabular Inflow Performance Relationship (IPR) to be specified using PIPESIM's multiple
value syntax (p.519). A Coning relationship can also be supplied, either stand-alone, or in addition
to a tabular IPR. The available range of formats in which the data can be supplied is a superset of
those available with IFPTAB, GIFPTAB and CONETAB.
Maincode: IPRCRV or IFPCRV

NAME= Required. Defines the name of the curve. This name is then used on (a)
subsequent LAYER statement(s).

GAS=(...) Specifies values of Gas flowrate (mmscfd or mmsm3d). Exclusive with LIQ=
and MASS=.

LIQ=(...) Specifies values of liquid flowrate (sbbl/d or sm3/d). Exclusive with GAS= and
MASS=.

MASS=(...) Specifies values of mass flowrate (lb/sec or kg/sec). Exclusive with GAS= and
LIQ=.

GLR=(...) Specifies values of Gas Liquid Ratio (scf/sbbl or sm3/sm3). Exclusive with
GOR=, OGR=, LGR=.

GOR=(...) Specifies values of Gas Oil Ratio (scf/sbbl or sm3/sm3). Exclusive with GLR=,
OGR=, LGR=.

OGR=(...) Specifies values of Oil Gas Ratio (sbbl/mmscf or sm3/mmsm3). Exclusive with
GOR=, GLR=, LGR=.

LGR=(...) Specifies values of Liquid Gas Ratio (sbbl/mmscf or sm3/mmsm3). Exclusive

with GOR=, OGR=, OGR=.

GWR=(...) Specifies values of Gas Water Ratio (scf/sbbl or sm3/sm3). Exclusive with
WGR= , WCUT=.

WGR=(...) Specifies values of Water Gas Ratio (sbbl/mmscf or sm3/mmsm3). Exclusive

with GWR= , WCUT=.

WCUT=(...) Specifies values of Watercut (% vol/vol). Exclusive with WGR= , GWR=.

PWSTATIC= Specifies the reservoir static (zero flowrate) pressure (psia or Bara).

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PWF=(...) Specifies values of Flowing Bottom Hole Pressure (psia or bara). Exclusive
with DP=. Must be accompanied by PWSTATIC= unless the first flowrate value
point is zero.

DP=(...) Specifies values of drawdown (Delta pressure, the difference between PWS
and PWF). (psi or bar). Exclusive with PWF=, and must be accompanied by
PWSTATIC=.

GASSG=(...) Specifies values of Gas Specific Gravity in a coning table. Exclusive with
CONEDGASSG=.

DEGREE= The degree of polynomial to fit to the data, default 1.

CONEDGASSG= Specifies the Specific gravity of the gas in the gas cap. Used to calculate the
produced gas SG. Exclusive with GASSG=.

Exactly one of the flowrate subcodes GAS=, LIQ= or MASS= must be specified. Then:
To specify an IPR table, supply also one of PWF= or DP=.
To specify a gas or liquid coning table, supply also one of GLR=, GOR=, LGR=, or OGR=. The
gas specific gravity may be provided with GASSG= values, or a single value of
CONEDGASSG=.
To specify a water coning table, supply one of WGR=, GWR=, or WCUT=.
Gas and Water coning can be supplied with IPR data in the same table.
Care must be taken when combining the coning subcodes, since some combinations can cause
unphysical situations, and others can leave the system undefined. For example, if OGR= and
WCUT= are provided, the water flowrate is undefined when OGR is zero, so WGR= should be
used instead of WCUT= or LGR= instead of OGR=. If GLR= and GWR= are provided, the GWRs
must always be less than the GLRs, so WCUT= should be used instead of GWR=, or OGR=
onstead of LGR=

Examples
1. This defines a coning table for a liquid production well. The statement has been provided on 2
lines using the '&' character as the continuation marker at the end of the first line. The entire
statement (i.e. the total characters in all the continued lines) may be no more than 255 characters
in length.

IFPCRV name=cc1 LIQ=(0,1000,2000,3000,4000) GLR=(300,300,550,600,620) &

WCUT=(10,10,18,22,30) GASSG=(.71 ,.71 ,.68 ,.67 ,.669)

2. This defines the same coning table as above, but shows how multiple statements can be used.
Each statement may be no more than 255 characters in length, but the use of multiple statements
allows more data points to be entered if necessary. Note that the curve name must appear on
every statement.

IFPCRV name=cc1 LIQ= (0 ,1000,2000,3000,4000)

IFPCRV name=cc1 GLR= (300 ,300 ,550 ,600 ,620 )

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IFPCRV name=cc1 WCUT= (10 ,10 ,18 ,22 ,30 )

IFPCRV name=cc1 GASSG=(.71 ,.71 ,.68 ,.67 ,.669)

8.5.11 IFPTAB Inflow Performance Tabulation (Optional)

Main-code: IFPTAB

Note: The IFPTAB statement is obsolete, its functionality has been replaced by IPRCRV (p.576).

Specifies a liquid inflow performance relationship in the form of a table of bottom hole pressure
versus flow rate. Each IFPTAB statement holds a single data point. To complete the tabulation, at
least four statements are required.

Values
should be provided without keywords in a strict positional order, as follows:

value 1 Data point ordinal. If the IFPTAB statements are provided in order of increasing
flowrate this can be set to 0 for all statements (recommended) ; otherwise, it must be
a value between 1 and 30 to specify the ordinal.

value 2 Liquid flow rate value at stock tank conditions. (sbbl/day or sm3/day)

value 3 Bottom hole pressure (bara or psia).

value 4 Gas Oil Ratio (optional, scf/sbbl or sm3/sm3)

value 5 Watercut (optional, %)

EXECUTE see note 4.

Notes:
1. The first 3 values are mandatory. If values 4 and 5 are present they define a table of coning
performance for the well or completion
2. One of the data points must be at zero flow rate such that the corresponding pressure is the
static bottom hole (and reservoir) pressure.
3. The ordinal (value 1) is present for historical reasons to ensure backwards compatibility with
earlier versions of the PIPESIM engine. As long as the statements are provided in order of
increasing flowrate, and no other statements apart from IFPTAB appear in the middle of the
table, the value can be left at zero.
4. If the IFPTAB table is provided inside the system profile, the last statement must contain no
values, but instead must contain the EXECUTE sub-code. This syntax ensures that only one
completion is actually executed regardless of the number of IFPTAB statements actually
present. If IFPTAB is provided outside the system profile the EXECUTE subcode is
unnecessary.

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5. If your model contains multiple completions, 2 or more IFPTAB tables can be used to enter data
relevant to each completion.

Example
! n liq pwf gor wcut
ifptab 0 0 3000 986 0
ifptab 0 1000 2990 986 2.0
ifptab 0 2699 2920 1096 2.2
ifptab 0 6329 2800 2540 2.8
ifptab 0 7288 2600 2980 3.9
ifptab 0 8082 2400 3370 5.6
ifptab 0 8805 2003 3770 8.0
ifptab execute

The ! line is a comment line.

8.5.12 CONETAB Coning Relationship Tabulation (Optional)

Main-code: CONETAB
The CONETAB statement is obsolete, its functionality has been replaced by IPRCRV (p.576).
Specifies a coning relationship for a well or completion, in the form of a table of stock-tank liquid
flowrate versus produced GOR and watercut. Each CONETAB statement holds a single data point.
To complete the tabulation, at least four statements are required. CONETAB does not define an
inflow performance relationship, it is intended to be used in addition to an existing maincode that
specifies the desired IPR. Values should be provided without keywords in a strict positional order,
as follows:

LIQUID= Liquid flow rate value at stock tank conditions. (sbbl/day or sm 3/day)

GOR= Gas Oil Ratio (scf/sbbl or sm 3/sm 3)

WCUT= Watercut (%)

Notes:
1. The CONETAB table should be provided in the system profile immediately before the maincode
specifying the required IPR.
2. No other maincode should appear in the body of the table.
3. Values should be provided in increasing order of liquid flow rate.
4. If your model contains multiple completions, 2 or more CONETAB tables can be used to enter
data for each completion.
5. For BLACKOIL (p.633) fluids, the Specific Gravity of the coned and associated gas should be
provided with the PROP (p.635) statement. See example below.

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Example
For example:

! liq gor wcut conetab 0 986 0 conetab 1000 986 2.0 conetab 2699 1096 2.2
conetab 6329 2540 2.8 conetab 7288 2980 3.9 conetab 8082 3370 5.6 conetab
8805 3770 8.0

8.5.13 BACKPRES Back Pressure Equation (BPE) (Optional)

Main-code: BACKPRES
This keyword is used to specify data for the Back Pressure Equation (p.313).

Subcodes
PWSTATIC The static reservoir pressure (psia or bar)

N The back pressure exponent (dimensionless).

C The back pressure constant (dimensions of (mmscf/d)/ (psi 2) n or equivalent SI).

8.5.14 HORWELL Horizontal Well Inflow Performance

The following Inflow Performance options are available in addition to the Distributed Productivity
Index Inflow option (see WELLPI (p.569))
Pseudo-steady state equation of Babu and Odeh for oil wells
Joshi's steady-state equation
Backpressure equation
The backpressure equation is accessed via the BACKPRES maincode BACKPRES (p.580), which
applies to horizontal completions as well as vertical. As with the WELLPI maincode, WELLPI
(p.569), the backpressure C and N parameters are assumed to apply per unit length of wellbore.
The steady-state and pseudo steady-state options are both accessed via the TYPE= subcode of
the HORWELL maincode. The well completion option, WCOPTION (p.573) , can be used in
conjunction with the HORWELL maincode.
Main-code: HORWELL

TYPE= PSSOIL The PSSOIL subcode calculates the horizontal well distributive
productivity index based on Babu and Odeh's (p.499) SPE paper
18298. It is recommended the user read this reference before
applying the equation. The equation is based upon the pseudo-
steady state IPR well model applied to a rectangular drainage area.

ADIM Drainage width perpendicular to the well (ft or m).

BDIM Drainage width parallel to the well (ft or m).

THICK Reservoir thickness (ft or m).

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KX Permeability in the x-direction (that is Kh) (mD)

KY Permeability in the y-direction (parallel to well) (mD).

KZ Permeability in the z-direction (that is Kv) (mD).

XZERO X-ordinate of horizontal well trajectory (ft or m).

YONE Starting y-ordinate of horizontal well trajectory (ft or m).

YTWO Ending y-ordinate of horizontal well trajectory (ft or m).

ZZERO Z-ordinate of horizontal well trajectory (ft or m).

RWELL Sandface radius (such as pipe + annulus + cement) (in or mm).

SKIN Mechanical skin factor (dimensionless).

PSSGAS The pseudo-steady state gas flow equation is based upon a circular
drainage area and is described in Joshi's (p.504) "Horizontal Well
Technology". It is recommended that the user read this reference
and Inflow Performance Relationships for Horizontal Completions
(p.338) . This equation contains two skin terms; the skin due to
drilling/perforations and the rate-dependent skin due to turbulent gas
flow around the wellbore.

THICK Reservoir thickness (ft or m).

KX Permeability in the x-direction (that is Kh) (mD).

KY Permeability in the y-direction (parallel to well) (mD).

KZ Permeability in the z-direction (that is Kv) (mD).

RWELL Sandface radius (i.e. pipe+annulus+cement) (in or mm).

REXT External boundary radius of drainage area (ft. or m). Default = infinity

SKIN Mechanical skin factor (dimensionless).

SSOIL The simplest form of horizontal well productivity calculations are the
steady-state analytical solutions which assumes that the pressure at
any point in the reservoir does not change with time. The steady-
state distributive productivity index is based upon Joshi's (p.504)
SPE 16868 "Review of Horizontal and Drainhole Technology". The
equation is based on the assumption that the horizontal well drains
an ellipsoidal volume around the wellbore of length L. See Inflow
Performance Relationships for Horizontal Completions (p.338) , for
more details.

ECCENT Wellbore eccentricity (i.e. offset of the well from the centre of the pay
zone) (in or mm).

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THICK Reservoir thickness (ft or m).

KX Permeability in the x-direction (that is Kh) (mD).

KY Permeability in the y-direction (parallel to well) (mD).

KZ Permeability in the z-direction (i.e. Kv) (mD).

RWELL Sandface radius (that is pipe+annulus+cement) (in or mm).

REXT External boundary radius of drainage area (ft or m).

SKIN Mechanical skin factor (dimensionless).

SSGAS The steady-state gas distributive productivity equation is described in

Joshi's (p.504) "Horizontal Well Technology", Chapter 9, and Inflow
Performance Relationships for Horizontal Completions (p.338)

THICK Reservoir thickness (ft or m).

KX Permeability in the x-direction (that is Kh) (mD).

KY Permeability in the y-direction (parallel to well) (mD).

KZ Permeability in the z-direction (that is Kv) (mD).

RWELL Sandface radius (that is pipe+annulus+cement) (in or mm).

REXT External boundary radius of drainage area (ft or m).

SKIN Mechanical skin factor (dimensionless).

8.5.15 LAYER Reservoir Layer Properties

Main-code: LAYER
LAYER specifies the presence of a distinct reservoir Layer or Zone. It allows the properties of a
fluid to be defined, along with its pressure and temperature. Some additional layer-specific
properties can also be set. LAYER is intended to be used in a model that contains multiple
completions, which may be point-type, or distributed/horizontal. It should only appear within the
system profile, and be followed by a statement that selects a choice of IPR relationship, for
example, WELLPI, FETKOVICH, IFPPSSE, and so on.
All subcodes are optional.

PWSTATIC= or Reservoir layer (Static bottom hole) pressure (bara or psia). This can
PRESSURE= also be defined on the selected IPR maincode, in which case it may be
omitted from LAYER. If supplied on both, the one on the IPR will be
used.

TEMPERATURE= Reservoir layer temperature (F or C). This should be the same as the
ambient temperature on the node, and is therefore unnecessary.

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USE= or FLUIDNAME= Name of a Black Oil or Compositional fluid, as previously defined with
BEGIN FLUID (p.550) . Exclusive with PVTFILE=.

PVTFILE= Name of an existing .PVT file defining a compositional fluid. Exclusive

with USE=.

INJECT= Controls if the a layer will accept fluid injection: can be set to YES or NO,
default YES.

IPRCURVENAME= Specifies the name of an Inflow Performance and/or Coning curve for
the Completion, as defined in (a) previous IPRCRV (p.576) statement(s).

LDORATE= or Specifies a fixed, overriding value for the Specific Inflow Rate in a
MDORATE= or horizontal completion. Normally the inflow rate of a horwell is calculated
GDORATE= from the supplied Inflow Performance data, and reservoir and wellbore
pressure difference. If one of these subcodes is supplied however, all
other data is ignored, and the reservoir inflow rate is unconditionally set
to this value. LDORATE= supplies a Liquid rate (bbl/day/ft or m3/day/m);
GDORATE= supplies a gas rate (mmscf/day/ft or mmsm3/day/m),
MDORATE= supplies a mass rate (lb/sec/ft or Kg/sec/m).

EXECUTE= For use with IPRCURVENAME=. If the supplied curve specifies a

complete Inflow Performance relationship, this subcode can be used to
render it executable.

PERMCURVENAM= or Specifies the name of an Oil/Water Relative Permeability table or curve

PERMCRVNAME= for the completion, as defined in (a) previous PERMCRV (p.584)
statement(s).

SATURATION= For use with PERMCURVENAME=. Allows the reservoir saturation value
to be specified. This results in the calculation of the watercut of the
produced fluid. If absent, the specified fluid watercut is used, and
reservoir saturation calculated from it.

HBALANCE= or Specifies the thermodynamic route for calculation of temperature/

ROUTE= enthalpy change consequent upon the DP across the completion. May
be set to ISENTHALPIC, for constant enthalpy (the default), or
ISOTHERMAL, for constant temperature.

Examples
Example 1
This is a simple layer and point completion such as might appear as part of a larger multi-
completion model:

LAYER temp = 220 use = 'fluid A' label = 'Layer one'

WELLPI pwstatic = 3650 LPI=9.5

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Example 2
This completion includes a coning relationship defined with . IPRCRV (p.576) , which must appear
first. LAYER follows because it references the curve name defined in the IPRCRV. Finally the
selected IPR, JONES, comes last:

IFPCRV name=cc1 LIQ= (0 ,1000,2000,3000,4000)

IFPCRV name=cc1 GLR= (300 ,300 ,550 ,600 ,620 )
IFPCRV name=cc1 WCUT= (10 ,10 ,18 ,22 ,30 )
IFPCRV name=cc1 GASSG=(.71 ,.71 ,.68 ,.67 ,.669)
LAYER temp=240 F pres=4503 psia use='fluid B' inject=NO IPRCURV=cc1
label='Layer two'
JONES LA=1e-4 LB=3e-2

8.5.16 RESERVOIR
Main-code: RESERVOIR
This maincode is obsolete, please do not use it.

8.5.17 PERMCRV: Curves of Relative Permeability versus Saturation

(Optional)
Main-code: PERMCRV
The PERMCRV statement is an alternative to PERMTAB (p.585) . Both these statements allow a
table/curve of oil/water relative permiability to be entered as a function of water saturation. They
differ in the format of the statements: PERMTAB allows a tabular data entry format using multiple
statements, whereas PERMCRV offers subcodes that accept PIPESIM's multiple value syntax
(p.519). PERMCRV requires the curve to be given a name that can be referenced in one or more
subsequent completions.

NAME= Required. Defines the name of the curve. This name is then used on (a) subsequent
LAYER statement(s).

SAT= Water Saturation in the reservoir, as a ratio 0 to 1.

OIL= Oil relative permeability, as a ratio 0 to 1.

WAT= Water relative permeability, as a ratio 0 to 1.

The complete definition of a curve requires all subcodes to be specified, but they may be spread
over 2 or 3 statements that reference the same curve name. NAME= must appear on all
statements.

Example
This example shows a table containing the same data as the example given for PERMTAB
(p.585) :

PERMCRV name=pc1 SAT = (0.0, 0.1, 0.2, 0.3 , 0.4 , 0.5 , 0.6, 0.7 , 0.8 ,
0.9 , 1 )

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PERMCRV name=pc1 OIL = (0.9, 0.9, 0.9, 0.6 , 0.43, 0.35 , 0.2, 0.13, 0.07,
0 , 0 )
PERMCRV name=pc1 WAT = (0.0, 0.0, 0.0, 0.05, 0.1 , 0.125, 0.2, 0.33, 0.44,
0.44, 0.44)
layer PERMCURV=pc1 temp = 185 F use = oil44 inject=no label = 'strat
bk'
ifppsse pwstatic = 4269 psia perm = 200 md thickness = 50 ft &
rade = 2000 ft skin = 2 diamwell = 5 in

8.5.18 PERMTAB: Tabulation of Relative Permeability versus Saturation

(Optional)
Main-code: PERMTAB
The PERMTAB statement is an alternative to PERMCRV. (p.584) Both statements allow entry of a
table of oil and water relative permeability against water saturation, in a different format.
Each PERMTAB statement holds a single data point. To complete the tabulation, at least four
statements are required. PERMTAB does not define an IPR relationship, it should only be used in
addition to the IFPPSSE maincode. If provided with any other IFP maincode it will be ignored.
Values should be provided without keywords in a strict positional order, as follows:

value 1 Water Saturation in the reservoir, as a ratio 0 to 1.

value 2 Oil relative permeability, as a ratio 0 to 1.

value 3 Water relative permeability, as a ratio 0 to 1.

Notes:
1. The PERMTAB table should be provided in the system profile immediately before the IFPPSSE
maincode.
2. No other maincode should appear in the body of the table
3. Values should be provided in increasing order of Water Saturation
4. If your model contains multiple completions, 2 or more PERMTAB tables can be used to enter
data for each completion.

Example
This example shows a table containing the same data as the example given for PERMCRV
(p.584) :

! wsat oil rp water rp

permtab 0.0 0.9 0.0
permtab 0.1 0.9 0.0
permtab 0.2 0.9 0.0
permtab 0.3 0.6 0.05
permtab 0.4 0.43 0.1
permtab 0.5 0.35 0.125
permtab 0.6 0.2 0.2
permtab 0.7 0.13 0.33

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permtab 0.8 0.07 0.44

permtab 0.9 0.0 0.44
permtab 1.0 0.0 0.44
layer temp = 185 F use = oil44 inject=no label = 'strat bk'
ifppsse pwstatic = 4269 psia perm = 200 md thickness = 50 ft &
rade = 2000 ft skin = 2 diamwell = 5 in

8.5.19 HVOGEL (Optional)

Main-code: HVOGEL

PWSTATIC=

AOFP= Absolute open flow potential

RF= Recovery factor

8.5.20 FORCHHEIMER (Optional)

Main-code: FORCHHEIMER
see the JONES (p.571) maincode.

8.5.21 FRACTURE: Data for Hydraulic Fracture

Main-code: FRACTURE
This maincode specifies that the mechanical and dynamic skin factors are to be calculated from
the details of the well fracture configuration provided. Note: The fracture options are only valid
when used in conjunction with the Pseudo-Steady-State or Transient equations (as defined under
the IFPPSSE and TRANSIENT main-codes).
The FRACTURE maincode is an alternative to the WCOPTION maincode, WCOPTION (p.573),
and is exclusive with it.

PERMEABILITY= Average fracture permeability (md).

WIDTH= Average fracture width (feet or metres).

LENGTH= Fracture half-length (feet or metres).

RESAREA= Reservoir area (square feet or square metres).

TRANSIENT= Controls the Transient option. May be set to ON or OFF. Default OFF.

POROSITY= Reservoir porosity (dimensionless, a value between 0 and 1.) Ignored unless
TRANSIENT=ON.

COMPRESS= Reservoir compressibility (1/psi or 1/Bar). Ignored unless TRANSIENT=ON.

TIME= Elapsed time since start of production (hours). Ignored unless

TRANSIENT=ON.

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CONDUCTIVITY=

See also Hydraulic Fracturing.

8.5.22 TRANSIENT: Data for the Transient Inflow equation (Optional)

Main-code: TRANSIENT

PWSTATIC= Static bottom hole pressure (bara or psia). This is the bottom
hole pressure at zero flow rate.

PERMEABILITY= Average formation permeability (md).

THICKNESS= Average formation thickness (metres or feet) .

RADEXTERNAL= Radius of external boundary of drainage area (metres or feet).

Default = 609.6 m or 2000 ft.

SKIN= Dimensionless skin factor. Default = 0.

DIAMWELLBORE= Wellbore diameter (inches or mm).

FLOWTYPE= Type of flow in well.

LIQ Liquid flow

GAS Gas flow

GASMETHOD=

PSEUDO Use pseudo pressure

SQUARED Use pressure squared

SOURCE=

ST Use the stock tank flow formulation of the transient IPR equation
(default)

RES Use the reservoir flow formulation of the transient IPR equation

BPCORRECTION= Allows user to choose whether to apply the Vogel correction

below the bubble point.

ON Applies Vogel correction.

OFF Does not apply Vogel correction.

PICOEFFICIEN= Vogel coefficient for Vogel correction. Default = 0.8.

DSKINLIQUID= Dynamic skin for liquid phase. Default = 0.

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DSKINGAS= Dynamic skin for gas phase. Default = 0.

DRAINAGESKIN=

POROSITY= Porosity of the reservoir, fraction (0 - 1)

COMPRESSIBIL= Total system compressibility (1/psi or 1/bar).

TIME= Time since the well started to flow, hours.

SWAPTOPSS=

ON

OFF

8.6 SYSTEM DATA

PIPE (p.615) Pipe Dimensions
INLET (p.539) System Inlet Data
EQUIPMENT (p.354) Equipment Data
NODE (p.614) System Profile Data
Changing Parameters within the System Profile (p.522)
SLUG (p.556) Slug Calculation Options
COMPRESSOR (p.595) Compressor
CHOKE (p.589) Choke
EXPANDER (p.599) Expander
HEATER (p.603) Heater/Cooler
PUMP (p.617) Pump
ESP (p.617) Electrical submersible Pump
PCP (p.387) Progressive Cavity Pump
MPUMP (p.612) Multiphase Pump
PUMPCRV (p.611) Pump Performance Curves
COMPCRV (p.593) Compressor Performance Curves
SEPARATOR (p.621) Separator
EROSION (p.555) Erosion Rate and Velocity
CORROSION (p.555) Corrosion Rate
COMPLETION (p.567) Completion Profile Delimiter
TUBING (p.567) Tubing Profile Delimiter
FLOWLINE (p.567) Flowline Profile Delimiter

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RISER (p.567) Riser Profile Delimiter

FMPUMP (p.602)
REINJECTOR (p.620)
MPBOOSTER (p.611)

8.6.1 CHOKE (Optional)

Also refer to Choke Theory (p.355)
Main-code: CHOKE
All subcodes are optional unless noted otherwise:

DBEAN= Required. Diameter of the choke bean (mm or inches)

DBEAN64= An alternative to DBEAN=, allows the bean diameter to be

specified in units of 1/64 in.

CCORR= Selects the Critical flow correlation. May be one of:

GILBERT Gilbert (p.362) correlation

ROS Ros (p.362) correlation

BAXENDELL Baxendell (p.362) correlation

ACHONG Achong (p.362) correlation

PILEHVARI Pilehvari (p.362) correlation

ASHFORD Ashford and Pierce (p.361) correlation

ASHFORDT Sachdeva (p.361) correlation

POETBECK Poetmann and Beck (p.361) correlation

OMANA Omana (p.361) correlation

THEORY or (default) The MECHANISTIC choke model is purely

MECHANISTIC theoretical, based on a combination of Bernoulli's equation
with an equation of continuity. Advanced users may wish to'
fine-tune' the model, or override some of the calculated
values, by means of the sub-codes CD, CSP, CPCV, YCRIT,
GASCP,and LIQCP.

USER User-supplied (p.362) correlation. This uses the same

equation as the Gilbert,Ros (p.362) and so on correlations,
but with parameters supplied with the subcodes A=, B= C=
and E=.

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SCCORR= Selects the required sub-critical flow correlation. Maybe one

of:

ASHFORD = Ashford and Pierce (p.361) correlation

MECHANISTIC (default) The MECHANISTIC choke model (see above).

API14B This is a special-case of the MECHANISTIC model, wherein

the GAS and Liquid Csp values are preset to 0.9 and 0.85
respectively.

CPRATIO= Pressure ratio at which flow through choke becomes critical.

(Default = 0.53). (It is also possible to force PIPESIM to
calculate the Critical Pressure Ratio; to do this, enter
CPRATIO=0.0.)

TOL= Percentage tolerance, for identification of critical flow

conditions. (Default 0.5%)

CD= Discharge coefficient (default = 0.6). This value is used to

calculate the flow coefficient, CSP.

CSP= Flow coefficient. This is normally calculated by PIPESIM, but

can be overridden, if desired, by use of this sub-code. The
valid range is 0 to 1.3, typically it is 0.6. It is used to calculate
the pressure drop.

CPCV=
/
Fluid-specific heat ratio, = CP CV . This is normally
calculated by PIPESIM, but can be overridden if desired. The
valid range is 0.7 to 2. Typically it is 1.26 for a natural gas, for
a diatomic gas it is 1.4. It is used to calculate the critical
pressure ratio, if CPRATIO=0.0 is specified.

YCRIT= Gas expansion factor at critical flow. This is normally

calculated by PIPESIM, but can be overridden if desired. The
valid range is 0.5 to 1. It is used to modify the pressure drop
equation to allow for gas compressibility.

GASCSP= Flow coefficient for the gas phase. This is normally equal to
the value calculated or input for CSP, but can be overridden if
desired. For API14B compatibility, set it to 0.9.

LIQCSP= Flow coefficient for the liquid phase. This is normally equal to
the value calculated or input for CSP, but can be overridden if
desired. For API14B compatibility, set it to 0.85.

CRITERION= Allows the reasons for identification of critical, and

supercritical, flow to be defined. This subcode will accept one
or more of the following values, supplied in multiple value
syntax (p.515) :

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PRATIO Pressure ratio < critical pressure ratio (default)

FLOWRATE Flowrate flowrate at critical flow

SONICUP Upstream velocity sonic

SONICDOWN Downstream velocity sonic

ALL All of the above

NONE The value NONE will effectively prevent the identification of

critical and supercritical flow, thus flow will always be
subcritical. NONE should be used for API14B compatibility.

VERBOSE= ON or OFF (Default OFF). Allows detailed choke calculation output for the
MECHANISTIC correlation. The detailed output appears on
the user's terminal screen and on the primary output page.
This output is intended primarily to aid the development and
debugging of the choke model, but can also be of use to the
advanced user.

SCADJUST ON or OFF If ON, the selected sub-critical correlation is adjusted to

ADJUSTSC= ensure it predicts a flowrate at critical pressure ratio that
matches that predicted by the critical correlation. Default is
OFF.

A=, B=, C=, E= Parameters for the USER critical correlation.

IDPIPE= or The diameter of the upstream pipe section (in or mm). It is

DPIPE= or used to calculate the Diameter Ratio (For more information,
PIPEID= refer to Choke Geometry (p.355).) This subcode is required
only if the choke is present in a branch and there is no other
accompanying pipe equipment. If the subcode is provided,
PIPESIM uses that value instead of the ID from any existing
upstream pipe.

MAXMASS= Maximum mass rate (lb/sec or Kg/sec).

MAXGAS= Maximum gas rate (mmscfd or mmsm3d).

MAXLIQUID= Maximum gross liquid rate (sbbl/day or sm3/day).

MAXOIL= Maximum oil rate (sbbl/day or sm3/day).

MAXWATER= Maximum water rate (sbbl/day or sm3/day).

Note: Notes for rate limit subcodes:

All rate limit values refer to the fluid at stock-tank pressure and temperature, 14.7 psia and 60F.
There is no provision for limiting phase flowrates at flowing or in-situ pressure and temperature.

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Application of any rate limit will result in the choke bean diameter being reduced from its
supplied value (in the DBEAN= subcode).This will cause an additional pressure drop in the
system or branch.
Any combination of rate limits may be specified. The choke will be sized to ensure that none of
them are exceeded.
In a single-branch model, the rate limits will be applied at the choke where they are specified.
In a network model, the limits will be "promoted" to the network branch level, and will be treated
as though they were specified on the BRANCH (p.678) statement. The network solution
algorithm will apply the rate limits at the inlet of the branch containing the choke.
In a network model, the rate limits will apply regardless of the direction of fluid flow in the
branch

The choke model will calculate the pressure ratio across the choke for the current flow rate. The
pressure ratio calculated is then categorized in one of 3 ways:
Subcritical
The pressure ratio (Pout/Pin) is higher than the critical pressure ratio. PIPESIM continues
the case with the calculated pressure drop.
Critical
The pressure ratio is within the tolerance of the critical pressure ratio. PIPESIM continues
the case with the calculated pressure drop, and writes an explanatory message to all
output pages. Pressures calculated in the profile from this point on represent maximum
values rather than true values; in reality, the pressures could be less than those reported.
The reason for this is that in critical flow, the flow rate is independent of the system's
downstream pressure.
Supercritical
The pressure ratio is lower than the critical pressure ratio. This represents a situation that
cannot occur in reality, therefore PIPESIM will abort the case or iteration. In a non-iterative
case, this will result in a CASE ABORTED message, but in an iterative case, a further
iteration is started, at a higher inlet pressure or lower flow rate.
PIPESIM does not attempt to model the entire system analytically, rather it breaks it down into
small elements, each of which are then analyzed in turn to achieve the desired answer. Because
the system's heat balance is calculated rigorously at every element, it is not possible for PIPESIM
to work backwards up the system profile from a known outlet pressure. Consequently, if the user
fixes the outlet pressure, an iterative solution to the case is required. For non-iterative cases,
PIPESIM starts its analysis of the profile with a fixed inlet pressure and flow rate. Iterative cases
are made up of several passes down the profile, with the iteration routine taking informed guesses
at the inlet pressure or flow rate; thus, for each separate iteration, the inlet pressure and flow rate
are effectively fixed, as for the non-iterative case.
When PIPESIM encounters a choke in the profile, it evaluates the pressure drop across the choke,
and labels it as one of critical, subcritical, or supercritical. The supercritical condition means that
the current flow rate cannot pass through the choke with the current upstream pressure: i.e., it is a
situation that cannot occur in reality. (Another example of such an impossible situation is a

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negative pressure; PIPESIM must cope with this too). PIPESIM deals with this by aborting the case
or iteration. If the case is iterative, the iteration routine will then guess a lower flow rate or higher
inlet pressure, and another pass down the profile will begin. The critical condition is comparatively
difficult to hit; it means that, at the current pressure upstream of the choke, the flow rate is very
close to the maximum possible flow rate through the choke. When critical conditions exist, the flow
rate is independent of the downstream pressure. The subcritical condition needs no special
handling.
In an iterative case, it often happens that the user's specified outlet pressure cannot be met. This
occurs when a choke in the profile is in critical flow. Any increase in the flow rate will result in
supercritical flow through the choke, and so this sets an upper limit for the iteration routine.
However, the outlet pressure for the flow rate that gives critical flow might be much higher than that
required. Normally in this situation, the iteration routine would increase the flow rate and try again,
but the presence of the choke in critical flow makes this pointless. Therefore, the iteration routine
considers the case to have converged on a solution, and prints the case results. The pressure
profile on the downstream side of the choke, while it does not represent the actual required
solution, nevertheless represents the maximum pressure that can be achieved there; in reality, the
pressures will be lower.
A wellhead choke or bean is used to control the production rate from a well. In the design of tubing
and well completions one must ensure that neither the tubing nor the perforations control the
production from the well. The flow capacity of the tubing and perforations always should be greater
than the inflow performance behavior of the reservoir. It is the choke that is designed to control the
production rate from a well. Wellhead chokes usually are selected so that fluctuations in the line
pressure downstream of the choke have no effect on the well flow rate. To ensure this condition,
flow throughout the choke must be at critical flow condition; that is, flow through the choke is at
acoustic velocity. For this condition to exist, downstream line pressure must be approximately 0.55
or less of the tubing or upstream pressure. Under this conditions the flow rate is a function of the
upstream or tubing pressure only.
Chokes are subjected to sand and gas cutting as well as asphalt and wax deposition, which
changes the shape and size of the choke. This then could result in considerable error when
compared to calculate values of choke for a standard choke size. A small error in the choke size
caused by a worn choke can produce a much larger error in the predicted oil rate. Thus a 'cut'
choke could result in estimated oil rates considerably lower than measured.
From the inflow performance relationship of a well and by knowing the tubing size in the well, the
tubing pressure curve for various flow rates can be calculated.

8.6.2 COMPCRV and PUMPCRV: Compressor and Pump performance

curves
Main-code: PUMPCRV or COMPCRV
Centrifugal pump and compressor performance curves are specified as a range of head and
efficiency or power values versus volumetric flow rates. These values should be specified before
the profile, and each curve is given a name so it can be referenced on a subsequent PUMP or
COMPRESSOR statement.

NAME= Required: The name of the curve, for referencing on a subsequent PUMP or
COMPRESSOR statement.

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SPEED= The speed for which this curve was generated. (rpm)

Q= Values of flow rate, supplied as a multiple value set (p.515) . Flowrates are
measured in volumetric terms at the flowing pressure and temperature at the inlet
to the device. For a pump curve, units are bbl/day or m3/day; for a compressor
curve, they are ft 3/min or m3/sec. (See note below).

FLOWRATE= Synonym for Q =.

HEAD= Values of head, supplied as a multiple value set (p.515). For a pump curve, units
are feet or metres. For a compressor curve they are ft-lbf/lbm (foot-pounds force
per pound mass) or Kj/kg. Note that the conversion factor between ft-lbf/lbm and
feet is 1.

EFFICIENCY= Values of efficiency (%), supplied as a multiple value set (p.515). (Default is
100%). Exclusive with POWER=.

POWER= Values of power (hp or kw), supplied as a multiple value set (p.515). Exclusive
with EFFICIENCY=.

STAGES= For a Pump curve only, the number of stages for which this curve is defined
(normally 1).

WHEELS= For a compressor curve only, the number of compressor wheels for which this
curve is defined.

The multiple value sets (p.515) supplied for Q=, HEAD=, and EFF= or POWER= sub-codes must
contain at least 3, and no more than 30 values, separated by commas, and enclosed in
parentheses. The values need not be entered in ascending or descending order, however there is
a strict one-for-one correspondence between the values in each list, based on their position. Each
list must contain the same number of values.
Since the multiple value lists can be quite lengthy, they may be supplied across more than one line
in the input file. This can be achieved either by use of the continuation character &, or by repeating
the maincode and curve name on each line. The examples below illustrate this, they both have the
same effect:

Examples
Example 1

PumpCrv name = GN7000 stages = 100 speed = 3600

PumpCrv name = GN7000 Q = (1250 ,3750 ,5800 ,7400 ,
9000 ,10666.7)
PumpCrv name = GN7000 head = (4827.88 ,4176.29,3624.68,3160.3 ,
2338.76,971.734)
PumpCrv name = GN7000 eff = (23.6865 ,
55.0738,67.3463,71.3873,63.476 ,31.7383)

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Example 2

PumpCrv name = GN7000 stages = 100 speed = 3600 &

Q = (1250 ,3750 ,5800 ,7400 ,9000 ,10666.7) &
head = (4827.88 ,4176.29,3624.68,3160.3 ,2338.76,971.734) &
eff = (23.6865 ,55.0738,67.3463,71.3873,63.476 ,31.7383)

8.6.3 COMPRESSOR Compressor (Optional)

Main-code: COMPRESSOR
Sub-codes: TYPE, ROUTE, POUT, DP, PRATIO, POWER, EFF, NAME, SPEED, WHEELS,
STONEWALL VERBOSE

TYPE= COMPRESSOR type.

CENTRIFUGA Centrifugal compressor

ROUTE= ADIABATIC Adiabatic compression is performed (default). For black oil

models the heat capacity ratio (C p/C v) for the adiabatic exponent
in the compression equations is assumed to be constant with a
value equal to 1.26. For compositional models the heat capacity
ratio is calculated using the relationship: Cp = Cv - R The heat
capacity is obtained at the average of the compressor suction and
discharge conditions.

POLYTROPIC Polytropic compression is performed. The heat capacity ratio (C

p/C v) is calculated as outlined above for ADIABATIC
compression. This is the default for Black Oil cases.

MOLLIER Compression is based upon the Mollier method, that is

isoentropic compression from suction to discharge pressures.
This option is valid for compositional models only, where it is also
the default.

POUT= Discharge pressure from the compressor (bara or psia) (default

20,000 psia)

DP= Pressure differential across the compressor (bar or psi) (default

10,000 psi)

PRATI= Compressor pressure ratio (default 1000)

POWER= Power available for compression (KW or hp) (default unlimited)

EFF= Overall efficiency of the compression (default = 100%)

NAME= The name of a previously specified Compressor Curve (see the

COMPCRV (p.593) maincode)

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SPEED= Speed at which the compressor will run. This is only useful when
a compressor curve name has been specified. (rpm) (default
unlimited)

WHEELS=

STONEWALL=

VERBOSE=

Notes:
1. At least one of the subcodes POUT, DP, PRATIO, POWER and SPEED should be supplied. If
2 or more are present, PIPESIM will treat them as upper limits, and will use whichever gives the
smallest DeltaP. The others will be recalculated and displayed as answers on the output file.
2. If a compressor curve name is supplied, the speed may also be specified. This is used to adjust
the supplied curve against its specified speed (as set with SPEED (p.593) = on the COMPCRV
(p.593) maincode). The adjustment is done using the so called affinity or fan laws, which state
that "capacity is directly proportional to speed, head is proportional to square of speed, and
power is proportional to cube of speed".
3. In order to avoid confusion with the COMPOSITION main code, the minimum abbreviation
acceptable for COMPRESSOR is COMPR.

8.6.4 RODPUMP: Rod- or Beam-pump

Main-code: RODPUMP or CVFMD
The RODPUMP statement allows the outline specification for a Rod- or Beam-pump to be
supplied.
A rod-pump is an example of a Constant Volume Fluid Motive Device (CVFMD). CVFMDs are
fixed-volume, positive-displacement pumps or compressors designed to move liquids, gases or 2-
phase mixtures. Other notable CVFMD examples are: Progressive cavity pumps, Twin screw
multiphase boosters, and reciprocating compressors. The statement allows a simplistic simulation
of such a device to be performed.

NOMLIQRATE= The flowing volume flowrate that the pump would produce, if it were pumping
with no back-pressure at its discharge (m3/day or bbl/day).

SLIPCOEF= A coefficient to specify the change in flowrate with respect to Delta pressure
(m3/day/bar or bbl/day/psi). This is used to compute the pressure rise across
the device when the actual flowrate is less than the specified nominal rate.

MAXDP= Maximum pressure rise the device is allowed to exhibit (psi or bar). This is
used to prevent excess rod loading.

MAXPOWER= Maximum power the device is allowed to draw (hp or kw). This is used to
prevent excess rod loading.

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RODDIAMETER= The Diameter of the drive rod (in or mm). The drive rod will be assumed to
exist in the downstream pipe or tubing, and will stretch up to the wellhead or
the end of the tubing. The fluid will flow in the annular space between the
tubing ID and the rod OD. The rod diameter can be adjusted in downstream
pipe sections by use of the RODDIAM= subcode on the PIPE (p.615)
statement, this is useful to simulate taper rods.

VOLUME= The swept volume of the pump cylinder, i.e. its cross-section area multiplied by
the stroke length (bbl or m3). In conjunction with SPEED=, this is an alternative
to the nominal rate.

SPEED= The pump speed, in strokes per minute. In conjunction with VOLUME=, this is
an alternative to the nominal rate.

NOMINALRATE= The flowing volume flowrate that the pump would produce, if it were pumping
with no back-pressure at its discharge (m3/sec or ft3/min). this is the same
information as NOMLIQRATE= but in different units, more suited to other types
of CVFMD.

8.6.5 EQUIPMENT Generic Equipment

Main-code: EQUIPMENT
The EQUIPMENT maincode may be used to simulate a generic unit operation in which the
pressure and/or temperature of the stream are modified.

DP= Pressure gain (positive), or loss (negative). (Bar or psi). NB. In a network model,
the DP is assumed to follow the flow direction in the branch, so if the branch flow
reverses, the DP will change sign. This can be controlled with DPIFD=, see
below. See note 2

DPIFD= "DP is Independent of Flow Direction". Set this to YES to ensure the sign of the
dp supplied with DP= is independent of branch flow direction in a network model.
Default is NO, thus if the branch flow reverses, the dp will change sign. An
example of a device whose DP is direction -independent is a choke. An example
of a direction-dependent DP is a vertical section of pipe.

POUT= or Equipment outlet set pressure (bara or psia). NB. In a network model, the
SETP= imposition of a set pressure is likely to prevent the model from converging. In a
single-branch model, if the outlet pressure and flowrate are fixed, the use of
SETP= will cause an input data error. See note 2

PRATIO= Pressure Ratio: the equipment outlet pressure is set to the specified multiple of
the inlet pressure. Exclusive with MAXP=, MINP=, SETP= and DP=. See note 2.

MAXP= Maximum pressure (psia or bara). If the pressure at the equipment is greater than
the supplied limit, then it will be adjusted down to the limit. See note 3.

MINP= Minimum pressure (psia or bara). If the pressure at the equipment is less than the
supplied limit, then it will be adjusted up to the limit. See note 3.

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ROUTE= Allows the thermodynamic route to be specified, for calculation of fluid

temperature change consequent upon changes in pressure. Exclusive with DT=
and SETT= ;can be used with DUTY=. See note 4. Available choices are:

ISENTHALPIC or ADIABATIC: Constant enthalpy (default)

ISENTROPIC or MOLLIER: Constant entropy (compositional cases only)

ISOTHERMAL: Constant temperature

DT= Temperature gain (+ve), or loss (-ve). (C or F). See note 1.

TOUT= or Outlet set temperature ( &deg;C or&deg;F). See note 1.

SETT=

DUTY= Duty to be used to raise the temperature of the fluid (KW or Btu/hr). See notes 1,
4 and 6.

MAXT= Maximum temperature (F or C). If the temperature at the equipment is greater

than the supplied limit, then it will be adjusted down to the limit. See note 7.

MINT= Minimum temperature (F or C). If the temperature at the equipment is less than
the supplied limit, then it will be adjusted up to the limit See note 7.

NAME= Defines the NAME of a user-supplied equipment entrypoint, as defined in a prior

USERDLL statement. Note: The presence of this subcode causes all others
(except OPTIONS=) to be ignored.

OPTIONS= A character string that is supplied to the user-supplied equipment routine. Must be
used with NAME=.

VERBOSE= Controls the appearance of the one-line output in the report. may be set to ON or
OFF, default ON.

Notes:
1. The subcodes SETT=, DT= and DUTY= are mutually exclusive.
2. The subcodes SETP=, DP= and PRATIO= are mutually exclusive.
3. If a MAXP= or MINP= is specified, the limit is applied AFTER any pressure change resulting
from a SETP=, DP= or PRATIO=, and BEFORE any temperature or enthalpy change is applied
or calculated.
4. If SETT= or DT is specified, the fluid outlet temperature will be set accordingly, otherwise it will
be calculated using the selected (or defaulted) thermodynamic ROUTE= and DUTY=.
5. If SETP=, DP= or PRATIO= are specified in the absence of TOUT and DT, the choice of
thermodynamic route is used to calculate the fluid outlet temperature. To simulate chokes and
to predict Joule-Thomson cooling across pressure reduction valves etc. the most appropriate
route is ISENTHALPIC (the default).

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6. If a DUTY is specified, the corresponding fluid enthalpy change will be calculated, and added to
that resulting from any pressure change using the selected ROUTE=. The outlet temperature is
then adjusted accordingly.
7. If a MAXT= or MINT= is specified, the limit is applied AFTER any temperature change resulting
from any other subcode.
8. All subcodes are optional.

Examples
Example 1
A pipeline compressor station (located at distance 120 Km and elevation 20 m) raises the pipeline
pressure 35 bar and after coolers cool the compressed gas down to 40 C before it reenters the
pipeline. Pipeline gas is withdrawn to power the compressors, so a RATE statement is used to
subtract 2.5 kg/sec from the pipeline. The following three lines define the compressor station:

NODE DIST= 120 km ELEV= 20 m

EQUIPMENT DP = 35 bar SETT = 40 C
RATE ADDMASS = -2.5 kg/sec

Example 2
A wellhead choke is to be set to reduce the calculated wellhead pressure to 60 bara. The program
will calculate the resulting temperature change across the choke (assuming an isoenthalpic
expansion) :

EQUIPMENT SETP = 60 bar

8.6.6 EXPANDER Expander (Optional)

Main-code: EXPANDER

DP= Pressure differential across the expander (bar or psi) (default 10,000)

POUT= Discharge pressure from the expander (bara or psia) (default 20 psia)

PRATIO= Expander pressure ratio (Pin/Pout ; default 1000)

EFF= Overall efficiency of the expansion (%) (Default = 100%)

POWER= Power required from expansion (KW or hp) (default unlimited)

ROUTE=

ADIABATIC Adiabatic expansion is performed (default). For black oil models

the heat capacity ratio (C p/C v) used as the adiabatic exponent in
the expansion equations is assumed to be constant with a value

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equal to 1.26 . For compositional models the heat capacity ratio is

calculated using the relationship : Cp = Cv - R. The heat capacity
is obtained at the average of the expander suction and discharge
conditions.

POLYTROPIC Polytropic expansion is performed. The heat capacity ratio (C p/C

v) is calculated in a similar manner to that outlined above for
ADIABATIC expansion. This is the default for Black Oil cases.

MOLLIER Expansion is based upon the Mollier method, that is isoentropic

expansion from suction to discharge pressures. This option is
valid for compositional models only, where it is the default.

UNDEFINED Undefined

NAME=

SPEED=

WHEELS=

STONEWALL=

ON

OFF

VERBOSE=

ON

OFF

Note: At least one of the subcodes POUT, DP, PRATIO, and POWER should be supplied. If 2 or
more are present, PIPESIM will treat them as upper limits, and will use whichever gives the
smallest DeltaP. The others will be recalculated and displayed as answers on the output file.

8.6.7 FITTING : Valves and Fittings

Main-code: FITTING
Pipe fittings can be modeled in PIPESIM using the FITTING keyword. Either a resistance
coefficient should be specified, or the type and dimensions of the fittings should be specified and
the resistance will be calculated.

TYPE= "GLOBE-CONV" Globe Valve Conventional

"GLOBE-YPAT" Globe Valve Y-Pattern

"ANGLE-CONV" Angle Valve Conventional

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"CHECK-SWING1" Check Swing Valve Conventional

"CHECK-SWING2" Check Swing Valve Clearway

"CHECK-LIFT1" Check Lift Globe Valve

"CHECK-LIFT2" Check Lift Angle Valve

"BALL-VALVE" Ball Valve

"GATE-VALVE" GateValve

"ELBOW-STD45" Standard 45 degree Elbow

"ELBOW-STD90" Standard 90 degree Elbow

"ELBOW-LR90" Standard 90 degree Long Radius Elbow

"ELBOW-SR90" Standard 90 degree Short Radius Elbow

"TEE-RUN" Tee - Flow through run

"TEE-BRANCH" Tee - Flow through branch

NOMINALD Nominal diameter (mm or inches)

MINORD= Minor internal diameter (mm or inches)

MAJORD= Major internal diameter (mm or inches)

DANGLE= Deflection angle

KVALUE = Resistance coefficient

If the resistance K is not specified it will be calculated. In this case the nominal diameter (p.483)
must be specified, together with the internal diameter of the fitting. Some fittings require two
internal diameters to be specified, the minor diameter d1 at a constriction and the major diameter
d2.

If the resistance is specified, one of the internal diameters (d1 or d2) should also be specified. If
both internal diameters are specified, the resistance is assumed to apply at the major internal
diameter d2, that is K = K 2.
See the Technical description (p.363) for further details.

EXAMPLES
The fitting keyword can be inserted between node keywords in a pipe. The fitting is placed
immediately after the preceding node.

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...
node dist = 0 elev = 0
node dist = 1000 elev = 0
fitting kvalue = 1.6 majord = 4.815
node dist = 1010 elev = 0
fitting type = "ANGLE-CONV" nominald = 5 majord = 5.047 minord = 4 dangle =
45
node dist = 1200 elev = 0
...

8.6.8 FMPUMP (Optional)

Main-code: FMPUMP

8.6.9 FRAMO 2009 (Optional)

See also Multiphase Boosting Technology (p.372), Framo 2009 Helico-Axial Multiphase Booster.
Main-code: FRAMO2009
This keyword requests a Framo pump, modelled with the framo2009 dll provided by Framo.

POUT= Discharge pressure from the pump (bara or psia)

DP= Pressure differential across the pump (bar or psi)

PRATIO= Pump pressure ratio

POWER= Power available for pump (KW or hp)

LIMSPEED= Maximum pump speed (valid range 0.2 1.0)

TUNE= Tuning parameter (valid range 0.7 1.5)

QRECIN= Flow in recirculation

NPARA= Number of pumps in parallel (valid range 1-7)

NAME= The name of the pump

FILE= Framo file containing pump performance curves. This sub-code must be specified.
Only the file name should be specified, not the path. The file must exist in the
framo09 sub-directory of the PIPESIM data directory (default location C:\Program
files\Schlumberger\PIPESIM\data\framo09).

PLOT Requests a pump performance plot. A plot file called file_n.pfm will be created in
the model directory, where file is the pump name specified by the NAME sub-
code and n is the case number.
The pump name should be unique, otherwise plot files will over write each other.
If the NAME sub-code is not given, the plot file will be called framopump_n.pfm.
Pump performance plot files can be viewed by PSPlot.

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EXAMPLE
framo2009 file='framopump.dat' name='test' dp=100 plot

8.6.10 HEATER Heater/Cooler (Optional)

Main-code: HEATER

DP= Pressure drop across the heater (bar or psi) (Default =0)

POUT= Discharge pressure from the heater (bara or psia)

PRATIO= Pressure ratio across the heater

TOUT= Discharge temperature from the heater (oC or oF)

DT= Temperature drop/increase through the heater/cooler (oC or oF)

VERBOSE=

STATUS=

Notes:
1. The subcodes TOUT DT and DUTY are mutually exclusive only one should be supplied.
Specification of the outlet temperature or DT will result in the calculation of the duty required to
meet these conditions. If the DUTY is supplied PIPESIM will calculate the outlet temperature.
2. The subcodes POUT and DP are mutually exclusive and optional. Changes in pressure across
a heater are modeled using an isoenthalpic route; if large pressure changes are required you
are better served by modeling the DP with a separate EQUIPMENT maincode which gives a
choice of route.

8.6.11 GASLIFT: Multiple Injection Ports in Gaslifted Wells

The GASLIFT statement is required to simulate the multiple gas lift valves resulting from a Gas Lift
Design in the PIPESIM GUI. It is also used to calculate the Deepest point of Injection (DIP).
GASLIFT should be entered in the initial part of the input file, ie. before the profile or the first NODE
statement. It specifies generic gas lift data such as casing head pressure (CHP), injection gas flow
rate and properties, etc. The profile may then include one or more INJPORT statements to specify
the position and properties of the gas lift valves.
Two modes of operation are available, viz. Deepest Injection Point (DIP), and Simulate; these are
selected with the MODE= subcode.
In DIP mode, PIPESIM will calculate the deepest possible injection point for the system as
specified. Any existing injection points and gas lift valves will be ignored. Required subcodes for
this mode are INJGASRATE=, DP=, CHP= and TEMP=.
In SIMULATE mode, PIPESIM will accept a set of gas lift valves positioned at various depths in the
system profile. Each valve has its associated settings such as Port diameter, test rack Pressure

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Setting. etc. The program will simulate the entire system as specified, determining which valve(s)
are operating, and calculate the injection gas flowrate through each valve. Required subcodes for
this mode are MAXQ=, CHP=, and TEMP=.
For either mode, the recommended job will fix the reservoir pressure and outlet (wellhead)
pressure, and calculate the system flowrate; i.e., use ITERN (p.537) TYPE=LFLOW. (Other
iteration types are more difficult to use since the design of the gaslift system constrains the
Injection valves to a narrow range of operating pressure, outside which no gas injection will occur,
rendering meaningful results unlikely.)

Main-code: GASLIFT
MODE= Required. Specifies the operational mode for the gaslift system. Available
modes are:

SIMULATE: requests a rigorous simulation of the system with a set of gas

lift valves installed. The important feature of this mode is that it calculates
the total flowrate of gas that is injected into all the valves, using the
positions and settings of the installed gas lift valves. Be aware however,
that this mode is very sensitive to the exact position and settings of the
valves. Consequently its results are usually difficult to interpret due to the
likleyhood multiple solutions, or no solution, to the model cases. For this
reason, PIPESIM uses one of the DIP modes instead (see below). Injection
valves must be provided at appropriate depths with INJPORT (p.607)
statements.

DIP: requests a calculation of the Deepest Injection Point (DIP). In this

mode, any existing Injection valves will be ignored. The program will
simulate the injection of gas at the maximum possible depth for the given
system parameters, and report the calculated DIP depth. In this mode the
fixed flowrate of gas as specified with INJGASRATE= is injected at the
deepest depth.

DIP3: similar to DIP mode, but the calculated deepest injection depth is
constrained to be coincident with the position of one of the existing injection
valves specified with INJPORT statements. See note 2.

MAXFLOWRATE= or Required for MODE=SIMULATE. The maximum available lift gas flow rate
MAXQ= (MMscf/d or MMm 3/d).

TEMPERATURE= Required. The temperature of the lift gas (F or C) at the casing head. The
program will adjust this by a formula that takes account of geothermal
temperature gradient and production temperature to calculate the annulus
temperature for each injection valve.

CHP= Required. The casing head pressure (psia or bara) at the wellhead where
the lift gas is supplied to the well. The program will adjust this by the
pressure of the static head of gas in the annulus between the wellhead and
the injection port to calculate the annulus pressure for each injection valve.

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DP= Required for MODE=DIP. The minimum allowable pressure difference

across the injection valve. The valve will be positioned at a depth that
ensures the DP between casing and tubing is at least this value. (psi or
bar)

FLOWRATE= or For MODE=DIP. The flow rate of lift gas (MMscf/d or MMm 3/d) to be
INJGASRATE= injected. See note 1.

FTEMPERATURE= Optional. A factor (f) that allows the injection port temperature (Tp) to be
interpolated between the casing gas temperature (Tc) and the production
wellbore temperature (Tw) using the formula Tp = Tc*(1-f) + Tw*f. Can be
set to a value between 0 and 1, default 1. The injection port temperature is
important in gas-charged valves because it determines the dome pressure
and hence the valve opening and closing pressures.

PLOT= Optional, can be set to OFF or ON, default OFF. Produces a plot file
representing the performance characteristics of each valve. One file is
produced for each valve, these are named model.Vxx, where model is the
model file core name, and xx is the valve number (shallowest being 01).
The valve performance is exercised over a range of casing and tubing
pressures, and the plot typically has tubing pressure on the X-axis against
gas flowrate in the Y-axis, with the casing pressure giving a number of
different lines.

MINFLOWRATE= or Optional, for MODE=SIMULATE. The lower limit of gas flowrate to be

MINQ= injected (MMscf/d or MMm 3/d). If the simulation for any case predicts less
than this gas flowrate, additional gas will be injected at the shallowest
valve. This simulates the effect of the operator increasing CHP to inject
more gas.

FLUIDNAME= or Optional. The name of the fluid (Black Oil or Compositional) representing
USE= the lift gas fluid specification, as specified with a BEGIN FLUID (p.550)
block.

SGGAS= Optional. For Black Oil fluids only, the lift gas specific gravity. (Default = SG
of the produced gas).

KGAS= Optional. For Black Oil fluids only, The lift gas thermal conductivity. (Default
= K of the produced gas).

CPGAS= Optional. For Black Oil fluids only, The lift gas heat capacity. (Default = CP
of the produced gas).

METHOD= Optional. Specifies the equation used to calculate gas flowrate across the
valve. Allowable values are 1 for PIPESIM's standard mechanistic choke
correlation, and 2 for the Thornhill-Craver equation.

PVTFILE= Optional. For compositional fluids only, the name of the PVT file containing
the composition of the lift gas.

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GLR= For MODE=DIP, injects the gas flowrate required to make the production
fluid Gas Liquid Ratio (GLR) equal the supplied value. (scf/sbbl or sm3/
sm3) See note 1.

GOR= For MODE=DIP, injects the gas flowrate required to make the production
fluid Gas Oil Ratio (GOR) equal the supplied value. (scf/sbbl or sm3/sm3)
See note 1.

INJGLR= For MODE=DIP, injects the gas flowrate required to increase the
production fluid Gas Liquid Ratio (GLR) by the supplied value. (scf/sbbl or
sm3/sm3) See note 1.

INJGOR= For MODE=DIP, injects the gas flowrate required to increase the
production fluid Gas Oil Ratio (GOR) by the supplied value. (scf/sbbl or
sm3/sm3) See note 1.

MAXDEPTH= Optional, for MODE=DIP, limits the injection depth to the specified
maximum.

FRICTION= Optional, For Mode=DIP. Requests a rigorous treatment of injection gas

pressure profile resulting from friction in the annulus. This can make a
significant difference to the calculated DIP when gas rate is high or annulus
cross-section area is small. Can be set to ON or OFF, default OFF.

U= Optional, for FRICTION=ON, specifies the overall Heat Transfer Coefficient

to be used for calculating injection gas temperature changes due to heat
exchange with the tubing and casing. (btu/hr/ft2/F or W/m2/C). Default 20
btu/hr/ft2/F.

IFACTOR= Optional, for FRICTION=ON, A factor (f) that allows the ambient
temperature (Ta) used in gas friction heat transfer calculations to be
interpolated between the ambient rock temperature (Tr) and the production
wellbore temperature (Tw) using the formula Ta = Tr*(1-f) + Tw*f. Can be
set to a value between 0 and 1, default 0.9.

PRINTF= Optional, for FRICTION=ON, requests detailed output from the simulation
of gas flow in the annulus. The resulting output pages are similar to those
produced for the production wellbore. Can be set to ON or OFF, default
ON.

SIP= Optional. Specifies the Surface Injection Pressure used for Alhanati Gas
Lift Instability Criteria calculation (p.397). (psia or bara)

Note:
1. The subcodes FLOWRATE=, GLR=, GOR=, INJGLR= and INJGOR= are mutually exclusive.
2. Any subcode valid for MODE=DIP is also valid for MODE=DIP3.

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8.6.12 INJPORT Gas Lift Injection Valve

INJPORT statements specify the position of Gas Lift Injection Valves. In conjunction with the
GASLIFT (p.603) statement they allow a well with multiple injection valves to be simulated.
PIPESIM will calculate the production flowrate and the quantity of gas injected through each valve.
INJPORT statements should be positioned in the system profile immediately following the NODE
statement representing the desired position for each valve. In a typical gas lift design, the profile
will contain between 4 and 10 injection valves.
Main-code: INJPORT

DPORT= The diameter of the valve port (in. or mm). Required.

PTR= The Test Rack Pressure Setting for the valve, measured at test
rack conditions, that is 60 oF and 14.696 psia. This is the pressure
(applied to the casing side of the valve, with the tubing side open
to atmosphere) required to just open the valve. Required.

MODE= The valve's mode of operation. Required.

DUMMY

ORIFICE

TUBING

IPO

PPO

CASING

AP2AB= The ratio of the Port Area to the Bellows Area, AP/AB, for the
valve. Required.

CV= The flow coefficient for the valve port. This is a value normally in
the range 0.4 to 1.6, used to characterize the port in the equation
for gas flow. The valve manufacturer usually measures this in the
laboratory. Optional, default 0.6.

TYPE= The construction type of the valve. (Optional,)

DUMMY

ORIFICE

BELLOWS Default

SPRING

LABEL= An identifier for the valve.

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TF= Throttling factor for the valve (mscfd/psi or msm3d/bar). Optional,

if not supplied it will be calculated using an assumed value of (P
open-Pclose).

PCO= Experimental: the Casing Opening pressure for the valve. If

supplied this value will be used instead of the calculated value.

PTC= Experimental: the Tubing Closing pressure for the valve. If

supplied this value will be used instead of the calculated value.

PDT= Experimental: the Dome Pressure of the valve at operating

temperature. If supplied this value will be used instead of the
calculated value.

TEMPERATURE= Experimental: The valve operating temperature. If supplied this

value will be used instead of the calculated value.

The values of TYPE= and OPMODE= determine the characteristics of the valve.
A Bellows valve has a dome and bellows, which is charged with gas (usually nitrogen) in the test
rack to provide the required closing force on the valve plunger. The force exerted by the gas
charge depends on its pressure, which increases with temperature. Since the temperature where
the valve is installed in the tubing is much higher than test rack temperature, this pressure
correction must be done using an accurate value for valve operating temperature if the valve
simulation is to be relied upon.
A Spring valve has a spring instead of a bellows to provide the closing force on the valve plunger.
The spring force is relatively insensitive to temperature variation.
An Orifice valve has no plunger, and is equivalent to a normal choke. It will always be open,
regardless of tubing and casing pressure, thus in theory not only can gas flow from casing to
tubing, but production fluid can also flow from tubing to casing. In practice this is not a problem as
static head limits fluid buildup in the casing. An orifice valve is sometimes specified as the deepest
injection valve, because it will not suffer from unwanted closure if the gas lift design no longer
matches the system operating parameters.
A dummy valve is a plug that passes no gas.
Bellows and spring valves are sensitive to both tubing and casing pressure to a greater or lesser
extent, depending on their construction and the way they are installed in the tubing string. The
objective of valve design, placement and test rack pressure setting is to achieve a desired
response to changes in tubing and casing pressure. These are called Modes of Operation, and
have the following names and meanings:
IPO:
Injection Pressure operated. Valve will respond only to changes in injection gas pressure.
Response is off-on rather than proportional.
PPO:
Production Pressure Operated. Valve will respond only to changes in tubing pressure.
Response is off-on rather than proportional.

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TUBING:
Tubing-sensitive proportional response. Valve will respond predominantly to changes in
tubing pressure, exhibiting a proportional response.
CASING:
Casing-sensitive proportional response. Valve will respond predominantly to changes in
casing pressure, exhibiting a proportional response.

8.6.13 INJGAS: Injection Gas (Optional) and INJFLUID: Fluid Injection

INJGAS and INJFLUID allow the injection and mixing of a side-stream fluid. They both work for
Blackoil and Compositional fluids.
INJGAS simulates a single gas injection point, and allows a specified quantity of gas to be added
to the production fluid at any position. This quantity can be expressed in volume or ratio terms. It
differs from GASLIFT (p.603) in that it always injects the specified gas quantity, whereas GASLIFT
(p.603) will calculate how much gas is injected.
INJFLUID simulates a single fluid injection point, and allows the mixing of the main stream with a
side-stream of any required composition and phase. It allows a base pressure and temperature to
be specified for the side stream, this is used to fix the volume flowrate if specified as a gas or liquid
rate.
INJGAS will only allow the injected fluid to be gas, it will apply certain sanity limits when working in
PIPESIM-NET mode, and it will calculate values for Alhanati Gas Lift Stability criteria. It also allows
injected gas properties such as SG, Cp and K to be defined for a black oil fluid.
Main-code: INJGAS or INJFLUID

GASRATE= Defines the flow rate of injection gas in volumetric terms (mmscf/d or
mmsm3/d).

MASSRATE= Defines the flow rate of injected fluid in mass terms (lb/sec or kg/sec).

LIQRATE= INJFLUID only. Defines the flow rate of injected fluid in volumetric terms of
its stock-tank liquid phase (sbbl/day or sm3/day).

FLOWRATE= or INJGAS only, a synonym for GASRATE=.

RATE=

GOR= or GLR= Defines the flowrate of injection gas in terms of Gas Liquid Ratio or Gas Oil
Ratio. Sufficient gas will be injected to adjust the produced fluid's GLR or
GOR to the specified value. If the fluid currently has a higher value, no gas
will be injected.

INJGLR= or Defines the flowrate of injection gas in terms of an increase in Gas Liquid
INJGOR= Ratio or Gas Oil Ratio. Sufficient gas will be injected to increase the
produced fluid's GLR or GOR by the specified value.

TEMP= or Temperature of injection fluid at the point of injection (F or C). If omitted,

IPTEMP= defaults to the temperature of the produced fluid at the injection point

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SG= INJGAS only, optional. For black oil fluids only, Specific gravity of the
injection gas (default = Value of gas SG from produced fluid)

CP= INJGAS only, optional. For black oil fluids only, Heat capacity of injection
gas (default = Value of gas Cp from produced fluid)

KGAS= INJGAS only, optional. For black oil fluids only, Thermal conductivity of
injection gas (default = Value of gas K from produced fluid)

CHP= INJGAS only, Optional. Casing head pressure to be used for Alhanati Gas
Lift Stability Criteria calculation. (psia or Bara)

DSIC= INJGAS only, Optional. Diameter of the Surface Injection Choke. Used for
Alhanati Gas Lift Stability Criteria calculation (in. or mm). Exclusive with
SIP=.

IDCT= INJGAS only, optional: the presence of the IDCT= subcode signals that gas
injection is occurring through coiled tubing. The value supplied is the Internal
Diameter of the Coiled Tubing (in. or mm.). The Cullinder & Smith
correlation is used to calculate the DP in the injection string, this is
compared with the available Casing Head Pressure and tubing pressure,
and insufficient CHP will trigger an informative message. NB: Subsequent
flow up the tubing should be specified as ANNULAR, using an appropriate
PIPE statement that supplies the correct annulus dimensions with AID= and
AOD= subcodes. Coiled tubing being used as a 'velocity string' (i.e. with no
injected gas) should be specified simply as annular flow with an appropriate
PIPE statement as above, there is no need for any INJGAS statement.

SIP= INJGAS only, optional. Surface Injection Pressure. Used for Alhanati gas Lift
Stability Criteria calculation. (psia or Bara).

DP= INJGAS only, Optional.. Injection port delta pressure (psia or Bara). used to
calculate casing pressure for Alhanait Gas Lift Stability Criteria calculation.
(psi or Bar). Exclusive with DPORT=.

DPORT= INJGAS only, Optional. Injection port diameter. Used for Alhanati gas Lift
Stability Criteria calculation. (in. or mm)

PVTFILE= Optional. For compositional fluids only, the name of a PVT file containing the
composition of the injected fluid. Exclusive with FLUIDNAME=, USE=, and
STREAMNAME=.

FLUIDNAME= or Optional. The name of the fluid (Black Oil or Compositional) representing the
USE= injected fluid specification, as specified with a BEGIN FLUID (p.550) block.
( A special-case fluid name of *SEP_DISCARD specifies that the injected
fluid specification and flowrate is obtained from the discard stream of a
separator (p.621) located somewhere upstream in the same branch. See
also STREAMNAME= below.). Exclusive with PVTFILE= and
STREAMNAME=.

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HANDLE=

STREAMNAME= Optional, INJFLUID only. The name of the fluid stream representing the
injected fluid specification, as specified on the DISCARDNAME= subcode of
an upstream separator. The injected stream definition includes its fluid
definition (Black Oil or Compositional), flowrate, and enthalpy. This feature
provides the same functionality as *SEP_DISCARD described above, but in
addition ensures the fluid enthalpy is conserved. Multiple separated streams
may be re-injected within the same branch by ensuring they are defined with
unique names. Exclusive with PVTFILE=, FLUIDNAME= and USE=.

PRINT= Optional. Requests a verbose printout of the specification of the injected

fluid.

CHTEMP= INJGAS only, Optional. Injection gas temperature can be provided at the
casing head (wellhead) as an alternative to TEMP=. This will be corrected to
a temperature at the injection point by use of a formula that depends on
geothermal gradient and production temperature. (F or C)

LIMIT= or
LIMITMR=

GLRLIMIT= or
LIMITGLR=

The quantity of gas or fluid to be injected must usually be specified, either as a volumetric or mass
rate, or as a ratio with the liquid phase of the produced fluid. Thus one of the subcodes
GASRATE=, MASSRATE=, LIQRATE= GOR=, GLR=, INJGOR= or INJGLR= should be specified.
However, if STREAMNAME= or *SEP_DISCARD is used, the flowrate is obtained from the
upstream separator..
Mixing of the injected and the produced fluid is assumed to occur at the pressure which pertains at
the injection point during the simulation. The temperature of the fluid after mixing is calculated by a
heat balance around the mixing point.
Alhanati gas-lift stability criteria are calculated for a gas lift system and added to the Plot file for use
by the Well Optimization feature, if sufficient information is provided on the INJGAS statement. Any
two of the subcodes SIP=, DPORT=, CHP=, DP= and DSIC= should be provided, preferably the
first two. The others will then be calculated.

8.6.14 MPBOOSTER (Optional)

Main-code: MPBOOSTER

TYPE= Multiphase pump type.

GENERIC

TWINSCREW

VENDOR

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NAME= The pump name.

ROUTE=

ADIABATIC Adiabatic compression is performed (default). For black oil models

the heat capacity ratio (C p/C v) for the adiabatic exponent in the
compression equations is assumed to be constant with a value equal
to 1.26. For compositional models the heat capacity ratio is
calculated using the relationship: Cp = Cv - R. The heat capacity is
obtained at the average of the compressor suction and discharge
conditions.

POLYTROPIC Polytropic compression is performed. The heat capacity ratio (C p/C

v) is calculated as outlined above for ADIABATIC compression.

MOLLIER Compression is based upon the Mollier method, that is isoentropic

compression from suction to discharge pressures. This option is valid
for compositional models only

POUT= Discharge pressure from the multiphase pump (bara or psia) (default
20,000 psia)

DP= Pressure differential across the pump (bar or psi) (default 10,000 psi)

PRATIO= Multiphase pump pressure ratio (default 1000)

POWER= Power available (KW or hp) (default unlimited)

PUMPEFF= Efficiency of compression of the gas phase (default 100%)

SPEED= Pump speed

VISCORR=

STATUS= Status of the pump.

GENERIC

TWINSCREW

VENDOR

8.6.15 MPUMP Multiphase Pump (Optional)

Main-code: MPUMP

TYPE= Multiphase pump type.

CENTRIFUGA Centrifugal pump.

NAME= The pump name.

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ROUTE=

ADIABATIC Adiabatic compression is performed (default). For black oil

models the heat capacity ratio (C p/C v) for the adiabatic
exponent in the compression equations is assumed to be
constant with a value equal to 1.26. For compositional models
the heat capacity ratio is calculated using the relationship: Cp
= Cv - R. The heat capacity is obtained at the average of the
compressor suction and discharge conditions.

POLYTROPIC Polytropic compression is performed. The heat capacity ratio

(C p/C v) is calculated as outlined above for ADIABATIC
compression.

MOLLIER Compression is based upon the Mollier method, that is

isoentropic compression from suction to discharge pressures.
This option is valid for compositional models only

POUT= Discharge pressure from the multiphase pump (bara or psia)

(default 20,000 psia)

DP= Pressure differential across the pump (bar or psi) (default

10,000 psi)

PRATIO= Multiphase pump pressure ratio (default 1000)

POWER= Power available (KW or hp) (default unlimited)

COMPEFF= Efficiency of pumping the liquid phase (default 100%)

PUMPEFF= Efficiency of compression of the gas phase (default 100%)

SPEED= Pump speed

STAGES=

STONEWALL=

ON

OFF

VERBOSE=

ON

OFF

TARGETGAS=

TARGETLIQUID=

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TARGETMASS=

Note: At least one of the subcodes POUT, DP, PRATIO, and POWER should be supplied. If 2 or
more are present, PIPESIM will treat them as upper limits, and will use whichever gives the
smallest DeltaP. The others will be recalculated and displayed as answers on the output file.

8.6.16 NODE System Profile Data (Required)

Main-code: NODE
The physical geometry of the pipeline system is defined by entering the distance and elevation
coordinates of each system node. A minimum of two nodes are required to define a system and
there is a maximum limit of 1,000 nodes.

Note: For the calculation of temperature and pressure profiles, PIPESIM internally subdivides the
section of pipe between each node into a number of segments. Normally 4 segments are created,
but this can be controlled from 1 to 50 if desired (see Options (p.525) ).

DISTANCE= Horizontal distance coordinate of the node (km or feet).

ELEVATION= Vertical elevation coordinate of the node (m or feet).

MD= Measured Depth (m or feet)

TVD= True Vertical Depth (m or feet)

TEMP= Ambient temperature at the node ( oC or oF). If no value is entered, the value will
be calculate: see below.

U= Overall heat transfer coefficient relative to the pipe outside diameter (W/m2/K or
Btu/hr/ft2/ oF). If no value is entered the value from the previous node is assumed.
The U sub-code is not required if the heat transfer coefficients are to be calculated
by the program (if specified they will be ignored)

LABEL= Node labels are for information only and can appear on any node card. There is a
maximum length limitation of 12 characters. The label should be included in quotes
if it contains delimiter characters (for example blanks). If a node is labelled, it will
appear on the Summary Output at the end of the job.

MP=

MT=

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Notes:
1. Each node may have either specification of DISTANCE= and ELEVATION= , or TVD= and
MD=, but not both. It is also possible to join together pipe sections with either specification, in
which case the nodes where the sections join are assumed to occupy the same position.
2. The ambient temperature is optional.
3. If it is omitted on MD/TVD nodes, it is assumed to be a point on a geothermal temperature
gradient, and its value is calculated by linear interpolation against TVD between known values
on either side. On the DIST/ELEV nodes however, the value from the previous node will be
used.
4. It is possible to place separate sections of pipe within the PIPESIM input file exactly as they
were measured, i.e. with their own particular X/Y datums, effectively a datum reset feature.
Datums are reset whenever a change of NODE card specification occurs (change from using
DISTANCE= and ELEVATION= to MD= and TVD=), and when a supercode is used
(COMPLETION, TUBING, FLOWLINE, RISER NAPOINT, see Completion (p.567) and
NAPOINT (p.659) ) .
5. As with all other maincodes and subcodes, the node data keywords can be abbreviated down
to the minimum number of letters required to make them unique.
6. In addition, if distance and elevation is used, the subcodes can be omitted, as long as the data
is supplied in the correct order, viz distance, elevation, temperature, U, label. Blank fields
should be delimited by commas.
7. Zero length pipe sections can be defined, that is NODE cards with DISTANCE= and
ELEVATION= sub-codes the same as the previous one can be defined.

8.6.17 PIPE: Pipe or Tubing cross-section dimensions (Required)

Main-code: PIPE

ID= Pipe Internal diameter (mm or inches).

WT= Pipe wall thickness (Default = 12.7 mm or 0.5 inches)

ROUGHNESS= Pipe roughness (Default = 0.025 mm or .001 inches).

AID= Annulus inside Diameter (mm or inches). (Default = 0). See

notes below.

AOD= Annulus Outside Diameter (mm or inches). See notes below.

FLOWTYPE= Specifies the flowpath for a tubing/annulus system. May be:

TUBING Flow is in the normal tubing or pipe, whose internal diameter is

specified with ID=. This is the default.

ANNULUS Flow is in the annular space between tubing and casing,

dimensions set with AID= and AOD=

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BOTH or Flow is in both tubing and annulus: tubing internal diameter is

TUBANN set with ID=, casing dimensions set with AOD=, ID= and WT=;
the AID= subcode will be ignored.

CONDUCTIVITY= Pipe thermal conductivity (W/m/K or Btu/hr/ft/ oF)

or KPIPE=

WAXTHIKNESS= The thickness of a coating of wax that exists on the inside of

the pipe (in or mm) (default zero).

WAXK= The thermal Conductivity of the wax (W/m/K or Btu/hr/ft/ oF)

RODDIAM= Specifies that a pump drive rod exists in the center of the pipe
or tubing, and supplies its diameter (in or mm). If flowtype is set
to TUBING, Fluid will flow in the annular space between the rod
and the pipe internal diameter specified with the ID= subcode.

AXID= or AAREA= Optional. The cross-section area of the flowpath (ft 2or m 2). If
or specified, this value is used preference to the area that would
ANNULUSAREA= otherwise be calculated from ID=, AID=, flowpath and so on to
compute the fluid velocity. This is useful for modeling flow in
ducts that do not have a circular or annular shape.

AWP= Optional. The total Wetted Perimeter WP (in or mm). If

specified, this value is used in preference to the sum of the
relevant diameters specified with ID=, AID- and AOD=,
depending on the flowpath. This is useful for modeling flow in
ducts that do not have a circular or annular shape.

AEHD= Optional. The Equivalent Hydraulic Diameter (in or mm). This is

normally calculated from the relation EHD = 4 AXID / WP . It is
used to obtain the friction factor. This is useful for modeling flow
in ducts that do not have a circular or annular shape.

ILH= or In-Line Heater. This subcode allows a fixed power or duty to be

ILHPOWER= or specified, that is used to transfer heat to the fluid flowing in the
ILHMAXPOWER= pipe. The value is interpreted as power per unit length
(BTU/hr/ft or Kw/m). See notes below.

ILHMINTEMP= This subcode allows a fixed minimum temperature to be

maintained across the pipeline by assigning required variable
heating power per unit length of pipe (BTU/hr/ft or Kw/m.) See
notes below.

RODDIAM= Drive rod diameter. This subcode allows the pipe cross-section
area to be reduced, to simulate the presence of a drive rod for
a pump. The diameter of the rod must be provided (inches or
mm). Note, if the RODPUMP or CVFMD statement is used to
place a pump in the system, the drive rod diameter can also be

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set there, in which case it is not necessary to supply it here as

well.

Note:
1. The AID= and AOD= subcodes should only be used if annular flow is desired. For normal pipe
or tubing flow, ID=should be used. The FLOWTYPE subcode should always be used to confirm
the desired type of flow.
2. Both AID= and AOD= refer to the dimensions of the annulus, that is the space between tubing
and casing, or between successive casings. For example, if annular flow between tubing and
casing is to be modeled, the AOD= is the casing inner diameter, and the AID= is the tubing
outer diameter.
3. Most of the published multiphase flow correlations have been developed assuming normal pipe
flow, not annular flow. Whilst Schlumberger have taken every care in the coding and validation
of these correlations, you should carefully examine the results of annular flow simulation to
ensure the selected correlation behaves as expected. We recommend that the results from a
number of correlations be compared when annular flow is modeled.
4. When ILHMINTEMP= and ILH= (or ILHPOWER= or ILHMAXPOWER=) subcodes are used
together, the supplied power is treated as the maximum limit. The specified minimum
temperature is maintained along the pipeline as long as the required power does not exceed
the available maximum power. When the required temperature cannot be maintained without
exceeding the power limit, the available power will be used as fixed power and resultant
temperature will be calculated.

8.6.18 PUMP Pump (Optional)

Main-code: PUMP

POUT= Discharge pressure from the pump (bara or psia) (default

20,000 psia)

DP= Pressure differential across the pump (bar or psi) (default

10,000 psia)

PRATIO= Pump pressure ratio (default 1000)

POWER= Power available for pump (KW or hp) (default unlimited)

EFF= Overall efficiency of the pump (%) (Default = 100%)

NAME= The name of the pump. Used to specify which pump curve
defined before the profile under the PUMPCRV main-code is
to be used.

SPEED= The pump impeller speed (rpm) (default unlimited)

STAGES= The number of stages for this particular pump. (default:

number of stages as specified on the PUMPCRV maincode.)

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ROUTE= The thermodynamic route of operation of the pump

ADIABATIC No heat transfer

ISENTHALPIC Constant enthalpy

MOLLIER Mollier

ISENTROPIC Constant entropy

ISOTHERMAL Constant temperature

ACF

UNDEFINED Undefined

VISCCORR= Viscosity correction

NONE

CENTRILIFT

REDA

TURZO

USER

VERBOSE=

ON

OFF

STAGECALCS= Perform the calculations through the pump on a stage-by-

stage basis. The details are then reported in the output file.

ON

OFF

SEPEFF=

EQUILIBRIUM=

ON

OFF

CALCNSTAGES=

MAXWCUT=

MINSSU=

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VISCFLUID=

OIL

WATER

LIQUID

MIXTURE

VISCFACTOR=

STATUS=

Notes:
1. At least one of the subcodes POUT, DP, PRATIO, POWER and SPEED should be supplied. If
2 or more are present, PIPESIM will treat them as upper limits, and will use whichever gives the
smallest DeltaP. The others will be recalculated and displayed as answers on the output file.
2. If a pump curve name is supplied, the speed and/or number of stages may also be supplied.
These are used to adjust the supplied curve against its specified speed and number of stages
(as set with SPEED= and STAGES= on the PUMPCRV maincode). The adjustment for speed is
done using the so called affinity or fan laws, which state that "capacity is directly proportional to
speed, head is proportional to square of speed, and power is proportional to cube of speed".

8.6.19 COMPCRV and PUMPCRV: Compressor and Pump performance

curves
Main-code: PUMPCRV or COMPCRV
Centrifugal pump and compressor performance curves are specified as a range of head and
efficiency or power values versus volumetric flow rates. These values should be specified before
the profile, and each curve is given a name so it can be referenced on a subsequent PUMP or
COMPRESSOR statement.

NAME= Required: The name of the curve, for referencing on a subsequent PUMP or
COMPRESSOR statement.

SPEED= The speed for which this curve was generated. (rpm)

Q= Values of flow rate, supplied as a multiple value set (p.515) . Flowrates are
measured in volumetric terms at the flowing pressure and temperature at the inlet
to the device. For a pump curve, units are bbl/day or m3/day; for a compressor
curve, they are ft 3/min or m3/sec. (See note below).

FLOWRATE= Synonym for Q =.

HEAD= Values of head, supplied as a multiple value set (p.515). For a pump curve, units
are feet or metres. For a compressor curve they are ft-lbf/lbm (foot-pounds force

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per pound mass) or Kj/kg. Note that the conversion factor between ft-lbf/lbm and
feet is 1.

EFFICIENCY= Values of efficiency (%), supplied as a multiple value set (p.515). (Default is
100%). Exclusive with POWER=.

POWER= Values of power (hp or kw), supplied as a multiple value set (p.515). Exclusive
with EFFICIENCY=.

STAGES= For a Pump curve only, the number of stages for which this curve is defined
(normally 1).

WHEELS= For a compressor curve only, the number of compressor wheels for which this
curve is defined.

The multiple value sets (p.515) supplied for Q=, HEAD=, and EFF= or POWER= sub-codes must
contain at least 3, and no more than 30 values, separated by commas, and enclosed in
parentheses. The values need not be entered in ascending or descending order, however there is
a strict one-for-one correspondence between the values in each list, based on their position. Each
list must contain the same number of values.
Since the multiple value lists can be quite lengthy, they may be supplied across more than one line
in the input file. This can be achieved either by use of the continuation character &, or by repeating
the maincode and curve name on each line. The examples below illustrate this, they both have the
same effect:

Examples
Example 1

PumpCrv name = GN7000 stages = 100 speed = 3600

PumpCrv name = GN7000 Q = (1250 ,3750 ,5800 ,7400 ,
9000 ,10666.7)
PumpCrv name = GN7000 head = (4827.88 ,4176.29,3624.68,3160.3 ,
2338.76,971.734)
PumpCrv name = GN7000 eff = (23.6865 ,
55.0738,67.3463,71.3873,63.476 ,31.7383)

Example 2

PumpCrv name = GN7000 stages = 100 speed = 3600 &

Q = (1250 ,3750 ,5800 ,7400 ,9000 ,10666.7) &
head = (4827.88 ,4176.29,3624.68,3160.3 ,2338.76,971.734) &
eff = (23.6865 ,55.0738,67.3463,71.3873,63.476 ,31.7383)

8.6.20 REINJECTOR (Optional)

Main-code: REINJECTOR

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8.6.21 RODPUMP: Rod- or Beam-pump

Main-code: RODPUMP or CVFMD
The RODPUMP statement allows the outline specification for a Rod- or Beam-pump to be
supplied.
A rod-pump is an example of a Constant Volume Fluid Motive Device (CVFMD). CVFMDs are
fixed-volume, positive-displacement pumps or compressors designed to move liquids, gases or 2-
phase mixtures. Other notable CVFMD examples are: Progressive cavity pumps, Twin screw
multiphase boosters, and reciprocating compressors. The statement allows a simplistic simulation
of such a device to be performed.

NOMLIQRATE= The flowing volume flowrate that the pump would produce, if it were pumping
with no back-pressure at its discharge (m3/day or bbl/day).

SLIPCOEF= A coefficient to specify the change in flowrate with respect to Delta pressure
(m3/day/bar or bbl/day/psi). This is used to compute the pressure rise across
the device when the actual flowrate is less than the specified nominal rate.

MAXDP= Maximum pressure rise the device is allowed to exhibit (psi or bar). This is
used to prevent excess rod loading.

MAXPOWER= Maximum power the device is allowed to draw (hp or kw). This is used to
prevent excess rod loading.

RODDIAMETER= The Diameter of the drive rod (in or mm). The drive rod will be assumed to
exist in the downstream pipe or tubing, and will stretch up to the wellhead or
the end of the tubing. The fluid will flow in the annular space between the
tubing ID and the rod OD. The rod diameter can be adjusted in downstream
pipe sections by use of the RODDIAM= subcode on the PIPE (p.615)
statement, this is useful to simulate taper rods.

VOLUME= The swept volume of the pump cylinder, i.e. its cross-section area multiplied by
the stroke length (bbl or m3). In conjunction with SPEED=, this is an alternative
to the nominal rate.

SPEED= The pump speed, in strokes per minute. In conjunction with VOLUME=, this is
an alternative to the nominal rate.

NOMINALRATE= The flowing volume flowrate that the pump would produce, if it were pumping
with no back-pressure at its discharge (m3/sec or ft3/min). this is the same
information as NOMLIQRATE= but in different units, more suited to other types
of CVFMD.

8.6.22 SEPARATOR Separator (Optional)

Main-code: SEPARATOR

TYPE= Type of separator: required, and may be set to one of:

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GAS Defines a gas separator: the Gas phase will be wholly or partly
discarded.

LIQUID Defines a liquid separator: the liquid phase(s) will be wholly or partly
discarded.

WATER Defines a water separator: the Aqueous Liquid phase will wholly or
partly discarded.

EFFICIENCY= The volumetric efficiency of separation expressed as a percentage, 0

to 100. At 100% efficiency, all of the discarded phase will be
removed; at lower values, some of the discard phase will remain in
the kept stream. Note that the efficiency applies only to the discarded
phase; no portion of the kept phase(s) will be discarded at any
efficiency.

DISCARDNAME= Optional: the name of the discarded fluid stream. The discarded
stream can be re-injected in the branch, in a downstream fluid
injector, if it is given a name. This is an alternative to
*SEP_DISCARD, as described in note 3 below.

VERBOSE= Optional: allows control over the detailed output for the separator,
written to the report file (.out).

ON Separator output is written to report file.

OFF Separator output is not written to report file.

Notes:
1. In a Black Oil case, the separator will result in a redefinition of the fluid's stock-tank Gas to
Liquid Ratio (originally supplied on the RATE maincode as GLR, GOR, OGR or LGR) to a GLR
or LGR. In a compositional case, a rigorous flash is performed at the separator pressure and
temperature, and the molar composition re-defined in terms of the flowrates of the components
in the kept phase(s).
2. If the efficiency is 100% and the flowrate is defined in terms of the discarded phase, the
flowrate basis will be changed to that of the kept phase.
3. Use of the SEPARATOR statement normally results in the separated phase being discarded
from the system. In a single branch model, or within a given branch of a network model, the
discarded phase can be recovered and re-injected into the branch further downstream, by use
of the special fluid name *SEP_DISCARD (p.609) on the INJFLUID (p.609) statement. In a
network model, a Network Separator (p.685) can be used (at the network level) to ensure
both separator outlet streams are kept.

8.6.23 WELLHEAD Wellhead Profile Delimiter

Main-code: WELLHEAD

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This maincode marks the position of the wellhead in the system profile. It is required when
modeling multiple injection ports in gas lifted wells.

8.7 HEAT TRANSFER DATA

HEAT (p.623) Heat Balance Options
COAT (p.626) COAT Pipe Coat and Annular Space Medium Data
TCOAT (p.627) Pipe Coat Thickness Data
KCOAT (p.628) Pipe Coat Thermal Conductivity Data
KFLUID (p.631) Fluid Thermal Conductivity Data
CONFIG (p.631) Configuration Data
Pipeline burial depth examples (p.632)

8.7.1 Notes on Heat Transfer Output Printing

1. Normally heat transfer input and output data is invoked by using: PRINT (p.539) HINPUT
HOUTPUT (See Section 1)
2. The radial temperature profile of coatings surrounding the pipe can be printed by invoking:
PRINT (p.539) EXTRA=TGRAD
3. Details of convective heat transfer calculations can be printed by invoking: PRINT (p.539)
EXTRA=CONVx where 'x' can be either 1, 2, 3, or 4 representing coats 1 to 4 respectively.
Note that details can only be obtained for 1 coat in each PIPESIM case performed.

8.7.2 HEAT Heat Balance Options (Optional)

Main-code: HEAT

BALANCE= OFF No heat balance is performed and the fluid temperature is

set equal to the ambient (or local ground) temperature as
specified in the system profile under the NODE main-code.

ON A heat balance is performed (default).

U= CALC Calculate heat transfer coefficients from data supplied in

this section.

INPUT Heat transfer coefficients are to be read from the NODE

cards (default).

HTCRD= Heat Transfer Coefficient Reference Diameter (in or mm).

This value will be used as the reference diameter (instead
of the current Pipe Outside Diameter) for all Heat Transfer
Coefficients printed in the Heat Transfer Output Data
(p.539) page.

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IFCMODE= INPUT Controls whether a separate Inside Film Coefficient (IFC)

is calculated when U values are supplied on NODE
statements (U=INPUT, see above). May be set to INPUT
or CALC. INPUT means the U supplied on the Nodes is
assumed to include the IFC; CALC means it does not, so
IFC will be calculated separately and added (using the
correct reciprocal formula) to the supplied U.(If INPUT is
used, the IFC is calculated, but not added; the calculated
value is compared to the supplied U, and if grossly
smaller, will trigger the production of a warning message.)
Applies only if U=INPUT. Default=INPUT.

CALC IFC is calculated and added to the supplied U value.

SPIFCMETHOD= Single phase fluid Inside Film Coefficient (HFI) correlation.

To be used in conjunction with MPIFCMETHOD= .If the
flow conditions are single phase then the PIPESIM engine
uses this correlation. The default method is BJA.

SEIDERTATE Seider and Tate

ORIGINAL Original

VOLAVERAGE Kreith eqn 8-20 (Vol Ave.)

KREITH10 Kreith eqn 10-6

GH9 Groothuis & Hendal eqn 9

GH10 Groothuis & Hendal eqn 10

BJA BJA (Kreith eqn 8-20)

SHELL Shell

BP Bp

MPIFCMETHOD= Multiphase Inside Film Coefficient (HFI) correlation

method that is used in conjunction with SPIFCMETHOD=.
If the flow conditions are multiphase then the PIPESIM
engine uses this correlation. The default method is BJA.

KAMINSKY Kaminsky

ORIGINAL Original

VOLAVERAGE Kreith eqn 8-20 (Vol Ave.)

KREITH10 Kreith eqn 10-6

GH9 Groothuis & Hendal eqn 9

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GH10 Groothuis & Hendal eqn 10

BJA BJA (Kreith eqn 8-20)

SHELL Shell

BP Bp

HOLDUP= IFC depends on holdup

ON

OFF Default

TRMIN=

TRMAX

WAX= Wax calculation mode.

PARTBURYMETH= Partial burial calculation method

2009 2009 Method

2000 2000 Method

1983 1983 Method

MASTER= Enthalpy is master.

TEMPERATURE

ENTHALPY

UVALUE=

RAMEYMETHOD= The Ramey heat transfer calculation method for tubings.

OFF Heat transfer coefficients for tubing are to be read from the
NODE cards (default).

LARGETIME Heat transfer coefficients are to be calculated for tubing

using the Ramey model (for times greater than 168 hr).
Note that the time is specified via OPTIONS subcode
RAMEYTIME.

GRNDCP= Ground specific heat capacity (default = 837.4 J/kg/K or

0.2 Btu/lb/oF) used in the Ramey model.

GRNDDEN= Ground density (default = 2242.6 kg/m3) or 140lb/ft3) used

in the Ramey model.

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DHEQUATION= Energy equation to calculate temperature changes in pipe

flow.

2009 Rigorous energy equation taking into account elevation,

friction and heat loss.

1983 Simplified energy equation.

Heat transfer mode

There are three heat transfer modes to select from:
1. No heat balance is performed and the fluid temperature is set equal to the ambient (or local
ground) temperature as specified in the system profile under the NODE main-code.
2. A heat balance is performed using overall heat transfer coefficients input under the NODE
main-code. Note: This is the default option. So, if the HEAT main-code is omitted, the program
will perform a heat balance and expect heat transfer coefficients to be entered under the NODE
maincode. If the program fails to find a 'U' value on the first node card an input data error will be
generated.
3. A heat balance is performed using heat transfer coefficients calculated by the program from the
data specified in this section.

8.7.3 COAT Pipe Coat and Annular Space Medium Data (Optional)
Main-code: COAT
The COAT statement allows the data for pipe coating or annular space thickness, conductivity and
medium to be specified for a single coat or annular space. For multiple coats, additional COAT
statements may be provided, up to a maximum of 26. COAT is an alternative to the TCOAT and
KCOAT statements, they both allow the same information to be entered.

NUMBER= The coat or annular space number to be specified. Coat 1 is the innermost
coat. Must be an integer between 1 and 26

THICKNESS= Coating or annular space thickness (ins or mm, default zero). All coats are
assumed to be of zero thickness until specified with a positive thickness

CONDUCTIVITY= , Coat thermal conductivity (W/m/K or Btu/hr/ft/ oF, default infinite).

K= Exclusive with MEDIUM=.

MEDIUM= The name of the fluid medium contained in the annular space. This must
match the core portion of a filename with the extension .APF in the
PIPESIM installation's data directory. Default available filenames to specify
typical annular fluids are provided, these are as documented for the
KCOAT statement. Exclusive with CONDUCTIVITY=.

PRESSURE= The average pressure in the annular space (psia or Bar, default 1000
psia).

LABEL=, NAME= The name of the coat or space.

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U= The overall heat transfer coefficient for this coat (W/m2/K or Btu/hr/ft2/ oF).
This value will be used instead of any calculated value. The reference
diameter for this will be the pipe outside diameter, that is the junction
between the pipe and the first coat, this can be changed using the RD=
subcode below.

RD= The Reference Diameter to be used for the U= subcode provided above
(in or mm).

RESETALL Specifies that all previous coatings information be reset to zero. This
allows new coatings information to be supplied with subsequent COAT (or
TCOAT and KCOAT) statements without risk that earlier higher-numbered
coats will be remembered.

Note: As with other data, any coat thickness data specified at a particular node will automatically
be carried forward to subsequent nodes unless altered or reset to zero thickness. A coat can be
removed (effectively) by specifying its thickness as zero. This will not affect the properties of
higher-numbered coats. All coats can be removed by use of the RESETALL subcode.

Example
PIPE ID=5.25 thickness =.375 K = 56.4
COAT resetall
COAT num = 1 thickness = 3 medium=brine name='brine-filled annulus'
COAT num = 2 thickness = 0.5 K = 50 name='casing 1'
COAT num = 3 thickness = 2 medium=gas65 name='gas filled annulus'
COAT num = 4 thickness = 0.5 K = 50 name='casing 2'
COAT num = 5 thickness = 3 K = 3.5 name='cement'

Note: All keywords can be entered using the EKT.

8.7.4 TCOAT Pipe Coat Thickness Data (Optional)

Main-code: TCOAT
The TCOAT and KCOAT main-codes are used to specify up to ten concentric pipe coatings for use
in the heat transfer calculations. This data is only required if U=CALCULATE is specified with the
HEAT (p.623) main-code. Note that the pipe thickness is specified under the PIPE (p.615) main-
code.

TPIPE= Thickness of pipe (default = 0.0 mm or in).

TWAX= Thickness of wax (default = 0.0 mm or in).

T1= Thickness of coat 1 (default = 0.0 mm or in).

T2= Thickness of coat 2 (default = 0.0 mm or in).

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T3= Thickness of coat 3 (default = 0.0 mm or in).

T4= Thickness of coat 4 (default = 0.0 mm or in).

T5= Thickness of coat 5 (default = 0.0 mm or in).

T6= Thickness of coat 6 (default = 0.0 mm or in).

T7= Thickness of coat 7 (default = 0.0 mm or in).

T8= Thickness of coat 8 (default = 0.0 mm or in).

T9= Thickness of coat 9 (default = 0.0 mm or in).

T10= Thickness of coat 10 (default = 0.0 mm or in).

Note: As with other data, any coat thickness data specified at a particular node will automatically
be carried forward to subsequent nodes unless altered or reset to zero.

8.7.5 KCOAT Pipe Coat Thermal Conductivity Data (Optional)

Main-code: KCOAT

KPIPE= Pipe thermal conductivity (default = 60.6 W/m/ oK or 35 Btu/hr/ft/ oF).

K1= Coat 1 thermal conductivity (W/m/K or Btu/hr/ft/ oF).

K2= Coat 2 thermal conductivity (W/m/K or Btu/hr/ft/ oF).

K3= Coat 3 thermal conductivity (W/m/K or Btu/hr/ft/ oF).

K4= Coat 4 thermal conductivity (W/m/K or Btu/hr/ft/ oF).

KWAX=

Note: The default value for coat thermal conductivities is infinity (effectively), which means that the
default thermal resistance is effectively zero.

The sub-codes described here are utilized in the modeling of convective heat transfer within fluid
filled annuli.

F1= The name of the data file in which annular fluid properties for Coat No. 1 are stored.

F2= The name of the data file in which annular fluid properties for Coat No. 2 are stored.

F3= The name of the data file in which annular fluid properties for Coat No. 3 are stored.

F4= The name of the data file in which annular fluid properties for Coat No. 4 are stored.

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P1= Average pressure in Coat No. 1 (default = 1,000 psia / 70 bara)

P2= Average pressure in Coat No. 2 (default = 1,000 psia / 70 bara)

P3= Average pressure in Coat No. 3 (default = 1,000 psia / 70 bara)

P4= Average pressure in Coat No. 4 (default = 1,000 psia / 70 bara)

Convective (Fx) and conductive (Kx) coatings can be specified in any sequence desired. The
example below illustrates the modeling of a riser within a gas filled caisson which is insulated on
the outside with 0.5" neoprene. Physical properties for the gas contained within the caisson will be
read from the file 'GAS65.APF'.

Note: The Fx and Kx subcodes for any coating are mutually exclusive. Calculated convective heat
transfer coefficients are printed to the HOUTPUT page as normal. In addition an equivalent thermal
conductivity is calculated from the convective heat transfer coefficient and printed to the relevant
position in the HINPUTpage.

Files
BJA have prepared data files for the most common annular fluids such as natural gas, brine, mud
and so on. These files are located in the PIPESIM data directory. The files currently available are
listed below together with a brief description of the file contents.

File Name Contents

wbm.apf Properties of a typical water based mud

obm.apf Properties of a typical oil based mud

gas65.apf Properties of a 0.65 S.G. gas

brine.apf Properties of a typical brine

Annular property data files are written in a simple to understand text file format to enable users to
edit files or create their own if required.

Example
The example below illustrates the table format.

Note: A column containing line numbers is not part of the file.

Line 1 Specification of file format. Should not be modified

Line 2 Title line. May be modified as necessary

Line 3 Specifies the number of properties to be read

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Line 4 Format in which lines are to be read. Should not be modified

Lines 5 - 10 Identifies the properties contained in the file and the order in which they are
arranged. Note that this order is fixed and cannot be changed by the user. The two
columns of numbers contain the conversion factors necessary to convert the
property from the units specified in the file to standard PIPESIM SI units. Column 1
contains the additive conversion factor whilst column 2 contains the multiplying
factor. This specification allows users to specify data in different units as required.

Line 11 Should not be modified.

Line 12 - 29 Contains the necessary physical property data in the sequence specified in Lines 5 -
10. Columns 1 & 2 contain the pressure and temperature to which the physical
property data relates. Note that the maximum number of pressure and temperature
points permitted within a file is 20.

Line 30 Identifies the end of file.

Example File: BRINE.APF

ANPROP-1.0 LINEAR TABLE-1 ,A, 0, 0, NOGO

JOB : WATER TEST-1
6
(7f11.0)
Pressure PSIA 0. 6.894730
Temperature F 255.3722 .5555555
Liquid Density LB/FT3 0. 16.01800
Liquid Viscosity cP 0. 1.000000
Liquid conductivity BTU/hrftF 0. 1.730104
Liquid Heat Capacity BTU/LBF 0. 4.186800
NEWLINE, SCALE, CONT
14.7 50 62.4 0.880 .332 1.000
14.7 60 62.3 0.760 .340 0.999
14.7 70 62.3 0.658 .347 0.998
14.7 80 62.2 0.578 .353 0.998
14.7 90 62.1 0.514 .359 0.997
14.7 100 62.0 0.458 .364 0.998
14.7 150 61.2 0.292 .384 1.000
14.7 200 60.1 0.205 .394 1.000
14.7 400 53.8 0.001 .394 1.000
1000 50 62.4 0.880 .332 1.000
1000 60 62.3 0.760 .340 0.999
1000 70 62.3 0.658 .347 0.998
1000 80 62.2 0.578 .353 0.998
1000 90 62.1 0.514 .359 0.997
1000 100 62.0 0.458 .364 0.998
1000 150 61.2 0.292 .384 1.000
1000 200 60.1 0.205 .394 1.000
1000 400 53.8 0.001 .394 1.000
composition

Typical Thermal Conductivities (p.488) in W/m/K (Solids) Thermal Conductivities (p.488) in W/m/K
(Liquids and Gases)

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Note: All keywords can be entered using the EKT.

8.7.6 FLUID Fluid Thermal Conductivity Data (Optional)

Main-code: KFLUID
The fluid thermal conductivities are used in the calculation of the pipe internal film heat transfer
coefficients. Default values are supplied and should be adequate for most cases.

OIL= Oil thermal conductivity (default = 0.138 W/m/K or 0.08 Btu/hr/ft/ oF).

GAS= Gas thermal conductivity (default = 0.035 W/m/K or 0.02 Btu/hr/ft/ oF).

WATER= Water thermal conductivity (default = 0.605 W/m/K or 0.35 Btu/hr/ft/ oF).

Note: All keywords can be entered using the EKT.

8.7.7 CONFIG: Pipe Heat Transfer Configuration Data (Optional)

Main-code: CONFIG
This data is only required if U=CALCULATE is specified under the HEAT main-code and if near-
surface horizontal or near-horizontal pipe is being considered. For pipe or tubing situated away
from the influences of air and seawater the CONFIG card is not required.

DEPTH= The burial depth (in mm or inches) as measured from the ground surface or
mudline to the center-line of the pipe. A negative burial depth implies that the pipe
center-line is above the surface and the pipe is therefore partially buried or fully
exposed. Default is Fully Buried at depth of 800 feet.

KGROUND= Ground thermal conductivity (W/m/K or Btu/hr/ft/F).

VAIR= Ambient air velocity. Used to calculate the outside film heat transfer coefficient
(Default = 0.033 m/s or 0.1 ft/s). Exclusive with VWATER=.

VWATER= Ambient water velocity. Used to calculate the outside film heat transfer coefficient.
(Default = 0.033 m/s or 0.1 ft/s). Exclusive with VAIR=.

WDENS= Ambient water density. (lb/ft3 or kg/m3).

WVISC= Ambient water viscosity. (cP)

WCP= Ambient water specific heat capacity. (btu/lb/F or KJ/Kg/C)

WK= Ambient water thermal conductivity. (btu/ft2/ft/F or KJ/m2/m/C)

WBETA= Ambient water coefficient of thermal expansion.

ADENS= Ambient air density. (lb/ft3 or kg/m3)

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AVISC= Ambient air viscosity.(cP)

ACP= Ambient air specific heat capacity. (btu/lb/F or KJ/Kg/C)

AK= Ambient air thermal conductivity. (btu/ft2/ft/F or KJ/m2/m/C)

ABETA= Ambient air coefficient of thermal expansion.

TOPDEPTH= The burial depth (in mm or inches) as measured from the surface to the top of the
pipe.

8.7.8 Pipeline burial depth examples

For a horizontal pipeline
Z : burial depth.
D : outside diameter of pipe and coatings

Burial depth Pipe and coatings Exposed to Schematic

air or water
D/2 > Z above ground / yes
seabed

Z = D/2 resting on ground/ yes

seabed

0 > Z > D / 2 partially (less than yes

half) buried

D/2 > Z > 0 partially (more than yes

half) buried

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Z > D/2 completely buried no

8.8 Fluid Models

8.8.1 BLACK OIL DATA
BLACKOIL (p.633) Black Oil Correlation Options
PROP (p.635) Fluid Property Data
LVIS (p.637) Liquid Viscosity Data
CPFLUID (p.642) Fluid Heat Capacity Data
RATE (p.535) Flow Rate Data
ITERN Iteration Data (Optional) (p.537)
TPRINT (p.642) Black Oil Table Printing
CALIBRATE (p.643) Black Oil Property Calibration
INJGAS and INJFLUID (p.609) Injection Gas and side stream fluid injection
WELLHEAD (p.622) Wellhead Profile Delimiter
GASLIFT (p.603) Multiple Injection Ports in Gaslifted Wells
INJPORT (p.607) Gas Lift Injection Port
CONTAMINANTS (p.644) Gas contaminants data

BLACKOIL: Black Oil Fluid definitions

Main-code: BLACKOIL
Fluid properties can be generated internally by so called "black oil" correlations which have been
developed by correlating gas/oil ratios for live crudes with various properties, such as oil and gas
gravities. The selected correlation is used to predict the quantity of gas dissolved in the oil at a
particular pressure and temperature.
The black oil correlations have been developed specifically for crude oil/gas/water systems and are
therefore most useful in predicting the phase behavior of crude oil well streams. When used in
conjunction with the calibration options, the black oil correlations can produce accurate phase
behavior data from a minimum of input data. They are particularly convenient in gas lift studies
where the effects of varying GLR and water cut are under investigation.
A Blackoil fluid must define its stock-tank volume phase split using one of: GLR=, GOR=, OGR=,
or LGR=, and one of WCUT=, WGR= and GWR=.

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Gas saturation (RS) correlations

RSCORR= ELSHARK Elsharkawy

GHETTO de Ghetto

GLASO Glas (p.424) correlation.

KART Kartoatmodjo

LASATER Lasater (p.425) correlation (default for bubble point pressure and solution
gas).

PETROSK Petrosky-Farshad

STANDING Standing (p.425) correlation (default for oil formation volume factor at the
bubble point)

VAZBEG Vazquezand Beggs (p.426) correlation (default for oil formation volume
factor above the bubble point).

Gas densities are calculated using a Z-factor correlation developed by Katz (p.505) and Standing
and so the black oil correlations can also be used for single phase gas systems and gas/
condensate systems with more or less constant gas/liquid ratios. However, if the accurate phase
behavior prediction of light hydrocarbon systems is important, it is recommended that the more
rigorous compositional models is employed.

Gas Compressibility correlation choices

GASZCORR= DPR The Dranchuk, Purvis and Robinson correlation for curve fitting the
Standing- Katz (p.505) reduced pressure-reduced temperature Z-
Factor chart.

GOPAL The Gopal correlation for curve fitting the Standing- Katz (p.505)
reduced pressure-reduced temperature Z-Factor chart.

HALLYAR Hall & Yarborough correlation for curve fitting the Standing- Katz
(p.505) reduced pressure-reduced temperature Z-Factor chart.

STANDING The Standing modification to the Brill and Beggs correlation for
curve-fitting the Standing- Katz (p.505) reduced pressure-reduced
temperature Z-Factor chart.

TSTANDING

Oil Formation Volume Factor correlation choices

OFVFCORR= ELSHARKAWY Elsharkawy

KART Kartoatmodjo

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PETROSKY Petrosky

STANDING Standing

VAZBEG Kartoatmodjo

Gas dissolution and saturation in water

WRSCORR= HPPAC

KATZ

NONE

Gas viscosities are calculated using the Lee et al. (p.505) correlation.
Blackoil fluids that have been previously defined with BEGIN FLUID (p.550) can be selected with
the FLUIDNAME= or USE= subcode.

Stock-tank Phase Ratios

A Blackoil fluid must define its stock-tank volume phase split using one of: GLR=, GOR=, OGR=,
or LGR=, and one of WCUT=, WGR= and GWR=. (For historical reasons, these subcodes are also
available on the RATE statement, but you are strongly encouraged to use them here instead. A
compositional fluid can also define them but they must be supplied on the COMPOSITION
statement. ).

GWR= Gas Water ratio at stock-tank conditions. (sm 3/sm 3 or scf/STB)

WGR= Water/gas ratio at stock-tank conditions. (sm 3/mmsm 3 or STB/mmscf).

WCUT= Watercut, i.e. the volume % aqueous phase in the total liquid phase at stock tank
conditions.

GLR= Gas/liquid ratio at stock tank conditions. (sm 3/sm 3 or scf/STB).

GOR= Gas/oil Ratio at stock tank conditions. (sm 3/sm 3 or scf/STB).

LGR= Liquid/gas ratio at stock-tank conditions. (sm 3/mmsm 3 or STB/mmscf).

OGR= Oil/gas ratio at stock-tank conditions. (sm 3/mmsm 3 or STB/mmscf).

Care must be exercised in combining these subcodes, as it is possible to specify a value for one of
them that renders the use of the other one meaningless or illegal: such as with WCUT=100, any
value for GOR= is meaningless; for example, GLR=0 conflicts with any non-zero value for GWR=.
It is however always possible to re-state the desired definition correctly by well-chosen alternative
subcodes.

PROP Fluid Property Data (Optional)

Main-code: PROP

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API= Dead oil API gravity at stock tank conditions (see note 1). Default = 30 API.
The API gravity is defined as follows: - API = (141.5/sg) - 131.5 where sg is the
oil specific gravity relative to water. Exclusive with DOD=.

DOD= Dead oil density (kg/sm 3 or lb/ft 3) at stock tank conditions (see note 1).
Default = 876 kg/sm 3. Exclusive with API=.

GASSG= Associated gas specific gravity relative to air (MW/28.964) at stock tank
conditions (see note 1). Range 0.55 < GASSG 1.2. Default = 0.64.

CONEDGASSG= Coned gas specific gravity (default: same as associated gas SG as defined
with GASSG=). The coned gas SG will only be used if a coning relationship
has been defined for the completion with CONETAB (p.579) or IPRCRV
(p.576). Coning will result in a mix of associated and coned gas, resulting in a
produced gas SG somewhere between these 2 values.

WATERSG= Water specific gravity at stock tank conditions (see note 1). Default = 1.02.

STENSION= Specifies the method for calculating Liquid/gas interfacial tension. This allows
for the possibility of three phase (gas/oil/water) flow where the liquid
hydrocarbon (oil or condensate) flows as a segregated layer on top of the
aqueous phase. Some 2-phase flow correlations (such as BJA and Duns and
Ros) take account of the interfacial surface tension when calculating such
parameters as the liquid wave height. Can be set to MIXED or SEGREGATED,
meaning:

MIXED: Surface tension is calculated based on the average properties of the

water and hydrocarbon liquid mixture. This is the default value.

SEGREGATED: Surface tension is calculated based on properties of the

hydrocarbon liquid only. This option should only be used when it is expected
that the liquid hydrocarbon and aqueous phases will be segregated, for
example, long pipelines operating in the stratified flow regime.

GSAT= The quantity of gas which would dissolve in the oil, and saturate it, at a given
pressure and temperature (sm3/sm3 or scf/bbl) (see note 2).

PSAT= The saturation pressure for GSAT= (bara or psia) (see note 2).

TSAT= The saturation temperature for GSAT= ( oC or oF) (see note 2).

PSEP= The separator pressure used by Kartoatmodjo (etc) correlations

TSEP= The separator temperature used by Kartoatmodjo (etc) correlations

Note:
1. The oil, water and gas properties should be entered at stock tank conditions, that is 14.696 psia
and 60 oF .

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2. The oil saturated gas content at a known temperature and pressure (for example at reservoir
conditions) should be entered to allow calibration of the black oil model. Such calibration will
significantly improve the accuracy of the predicted gas/liquid ratios. If the calibration data is
omitted the program will calibrate the correlation on the basis of oil and gas gravity alone and
there will be a consequent loss in accuracy. Note, the value of GSAT= is independent of any
GLR= or GOR= supplied on the BLACKOIL statement

LVIS: Liquid Viscosity Data (Optional)

Main-code: LVIS

DOVCORR= Specifies the choice of Dead Oil Viscosity correlation.

USER or BEAL Dead oil viscosity will be calculated by fitting two

measured values of viscosity versus temperature to
Beal's chart. Use with TEMP1=, TEMP2=, VIS1= and
VIS2=. PIPESIM will fit a curve of the form
1
log ( )
T
through the two given data points and then interpolate (or
extrapolate) to find dead oil viscosities at given
temperatures. Normally you would enter viscosity data at
temperatures close to the expected maximum and
minimum operating temperatures. Entering two identical
temperatures or viscosities will cause an error.

TABLE Dead oil viscosity will be calculated by fitting a table of

viscosity vs. temperature to Beal's chart. Use with
TEMPS= and VISCS=. See note 1 below

BEGROB Beggs and Robinson (1975). This correlation is

constrained to work within limits as published by the API
(Petroleum Engineering handbook, Page 22-16), that is
Temperature between 70 and 295 oF, and oil API gravity
between 16 and 58.

GLASO Dead oil Viscosity will be calculated using the correlation

of Glas (1980)

KARTOATMODJO Kartoatmodjo and Schmidt correlation

GHETTO De Ghetto correlation

HOSSAIN Hossain correlation

ELSHARKAWY Elsharkawy correlation

PETROVSKY Petrovsky correlation

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LOVCORR= Specifies the choice of Live (gas-saturated) Oil Viscosity

correlation. May be set to one of:

CHEWCON Chew and Connally correlation

BEGROB Beggs and Robinson correlation

KARTOATMODJO Kartoatmodjo and Schmidt correlation

KHAN Khan correlation

GHETTO De Ghetto correlation

HOSSAIN Hossain correlation

ELSHARKAWY Elsharkawy correlation

PETROVSKY Petrovsky correlation

UOVCORR= Specifies the choice of Undersaturated Oil Viscosity

correlation. May be set to one of:

VAZBEG Vasquez and Beggs correlation (default)

KOUZEL Kouzel correlation. Coefficients are supplied with the KA=

and KB= subcodes.

KARTOATMODJO Kartoatmodjo and Schmidt correlation

KHAN Khan correlation

GHETTO De Ghetto correlation

HOSSAIN Hossain correlation

ELSHARKAWY Elsharkawy correlation

BERGMAN Bergman and Sutton correlation

PETROVSKY Petrovsky correlation

NONE Undersaturated oil viscosity calculation will be omitted, oil

viscosity will be set to the result of the Live Oil viscosity
correlation at the minimum of (actual and bubble point)
pressure.

EMULSION= Used to select one of various options for the calculation

of oil-water mixture viscosities. The water viscosity data
is generated internally by PIPESIM, using the van Wingel
correlation. Generally speaking, at water cuts less than
approximately 60% water (by volume), the oil phase is
continuous with the water phase distributed. Under these

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conditions some oil-water mixtures can form highly

viscous water-in-oil emulsions, particularly at water cuts
in the range of 30-50%. Emulsion viscosities many times
higher than that of either the oil or water are not
uncommon. At water cuts above 60%, water is usually
the continuous phase and the resulting oil-in-water
emulsion has a viscosity similar to that of water. Used in
conjunction with the CUTOFF= subcode.

SWAP The mixture viscosity equals the oil viscosity at water cuts
less than or equal to cutoff % and equals the water
viscosity at water cuts greater than cutoff % (default).

VOLRATIO The mixture viscosity equals the volume ratio of the oil
and water viscosities.

WLOOSE Use Woelflin "Loose Emulsion" correlation at watercuts

below the cutoff, set to water viscosity above.

WMEDIUM Use Woelflin "Medium Emulsion" correlation at watercuts

below the cutoff, set to water viscosity above.

WTIGHT Use Woelflin "Tight Emulsion" correlation at watercuts

below the cutoff, set to water viscosity above.

WORIG Use PIPESIM original Woelflin loose emulsion correlation

at watercuts below the cutoff, set to water viscosity
above.

KENMONROE Liquid viscosities are calculated from oil and water

viscosities using the Kendal & Monroe equation. This is
the option used when Emulsions are set to None for a
Compositional fluid.

TABLE Emulsion viscosities are interpolated from the table

supplied with the EWCUTS= and EVISCS= subcodes.
See note 1 below.

BRINKMAN Use the Brinkman correlation. This generally predicts

elevated liquid viscosities on either side of the cutoff.

VAND Use the Vand correlation, using Vand's coefficients. This

generally predicts elevated liquid viscosities on either
side of the cutoff.

VANDBARNEA Use the Vand correlation, using Barnea and Mizrahi

coefficients. This generally predicts elevated liquid
viscosities on either side of the cutoff.

VANDUSER Use the Vand correlation, using coefficients supplied with

the K1= and K2= subcodes. This predicts liquid

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viscosities on either side of the cutoff. Suitable choice of

coefficients can yield elevated or depressed viscosities.

RICHARDSON Use the Richardson correlation, using coefficients

supplied with the RKOIW= and RKWIO= subcodes. This
predicts liquid viscosities on either side of the cutoff.
Suitable choice of coefficients can yield elevated or
depressed viscosities.

LEVITON Use the Leviton and Leighton correlation. This generally

predicts elevated liquid viscosities on either side of the
cutoff.

REDAOIW

REDAWIO

REDASWAP

ABPCORR=

ON

OFF

ORDER=

UCORR=

TEMP1= Temperature 1 for DOVCORR=USER. (Default = 93.3

oC/200 oF)

VIS1= Oil viscosity at temperature 1 for DOVCORR=USER.

(Default = 0.5 centipoise)

TEMP2= Temperature 2 for DOVCORR=USER. (Default = 15.6

oC/ 60 oF).

VIS2= Oil viscosity at temperature 2 for DOVCORR=USER.

(Default = 10 centipoise).

VISCS= List of oil viscosities for DOVCORR=TABLE, in Multiple

Value format. See note 1.

TEMPS= List of temperatures for DOVCORR=TABLE, in Multiple

Value format. See note 1.

CUTOFF= or The value of watercut where Phase Inversion occurs. In

BOUNDARY= an oil-water mixture at low watercuts, water droplets are
carried dispersed in a continuous oil phase. At much
higher watercuts, water is the continuous phase and oil
droplets are dispersed in it. The CUTOFF is the watercut

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where the continuous phase changes. It is used by the

Emulsion subcode, see above. (%, default 60)

PRESSURES=

FLTYPES=

LIVEOIL

DEADOIL

EWCUTS= List of Watercuts for EMULSION=TABLE, in Multiple

Value format. The first watercut value in the table must
be zero. See note 1.

EVISCS= List of oil viscosities for EMULSION=TABLE, in Multiple

Value format. The first viscosity value in the table is used
to divide into all the others to yield multipliers. See note 1.

K1= or VANDK1= Coefficient k1 for use in the VANDUSER correlation,

default 2.5

K2= or VANDK2= Coefficient k2 for use in the VANDUSER correlation,

default 0.609

RK= or
KRICHARDSON=

RKOIW= or Coefficient k for the RICHARDSON correlation, used

KROIW= when oil-in-water conditions expected (watercut > cutoff).

RKWIO= or Coefficient k for the RICHARDSON correlation, used

KRWIO= when water-in-oil conditions expected (watercut < cutoff).

KA= Value of the A parameter for the Kouzel UOV correlation,

default 0.0239

KB= Value of the B parameter for the Kouzel UOV correlation,

default 0.01638

TPVT= Controls three-point viscosity tuning.

ON

OFF

Note: When using the user-supplied table options (DOVCORR=TABLE and EMULSION=TABLE),
at least 3 and no more than 30 viscosity and (temperature or watercut) values must be supplied.
The values need not be entered in any particular order, but there is a strict one-to-one
correspondence between the values in the subcode pairs. Once read, he values will be sorted in

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order of increasing temperature/watercut for use by the engine. Viscosity must never increase with
temperature, but may vary with watercut as desired.

CPFLUID: Fluid Heat Capacity Data (Optional)

Main-code: CPFLUID
Fluid specific heat capacity data is required for the calculation of fluid enthalpies.

OIL= Oil heat capacity. Default = 1.89 kJ/kg/K or 0.45 Btu/lb/ oF.

GAS= Gas heat capacity. Default = 2.31 kJ/kg/K or 0.55 Btu/lb/ oF.

WATER= Water heat capacity. Default = 4.3 kJ/kg/K or 1.0 Btu/lb/ oF.

HVAP= Latent heat of vaporization. Default = 0.0 kJ/kg or 0.0 BTU/lb

CPFLUID is only used for black oil fluids: compositional fluids use heat capacities calculated by the
selected physical properties package.

Note: All keywords can be entered using the EKT.

TPRINT Black Oil Table Printing (Optional)

Main-code: TPRINT
The TEMPERATURE and PRESSURE sub-codes have been added to the TPRINT main-code to
permit the generation of tables of black oil properties.
Note that the property table is printed for information only and cannot be used as input for
subsequent PIPESIM jobs.

TEMPERATURE= Temperature points at which properties should be tabulated ( oC oroF). A

maximum of 20 points may be specified

PRESSURE= Pressure points at which properties should be tabulated (bara or psia). A

maximum of 20 points may be specified.

The format of the table is similar to that generated for a compositional table, however the
properties tabulated in the table do differ from the compositional case.

Example
In the following example, a table of black oil properties at 5 temperatures and pressures is
specified:

TPRINT temp = (400,300, 250, 200, 150)

TPRINT pressure =(3000,2500,2000,1500,1000)

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Note: All keywords can be entered using the EKT.

CALIBRATE: Black Oil Property Calibration (Optional)

In many cases, actual measured values for some properties show a slight variance when
compared with the value calculated by the black oil model. In this situation it is useful to calibrate
(or match, or tune) the property using the measured point. PIPESIM uses the known data for the
property to calculate a calibration constant K c as noted below:

Measuredproperty (T , p )
Kc = Eq. 8.1
Calculatedproperty (T , p )
This calibration constant is then used to modify all subsequent calculations of the property in
question, that is:

CalibratedValue = K c PIPESIMCalculatedValue Eq. 8.2

Properties which may be calibrated in this manner are

Saturated Oil formation volume factor
Saturated oil viscosity
Undersaturated oil formation volume factor
Undersaturated oil viscosity
Gas viscosity
Gas compressibility factor

Main-code: CALIBRATE

FVFRN= Measured value for Saturated oil formation volume factor.

TFVFRN= Temperature to which the figure given for FVFRN= refers (oC oroF).

PFVFRN= Pressure to which the figure given for FVFRN= refers (bara or psia).

LOVIS= Measured value for saturated oil viscosity (cP).

TLOVIS= Temperature to which the figure given for LOVIS= refers (oC oroF).

PLOVIS= Pressure to which the figure given for LOVIS= refers (bara or psia).

UFVFRN= Measured value for undersaturated oil formation volume factor.

TUFVFRN= Temperature to which the figure given for UFVFRN= refers (oC oroF).

PUFVFRN= Pressure to which the figure given for UFVFRN= refers (bara or psia).

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UOVIS= Measured value for undersaturated oil viscosity (cP).

TUOVIS= Temperature to which the figure given for UOVIS= refers (oC oroF).

PUOVIS= Pressure to which the figure given for UOVIS= refers (bara or psia).

GASZ= Measured gas compressibility factor.

TGASZ= Temperature to which the figure given for GASZ= refers (oC oroF).

PGASZ= Pressure to which the figure given for GASZ= refers (bara or psia).

GVIS= Measured gas viscosity (cP).

TGVIS= Temperature to which the figure given for GVIS= refers (oC oroF).

PGVIS= Pressure to which the figure given for GVIS= refers (bara or psia).

For each property being calibrated all three subcodes that is property, temperature and pressure
must be specified.

Example
The example below supplies calibration values for the saturated oil formation volume factor and
viscosity:

CALIBRATE FVFRN = 1.4 TFVFRN = 250 PFVFRN = 4000

CALIBRATE LOVIS = 0.85 TLOVIS = 275 PLOVIS = 2200

CONTAMINANTS Gas phase contaminants data (optional)

Main-code: CONTAMINANTS
Gas Compressibility Factor may be corrected for the presence of non hydrocarbon impurities.
These must be measured as mole fractions (i.e. a value between 0 and 1) of the gas phase at
stock-tank conditions.

CO2= Mole fraction of CO2 (default zero)

H2S= Mole fraction of H2S (default zero)

N2= Mole fraction of N2 (default zero)

H2= Mole fraction of H2 (default zero)

CO= Mole fraction of CO (default zero)

The CO2 and H2S values are used to modify the pseudo-critical pressure and temperature (used
to calculate gas compressibility factor) as described in Beggs pages 30-31. The N2 value is used
to adjust the gas compressibility factor as described in McCain page 120.

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The Black Oil model treats contaminants as part of the gas phase, and assumes they dissolve in
the oil as pressure increases in the same manner as the hydrocarbon gas components. Thus for
any given fluid, the mole fractions will not vary with pressure, temperature or RS.

8.8.2 COMPOSITIONAL DATA

COMP (p.648) Fluid Data File Specification
TPRINT (p.654) Tabular Data Print Options
RATE (p.535) Flow Rate Data

AQUEOUS: Aqueous Component Specification

Also refer to Compositional Modeling (p.449) , COMPOSITION (p.648), LIBRARY (p.652),
PETROFRAC (p.653) and MODEL. (p.652)
A compositional fluid is usually defined with the PIPESIM GUI, and is written to a PVT file. The
name of this file can be referenced with the COMPOSITION (p.648) keyword. Another way to
define a composition is with the LIBRARY, PETROFRAC, AQUEOUS and MODEL statements.
The composition consists of a set of component names, their respective mole fractions, and a
collection of modeling parameters for the phase behavior package. As such it specifies the
composition of the total stream, regardless of any phase split the composition may exhibit at any
pressure and temperature. The AQUEOUS keyword specifies the unit system in which the
aqueous components will be specified.
Main-code: AQUEOUS

BASIS= Selects the desired units. Can be one of:

MOLAR: Aqueous components are specified in moles
GAS: Aqueous components are specified as WGR in m3/mmsm3
LIQUID: Aqueous components are specified as watercut percent in vol/vol

CEMULSION Compositional Liquid Emulsion Data (Optional)

Main-code: CEMULSION

INVERSION= or Specifies the inversion point, the value of watercut where

CUTOFF= or Phase Inversion occurs. In an oil-water mixture at low
BOUNDARY= watercuts, water droplets are carried dispersed in a
continuous oil phase. At much higher watercuts, water is
the continuous phase and oil droplets are dispersed in it.
The inversion point is the watercut where the continuous
phase changes. (%, default 60). The inversion point can
also be calculated using the Brauner and Ullman
correlation, this can be selected by supplying the special
value "*CALC".

TR= or The width of a transition region, which is assumed to exist

TRANSITION= immediately above the inversion point. When the fluid

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watercut falls within the transition region, the liquid

viscosity is calculated by interpolation between that at the
inversion point and the water viscosity.

METHOD= or Selects the required emulsion model. Available models

MODEL= are:

SWAP The mixture viscosity equals the oil viscosity at water cuts
less than or equal to the inversion point, and equals the
water viscosity at water cuts greater than the inversion
point (default).

VOLRATIO The mixture viscosity equals the volume ratio of the oil and
water viscosities.

WLOOSE Use Woelflin "Loose Emulsion" correlation at watercuts

below the inversion point, set to water viscosity above.

WMEDIUM Use Woelflin "Medium Emulsion" correlation at watercuts

below the inversion point, set to water viscosity above.

WTIGHT Use Woelflin "Tight Emulsion" correlation at watercuts

below the inversion point, set to water viscosity above.

WORIG Use PIPESIM original Woelflin loose emulsion correlation

at watercuts below the inversion point, set to water
viscosity above.

KENMONROE Liquid viscosities are calculated from oil and water

viscosities using the Kendal & Monroe equation. This is the
option used when Emulsions are set to None for a
Compositional fluid.

TABLE or USER Emulsion viscosities are interpolated from the table

supplied with the WCUTS= and VISCS= subcodes. The
table is applied at watercuts below and at the inversion
point, set to water viscosity above.

BRINKMAN Use the Brinkman correlation. This generally predicts

elevated liquid viscosities on either side of the inversion
point.

VAND Use the Vand correlation, using Vand's coefficients. This

generally predicts elevated liquid viscosities on either side
of the inversion point.

VANDBARNEA Use the Vand correlation, using Barnea and Mizrahi

coefficients. This generally predicts elevated liquid
viscosities on either side of the inversion point.

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VANDUSER Use the Vand correlation, using coefficients supplied with

the K1= and K2= subcodes. This predicts liquid viscosities
on either side of the inversion point. Suitable choice of
coefficients can yield elevated or depressed viscosities.

RICHARDSON Use the Richardson correlation, using coefficients supplied

with the RKOIW= and RKWIO= subcodes. This predicts
liquid viscosities on either side of the inversion point.
Suitable choice of coefficients can yield elevated or
depressed viscosities.

LEVITON Use the Leviton and Leighton correlation. This generally

predicts elevated liquid viscosities on either side of the
inversion point.

REDAOIW Use Reda Oil-in-Water correlation for all watercuts.

(Inversion point is ignored.)

REDAWIO Use Reda Water-in-Oil correlation for all watercuts.

(Inversion point is ignored.)

REDASWAP Use Reda Oil-in-Water at watercuts below the inversion

point and Reda Water-in-Oil correlation at or above the
inversion point.

WCUTS= or List of Watercuts for METHOD=TABLE, in Multiple Value

WATERCUTS= format. The first watercut value in the table must be zero.
Between 3 and 40 values must be supplied.

VISCS= or List of oil viscosities for METHOD=TABLE, in Multiple

VISCOSITIES= Value format. The first viscosity value in the table is used
to divide into all the others to yield multipliers.

K1= or VANDK1= Coefficient k1 for use in the VANDUSER correlation. The

default value is 2.5

K2= or VANDK2= Coefficient k2 for use in the VANDUSER correlation. The

default value is 0.609

RK= or Coefficient k for the Richardson correlation. Use

KRICHARDSON= throughout the watercut range. (Inversion point is ignored.)

RKOIW= or Coefficient k for the RICHARDSON correlation, used when

KROIW= watercut is below the inversion point.

RKWIO= or Coefficient k for the RICHARDSON correlation, used when

KRWIO= watercut is at or above the inversion point.

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COMPOSITION: Compositional Fluid Specification

Also refer to Compositional Modeling (p.449), LIBRARY (p.652), PETROFRAC (p.653),
AQUEOUS (p.645) and MODEL. (p.652)
A compositional fluid is usually defined with the PIPESIM GUI, and is written to a PVT file. The
name of this file can be referenced with COMPOSITION as documented here. (Another way to
define a composition is with the LIBRARY (p.652), PETROFRAC (p.653), AQUEOUS (p.645)
and MODEL (p.652) statements.)
PVT files can also be written by other programs, and can conform to a number of different formats.
PVT files may contain a table of fluid physical properties and phase split at various pressures and
temperatures; this table may be in addition to, or instead of, a fluid composition. (In the absence of
a composition certain PIPESIM features will not be available; these include fluid mixing ( INJGAS,
INJFLUID (p.609)), separation ( SEPARATOR (p.621)) and the transformation subcodes described
below.)
The composition will consist of a set of component names, their respective mole fractions, and a
collection of modeling parameters for the phase behavior package. As such it specifies the
composition of the total stream, regardless of any phase split the composition may exhibit at any
pressure and temperature.
The supplied composition may be transformed to match a given stock tank phase split. The
subcodes GLR=, WCUT= and so on allow this predefined composition to be transformed so as to
match a specified phase ratios; this of necessity will change the components' mole fractions. The
original composition must exhibit a phase split at stock-tank conditions that includes some of the
phase(s) to be adjusted.
An example of few example of composition are below
library name='CARBON DIOXIDE' comp=0.020600
library name=NITROGEN comp=0.005060
library name=METHANE comp=0.760200
library name=ETHANE comp=0.078500
library name=PROPANE comp=0.039500
library name=ISOBUTANE comp=0.005960
library name=BUTANE comp=0.014400
library name=ISOPENTANE comp=0.004670
library name=PENTANE comp=0.006058
petro name=BPC6 comp=0.007548 tboil=129.29 molwt=0.860E2 sg=0.676
petro name=BPC7 comp=0.010000 tboil=167.09 molwt=0.930E2 sg=0.725
petro name=BPC8 comp=0.010600 tboil=228.29 molwt=0.105E3 sg=0.760
petro name=BPC9 comp=0.006852 tboil=271.49 molwt=0.117E3 sg=0.780
petro name=BP19 comp=0.010400 tboil=359.69 molwt=0.148E3 sg=0.805
petro name=BP27 comp=0.009832 tboil=519.89 molwt=0.212E3 sg=0.835
petro name=BP37 comp=0.001986 tboil=717.89 molwt=0.325E3 sg=0.864

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petro name=BP47 comp=0.000794 tboil=876.29 molwt=0.477E3 sg=0.883

model eos=rks bip=oil1 vis=pedersen
aqueous basis=molar
library name=WATER comp=0.007014

Example of fluid using the default package Multiflash and the RKS equation of state

library name=N2 comp=0.005060

library name=C1 comp=0.760200
library name=C2 comp=0.078500
library name=C3 comp=0.039500
library name=IC4 comp=0.005960
library name=NC4 comp=0.014400
library name=IC5 comp=0.004670
library name=NC5 comp=0.006058
petro name=BPC6 comp=0.007548 tboil=129.29 molwt=0.860E2 sg=0.676
petro name=BPC7 comp=0.010000 tboil=167.09 molwt=0.930E2 sg=0.725
petro name=BPC8 comp=0.010600 tboil=228.29 molwt=0.105E3 sg=0.760
petro name=BPC9 comp=0.006852 tboil=271.49 molwt=0.117E3 sg=0.780
petro name=BP19 comp=0.010400 tboil=359.69 molwt=0.148E3 sg=0.805
petro name=BP27 comp=0.009832 tboil=519.89 molwt=0.212E3 sg=0.835
petro name=BP37 comp=0.001986 tboil=717.89 molwt=0.325E3 sg=0.864
petro name=BP47 comp=0.000794 tboil=876.29 molwt=0.477E3 sg=0.883
model eos=E300PR2
comp package = PVT_E300
aqueous basis=molar
library name=H2O comp=0.007014

Example of fluid using the Eclipse 300 flash package and the Peng Robinson 2 equation of state

Main-code: COMPOSITION

FILENAME= or The name of the data file in which the fluid definition and/or property data
PVTFILENAME= or tables are stored. The name should be enclosed in quotes if it contains
FILE= delimiter characters or spaces.

USE= Optional. The name of the fluid as specified with a BEGIN FLUID (p.550)
block.

LVISFACTOR= A multiplier for adjusting the tabular liquid viscosity data. (Default = 1.0).

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CRICONDENBAR= Upper pressure limit (bara or psia) or the two-phase region which is used
to decide the method of interpolation between 100% liquid and 100%
vapor data points. Above this value PIPESIM will assume dense phase
and interpolate the tabular data appropriately. (Default = 0.0)

WCUT= Watercut, that is the volume % aqueous phase in the total liquid phase at
stock tank conditions. See note 1.

GLR= Gas/liquid ratio at stock tank conditions (sm 3/sm 3or scf/stb). See note
1.

GOR= Gas/oil Ratio at stock tank conditions (sm 3/sm 3or scf/stb). See note 1.

LGR= Liquid/gas ratio (sm 3/mmsm 3or stb/mmscf) .See note 1.

OGR= Oil/gas ratio at stock tank conditions (sm 3/sm 3or stb/mmscf). See note
1.

GWR= Gas/water ratio at stock tank conditions (sm 3/sm 3or scf/stb). See note
1.

WGR= Water/gas ratio (sm 3/mmsm 3or stb/mmscf) .See note 1.

PPMETHOD= Flashing method for Physical Properties prediction: may be 1, 2, or 3.

See note 5 below.

THMETHOD= Flashing method for Temperature-Enthalpy-Entropy balance: may be 1,

2, or 3. See note 5 below.

PRINT Prints a verbose printout of the fluid composition and stock-tank phase
split.

"one component" behavior. Can be set to ON or OFF (default is

OFF). If enabled, the fluid is assumed to consist entirely of one
component molecule, and hence does not exhibit a classical phase
envelope when graphed on axes of pressure versus temperature. Salient
Examples of such systems are pure water or steam, pure Carbon
Dioxide, pure methane, and so on. Special algorithms must be employed
to ensure accurate results in such systems.

PACKAGE= Selects the desired PVT code package name. It can be one of:
MULTIFLASH: The third party company Infochem supplies the Multiflash
package
SHELL: Shell oil company's proprietary package
PVT_E300: Eclipse 300 PVT package
PVT_DBR: DBR PVT 2-Phase package
PVT_GERG: GERG PVT package

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PVT_NIST: NIST REFPROP PVT package

Note:
1. The presence of any of the subcodes GLR=, GOR=, LGR=, OGR=, WCUT=, WGR= or GWR=
causes the supplied composition to be transformed match the specified phase ratios. The fluid
is flashed at stock-tank pressure and temperature, and the resulting phases are re-combined to
yield a new composition.
2. The subcodes GLR=, GOR=, OGR= and LGR= are optional, and mutually exclusive..
3. The subcodes WCUT=, WGR= and GWR= are optional and mutually exclusive
4. Care must be exercised in combining these subcodes, as it is possible to specify a value for
one of them that renders the use of the other one meaningless or illegal: for example with
WCUT=100, any value for GOR= is meaningless; for example GLR=0 conflicts with any non-
zero value for GWR=. It is however always possible to re-state the desired definition correctly
by well-chosen alternative subcodes.
5. The PPMETHOD= and THMETHOD subcodes control the manner in which Physical properties
are computed. The balance is between speed and accuracy. Each of these subcodes can be
set to the value 1, 2 or 3, which have the following meanings:
1: Always Interpolate (fastest). This option uses linear interpolation between physical
properties stored on a predefined grid of temperature and pressure points (default).
3: Always Rigorous Flash (slowest). Interpolation never occurs: properties are obtained by
flashing at the required pressure and temperature. This is the slowest, but most accurate,
method.
2: Rigorous Flash when close to the Phase Envelope, interpolation elsewhere. This is a
compromise between speed and accuracy, which assumes that properties will change more
rapidly when close to a phase boundary. Interpolation is performed whenever the grid points
comprising a rectangle all show the presence of the same phases. For example if all 4
points in the rectangle have some oil, some gas, and no water, then we assume the
rectangle lies entirely within the 2-phase region of the hydrocarbon phase envelope, so
interpolation is appropriate. If however one, two or three of the points have no oil, then
clearly the hydrocarbon dew point line crosses the rectangle, so a rigorous flash is required.
PPMETHOD= controls determination of transport Physical properties (PP) These are the values
required to perform the multiphase fluid flow and heat transfer calculations, and include phase
volume fractions, densities, viscosities, heat capacities and surface tensions.
THMETHOD= controls the Temperature-Energy Balance These values are used to maintain the
temperature/enthalpy/entropy balance of the fluid.
In most simulations, for every PP flash that is performed, there are about 5 to 10 TH flashes,
thus the TH flashes will have the greatest effect on speed and run time. The inaccuracies of TH
interpolated flashes are usually minimal.
The speed impact of each choice will obviously depend on the composition, and the phase
behavior in the PT region of interest. As a rough guide, taking the base case as interpolation,
swapping just the PP flashes to "rigorous" will multiply your run time by about 4. With TH

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flashes also "rigorous", run time will probably increase at least 20 fold. Use of the 'compromise'
choices will be faster.
For those requiring more accuracy, we have found the "most useful" setting (that is the greatest
increase in accuracy for the smallest effect on performance) to be PPMETHOD=2,
THMETHOD=1..

LIBRARY: Library Component Specification

Also refer to Compositional Modeling (p.449) , COMPOSITION (p.648), PETROFRAC (p.653),
AQUEOUS (p.645) and MODEL. (p.652)
A compositional fluid is usually defined with the PIPESIM GUI, and is written to a PVT file. The
name of this file can be referenced with the COMPOSITION (p.648) keyword. Another way to
define a composition is with the LIBRARY, PETROFRAC, AQUEOUS and MODEL statements.
The composition consists of a set of component names, their respective mole fractions, and a
collection of modeling parameters for the phase behavior package. As such it specifies the
composition of the total stream, regardless of any phase split the composition may exhibit at any
pressure and temperature. The LIBRARY keyword specifies the name and the composition of the
library component..
Main-code: LIBRARY

NAME= The name of the component in the library

COMPOSITION= The composition (in moles for non aqueous elements and in the unit specified
by the AQUEOUS (p.645) keyword for aqueous elements)

MODEL: Model Properties Specification

Also refer to Compositional Modeling (p.449) , COMPOSITION (p.648), LIBRARY (p.652),
PETROFRAC (p.653), AQUEOUS (p.645) and MODEL. (p.652)
A compositional fluid is usually defined with the PIPESIM GUI, and is written to a PVT file. The
name of this file can be referenced with the COMPOSITION (p.648) keyword. Another way to
define a composition is with the LIBRARY, PETROFRAC, AQUEOUS and MODEL statements.
The composition consists of a set of component names, their respective mole fractions, and a
collection of modeling parameters for the phase behavior package. As such it specifies the
composition of the total stream, regardless of any phase split the composition may exhibit at any
pressure and temperature. The MODEL keyword specifies the fluid property model in terms of
EOS, Viscosity model, BIP set, Physical properties method and Temperature-Enthalpy balance
method. In addition, the flash package can be specified. This is a requested package and the
engine will try to honor it if another package has not yet be loaded. To enforce the loading of a
specific package, use the package subcode of the main code COMPOSITION (p.648).
Main-code: MODEL

EOS= optional RKS or PR or CSM or RKSS or CPA or BWRS or CSMA or PVTIPRC

or PVTIPRC3P or PVTIPRS or PVTIPR3P or E300PR2 or E300PR2C or

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E300PR3C or E300SRK2 or E300SRK3 or DBR2PR2C or DBR2PR3C or

DBR2SRK2 or DBR2SRK3 or GERG-2008 or NIST-DEFAULT.

VISCOSITY= optional PEDERSEN, PEDERSEN-E, PED-E, LBC, LBC-E, LBC-D, LBCSE,

LBCVR, LBCWOEL. PEDSE, PEDVR, PEDWOEL, SHELL_MODEL

BIP= optional PVTIDEFAULT, FILE (BIP File), OIL1, OIL2, OIL3, OIL4,
E300_DEFAULT, E300_USERFILE, DBR2_DEFAULT, DBR2_USERFILE,
GERG_DEFAULT, NIST_DEFAULT. See BIP.

PACKAGE= optional
MULTIFLASH: The third party company Infochem supplies the Multiflash package
SHELL: Shell oil company's proprietary package
PVT_E300: Eclipse 300 PVT package
PVT_DBR: DBR PVT 2-Phase package
PVT_GERG: GERG PVT package
PVT_NIST: NIST REFPROP PVT package

PPPACKAGE= optional
MULTIFLASH: The third party company Infochem supplies the Multiflash package
SHELL: Shell oil company's proprietary package
PVT_E300: Eclipse 300 PVT package
PVT_DBR: DBR PVT 2-Phase package
PVT_GERG: GERG PVT package
PVT_NIST: NIST REFPROP PVT package

PPMETHOD= optional 1, 2 or 3

THMETHOD= optional 1, 2 or 3

PETROFRAC: Petroleum Fraction Specification

Also refer to Compositional Modeling (p.449) , COMPOSITION (p.648), LIBRARY (p.652),
AQUEOUS (p.645) and MODEL. (p.652)
A compositional fluid is usually defined with the PIPESIM GUI, and is written to a PVT file. The
name of this file can be referenced with the COMPOSITION (p.648) keyword. Another way to
define a composition is with the LIBRARY, PETROFRAC, AQUEOUS and MODEL statements.
The composition consists of a set of component names, their respective mole fractions, and a
collection of modeling parameters for the phase behavior package. As such it specifies the
composition of the total stream, regardless of any phase split the composition may exhibit at any
pressure and temperature. The PETROFRAC keyword specifies the name, composition and
properties of the petroleum fraction..
Main-code: PETROFRAC

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NAME= The name of the petroleum fraction

COMPOSITION= The composition (in moles) default 0

BPOINT= optional Boiling Point

MW= optional The molecular weight

SG= optional The specific gravity

TCRIT= optional The critical temperature

PCRIT= optional The critical pressure

ACENTRIC= optional The acentric factor

VISCOSITY= optional The reference viscosity

Notes:
Minimum data requirements for a petrofraction component are for the Multiflash package:
a. Either MW and SG
b. BPOINT and SG
c. PCRIT, TCRIT and ACENTRIC
There is no petroleum fraction supported in GERG and NIST. In E300 and DBR, the minimum
data required is the molecular weight (MW)

TPRINT Tabular Data Print Options (Optional)

Main-code: TPRINT

FILE= The name of the fluid data file to be printed (12 characters maximum) which should be
entered in quotes if the string contains delimiter characters. Up to five different files can
be specified. Once a file has been specified it will be printed at the beginning of each
case in the job until table printing is switched off using the NONE sub-code. To print the
main fluid, use the wildcard * INLINE.

NONE= Turns the table printing option off. Table printing can produce large amounts of output, so
it is common practice to print the data files in the first case of a job and then insert a
TPRINT, NONE command in the second case to suppress table printing in the
subsequent cases.

8.9 PIPESIM OPERATIONS OPTIONS

MULTICASE Introduction and Summary (p.659)
Explicit Subcodes (p.660)
General PurposeSubcodes (p.663)

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Combining MULTICASE and CASE/ENDCASE (p.664)

Multiple Case and PS PLOT (p.665)
Reservoir Simulator Tabular Data Interface (p.666)
Changing Profile Data by Assignment (p.667)
ITERN Iteration Data (Optional) (p.537)
Wax Deposition (p.670)

8.9.1 NAPLOT: Nodal Analysis

Main-code: NAPLOT
This maincode, in conjunction with PIPESIM graphics processor PS-PLOT, allows the generation
of a graph of inflow/outflow curves about the Nodal Analysis point specified with the NAPOINT
maincode.
The '?' - delimiter symbols are like the general purpose ("greek") sub-codes on the MULTICASE
statement. They can be used anywhere in the subsequent profile, and be equated to multiple
values in the same way as the sub-codes on MULTICASE. For more information see MULTICASE
(p.659).
All subcodes are optional.

?INFLOW= The inflow sensitivity values. Each value will produce one inflow curve. If omitted,
a single inflow curve will be generated. See note 6.

?INFLOW2= These sub codes may be equated to a range of values, the number of values
?INFLOW3= provided must equal the number provided in the ?INFLOW subcode. The values
provided are selected in step with those on ?INFLOW. See note 6.
?INFLOW4=
?INFLOW5=

?OUTFLOW= The outflow sensitivity values. Each value will produce one outflow curve. If
omitted, a single inflow curve will be generated. See note 6.

?OUTFLOW2= These sub codes may be equated to a range of values, the number of values
?OUTFLOW3= provided must equal the number provided in the ?OUTFLOW subcode. The
values provided are selected in step with those on ?OUTFLOW. See note 6.
?OUTFLOW4=
?OUTFLOW5=

NINPTS= The number of points to be used to generate each inflow curve (default 20,
maximum 200).

NOUTPTS= The number of points to be used to generate each outflow curve (default 20,
maximum 200).

POUT= The system outlet pressure. This is used to generate the outflow curves. If this
subcode is omitted the system outlet pressure will be obtained from the POUT=
subcode of the ITERN statement. See note 3. (Psia or Bara.)

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LIMITIN= This subcode controls the application of any flowrate limit to the inflow curves.
(Flowrate limits are supplied on the MAXLIQ=, MAXGAS= or MAXMASS=
subcodes, or are assumed implicitly from the maximum value on GAS=, LIQ= or
MASS= subcodes.) Can be set to YES or NO, the default being NO. If YES, the
limit is applied, so the inflow curves will extend to that flowrate limit or to each
curve's natural AOFP (Absolute Open Flow Potential, i.e. the rate at which the
operating point pressure falls to zero), whichever is smaller. If NO, the limit is not
applied so all inflow curves will extend to their natural AOFP..

LIMITOUT= This subcode controls the application of a calculated pressure limit to the outflow
curves. (The pressure limit will be calculated from the maximum pressure
occurring on any of the inflow curves. Note: an explicit pressure limit can also be
provided with the MAXP= subcode, which will take priority.) Can be set to YES or
NO, the default being NO. If the limit is applied, then the outflow curves will
extend to the maximum rate limit supplied or calculated, or to 20% above the
maximum pressure calculated for any of the inflow curves.

MAXP= The maximum pressure to be used when generating the outflow curves. (Psia or
Bara.) Default is double the maximum pressure in any of the inflow curves.

MINP= The minimum pressure to be used when generating the inflow curves. (Psia or
bara). Default is none, so the inflow curves will extend to their AOFP or the
specified flowrate limit.

MAXLIQ= The maximum liquid flow rate to be used when generating the outflow curves.
See notes 2 and 4. (m 3/d or STB/D).

MAXGAS= The maximum gas flow rate to be used when generating the outflow curves. See
notes 2 and 4. (MMm 3/d or MMscf/d).

MAXMASS= The maximum mass flow rate to be used when generating the outflow curves.
See notes 2 and 4. (kg/s or lbs/s).

PRINT= Sets the number of cases for which detailed output will be generated in the
output file: default is 1. This number is applied separately to the inflow, outflow
and operating points, so you actually get 3 times as many cases printed as the
value you supply. Eg. at its default of 1, you will get detailed output for the first
inflow point, the first outflow point, and the first operating point; set it to 5 and you
get the first 5 cases of inflow, the first 5 of outflow, and the first 5 operating
points.

OPPOINTS= Controls the explicit generation and display of Operating Points. Can be set to
YES or NO, default is YES.
The intersection of one inflow curve and one outflow curve is known as an
Operating Point. Whilst it is possible to infer the system flowrate geometrically
from the line intersections alone, it is more accurate and far safer to calculate the
flowrate by simulating the system end-to-end, which PIPESIM is well designed to
do. The resulting pressure and flow rate is displayed on the Nodal Analysis graph
as an Operating Point. This explicit calculation ensures the inflow and outflow

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fluid properties and temperature are identical, thus eliminating the possibility of a
mismatch and consequent error in answer interpretation.
Operating points are generated for each permutation from the lists of inflow and
outflow sensitivity variables, as supplied in the ?INFLOW= and ?OUTFLOW=
subcodes. However, it is possible to set up the sensitivities so that some
combinations are invalid, and these do not result in operating points being
generated and displayed. For example, if you set both inflow and outflow
sensitivity to the fluid watercut, most of the permutations will be invalid, because
the fluid at the intersection cannot have 2 different values for watercut. With
Operating point generation enabled, the valid intersections are clearly
distinguishable from the invalid ones: operating points will only be generated for
"valid" combinations.
Sometimes it will happen that the displayed operating point does not coincide
with the geometric intersection. The cause of this will always be that the outflow
fluid properties or temperature do not match that of the operating point. The fact
that the mismatch is evident should be regarded as a feature, not a bug, and
should alert the user to a problem or condition that requires particular caution and
attention.
With operating point generation enabled, the profile plot file will contain valid
profile plots for each operating point: these can be viewed by selecting Reports
> Profile Plot in the PIPESIM GUI.

MATCH= This subcode selects the method by which the fluid temperature and composition
is matched between the inflow and outflow curves. Can be set to:
MAXFL: The inflow curve with the maximum AOFP rate is used. All outflow
curves will use the values interpolated from this single inflow curve. (This was the
behaviour in release 2009.1 and earlier, before the operating points were
available).
OP: The generated Operating Points are used, along with the appropriate inflow
curve on the low flowrate side. At flowrates higher than the operating points, the
temperature and composition from the highest appropriate operating point is
used. This is the default. If operating point generation is suppressed however
(see OPPOINT= below), the MAXFL method will be used.
OP2: The generated Operating Points are used, along with the appropriate inflow
curve on both sides. This option can cause the outflow curves to exhibit marked
changes in slope at high flowrates, caused by the use of unrealistially low
temperatures interpolated from the high rate inflow curve close to its AOFP.
OFF: matching is turned off. The outflow curves will use the system-defined fluid
properties and inlet temperature.
Matching is important to ensure the fluid temperature/enthalpy and composition
are consistent across inflow and outflow curves. Without it, the intersections or
operating points between the curves may bear little or no resemblance to
physical reality. The matching is achieved by using the temperatures and
composition(s) from the correct inflow curve or operating point(s) to generate the
ones used for the outflow curves. For example, if the inflow curves are generated

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from multiple completions, each of which has a different reservoir fluid, the
resulting mixed fluid composition at the NA point will change at each value of
flowrate. The matching algorithm ensures the temperature and composition are
interpolated from the correct inflow curves and operating points, so as to produce
outflow curves that use an appropriate fluid composition and temperature. Thus
each point on the outflow curve will usually have a unique temperature and
composition. Matching is applicable to both black oil and compositional fluids.

MATCHENTH= Allows the use of Enthalpy, instead of temperature, in the matching (see
MATCH= above). Can be set to YES or NO. The default is NO.

LIQ= A set of stock-tank liquid flow rates to be used when generating the outflow
curves. A maximum of 200 flow rates may be specified. If omitted, the program
will generate the set of flowrates at run-time. See notes 1, 2, 5 and 6. (m 3/d or
STB/D).

GAS= A set of stock-tank gas flow rates to be used when generating the outflow curves.
A maximum of 200 flow rates may be specified. If omitted, the program will
generate the set of flowrates at run-time See notes 1, 2, 5 and 6. (MMm 3/d or
MMscf/d).

MASS= A set of mass flow rates to be used when generating the outflow curves. A
maximum of 200 flow rates may be specified. If omitted, the program will
generate the set of flowrates at run-time. See notes 1, 2, 5 and 6. (kg/s or lbs/s).

Notes:
1. If a set of flow rates are supplied with GAS= LIQ= or MASS= subcodes, they will be used to
generate the outflow curves. A maximum of 200 flow rates may be supplied, and the Range
Format can be used. If omitted, then the program will choose the rates for the outflow curves
using an algorithm designed to distribute the points on the curve to best effect. This will result in
rates being clustered close together in areas where the pressure is changing fastest, i.e. in
regions of maximum slope. Rates will also be generated at the operating points, to make the
validity (or otherwise) of the curve intersections evident. (The rates used for the inflow curves
are always generated with this algorithm.)
2. The subcodes LIQ=, GAS=, MASS=, MAXLIQ=, MAXGAS=, and MAXMASS= are mutually
exclusive.
3. The pressure iteration is the only valid iterative option when doing nodal analysis, and is only
applicable to the outflow curves. The outlet pressure and the flow rate are known which
requires the calculation of an inlet flowing pressure. POUT can be specified either on the
NAPLOT statement, or the ITERN statement.
4. MAXLIQ=, MAXGAS= and MAXMASS= will also apply to the inflow curves if
LIMITINFLOW=YES.
5. The special value "*none" can be used on the LIQ=, GAS= and MASS= subcodes. If used, its
effect is to remove or cancel an existing list of flowrates supplied on a previous statement. An
example of why this might be useful is to override a list of rates supplied by PIPESIM.

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6. The multiple values should be supplied enclosed in parenthesis, and separated by commas. A
multi-value range can also be specified. For more information, see Multiple value Data Sets.
(p.519)

8.9.2 NAPOINT System Analysis Point

Main-code: NAPOINT
Use this main-code to specify the required system (nodal) analysis point. NAPOINT divides the
profile into two halves, and effectively runs separate jobs on each half. NAPOINT can be placed
anywhere in the profile.

LABEL=

RESETDATUM=

ON

OFF

8.9.3 MULTICASE Introduction and Summary

The MULTICASE card is available to allow the user to set up many PIPESIM cases without having
to enter many CASE and ENDCASE cards. By use of the MULTICASE card, it is possible to
specify multiple values for various flow parameters on one card, rather than repeating cases.
The central idea behind MULTICASE is that its sub-codes can accept more than one value. So if,
for example, you want to run 8 cases at various different flow rates, then instead of having to
append an extra 7 explicit cases to your input file, a single MULTICASE card can be used to
specify all 8 flow rates, and PIPESIM will execute the 8 separate cases automatically.
If a second multiple-valued subcode is provided, PIPESIM will execute as many separate cases as
are required to combine all the values in each multiple subcode. So, for example, if we had:
Example

MULTICASE LIQ=(10,20,30,40,50,60,70,80) WCUT=(30,60,90)

The result would be 24 cases, representing the combination of all specified flow rates with all
specified water cuts.
There are two distinct classes of sub-code available:
1. Explicit sub codes, such as LIQ=, WCUT, and IPRES are simply duplicates (or duplicate the
function of) sub codes that appear on other main codes, such as RATE and INLET. The
important difference is that they only accept multiple values on the MULTICASE card.
2. General purpose sub codes, such as ?ALPHA and ?BETA, which accept multiple values on the
MULTICASE card and are then used in place of a sub code value further down the input data.

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The provision of MULTICASE has allowed other sophisticated PIPESIM features to be built
alongside it, for example the Reservoir Table Interface (p.666) and Well Performance Curve
Generation.

General Rules for use with MULTICASE

The following notes apply to all subcodes on MULTICASE. Further restrictions exist for particular
sub-codes and combinations of sub-codes, and these are documented where they arise.
1. The MULTICASE main-code must appear before the first NODE card in the job.
2. Each multiple-valued sub-code can be equated to a maximum of 20 values, separated from one
another by commas, and the whole group enclosed in parentheses.
3. In any job, the maximum number of subcodes containing multiple values is 5.
4. The MULTICASE card cannot be continued: however, 2 or more MULTICASE cards can
appear sequentially in the input file, thus allowing many sub-codes to be specified.
5. Each sub-code containing multiple values must appear on a single MULTICASE card. A
maximum of 80 characters is allowed for all values enclosed in parentheses. The maximum
input line length is 140 characters.
6. The MULTICASE card(s) should appear immediately before the first NODE card in the job,
except when greek symbols are used, when the card(s) using the greeks should appear
between MULTICASE and NODE.
7. MULTICASE was designed to be used instead of explicit extra cases (the CASE and
ENDCASE cards), however both can be used in combination as long as no MULTICASE cards
appear in subsequent explicit cases.
8. When subsequent explicit cases are used with MULTICASE, each subsequent explicit case will
result in another complete set of multiple cases (see Section 8.4 for an example of this). The
LIMIT subcode applies only to the set of multiple cases defined by the MULTICASE card(s), not
to the total number of cases in the job.
9. MULTICASE jobs contain an implied 'loop' structure in the input data. Every line of input
between the MULTICASE card(s) and the beginning of the system profile is scanned at the start
at the beginning of every case, to ensure that any Greek symbols are assigned the correct
values. Only the symbolic information is processed, and any other input is ignored except on
the first case.

Multiple Case Specification Card

Main-code: MULTICASE
The subcodes available on the MULTICASE card can be divided into two distinct categories as
outlined in Explicit subcodes (p.660) and general purpose subcodes (p.663) .

8.9.4 Explicit Subcodes

LIQ= ( , ) Gross liquid flow rate values at stock tank conditions. A maximum of 20
flow rates may be specified (sm3/d or STB/D).

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GLR= ( , ) Gas/liquid ratio values at stock tank conditions. A maximum of 20 values

may be specified (sm3/sm3 scf/STB/D). Default = 0.

GAS= ( , ) Gas flow rate values at stock tank conditions. A maximum of 20 flow rates
may be specified. (mmsm3/d or mmscf/d).

LGR= ( , ) Liquid/gas ratio values at stock tank conditions. A maximum of 20 values

may be specified. (sm3/d or STB/scf). Default= 0.

GOR= ( , ) Gas/oil ratio values at stock tank conditions. A maximum of 20 values may
be specified. (sm 3/sm 3 or scf/STB). Default = 0.

OGR= ( , ) Oil/gas ratio values at stock tank conditions. A maximum of 20 values may
be specified. (sm 3/d or STB/scf). Default = 0. Note that the flow rate may
be expressed either on the basis of the stock tank liquid or gas flow rate.
The LIQ+GLR and GAS+LGR options are therefore mutually exclusive. An
error will be reported if an invalid combination is entered and program
execution will be terminated.

MASS= ( , ) Mass flow rates for use with compositional cases. A maximum of 20 flow
rates may be specified. (Kg/s or lbs/s).

WCUT= Water cut values that is the volume % water in the liquid phase at stock
(,) tank conditions. A maximum of 20 values may be specified. Default = 0.

WTYPE= Alphanumeric sub-code. This describes the type of well under

(,) consideration that is Injector (INJ) or Producer (PRD). This sub-code is
only required if the WTHP sub-code is used.

WTHP= Tubing head pressure values. The definition of tubing head pressure is
(,) dependent on the physical configuration of the well. In the case of a
producer it is the system outlet (last node) pressure, that is tubing head
pressure for a well only, or the separator pressure in the case of a well
and flowline. In the case of an injector it is the system inlet (first node)
pressure, (bara or psia). A maximum of 20 values may be specified. The
WTYPE sub-code must accompany this sub-code.

IPRES= Inlet set pressure (bara or psia). This provides a means of specifying the
(,) inlet pressure of a system. The maximum number of values which may be
specified is 20.

OPRES= Outlet set pressure (bara or psia). Similar usage to the IPRES sub-code
(,) above. The maximum number of values which may be specified is 20.

XEST= This sub-code does not take multiple values under the MULTICASE
option, but may take a value for iterative cases as defined previously
under the ITERN card (see Section 2.4). For cases where the inlet or
bottom hole pressures are to be calculated an estimate of the parameter
may be made using the following formula.

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Default = well (pipe) vertical length x pressure gradient + WTHP (OPRES)

Pressure 0.0679 bar/m or 0.3 psi/ft for liquid) = 0.0113 bar/m or 0.05 psi/ft (for gas).
gradient
=

ITYPE= Iteration Type see ITERN card description.

PRINT= If the MULTICASE option is specified then all output except titles will be
suppressed after the first case. In order to override this 'auto-noprint'
procedure the sub-code PRINT must be included. Care should be
exercised here if a large number of cases are set up as very large
quantities of output can be generated.

LIMIT= This sub-code sets a limit on the number of cases which will be run, and
will abort the job at the start of execution if the number of cases to be run
is greater than this. The default value is ONE, and therefore a limit must
be set by you as a guard against an excessive number of cases being run.

LINE= When using 3 or more Multicase options, this sub-code allows you to
specify which loop controls the line structure. In the absence of a LINE=
sub-code, the innermost loop controls this. Every time the innermost loop
resets to its first value, a new line is started in the Job Plot file. You can
specify the depth of the required controlling loop with the LINE= sub-code.

Notes:
1. Some sub-codes on the MULTICASE card are duplicates, or equivalents of sub-codes on the
ITERN, RATE, and INLET cards (for example the IPRES sub-code is equivalent to the PRES
sub-code on the INLET card and the XEST sub-code serves the same purpose as the one
appearing on the ITERN card ). If such duplicate or equivalent sub-codes are used on both the
MULTICASE card and elsewhere in the same case, then the values supplied on the
MULTICASE card will override the values supplied elsewhere. For example, Here the
LASTANSWER sub-code (see Section 9.1) has been specified along with the MULTICASE
card. Outlet and Inlet Pressures have been specified under both the ITERN and INLET cards in
addition to being specified under the MULTICASE card. In such an example PIPESIM will
ignore the POUT, TYPE, PRESS and XEST sub-codes specified under the ITERN and INLET
sub-codes and will use IPRESS, OPRESS and XEST values specified under the MULTICASE
card. The LASTANSWER option will be in operation even though the rest of the sub-codes
specified under the ITERN card will be ignored.
2. The sub-codes can be entered in any order.
3. The use of certain sub-codes excludes the use of other sub-codes
a. Flow rate must be defined (with LIQ, GAS or MASS sub-codes) when the WTHP sub-code is
used.
b. The well type must be defined with the WTYPE sub-code when the WTHP sub-code is used.
c. ITYPE, IPRES and OPRES sub-codes exclude the use of the WTHP sub-code .

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d. Iteration type must be defined with the ITYPE sub-code when the OPRES sub-code is used
and outlet pressure must be defined under OPRES when the ITYPE sub-code is used.
e. If LIQ, GAS or MASS sub-codes appear on the MULTICASE card then either IPRES or
OPRES may be used but not both.

8.9.5 General Purpose Subcodes

Sub-codes : ?ALPHA, ?BETA, ?GAMMA, ?DELTA, ?EPSILON
The subcodes described here greatly increase the power and flexibility of MULTICASE.
The purpose of the MULTICASE maincode is to allow the user to execute a PIPESIM case for
every combination of a set of input variables. For example, suppose we specify 3 water cuts, 4 flow
rates, 5 GLR's and 6 outlet pressures: all possible combinations of these values will result in
PIPESIM executing 360 individual cases, since 3 X 4 X 5 X 6 = 360. The process of selecting
every possible combination of a series of variables is called permutation, and so we often use the
verb permute when describing what the MULTICASE maincode can do.
Five new general-purpose symbolic subcodes have been added, namely: ?ALPHA, BETA, ?
GAMMA, ?DELTA, and ?EPSILON. They are collectively known as Greeks. They can be equated
to multiple values in the same way as other subcodes on MULTICASE. The symbols can then be
used further down the input data in place of any other value. Thus, the greeks behave similarly to
symbols created by the ASSIGN (p.667) maincode.

Examples
In the following example, 3 values of inlet temperature are permuted with 2 values of Gas-Lift GLR
in a well:

Example 1
Example

RATE LIQ=45 GLR=180

MULTICASE ?ALPHA =(210,250,290)
MULTICASE ?BETA=(200, 220)
INLET PRESS=4200 TEMP=?BETA
NODE DIST=0 ELEV=-4000 TEMP=?BETA
NODE DIST=0 ELEV=-3000 LABEL='GAS LIFT'
RATE GLR=?ALPHA
NODE DIST=0 ELEV=-2000

The symbol ?BETA is set to 2 values on the MULTICASE card. ?BETA is then used on the INLET
card in place of the value of Inlet Temperature. Note that, while it is possible to control Inlet
Pressure with the existing IPRES subcode on the MULTICASE card, Inlet Temperature is not
available as an explicit subcode on MULTICASE. However, because of the 'general-purpose'
nature of the Greek symbols, it is now possible to control it (and, in principle, almost anything else)
from the MULTICASE card.
The symbol ?ALPHA is set to 3 values on the MULTICASE card. ?ALPHA is then used on the
RATE card in the profile, in place of the value for GLR. Thus, like the ASSIGN card, the greek

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symbols provide a convenient way to change values within the system profile. Unlike the ASSIGN
card however, the values equated on the MULTICASE card will be permuted to result in a number
of cases being executed.

Example 2
The values equated to the greeks can be any appropriate numeric value or character string,
depending on the use to which it is put further down the input data. For example, it is possible to
permute a range of flow correlations:

MULTICASE ?DELTA=(BBO,BJA1,BJA2)?GAMMA=(BB,TD)
HCORR PLOSS=BBO HOLDUP=?DELTA MAP=?GAMMA

Notes:
1. The new greek subcodes can be used in conjunction with the existing MULTICASE subcodes,
but the maximum number of multiple value specifications on any MULTICASE card set remains
5. One 'multiple value specification' consists of a keyword equated to a number of values in
parentheses.
2. PIPESIM scans its input data once, starting at the top, so any greek symbols must be equated
on the MULTICASE card before they are used in place of a value elsewhere.

8.9.6 Combining MULTICASE and CASE/ENDCASE

The MULTICASE card is a way of achieving a large number of PIPESIM cases for comparatively
little input data. It can be called a 'shortcut', for the alternative is to provide explicit extra cases in
the input data, with the ENDCASE and CASE cards. In general, it is always possible to 'expand' a
job containing MULTICASE cards into one containing a (large?) number of explicit cases, with
CASE and ENDCASE cards (except where certain maincodes require the presence of
MULTICASE, viz. TABLE and WPCURVE). However, it is not always possible to 'compress' a job
consisting of a number of explicit cases into a MULTICASE job. The choice is therefore open to
you, depending on the application, whether to use MULTICASE or explicit cases. It is also possible
(but tricky) to combine the two.
Why would anyone want to use MULTICASE and explicit cases? There are a number of things that
are just not possible with MULTICASE, where explicit extra cases are the only way to achieve the
desired result. For example, suppose you want to see the effect of changing pipe diameter and
flow rate on the resulting outlet pressure from a flowline. You might set up something like this:
Example

MULTICASE LIQ=(200,300,400,500,600,700,800)
MULTICASE ?ALPHA=(4.2,5,5.5,6.2)
PIPE ID=?ALPHA
NODE DIST=0 ELEV=0

This would result in 28 cases, one for each flow rate/diameter combination. However, it is
incomplete. The pipe wall thickness has not been specified on the PIPE card. And it's when we try
to add the wall thickness that the problems arise, because each pipe diameter has its own
particular wall thickness. We can't use another greek on the MULTICASE card to specify the wall

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thicknesses, because to do so would result in PIPESIM permuting all combinations of diameter and
wall thickness and running 112 cases, which is definitely not what we want! The only sensible
solution to this problem is to remove the pipe diameter from the MULTICASE, and add 3 more
explicit cases to do what we want. However, there is a catch. To see what the catch is, look at the
modified input data:
Example

PIPE ID=4.2 WT=.6

MULTICASE LIQ=(200,300,400,500,600,700,800)
MULTICASE ?ALPHA=(4.2,5,5.5,6.2)
NODE DIST=0 ELEV=0
...
ENDCASE
CASE Second size
PIPE ?ID=5 WT=0.8
ENDCASE
CASE Third size
PIPE ID=6.2 WT=0.8

Now we have complete control over what is with what. The first explicit case will consist of 7
multicase cases, one for each of the flow rates on three MULTICASE card, all at the first pipe
diameter and wall thickness. The second explicit case changes the diameter and wall thickness,
and because it changes nothing else, it too will consist of 7 multiple cases for each flow rate. And
so for the third and fourth explicit cases. What, therefore, is the catch?
The catch in the above example concerns the position of the first PIPE card. Notice that, in the first
example, the PIPE card appeared after the MULTICASE cards. It had to appear there because it
contained a greek symbol which was defined on the MULTICASE card. Why, therefore, have we
moved it? The reason : All input data between the MULTICASE cards and the first NODE card is
scanned by PIPESIM on each case. Therefore, values supplied in these cards will override any
values supplied in subsequent explicit cases.
This, then is the 'MULTICASE/Explicit Case Combination Catch': it is perfectly possible to mix
MULTICASE and explicit cases in the same job, but take care not to put any cards between the
MULTICASE cards and the first NODE card unless they really need to be there, that is if they use
greek symbols defined on the MULTICASE cards.
There is something else which, although perfectly possible and legal, you are advised not to do: do
not put further MULTICASE cards in subsequent cases. You almost certainly will not get the result
you expect if you do.

8.9.7 Multiple Case and PS-PLOT

The order in which the subcodes appear on the MULTICASE card determines the order in which
the cases will be executed, which in turn determines which points make up a single 'line' on the
finished graph. Therefore, care should be exercised to ensure that the subcodes appear in an
appropriate order.
An example will serve to clarify this point:

MULTICASE WCUT=(0,25,50,75,90) LIQ=(20,50,100,150,200,250)

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This multicase card will result in 30 cases being executed. Since the LIQ subcode appears last, it
forms the 'inner' loop of the execution process: PIPESIM will take the first WCUT value and
execute 6 cases, one at each of the liquid flow rates. Then it will take the second WCUT value, and
execute another 6 cases, one for each of the liquid flow rates. This loop will be repeated until all 5
water cut values have been executed. Since the plot file is written to at the end of every case, the
first 6 points will represent 6 different flow rates at the first water cut, the next 6 will represent 6
flow rates at the second water cut, and so on. Thus the graph that PS-PLOT will draw will contain 5
curves, Bone for each water cut. Each curve will consist of 6 points, corresponding to the flow
rates. Now consider the following MULTICASE card:

MULTICASE LIQ=(20,50,100,150,200,250) WCUT=(0,25,50,75,90)

The only difference between this card and the previous card is the order of the subcodes. Now, the
WCUT subcode appears last and so will form the 'inner' loop of execution. Thus the graph that PS-
PLOT will draw will contain 6 curves, Bone for each flow rate; each curve will consist of 5 points,
one for each water cut.

8.9.8 Reservoir Simulator Tabular Data Interface

Main-code : TABLE
This main-code is used to write tabular performance data to a file for input into another model
(such as a reservoir simulator). The effects of variations of one or more (up to four) parameters are
investigated. A tabular data file is created in a format as specified under the TYPE sub-code
accordingly.
The TABLE main-code should appear before the first NODE (p.614) card in a job and for PIPESIM
versions 2.4+ should appear after the MULTICASE (p.659) card.

FLOWTYPE= Type of flow by definition specified by the Reservoir Simulator. This

must be specified by the user and may be LIQ or GAS for multiphase
flow or OIL, WATER, or GAS for single phase flow

LIQ Liquid

GAS Gas

OIL Oil

WATER Water

TYPE= Type (or format) of data file to which the results of the calculations are
written.

PORES PORES

ECLIPSE ECLIPSE

VIP VIP

WEPS WEPS

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MORES MORES

COMP4 COMP4

ADDTEMP= Type of variable to write to the data file (Default = NO)

NO Write out only the BHP data

YES In addition to the BHP data, also write out the Temperature data in a
separate VFP Table file

USERELEV= User specified bottom hole datum depth, in default system unit. If given,
it overrides the engine computed default value.

NUMBER= Table number (between 1 and 10000) which forms part of the name of
the interface data file to be created and appears within the file itself (for
example, if input file is fred.psm and NUMBER=2, for a production well,
the BHP data file name is fred.VFPPROD.BHP.02.txt). Default = 1.

ALQ= Artifical Lift Quantity. Sensitivity values can be specified for one of the
following quantities: INJGAS, GLR, GOR, INJGLR, INJGOR, INJMAS,
INJLIQ, PUMPDP, PUMPPR, PUMPPO, PUMPPW, PUMPST and
PUMPSP.

Note:
1. Any RATE (p.535) or ITERN (p.537) card in the job input is ignored once the MULTICASE
(p.659) and TABLE option have been selected.
2. The sub-codes can be entered in any order.

8.9.9 ASSIGN Changing Profile Data by Assignment

Main-code: ASSIGN
In PIPESIM Versions 2.70 and higher, ASSIGN can be used to supply "parallel values" in
MULTICASE'd jobs. Any ASSIGN card defining a multiple-valued symbol, which appears after a
MULTICASE card defining a Greek symbol or explicit multi-value subcode, will be treated as
parallel to the multicase symbol or sub-code immediately preceding it. Please note, a multi-value
ASSIGN card must not appear before the first MULTICASE card.
Suppose you want to set up a MULTICASE job to permute a range of PIPE IDs against something
else, e.g. water cut. To make the analysis more rigorous the correct wall thickness (WT) for each
ID should be used. If a 3rd Greek on the MULTICASE card is included, this will permute all the
combinations of ID and WT, not what is required. However, by using an ASSIGN card, containing
the extra data, at the correct point, will result in the required result.

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Notes:
1. In PIPESIM Versions 2.41 and higher it is now possible to change variable values within a
system profile without repeating the whole profile. Previously, if a value within the profile was
changed in a second or subsequent case, then the complete system profile had to be re-
entered. It is possible for you to invent one or more symbols and then assign different values to
the symbol in subsequent cases. The symbol is typically used within the profile in place of a
numeric value. The value can then be assigned outside the profile, thus obviating the need to
repeat the entire system profile in subsequent cases.
2. All symbols must begin with a question mark "?" and are limited to 12 characters. The value
assigned can be any appropriate numeric value or alphanumeric string. If delimiters are
included, the string must be enclosed in quotes. Up to 30 symbols can be defined and
assigned.
3. ASSIGN may be used to update data within the profile but it can not be used to introduce new
main-codes or sub-codes within the profile. If a new main-code or sub-code is introduced within
the profile (that is after the second NODE card) then the whole profile must be repeated.

Example
MULTICASE ?BETA =(0,20,50,80)
MULTICASE ?ALPHA=(3,4,4.5,5,6)
ASSIGN ?THICK=(0.4,0.5,0.5,0.6,0.6)
INLET PRESS=900 TEMP=70
RATE LIQ=3000 WCUT=?BETA
PIPE ID=?ALPHA WT=?THICK

8.9.10 OPTIMIZE
Allows the PIPESIM single branch engine to calculate optimal values of parameters to match
measured pressure and / or temperature data.
Main-code: OPTIMIZE

?OPT01= (...,...) Minimum and maximum values for 1st optimization variable.

?OPT02= (...,...) Minimum and maximum values for 2nd optimization variable.

?OPT03= (...,...) Minimum and maximum for 3rd optimization variable.

?OPT04= (...,...) Minimum and maximum for 4th optimization variable.

?OPT05= (...,...) Minimum and maximum for 5th optimization variable.

PMATCH= Weighting factor for pressure match.

TMATCH= Weighting factor for temperature match.

TOL= Accuracy (default 0.02). Optimization converges when the fractional change
in the RMS is less than the specified accuracy.

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Note: To ensure good convergence, PIPESIM automatically scales the single

branch pressure tolerance (PTOL) to be tighter/smaller than the RMS
tolerance (TOL). However, if either of these tolerances are manually altered
using keywords in such a way that PTOL > TOL, this could result in
convergence problems for the data matching operation.

MAXIT= Maximum number of iterations (default 200). Optimization finishes without

convergence if the number of PIPESIM iterations needed exceeds this limit.
The actual number of PIPESIM runs may be less than the reported number of
iterations. This is because the optimizer may call PIPESIM with the same
inputs as an earlier iteration. In this case PIPESIM is not re-run the results
are read from memory.

VERBOSE= ON Outputs details of optimizer iteration runs

OFF Outputs details of the initial and optimized runs. (Default)

Examples
Example 1: optimizing flow correlation parameters to match measured pressure data
In this example the friction factor and hold up factor for the vertical flow correlation are set equal to
the first two optimization variables. The OPTIMIZE keyword is used to set the range for these two
variables (0.2 to 5 in both cases) and to select measured pressure data matching. The OPTIMIZE
keyword is used to set the range for these two variables (0.2 to 5 in both cases) and to select
measured pressure data matching.

optimize ?opt01(0.2,5) ?opt02=(0.2,5) pmatch=1

vcorr type=HBR ffactor=?opt01 hfactor=?opt02

Example 2: optimizing heat loss rate to match measured temperature data

In this example the u value multiplier is set equal to the first optimization variable. The OPTIMIZE
keyword is used to set the range (0.01 to 100) and to select measured temperature data matching.

optimize ?opt01(0.01,100) tmatch=1

vcorr ufactor=?opt01

Example 3: matching measured pressure and temperature data simultaneously

In this example the two previous examples are combined to match both pressure and temperature
data simultaneously. This can be important in cases when the heat loss affect the pressure
calculations. The relative weightings of the pressure and temperature matches have been set
equal in this example. The MULTICASE keyword is also used to allow multiple flow correlations to
be used.

multicase ?beta=(ANSARI,DR,HBR)
optimize ?opt01(0.2,5) ?opt02=(0.2,5) ?opt03=(0.01,100) pmatch=1 tmatch=1

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vcorr type=?beta ffactor=?opt01 hfactor=?opt02

options ufactor=?opt03

Example 4: controlling the optimization

To control the optimization you can set the accuracy and maximum number of iterations:

optimize tol=0.001 maxit=500

The keyword can be supplied using Engine Options to control the Data Matching operation.

8.9.11 Wax deposition and Time Stepping modeling options

Main-code: WAX or TIME
The deposition of wax from a fluid on to the walls of the pipe or tubing can be modeled as a
function of time. Data must be provided to specify the required wax properties, the required time
parameters, and timestep calculation criteria. Since these properties overlap to a considerable
degree they can all be provided on either the WAX or TIME maincode. All times are currently
assumed to be in HOURS.
Wax deposition can also be modeled on an instantaneous basis. The rate of wax deposition can be
calculated, and used to produce a graph of (for example) wax deposition rate against distance.
Multiple sensitivity cases can then be used in the usual way to sensitize on variables of interest, so
as to observe their effect on wax deposition rate. To do this, ensure your job omits any of the
following time-based subcodes, and specify the desired sensitivity variable values with
MULTICASE.

Time subcodes
Subcodes concerned only with setting time-based data and options:

DURATION= Duration of the simulation: provides an alternative to ENDTIME=. To simulate

the system over a period of time the duration must be positive: if it is zero, the
simulation will consist of a normal PIPESIM steady-state run, valid for an
arbitrary instant in time (which is useful for investigating the factors that
contribute to wax deposition).

STEPSIZE= The size of each timestep: only used if OPTION is 1. Timestep size can also
be computed automatically during the run by selecting a suitable OPTION.

STARTTIME= Time at which simulation is to start. (Default zero)

ENDTIME= Time at which simulation is to finish: see also DURATION= below. (Default
zero)

UNITS= Units of time to be used in simulation. Can be any of YEARS, MONTHS,

WEEKS, DAYS, HOURS, MINUTES, or SECONDS.

MINSTEPSIZE= The minimum allowable time step size that can be computed from OPTIONS
2 through 5.

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REPINTERVAL= The interval between reporting steps. This can be set independently of the
timestep size to allow a number of timesteps to occur with no reported output,
if desired. The timestep size will be adjusted to ensure that one ends at each
report interval, in order to allow the report to be written.

PRINT= Specifies the number of timesteps for which the detailed wax deposition
output page will appear. This value will override the CASES= subcode of
PRINT.

RESTART= Time at which to restart from a previous simulation. If a restart time is

specified it overrides any supplied STARTTIME. The wax profile to restart
from is obtained from the restart file, see READRESTART.

READRESTART= Specifies the name of the restart file to read (default model name.WRS). Has
no effect unless accompanied by RESTART=. The file will be searched for a
profile representing the specified restart time. If necessary, 2 existing profiles
will be interpolated to create a profile representing the required time.

WRITERESTART= Specifies the name of the restart file to write to (default model name.WRS) A
restart file is always written if the run is stepping through time (that is has a
positive duration, see above). If the run is restarting and the read and write
restart filenames are identical, the new profiles will be written at the file
position corresponding to the time of restart, thus any pre-existing profiles for
later timesteps will be overwritten and lost. If this is not the desired behavior,
this or the previous subcode can be used to specify alternate file names,
which can be copies or new files as appropriate. In addition the model name
may be changed (with the File/Save As) menu.

Termination subcodes
Subcodes concerned with or terminating the timestepping simulation, as a result of simulation
conditions:

MAXPIGDP= The maximum Delta Pressure available to push a wax removal scraper
pig through the line. The simulation will terminate early when sufficient
wax has deposited to cause the specified DP to occur.

MAXSYSDP= An upper limit on the Delta Pressure between system inlet and outlet
(psi or bar). In order to take effect, the simulation operation must have
specified that inlet pressure or outlet pressure be the calculated
variable.

MAXWAXTHICK= or An upper limit in the thickness of the wax deposit anywhere in the
MAXTHICKNESS= system (in or mm).

MAXVOLUME= or The maximum volume of wax allowed to accumulate in the system. (ft3
MAXWAXVOLUME= or or m3)
MAXPIGVOLUME=

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MINLIQRATE= A lower limit for system stock-tank liquid flowrate. (bbl or m3). In order
to take effect, the simulation operation must have specified that
flowrate be the calculated variable.

MINGASRATE= A lower limit for system stock-tank gas flowrate. (mmscf3 or mmm3). In
order to take effect, the simulation operation must have specified that
flowrate be the calculated variable.

MINMASSRATE= A lower limit for system total mass flowrate. (lb/sec or kg/sec). In order
to take effect, the simulation operation must have specified that
flowrate be the calculated variable.

MINID= or MINWAXID= A lower limit on the internal Diameter of the wax deposit anywhere in
the system (in or mm).

Wax subcodes
Subcodes concerned with Setting wax properties, deposition properties, and modelling options:

METHOD= or The chosen Wax Deposition method. May be:

CLIENTMODEL= DBR or DBRS: D. B. Robinson and Associates, single-phase
DBRM: D. B. Robinson and Associates, multi-phase
SHELL: Shell oil Company proprietary method
BP: British Petroleum Company proprietary method
Note that all methods require an explicit license. D .B. Robinson
and Associates is a wholly-owned subsidiary of Schlumberger.

DENSITY= or RHOWAX= or Wax density (lb/ft3 or kg/m3).

WAXRHO=

CONDUCTIVITY= or Wax thermal conductivity (BTU/hr/ft/F or W/m/C).

WAXCONDUCTIVITY=

ROUGHMODE = Specifies whether wax wall roughness is to be calculated. Set to

INPUT to use the roughness suppied with ROUGH= below (or on
the PIPE statement), or CALC to have it calculated.

ROUGHNESS= or Surface roughness of the wax (in or mm) .

WAXROUGHNESS= or
ROUGH=

WAXYIELDSTR = or the Yield strength of the deposited wax (psi or/bar). Used to
TAUWAX= or WAXTAU= or calculate DP during pigging.
YIELDSTRENGTH=

IFCMETHOD= Inside Film Coefficient method. This is provided for backwards

compatibility, and accepts the same values as SPIFCMETHOD=
and MPIFCMETHOD= subcodes on the HEAT statement.

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BP, DBRS or DBRM method subcodes

Subcodes that are specific to the BP, DBRS or DBRM methods:

FILENAME= or FNAME= or The name of the Wax properties file. the BP and DBR methods
INPUTFNAME= require a separate file to hold wax thermodynamic and deposition
properties, the format of which is proprietary to each method.

BPFILENAME= or Same as FILENAME=, and sets METHOD=BP.

BPFNAME= or
BPINPUTFNAME=

DBRFILENAME= or Same as FILENAME=, and sets METHOD=DBRS.

DBRFNAME= or
DBRINPUTFNAME=

OILFRAC= Oil fraction in the wax (0 to 0.99).

SHEARCOEF= or Shear coefficient to simulate wax stripping. Also known as Shear

SRMULT= reduction Multiplier. Note: Each keyword has different ranges:
SHEARCOEFF= is intended to be used with the BP method (0 to 1);
SRMULT= is intended to be used with the DBR method (10 to
+10).

DIFFCO= or MDMULT= Molecular Diffusion coefficient multiplier. Note: Each keyword has
DIFCOEFACTOR= different ranges:
Both DIFFCO= and DIFCOEFACTOR= are intended to be used with
the BP subcode (0.01 to 1); MDMULT= is intended to be used with
the DBR subcode (10 to +10).

COEFWAXK= Multiplier for the oil thermal conductivity, to simulate the thermal
conductivity of the wax deposit. Must be in the range 1 to 2. BP
method only

DCMETHO= or Diffusion Coefficient method, may be:

FLAGDIFFCOEF= WILKECHANG: Wilke & Chang
HAYDUMINHAS: Hayduk & Minhas
USER: user-supplied with DIFFCO=
BP method only.

ROUGHCOEF= Roughness multiplier (0 to 1). BP method only.

BPFFMETHOD= BP Friction factor method. Can be set to ON or OFF. Controls which

Friction factor is used for calculating the Inside Film Coefficient with
BP method (IFCMETHOD=BP). If set to ON, then the friction factor
is calculated using the BP internal flow correlation. if set to OFF, the
friction factor is calculated by the PIPESIM selected flow correlation.
BP method only.

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COEFWAXK= Wax Thermal Conductivity Coefficient (0 to 100). BP method only.

LHCOEF= Coefficient on Liquid Holdup for two-phase scaling (-5 to +5). DBRM
method only.

S2YCOEFF= Coefficient on ratio of shear stress to yield stress (-5 to +5). DBRM
method only.

SFCOEF= Coefficient on shear factor used in porosity calculation (-5 to +5).

DBRM method only.

SWCOEFF= Coefficient on Surface Wetting for two-phase scaling (-5 to +5)

DBRM method only.

T2RCOEFF= Coefficient on ratio of wax thickness to radius (-5 to +5).DBRM

method only.

TFCOEF= Coefficient on temperature factor used in oil fraction calculation (-5

to +5). DBRM method only.

TRANSTEMPRANGE= or Wax transition temperature range / region (F or C). DBRM method

WAXTRANSTEMP= only.

Shell subcodes
Subcodes specific to the SHELL method:

OPTION= Options to control how the timestep size is computed. An integer in the range
1 through 5, meaning:
1: Fixed timestep using the user's specified step size.
2: Auto timestep, all constraints: Wax DX, HTC , DP.
3: Auto timestep, wax DX and DP constraints only.
4: Auto timestep, wax DX and HTC constraints only.
5: Auto timestep, wax DX constraint only.

MINDX= The minimum allowable increase in wax ID. This sets a lower limit on the
timestep size computed from OPTIONS 2 through 5.

SETDX= The maximum increase in wax ID. This is used to compute the timestep size
from OPTIONS 2 through 5.

HTCLIMIT= Controls the application of the Heat Transfer Coefficient limit on the timestep
size. Set to ON or OFF.

RELAX= The relaxation factor for automated timestep adjustment computed from
OPTIONS 2 through 5. Must be a real number between 0 and 1; higher
values favour the new value, lower the old.

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DFRACTION= Fraction of the pressure drop change allowed with the new timestep (0.01 ==
1%) computed from OPTIONS 2 through 5.

CWDPRES= Critical Wax Deposition Pressures. A vector of pressures, up to 30 may be

provided, which must be in ascending order (psia or bara). Values are
separated by commas and enclosed in parentheses.

CWDTEMP= Critical Wax Deposition Temperatures. A vector of temperatures, up to 30

may be provided, to correspond with the values for CWDPRES= (F or C).
Values are separated by commas and enclosed in parentheses.

MPTEMP= Modeling Parameter temperatures. A vector of temperatures, up to 30 may be

provided, which must be in ascending order (F or C). Values are separated by
commas and enclosed in parentheses.

MPA= Modeling Parameter A values. A vector of coefficients, up to 30 may be

provided, to correspond with the values for MBTEMP=. Values are separated
by commas and enclosed in parentheses.

MPB= Modeling Parameter B values. A vector of coefficients, up to 30 may be

provided, to correspond with the values for MBTEMP=. Values are separated
by commas and enclosed in parentheses

MPC=, MPD=, Additional subcodes to specify modelling parameters C through J. Each

MPE=, MPF=, requires a vector of coefficients, up to 30 may be provided, to correspond with
MPG=, MPH=, the values for MBTEMP=. Values are separated by commas and enclosed in
MPI=, MPJ= parentheses

RATEMODEL= or Deposition rate model number. Currently there is only one rate model,
MODEL= number 1.

CWRPRES= Critical Wax Removal Pressures. A vector of pressures, up to 30 may be

provided, which must be in ascending order (psia or bara). Values are
separated by commas and enclosed in parentheses.

CWRTEMP= Critical Wax Removal Temperatures. A vector of temperatures, up to 30 may

be provided, to correspond with the values for CWDPRES= (F or C). Values
are separated by commas and enclosed in parentheses.

MODE= Controls whether to model wax deposition or removal: set to DEPOSITION or

REMOVAL.

8.10 PIPESIM-Net keywords

SETUP (p.40)
BRANCH (p.678)
SOURCE (p.680)
SINK (p.683)

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JUNCTION (p.685)
NSEPARATOR (p.685)

Note: The preferred order of statements is: SETUP (p.40) , SOURCE (p.680) , JUNCTION
(p.685) , SINK (p.683) , BRANCH (p.678) , NSEPARATOR (p.685).

See Input Files and Data Conventions (p.515) for more detailed information on formatting.

8.10.1 SETUP
SETUP is a network keyword (p.675), used to define various network options.

Subcodes
TITLE= The model title. Can include spaces if enclosed in quotes.

TOLERANCE= The overall tolerance of the converged network solution. Must be

between 0.5 and 1e-6, default 0.01.

MAXITER= The maximum allowable number of overall network iterations. Must be

between 3 and 1000, default 100.

FLUIDMODEL= or An override on the type of fluid model to use. This is not normally
COMPOSITION= required, as it is obtained from the fluid definitions supplied in the branch
files, but can be supplied here if desired. Can be set to:

BLACKOIL: Fluid type is set to black oil

COMPOSITION: Fluid type is set to compositional

STEAM: fluid type is set to steam

UNSTABLEWELL= How to treat unstable wells. If the converged network solution results in a
well operating in its unstable, or liquid-loaded region, you may wish it be
automatically shut in. Can be set to SHUT or FLOW, meaning:

SHUT: Shut in any well that is operating in its unstable region. This is the
default.

FLOW: allow unstable wells to remain in operation.

RECIPBYPASS= How to treat redundant Reciprocating Compressor (recips). The network

solution can converge with a recip in a so-called redundant state,
where pressure actually reduces across it instead of increasing. Clearly,
a recip in this state is not doing the job it was intended to do, and the
network would be better off without it. If this subcode is set to ON, then
any redindant recip will be bypassed, i.e. effectively removed from the
model solution. Can be set to ON or OFF, default ON.

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ALGORITHM= The choice of network solution algorithm. Can be set to WEGSTEIN or

JACOBIAN, default WEGSTEIN.

WOFLMODE= Global settings for Wells Off Line Mode. May be set to:

OFF: Disable WOFL mode. All pressure-specified production wells and

source branches are modelled ON-line.

CREATE: Enable WOFL mode, and unconditionally create WOFL files

for all pressure-specified sources and production wells at the start of the
simulation.

CREATE?: Enable WOFL mode. Read and validate any existing WOFL
files, comparing the fluid definition, pressure boundary condition, and
branch geometry in them to the corresponding values in the current
model for the branch. If they match, use the file, otherwise re-create it.

USE: Enable WOFL mode. Unconditionally read any existing WOFL files
and use them, despite possible mismatch between them and the current
model settings. No new files will be created.

ECHOBRANCH= Allows the contents of all well and branch geometry files to be echoed to
the network output file. Can be set to YES or NO, default NO.

SKIPINACTIVE= Controls the skipping (i.e., omission of processing) of geometry files for
inactive branches: can be set to YES or NO.

In a coupled PIPESIM/Eclipse/IAM simulation, it is common practice to

start the simulation with a number of branches turned OFF. The
timestepping simulation then turns them ON at a later timestep, maybe
after many hours of simulation CPU time. If at this time it is found that the
branch geometry files concerned contain syntax or logic errors, the
simulation has to be aborted, resulting in much time and work lost.
Clearly, for this type of simulation, it is preferable to check and validate
all branch geometry files at the start of the run, so as to diagnose such
errors as early as possible. Thus the default state for a coupled
simulation is NO.

By contrast, in a normal uncoupled PIPESIM run, a branch's ON or OFF

state will not change during the run, so any syntax or logic errors caused
by the contents of inactive geometry files can be ignored. Thus the
default state for an uncoupled simulation is YES.

This flag can also be set with the -E command line switch, which has the
same effect as setting it to YES.

RESTARTINTERVAL= Specifies the time interval between writing restart files: a value in
seconds, default 1800. The interval is measured in real (i.e. wallclock,
not CPU) seconds.

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Restart files are written at the end of every simulation, and at the end of
any as-yet-unconverged network iteration after the specified interval. The
purpose of the restart file is to allow the simulation to be restarted, which
is useful to allow a new simulation to re-use the converged results of a
previous one, and/or to recover from a simulation that terminated
abnormally. However, the file writing can take considerable time, and so
impose a speed penalty on the overall simulation. So there is strong
incentive to minimise the frequency of writing them.

By default the files are written every half-hour, the idea being that if the
program is interrupted or fails abnormally, you can restart it, having lost
at most half an hour's work. If you would prefer to loose less work in this
event, set the interval to a value smaller than 1800 seconds, but by doing
so you accept the extra overhead of writing the files more often.

You can also increase the interval to reduce the restart file writing.
Setting it to a very large value (eg 1e10) will result in the files being
written only when the simulation converges, or when it hits iteration limit.

ECHONET= Controls the echo of the network input data to the output file. can be set
to YES or NO, default YES.

8.10.2 BRANCH
BRANCH is a network keyword (p.675), used to define a branch and associated network topology.

Subcodes
NAME= The name of the branch. Can include spaces if enclosed in quotes.

FILENAME= The file name containing the Branch's input data, as formatted for a
Single-branch PIPESIM model. Can include spaces if enclosed in quotes.
See note 1.

START= The branch start Network Node name. See note 1.

END= The branch end Network Node name. See note 1.

BLOCK= Specifies a direction in which flow is blocked, i.e. not allowed to go. Can
be set to:

NONE: No flow block exists, so flow may go in either direction

FORWARD: Flow is blocked in the forward direction, so it may only go in

reverse.

REVERSE: Flow is blocked in the reverse direction, so it may only go

forward,

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BOTH: flow is blocked in both directions, so the branch is effectively

inactive.

ON Specifies that the branch is active and that no flow block exists in it, so
flow can go in either direction. has the same effect as BLOCK=NONE.

OFF Specifies that the branch is inactive and flow is blocked in both
directions. has the same effect as BLOCK=BOTH.

ESTLIQUID= or An estimate of the flowrate in the branch, as a stock-tank liquid rate

EST_LIQUID= (sbbl/d or sm3/d). The iterative network solution algorithm will commence
with this as the branch flowrate.

ESTGAS= or An estimate of the flowrate in the branch, as a stock-tank gas rate

EST_GAS= (mmscf/d or mmsm3/d). The iterative network solution algorithm will
commence with this as the branch flowrate.

ESTMASS= or An estimate of the flowrate in the branch, as a mass rate (lb/sec or Kg/
EST_MASS= sec). The iterative network solution algorithm will commence with this as
the branch flowrate.

UPPERMASS= or Upper limit of mass flowrate for the branch (lb/sec or Kg/sec).. See note 2.
MAXMASS= or
LIMITMASS=

UPPEROIL= or Upper limit of oil flowrate for the branch(sbbl/d or sm3/d). See note 2.
MAXOIL= or
LIMITOIL=

UPPERLIQ= or Upper limit of liquid flowrate for the branch (sbbl/d or sm3/d). See note 2.
MAXLIQ= or
LIMITLIQ=

UPPERGAS= or Upper limit of gas flowrate for the branch (mmscf/d or mmsm3/d). See
MAXGAS= or note 2.
LIMITGAS=

UPPERWAT= or Upper limit of water flowrate for the branch (sbbl/d or sm3/d). See note 2.
MAXWAT= or
LIMITWAT=

USERESTART= A per-branch override on the use of solution data from restart files. When
a model run is restarted, by default, the solution information for all
branches is extracted from the restart file, and used as the start point for
the run. This subcode allows the restart information for this branch to be
ignored, so the run will use default information for the branch. Can be set
to YES, to use the restart data, or NO, to ignore it. Default is YES.

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Notes:
1. The names of the network nodes which adjoin the branch must be specified with the START=
and END= subcodes. Network nodes are defined with the statements SOURCE, (p.680) SINK
(p.683) , JUNCTION (p.685) and NSEPARATOR (p.685) statements. The pipeline
geometry as detailed in the file supplied with the FILENAME= subcode, is assumed to start at
the network node named with the START= subcode, and end at the node named with END=.
Note, this does not specify the direction of fluid flow: the network solution will determine if the
branch actually flows forward, i.e. with the geometry direction, or reverse, i.e. against the
geometry direction.
2. Any combination of Maximum Flowrate limits may be specified, the simulation will enforce
whichever turns out to be most limiting. The limits are enforced by the addition of a choke at the
branch outlet. The choke bean diameter is calculated so as to enforce the limit, so a pressure
drop will occur across the choke. Flowrate limits may be applied to all branches, except for (a)
any branch connected to the outlet of a network separator, and (b) any branch draining a
source with a fixed flowrate specification.

8.10.3 SOURCE
SOURCE is a network keyword (p.675), used to define conditions at a network inlet.

Subcodes
NAME= The name of the source. Can include spaces if enclosed in quotes.

PRESSURE= Source pressure specification (psia or bara). See note 1.

TEMPERATURE= Temperature of fluid flowing from the source (F or C). If absent, this is
obtained from the data in the branch geometry file.

LIQUIDRATE= or LIQ= Source flowrate specification, as a stock tank liquid rate (sbbl/d or
sm3/d). See note 1.

GASRATE= or GAS= Source flowrate specification, as a Stock tank gas rate (mmscf/d or
mmscm/d) . See note 1.

MASSRATE= or Source flowrate specification, as a Stock tank mass rate (lb/sec or Kg/
MASS= sec). See note 1.

REBC= Remove Existing Boundary Condition for the source. This is used when
multiple SOURCE statements refer to the same named source, and you
want this statement to remove all boundary conditions for this source
specified with earlier statements.

FCLIQUID= Source flowrate specification, as a Flowing liquid rate (bbl/d or m3/d).

See notes 1 & 2.

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FCGAS= Source flowrate specification, as a Flowing gas rate (mmscfd or sm3/d).

Note the units of this are at stock-tank conditions.

FCPRESSURE= The pressure for the accompanying flowing rate specified with FCLIQ= or
FCGAS= (psia or Bara)

FCTEMPERATUR= The temperature for the accompanying flowing rate specified with
FCLIQ= or FCGAS= (F or C)

CURVEP= For curve specified source, an array of pressures (psia or bara). See note
3. Example:

CURVEP=(20,1000,2000) psia

CURVEL= For curve specified sources, an array of liquid rates (bbl/d or m3/d). See
note 3. Example:

CURVEL=(20,1000,2000) bbld

CURVEG= For curve specified sources, an array of gas rates (mmscfd or mmsm3d).
See note 3. Example:

CURVEG=(20,1000,2000) mmscfd

CURVEM= For curve specified sources, an array of mass rates (lb/s or Kg/s). See
note 3. Example:

CURVEM=(20,1000,2000) lb/s

CURVET= For curve specified sources, an array of temperatures (F or C). See note
3. Example:

CURVET=(20,40,60) F

ON Specifies that the source is active, or switched ON.

OFF Specifies that the source is inactive, or switched OFF.

CURVEFILE= Specifies that the source and adjoining branch has already been
simulated in Wells Off-Line (WOFL) mode, and that the results of this are
available in the named file. Example:

CURVEFILE='Curve1.PWH'

A number of additional special values may be supplied instead of the

filenale, these are distinguished by the first character being an asterisk,
'*', namely:

CURVEFLIE=*USE: this has the same effect as above, but the filename
to read from is assumed from the default source and branch names.

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CURVEFLIE=*CREATE : Specifies that a WOFL file for the source and

adjoining branch are to be created at the start of the network simulation.
The network simulation will then use the results in this file.

CURVEFLIE=*CREATE?: Same as above, except that any pre-existing

file will be used if its specifications match the current network's.

QUALITY= For steam systems, the quality (fraction gas) of the steam flowing into the
source. If absent, this will be obtained from the branch geometry file.

CURVESENS_P= For WOFL specified sources, supplies sensitivity information in units that
match the data in the WOFL file.

CURVESENS_T= For WOFL specified sources, supplies sensitivity information in units that
match the data in the current (.TNT) file.

CURVESENS_S= For WOFL specified sources, supplies sensitivity information in Strict SI

units.

UPPERMASS= or Upper limit of mass flowrate for the source (lb/sec or Kg/sec).. See note
MAXMASS= or 4.
LIMITMASS=

UPPEROIL= or Upper limit of oil flowrate for the source (sbbl/d or sm3/d). See note 4.
MAXOIL= or
LIMITOIL=

UPPERLIQ= or Upper limit of liquid flowrate for the source (sbbl/d or sm3/d). See note 4.
MAXLIQ= or
LIMITLIQ=

UPPERGAS= or Upper limit of gas flowrate for the source (mmscf/d or mmsm3/d). See
MAXGAS= or note 4.
LIMITGAS=

UPPERWAT= or Upper limit of water flowrate for the source (sbbl/d or sm3/d). See note 4.
MAXWAT= or
LIMITWAT=

ELEVATION= Absolute elevation of the source (ft or m). If supplied, this will be used as
a datum for plotting branch elevations. If more than one junction has an
elevation, they will be used to cross-check with other source, sink and
junction elevations, to help identify where loop elevation mismatch
error(s) have occurred.

N.B. It is useful to supply the absolute elevations of any number of

Network nodes (Junctions, Sources, and Sinks). This allows the elevation
data in the connecting branches to be checked. Note that the same node
name may appear in multiple SOURCE statements: the data on each
statement is additive for the overall node specification. Thus for example,

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a series of SOURCE statements can be supplied under Setup Engine

options to set the node elevations for sources already specified in the
GUI's model. Same goes for JUNCTION and SINK statements.

ESTPRESSURE= Estimate of pressure to be used as a starting point for the network

solution (psia or bara).

Notes:
1. A source may have a pressure specification, or a flowrate specification, or a curve specification.
These are known as Hydraulic Boundary Conditions.
2. A flowing flowrate may be specified as an alternative to a stock-tank flowrate. It must be
accompanied by FCPRES= and FCTEMP= .
3. A source may be specified with a curve of flowrate against pressure, as an alternative to a fixed
pressure or flowrate. The subcodes CURVEP=, and one of (CURVEG=, CURVEL=, or
CURVEM=) are used for this, they all accept Multiple Value Data Set (p.519). The curve may
be accompanied by a temperature array with CURVET=. All subcodes so specified must have
the same number of values. Between 3 and 30 values may be supplied.
4. Any combination of Maximum Flowrate limits may be specified, the simulation will enforce
whichever turns out to be most limiting. The limits are enforced in the adjoining branch, by the
addition of a choke at the branch outlet. The choke bean diameter is calculated so as to enforce
the limit, so a pressure drop will occur across the choke.

8.10.4 SINK
SINK is a network keyword (p.675), used to define conditions at a network outlet.

Subcodes
NAME= The name of the sink. Can include spaces if enclosed in quotes.

PRESSURE= Sink pressure specification (psia or bara). See note 1.

LIQUIDRATE= or LIQ= Sink flowrate specification, as a stock tank liquid rate (sbbl/d or sm3/d).
See note 1.

GASRATE= or GAS= Sink flowrate specification, as a Stock tank gas rate (mmscf/d or mmscm/
d) . See note 1.

MASSRATE= or Source flowrate specification, as a Stock tank mass rate (lb/sec or Kg/
MASS= sec). See note 1.

REBC= Remove Existing Boundary Condition for the sink. This is used when
multiple SINK statements refer to the same named sink, and you want
this statement to remove all boundary conditions for this sink specified
with earlier statements.

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ON Specifies that the sink is active, or switched ON.

OFF Specifies that the sink is inactive, or switched OFF.

UPPERMASS= or Upper limit of mass flowrate for the sink (lb/sec or Kg/sec).. See note 2.
MAXMASS=

UPPEROIL= or Upper limit of oil flowrate for the sink (sbbl/d or sm3/d). See note 2.
MAXOIL=

UPPERLIQ= or Upper limit of liquid flowrate for the sink (sbbl/d or sm3/d). See note 2.
MAXLIQ=

UPPERGAS= or Upper limit of gas flowrate for the sink (mmscf/d or mmsm3/d). See note
MAXGAS= 2.

UPPERWAT= or Upper limit of water flowrate for the sink (sbbl/d or sm3/d). See note 2.
MAXWAT=

ELEVATION= Absolute elevation of the sink (ft or m). If supplied, this will be used as a
datum for plotting branch elevations. If more than one network node has
an elevation, they will be used to cross-check with other source, sink and
junction elevations, to help identify where loop elevation mismatch
error(s) have occurred.

N.B. It is useful to supply the absolute elevations of any number of

Network nodes (Junctions, Sources, and Sinks). This allows the elevation
data in the connecting branches to be checked. Note that the same node
name may appear in multiple SINK statements: the data on each
statement is additive for the overall node specification. Thus for example,
a series of SINK statements can be supplied under Setup Engine
options to set the node elevations for sinks already specified in the GUI's
model. The same goes for JUNCTION and SOURCE statements.

ESTPRESSURE= Estimate of sink pressure to be used as a starting point for the network
solution (psia or bara).

Notes:
1. A sink may have a pressure specification, or a flowrate specification. These are known as
Hydraulic Boundary Conditions.
2. Any combination of Maximum Flowrate limits may be specified, the simulation will enforce
whichever turns out to be most limiting. The limits are enforced in the adjoining branch, by the
addition of a choke at the branch outlet. The choke bean diameter is calculated so as to enforce
the limit, so a pressure drop will occur across the choke.

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8.10.5 JUNCTION
JUNCTION is a network keyword (p.675), used to define a junction, or to supply additional or
override data for an existing junction.

Subcodes
NAME= Name of the junction. Can include spaces if enclosed in quotes.

ESTPRESSURE= Estimate of pressure to be used as a starting point for the network

solution (bara or psia)

ESTTEMPERATURE= Estimate of fluid temperature to be used as a starting point for the network
solution (F or C)

ELEVATION= Absolute elevation of the junction (ft or m). If supplied, this will be used as
a datum for plotting branch elevations. If more than one Network node
has an elevation, they will be used to cross-check with other node
elevations, to help identify where loop elevation mismatch error(s) have
occurred.

N.B. It is possible, and useful, to supply the absolute elevations of any

number of Network nodes (Junctions, Sources, and Sinks). This allows
the elevation data in the connecting branches to be checked. Note that
the same node name may appear in multiple JUNCTION statements: the
data on each statement is additive for the overall node specification. Thus
for example, a series of JUNCTION statements can be supplied under
Setup Engine options to set the node elevations for junctions already
specified in the GUI's model. Same goes for SOURCE and SINK
statements.

8.10.6 NSEPARATOR
NSEPARATOR is a network keyword (p.675), used to define a network separator.

Subcodes
NAME= Name of the separator

FEEDBRANCH= Name of the branch feeding the separator

DISCARDBRANCH= Name of the branch to receive the discarded stream. See note 1.

TYPE= The phase of the discarded stream: may be GAS, LIQUID, or WATER.
See note 1.

PRESSURE= Separator pressure (psia or bara). This is optional: see note 2.

EFFICIENCY= Percentage efficiency of the separation process: see note 3. Must be in the
range 10 to 100.

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Notes:
1. A network separator causes a feed stream to be separated into 2 outlet streams, as specified
by the TYPE= subcode. They are known as the discard stream and the kept stream, for
compatability with the single-branch separator (p.621). In a network model however, the term
discard is misleading, because the discard stream is not discarded, it is separated and made
to flow into the branch named with the DISCARDBRANCH= subcode.
2. The requirements of the network solution dictate that a pressure discontinuity must occur at the
outlets of a network separator. If a pressure has been specified, then both of the outlet
branches will exhibit a pressure discontinuity, calculated to ensure that the separated streams'
flowrates are maintained in the downstream network(s). If a pressure is not specified, then only
the discard branch will exhibit a discontinuity. These discontinuities represent the necessary
pressure control valves and/or pumps that are required to maintain liquid level control in the
separator.
3. The efficiency term refers to how much of the discard phase is separated from the feed
stream. For example, an efficiency of 90% in a gas separator will cause 90% of the gas phase
to be sent down the discard branch; the remaining gas, plus ALL of the liquid, will go down the
keep branch.
4. Separators work at flowing, or in-situ, pressure and temperature. The flowing phase split as
predicted by the selected fluid PVT model will usually be very different from the stock-tank
phase split, please bear this in mind when you look at the resulting branch flowrates. In
particular, PIPESIM allows you to display branch and node flowrates using the report tool, but
alas this shows only stock-tank rates, which are not useful to understand separator
performance.
5. If the phase to be separated does not exist, then clearly the separator cannot function as
expected. In this case all flow will go down the keep branch. Inlet and outlet compositions will
be identical.
6. If the phase to be separated is the only phase present, then clearly the separator cannot
function as expected. In this case the efficient fraction of the flow will go down the discard
branch, with the remainder going down the keep branch. Inlet and outlet compositions will be
identical.

8.11 Keyword Index

Input Files and Input Data Conventions (p.515)
General Data (p.522)
Compositional Data (p.645)
Blackoil Data (p.633)
Heat Transfer Data (p.623)
Flow Correlation Data (p.554)
System and Equipment Data (p.588)

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Well Performance Modeling (p.566)

PIPESIM Operations (p.654)
PIPESIM-Net Keywords (p.675)

8.11.1 Keyword List

A (p.511) B (p.511) C (p.512) D (p.512) E (p.512) F (p.512) G (p.512) H (p.513) I (p.513) J (p.513)
K (p.513) L (p.513) M (p.513) N (p.514) O (p.514) P (p.514) Q (p.514) R (p.514) S (p.514) T
(p.515) U (p.515) V (p.515) W (p.515) X (p.515) Y (p.515) Z (p.515)

A
ASSIGN (p.667)

B
BACKPRES (p.580)
BEGIN (p.550)
BLACKOIL (p.633)
BRANCH (p.678)

C
CASE (p.524)
CALIBRATE (p.643)
CHOKE (p.589)
COAT (p.626)
COMP (p.648)
COMPCRV (p.593)
COMPLETION (p.567)
COMPRESSOR (p.595)
CONETAB (p.579)
CONFIG (p.631)
CONTAMINANTS (p.644)
CORROSION (p.555)
CPFLUID (p.642)

DE
END (p.550)
ENDCASE (p.550)
ENDJOB (p.550)

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EROSION (p.555)
EQUIPMENT (p.354)
ESP (p.617)
EXPANDER (p.599)

F
FETKOVICH (p.570)
FITTING (p.600)
FLOWLINE (p.567)
FMPUMP (p.602)
FORCHHEIMER (p.586)
FRACTURE (p.586)
FRAMO2009 (p.602)

G
GASLIFT (p.603)

H
HCORR (p.561)
HEATER (p.603)
HEADER (p.523)
HEAT (p.623)
HORWELL (p.580)
HVOGEL (p.586)

I
IFPPSSE (p.571)
IFPTAB (p.578)
IFPCRV (p.576)
INLET (p.539)
INJGAS (p.609)
INJFLUID (p.609)
INJPORT (p.607)
IPRCRV (p.576)
ITERN (p.537)

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J
JOB (p.523)
JONES (p.571)
JUNCTION (p.685)

K
KCOAT (p.628)

L
LAYER (p.582)
LVIS (p.637)

M
MPBOOSTER (p.611)
MPUMP (p.612)
MULTICASE (p.659)

N
NAPLOT (p.655)
NAPOINT (p.659)
NODE (p.614)
NOPRINT (p.550)
NSEPARATOR (p.685)

O
OPTIONS (p.525)
OPTIMIZE (p.668)

P
PCP (p.617)
PERMCRV (p.584)
PERMTAB (p.585)
PETROFRAC (p.653)
PIPE (p.615)
PLOT (p.547)
PRINT (p.539)
PROP (p.635)

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PUMP (p.617)
PUMPCRV (p.593)
PUSH (p.552)

QR
RATE - Compositional (p.654)
RATE - Blackoil (p.535)
REINJECTOR (p.620)
RISER (p.567)

S
SEPARATOR (p.621)
SETUP (p.40)
SINK (p.683)
SLUG (p.556)
SOURCE (p.680)
SPHASE (p.564)

T
TABLE (p.666)
TCOAT (p.627)
TIME (p.670)
TPRINT - Compositional (p.654)
TPRINT - Blackoil (p.642)
TRANSIENT (p.587)
TUBING (p.567)

U
UNITS (p.524)
USERDLL - Flow Correlations (p.566)
USERDLL - Equipment (p.554)

V
VCORR (p.557)
VOGEL (p.570)

W
Wax Deposition (p.670)

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WELLHEAD (p.622)
WELLPI (p.569)
WCOPTION (p.573)
WPCURVE (p.570)

XYZ

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9
Tutorials
The following tutorials are described in detail:
Oil Well Performance Analysis (p.692)
Gas Well Performance Analysis (p.716)
Subsea Tieback Design (p.740)
Looped Gas Gathering Network (p.766)
Simple Network Model on the GIS Map (p.778)
Pipe Inline Heating (p.793)

9.1 Oil Well Performance Analysis

This tutorial examines a producing oil well located in the North Sea. You will analyze the
performance of this well using NODAL analysis and calibrate the black oil fluid correlations using
laboratory data to improve modeling accuracy.
You will also analyze the behavior of the well with increased water cut and implement gas lift at a
later stage when the well is unable to flow naturally.
In this tutorial, you will perform the following tasks:
Build the Well Model (p.693)
Perform a NODAL Analysis (p.699)
Generate a Pressure/Temperature Profile (p.700)
Calibrate PVT Data (p.704)
Match PI (p.706)
Analyze Water Cut Sensitivity (p.707)
Evaluate Gas Lift Performance (p.709)
Model Multiple Completions (p.712)
Model a Downhole Choke (p.714)

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9.1.1 NODAL Analysis

Nodal analysis is used to evaluate the performance of production or injection wells. It involves
specifying a nodal point, usually at the bottomhole or wellhead, and dividing the producing system
into two parts - the inflow and the outflow. This is represented graphically below.
The solution node is defined as the location where the pressure differential upstream (inflow) and
downstream (outflow) of the node is zero.
Solution nodes can be judiciously selected to isolate the effect of certain variables. For example, if
the node is chosen at the bottomhole, factors that affect the inflow performance of a production
well, such as skin factor, can be analyzed independently of variables that affect the outflow, such
as tubing diameter or separator pressure.
Figure 9.1. Intersection points of the inflow and outflow performance curves

9.1.2 Task 1: Build the Well Model

In this task, you will build a model of an oil production well.
Although the following task could be performed in a network centric workspace, you will use the
well centric mode for it.
Do the following:
1. Launch PIPESIM and select the option to create a new, well centric workspace.

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2. The Insert tab is active. From the Tubulars group of the well editor, add casing to the well by
clicking Casing and dragging the casing onto the wellhead. Drop the casing at the wellhead
only when the casing is green and the green circle is flashing as shown in the figure below.

3. On the Tubulars tab of the well editor, click

on the far right to open the Casing Catalog.

4. In the Casing catalog, go to the Outside Diameter (OD) column and select Greater than from
the option list and type in a value of eight (8) in the text field to filter the catalog to display only
casings with an OD greater than 8 in, as below.

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5. Select the L80 grade of casing by highlighting the corresponding row, and click OK.
6. Change the Bottom MD of the casing to 9000 ft.
7. Click

to add a tubing string.

Note: Alternatively, you may add a tubing by dragging it from the Insert toolbar as was done
previously for the casing.

8. Specify the values shown below. Enter the numbers instead of using the catalog.

9. On the Deviation survey tab, change the Survey type to 2D. Make sure the Angle is selected
as the Dependent parameter, then enter the MD and TVD values for a 2D survey as shown
below.

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10.On the Heat transfer tab, configure the Heat transfer parameters as shown in the following
figure.

11.On the Completions tab, add a completion to the well by dragging it from the Insert tab or
clicking the

Enter the Completion information as shown in the following figure.

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Note: The IPR plot will not display because no fluid has been defined yet.

12.On the Fluid model tab, create a new Black Oil fluid for the Completion using the parameters
shown in the following figure (You may or may not choose to create the fluid by editing an
existing template). Leave the defaults for all the other tabs on the Fluid editor, and exit the
dialog box.

13.The dynamic well schematic diagram on the left represents the wellbore configuration up to this
point. The green flow lines represent fluid flow paths. The current well configuration indicates a
dual flow path, supporting the simultaneous flow of fluid up the tubing and annulus. In the next
step, you will restrict fluid flow to the tubing only, by adding a packer. You will end up with the
well schematic on the right. Go to the next step to do this.

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14.On the Downhole equipment tab, add a Packer at 8,500 ft to prevent flow up the annulus
between the tubing and casing.

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15.On the Home tab, select Simulation settings and ensure that the Hagedorn-Brown
correlation for vertical multiphase flow and the Beggs & Brill Revised correlation for
horizontal multiphase flow, are selected.
16.Exit the Simulation settings and save your workspace.

9.1.3 Task 2: Perform a NODAL Analysis

In this task, you will perform a Nodal analysis operation to determine the absolute open flow
potential (AOFP) of the well and its operating/solution point (i.e. the intersection of the inflow and
outflow curves), for a given flowing wellhead (outlet) pressure. To do this, you will need to add a
Nodal analysis point at the bottomhole to divide the system into two parts, inflow and outflow as
described previously. The inflow curve on the resulting plot extends from the reservoir to the
bottomhole, while the outflow curve describes flow from the bottomhole to the wellhead.
Do the following:
1. On the Home tab, click Nodal analysis.
2. Select Bottomhole to choose the nodal analysis point location, and click OK.
3. Enter an Outlet pressure value of 300 psi and click Run.

The System results plot displays with the following results.

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4. To extract a more accurate value of the AOFP, go to the Completions tab of the Well editor.
Click the Reservoir tab. The IPR plot is displayed. Click the View data in a table icon at the
bottom-right of the IPR plot to display the plot as a grid.

Note: The icon is annotated in the above plot

Extract the AOFP value (Flow rate at Pwf 0 psi).

Parameter Value
Operating Point Flow rate 8840 stb/d
Operating Point BHP 2495 psi
AOFP 21,311 stb/d
5. Return to the Nodal analysis task and click the Profile Results tab to review the pressure
profile corresponding to the calculated operating point.

9.1.4 Task 3: Generate a Pressure/Temperature Profile

The Nodal Analysis task generates System plots, which are displayed on the System results tab,
and Profile plots for each operating point, which are displayed on the Profile results tab. However,
you can also generate profile plots using the P/T Profile (Pressure/Temperature) task. The
advantage of the P/T Profile task over the Nodal analysis task for this purpose, is that you may
calculate boundary pressures by supplying a rate.
Do the following:
1. Set up a P/T task specifying Liquid flowrate as the Calculated variable.
2. Enter the Outlet Pressure (Wellhead, in this example) of 300 psi.

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3. Leave Sensitivity Data empty.

4. Set the Default Profile Plot to Elevation vs Pressure.

Note: Inlet and outlet pressure always refer to the boundaries of the system. In this case, the
inlet pressure is the reservoir pressure, while the outlet pressure corresponds to the wellhead
pressure. The inlet pressure is automatically populated from the completion or source level,
while the outlet pressure is always specified manually within the task.

5. Run the model.

6. The Profile results tab displays. Review the results in plot and grid format by selecting Show
plot and Show grid respectively. Compare your results with the answers below.

Note: To see the results at finer intervals in order to get a more accurate depth at which gas
appears, go to Home Simulation settings Advanced and check the Print computation
segment result box, as below. Exit the dialog box and re-run the P/T profile task.

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Parameter Value
Production Rate 8,840 stb/d
Flowing BHP 2,495 psia
Flowing WHT 138 degF
Depth at which gas appears Between 7,082 ft and 7,199 ft

9.1.5 Fluid Calibration

Black oil fluid properties (also known as PVT properties) are predicted by correlations developed
by fitting experimental fluid data with mathematical models. Various correlations have been
developed over the years based on experimental data sets covering a range of fluid properties.
The PIPESIM Help system describes the range of fluid properties used to develop each
correlation, which helps you select the most appropriate correlation for your fluid. For more
information, refer to Black oil Correlations (p.421). The default correlations in PIPESIM are based
on the overall accuracy of the correlations, as applied to a broad range of fluids.
To increase the accuracy of fluid property calculations, PIPESIM provides functionality to match
PVT fluid properties with laboratory data. Calibration of these properties can greatly increase the
accuracy of the correlations over the range of pressures and temperatures for the system being
modeled.
For example, calibration of the bubble point pressure can result in the initial appearance of gas at a
depth, hundreds or even thousands of feet shallower or deeper than in an un-calibrated model.
This will result in a significantly different mixture fluid density and, thus, a vastly different
elevational pressure gradient.
Likewise, calibration of the fluid viscosity can drastically improve the calculation of the frictional
pressure gradient, especially in heavy oils and emulsions.
If the calibration data is omitted, PIPESIM calibrates on the basis of oil and gas gravity alone,
resulting in a loss of accuracy.
After the calibration is performed, a calibration factor is calculated as the ratio of the measured
value to the value calculated by the selected correlation for the PVT property.
The calibration method available in PIPESIM 2014.1 is Single Point Calibration.

9.1.6 Single Point Calibration

In many cases, actual measured values for PVT properties show a variance from the values
calculated using the correlations. When this occurs, it is useful to calibrate the property using the
measured value. PIPESIM can use the known data for the property to calculate a calibration
constant Kc;
Kc = Measured Property @(P,T)/Calculated Property @(P,T)
This calibration constant is used to modify all subsequent calculations of the property in question,
as below:
Calibrated value = Kc * (Predicted value)

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9.1.7 Task 4: Calibrate PVT Data

Do the following:
1. Access the Fluid editor either through the Completions tab of the Well editor or from the Fluid
Manager on the Home tab.
2. Select the Viscosity tab and enter the measured dead oil viscosity data as below. Also, change
the undersaturated oil viscosity correlation and the emulsion viscosity method to Bergman &
Sutton and Brinkman respectively.

3. Select the Calibration tab and enter the additional measured PVT data shown below. The
selected black oil correlations will be tuned to match this data.

4. Click Close. The fluid model is now calibrated.

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5. Re-run the P/T Profile task with the same boundary conditions and observe the difference in
results between this calibrated model and the uncalibrated model in the previous task.

Wellhead Pressure Calibrated Uncalibrated

Production Rate 8,171 stb/d 8,840 stb/d
Flowing BHP 2,579 psia 2,495 psia
Flowing WHT 134 deg F 138 deg F
AOFP 21, 320 stb/d 21,311 stb/d
Depth where gas appears Between 6848 and 6965 ft Between 7,082 and 7,199 ft

9.1.8 Multiphase Flow Correlation Calibration

PIPESIM simulation results can be further improved by calibrating the multiphase flow correlations
(horizontal and vertical) with measured flowing pressure and temperature data, for instance from a
flowing gradient survey. A flowing gradient survey is a measurement of the flowing pressure and
temperature distribution with depth for a tubing (as depicted in the figure below), or with length for
a flowline, while producing/injecting at a constant, stabilized rate. Flowing gradient surveys for
wells are done using wireline/slickline tools. Other measurements such as the rate, wellhead
pressure and phase ratios such as water cut and GOR are also recorded during the survey. The
result of these measurements for a well, is a plot of flowing fluid pressure and temperature versus
vertical depth.

PIPESIM provides the functionality to calibrate the multiphase flow correlations to match these
measured flowing pressure and temperature profiles. For the flowing pressure calibration,
PIPESIM performs a regression by tuning multipliers of the friction and holdup terms of the
pressure drop equation, to minimize the root mean squared error (RMS) between the measured
and predicted pressure values (the predicted values are from the multiphase flow correlations).
The flowing temperature calibration is done by tuning the overall heat transfer coefficient (U-value)
to minimize the RMS error between the measured flowing temperatures and the predicted
temperatures. This feature is currently available only in the Classic PIPESIM version (2012 and
older) but will be introduced to the newer PIPESIM versions.

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9.1.9 Inflow Performance Matching

PIPESIM also provides the option to calibrate the IPR equations with flowing well test data, if
available, as a means of further increasing the accuracy and predictability of the models. Ideally,
this step should be performed after calibrating the multiphase flow correlations for the Outflow, with
measured flowing rate and pressure data for instance from a flowing gradient survey, as discussed
previously. Nevertheless, even if the Outflow curves cannot be calibrated due to a lack of
measurements which is often the case, the IPR should still be calibrated, if well performance data
is available. Most of the PIPESIM IPR equations can be calibrated with well test data (multipoint or
isochronal); simply check the Use test data box in the Completions tab of the Well editor and
enter the data.
Even with the absence of multipoint or isochronal well test data, if only the rate, static reservoir
pressure and flowing wellhead pressure are available, they can be matched by tuning the uncertain
parameters of the IPR equation such as Skin for the Darcy equation or Production Index for the PI
equation. For the oil well in this case, a Liquid PI value of 8 STB/d psi was initially specified. It will
now be tuned to a more accurate value based on available well performance information.
The following exercise will continue with the previous model. Additional information has been
provided in the form of well test results; it was found that the well flowed 9000 stb/d of liquid at a
flowing of wellhead pressure of 300 psi. This data will be used to calibrate the IPR.

9.1.10 Task 5: Sensitizing on the Well PI to Match Well Performance

The objective of this task is to determine an accurate productivity index value based on a
production test run on the well. The production test was run for 4 hours and resulted in a stabilized
flow rate of 9000 stb/d measured at a flowing wellhead pressure of 300 psi.
Do the following:
1. Launch the P/T profile task from the Home tab.
2. Select Custom as the Calculated Variable.
3. Choose Completion as the Object from the options list.
4. Choose Liquid PI as the Variable from the options list and enter a range of 5 to 10 stb/d.psi.
5. Leave the Proportionality set to the default, Direct. Make sure the inlet and wellhead
pressures are still set to 3600 psi and 300 psi respectively.
6. Enter the well test rate of 9000 stb/d as the Liquid flowrate. When complete, this window
displays.

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7. Click Run to launch the task. Determine the Liquid PI value that matches the well test results
and compare it to the answer in the table below.
8. Update the PI value in the Completion tab of the well with the new matched value.
9. Rerun the Nodal analysis task to determine the new AOFP of the well. Compare the results with
those from the previous exercise in the following table.

Parameter Value
Matched PI 9.375 stb/d/psi
New AOFP 24,984 stb/d
Previous AOFP 21,320 stb/d

9.1.11 Well Performance Analysis

After you create the well model and calibrate the inflow, outflow and fluid models to generate an
accurate representation of the current well scenario, you can simulate a variety of future or
hypothetical operating scenarios, such as declining reservoir pressure, increasing water cuts, etc.
and subsequently evaluate the most viable options for optimizing the well performance.

9.1.12 Task 6: Analyze Water Cut Sensitivity

After an initial design has been made, it is important to evaluate how the system will respond to
changing operating conditions. For example, increasing water production is inevitable for most oil
and gas fields with a water-drive mechanism, and as a result, it needs to be considered in the well
design.
At some point in the producing life of the well, it is possible that the reservoir pressure will be
insufficient to lift the fluid to the surface, when the water cut reaches a specific limit because water
is denser than oil. As the water cut increases, the hydrostatic/elevational pressure gradient also
increases. Using the wellhead pressure, reservoir pressure, and matched PI from the previous
exercise, you can determine the highest possible water cut this well can produce.
You can either use the PIPESIM System Analysis or Nodal Analysis task to model this problem.
System Analysisapproach
Do the following:
1. If you did not do so already, update the PI value in the Completion tab of the well with the
matched value in the previous task.
2. Select System analysis from the Home tab.
3. Select Liquid flowrate as the Calculated variable and enter 300 psi as the Outlet Pressure
(the required minimum wellhead pressure).
4. For the X-Axis , select Completion as the object, and Water cut as the variable.
5. Click Range to open the dialog box and configure water cut values of 40% to 80% in
increments of 5%.

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6. Run the task to generate a plot of calculated liquid rate vs. water cut. You will notice that the
plot terminates at 70% and not the maximum water cut value of 80% that was entered in the
range. This is the hydraulic limit for this well. Beyond a water cut of approximately 70%, the well
will be unable to flow naturally and dies.
7. Rerun the System analysis task using more closely spaced water cut sensitivity values
(between 70% and 75%), to narrow in on a more exact value of the water cut limit.
NODAL Analysis approach
Do the following:
1. Launch the Nodal analysis task.
2. Click the Sensitivities tab and select Completion as the Inflow Sensitivity object.
3. Select Water cut as the sensitivity variable and enter a range of water cuts from 40 % to 80 %
in increments of 5 % (follow the same procedure as in the previous System analysis task).
4. Run the task and identify the water cut limit for the well in the Systems plot. You will notice that
similar to the System analysis task, there are no Outflow curves for water cuts greater than
70%, confirming that this is the water cut limit for this well to flow naturally. Refer to the figure
below.

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Note: You can zoom in on an area of interest in a plot by using your mouse to draw a rectangle
over it starting from the top-left to the bottom-right, as indicated in the figure below. Do the
reverse to un-zoom the plot.

Parameter Value
Critical Water Cut 71%

9.1.13 Task 7: Evaluate Gas Lift Performance

It has been established that the well will "die" or stop flowing when the critical water cut limit of
71% is reached. It is important to evaluate various artificial lift scenarios to extend the producing
life of this well. PIPESIM supports the following artificial lift methods: Rod pumps, Gas lift, ESPs,
PCPs and Multiphase boosters, but only Gas lift will be considered for the oil well in this tutorial.
The basic principle behind gas lift injection in oil wells is to lower the density of the flowing fluid in
the tubing. This results in a reduction of the elevational/hydrostatic component of the pressure
gradient and ultimately, a lower flowing bottomhole pressure. Lowering the flowing bottomhole
pressure, increases reservoir drawdown which will in turn, increase the production rate.
In this task, you will examine how the well responds to gas lift by introducing a gas lift injection
point near the bottom of the tubing, above the packer. You will use the System Analysis task to

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evaluate the impact of varying gas injection rates on the liquid flow rates for various water cut
values.
Do the following:
1. Click the Artificial lift tab of the Well editor and a Gas lift injection point at 8000 ft and
configure the remaining parameters as below.

2. Launch the System analysis task. Delete the previous water cut sensitivity values. Reconfigure
the task to calculate Liquid flowrate as a function of the permuted variables; Gas lift injection
rate on the X-axis, and Water cut as shown in the figure below. Enter a range from 0 to 10
mmscf/d in 0.5 mmscf/d increments for the gas lift injection rate, and water cut values of 10%,
40% and 70%.

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3. Run the task.

4. View the System results tab and compare your results with the answers below. Determine the
optimum injection gas rate for the 10%, 40% and 70% water cut scenarios.

Note: The optimum gas lift injection rate is subjective and depends on personal judgment, so
your answers may not match those below, and in practical terms, it will also depend on
constraints such as gas availability and economic factors.

You will observe that the liquid rate increases with increasing gas injection rate up to a point,
after which it plateaus.
Explain why this is.

Water Cut (%) *Optimum Gas Injection Rate (MMscf/d) Liquid Rate (stb/d)
10 4.5 11,382
40 5.5 10,576
70 6.5 10,464

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9.1.14 Task 8: Model Multiple Completions

For our example, well log analysis shows that a shallow gas zone exists uphole from the
producing zone. As an alternative to gas lift injection, you will investigate the benefits of perforating
this gas zone and commingling its production with the lower oil zone, as a means of self-lifting the
well.
Do the following:
1. On the Artificial lift tab of the Well editor, delete or deactivate the Gas lift injection point.
2. On the Completions tab, add a second, shallower completion at a depth of 8000 ft MD.
3. For this upper gas zone, there is enough data available to use the Darcy Pseudo-steady state
equation. Enter the following IPR data in the Reservoir and Skin tabs.

4. On the Skin tab, ensure that a value of 0 is specified for both the Mechanical and Rate
dependent skin.

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5. Click the Fluid model tab for the upper zone and create a new fluid using the Dry gas template.
Leave all the default values for this template.
You will observe that the well schematic diagram has automatically been updated to reflect the
new upper zone completion that was added. However, the flow path lines have now turned red,
indicating that the well is unsolvable in its current state.
6. To resolve this problem, from the Downhole equipment tab, add a packer at 7000 ft. and then
add a sliding sleeve at 8000 ft. Make sure you check the Active box for the sliding sleeve. The
equipment you just added ensures that the flow from the upper zone is directed into the tubing
through the open sliding sleeve.
7. To analyze the effect of perforating the upper zone (compared with gas lift injection), run a P/T
Profile task to calculate the liquid flowrate with a water cut of 10 % from the lower oil
completion, as below.

8. Review the System and Profile results. Determine how much gas is produced from the upper
zone (You can extract this information for this scenario (for example, self-lifting), by clicking the
Profile results tab, selecting Show grid, and clicking Expand all to review the results for the
shallower completion). Compare your answers with the results below. How does self-lifting
compare with gas lift injection for this well?

Gas Lift Injection Self-Lifting

Water cut, % 10 10
Liquid rate, stb/d 11,382 11,279
Gas rate, MMscf/d 4.5* 3.925**
* Optimum gas injection rate for gas lift scenario (previous task)
** Gas rate from upper zone for self-lifting scenario

Note: The problem with self-lifting the well, as compared to gas lift injection is; if there is no flow
control valve, there will be no way to regulate the amount of gas from the upper zone. This
ability to regulate the flow will be critical to optimize the production rate, as conditions change in
the well.

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9.1.15 Task 9: Model a Downhole Choke

A downhole choke is used to control the flow rate within a wellbore. Downhole choke equations
and calculations are similar to those used for surface chokes. In this task, you will use a downhole
choke to control the amount of gas allowed to flow into the tubing to lift the oil.
Do the following:
1. On the Downhole equipment tab of the Well editor, add a Choke at 7500 ft. Enter a Bean
size of 1 in, as below.

2. Launch the System analysis task and delete all the previous sensitivity values.
3. Select Liquid flowrate as the Calculated Variable.
4. Select Choke as the sensitivity object and Bean size (the orifice size) as the sensitivity variable
on the X-axis.
5. Enter a range of bean sizes from 0.5 to 3.5 inches in 0.25 inch increments and run the task.
You should get the plot below.

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6. Assuming that due to limited gas availability, there is a gas lift injection constraint of 3 MMScf/d
per well. What bean size would be required to achieve this rate from the upper zone?
To answer the above question, go to the Profile results tab, change the Y-axis to Stock-tank
gas flow rate. This displays the profile of the stock tank gas rate, starting from the
bottomhole, up to the wellhead. At a total distance of 800 ft, which corresponds to the depth
of the upper gas zone (8000 ft), the gas rate increases from the dissolved gas amount to a
value which is a total of the dissolved gas and the gas that comes in through the choke from
the upper zone. See plot below.

The actual gas rate from the upper zone is the difference in the gas rate below and above
the upper zone. You need to view the profile results as a table by clicking the View data as
table icon in the bottom-right of the Profile results plot (see above) and calculate this
difference, for all bean sizes, to determine which bean size gives an incremental rate of
approximately 3 MMScf/d. Compare your results with the answers below and also determine
what the liquid rate would be if the well is choked to this bean size.

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Parameter Value
Bean size for gas lift rate of 3 MMScf/d from upper zone 1 in
Stock tank gas rate below upper zone (Bean size = 1 in) 4.22 MMscf/d
Stock tank gas rate above upper zone (Bean size =1 in) 7.28 MMscf/d
Gas rate from upper zone (Bean size =1 in) [=7.28 4.22] 3.06 MMscf/d
Stock tank liquid rate for selected bean size 9385 stb/d

9.2 Gas Well Performance

This tutorial will cover the modeling of a gas well with a compositional fluid, rather than a black oil
fluid, as introduced in the Oil well tutorial.
In this tutorial, you will perform the following tasks:
Create a Compositional Fluid Model for a Gas Well (p.720)
Calculate Gas Well Deliverability (p.726)
Calibrate the Inflow Model Using Multipoint Test Data (p.727)
Select a Tubing Size (p.729)
Model a Flowline and Choke (p.731)
Predict Future Production Rates (p.734)
Determine a Critical Gas Rate to Prevent Well Loading (p.736)

9.2.1 Compositional Fluid Modeling

PIPESIM offers full compositional fluid modeling as a more advanced alternative to Black Oil fluid
modeling. In compositional fluid modeling, the individual components (Methane, Ethane, Water,
etc.) that comprise the fluid are specified, and the fluid phase behavior is modeled using Equations
of State. Compositional fluid modeling is generally regarded as more accurate, especially for wet
gas, condensate and volatile oil systems. However, Black oil modeling is the more-commonly used
approach, because detailed compositional data is less frequently available to the production/
reservoir engineer.
PIPESIM allows you to choose from the following Compositional PVT flash packages.
Multiflash: This is a third-party compositional package provided by the company, KBC.
Multiflash is available in PIPESIM in 2 modes; Natively (using the PIPESIM interface) and
Standalone (using MFL files). It is the only PVT package in PIPESIM that enables solids
precipitation (for example, hydrates, waxes and asphaltenes). It requires additional license
features. For more information, see Multiflash in the Compositional Fluid mode (native) vs
Multiflash MFL files. (p.146).
E300: This the flash package used by Schlumbergers ECLIPSE reservoir simulator. The E300
(Eclipse 300) Flash is a newer interface to the previous ECLIPSE two-phase flash, and includes
additional Equations of State.
GERG : This is a two-phase flash package using the GERG-2008 Equation of State.

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Equations of State (EoS)

Equations of State describe the pressure, volume and temperature (PVT) behavior of pure
components and mixtures. Most thermodynamic and transport properties are derived from
Equations of State.
One of the simplest Equations of State is the ideal gas law, PV= nRT, which is roughly accurate for
gases at low pressures and high temperatures.

Note: The Black Oil model uses the ideal gas equation along with a compressibility factor (Z) to
account for non-ideal behavior.

This equation, however, becomes increasingly inaccurate at higher pressures and temperatures,
and it fails to predict condensation from a gas to a liquid. As a result, more accurate Equations of
State have been developed for gases and liquids.
The following table describes the Equations of State available in PIPESIM:

PVT Package Equations of State

Multiflash 3-parameter Peng-Robinson (1976)
(Native) 3-parameter Soave-Redlich-Kwong (1972)
Multi-reference fluid corresponding states (CSMA)
Benedict-Webb-Rubin-Starling (BWRS)
Cubic Plus Association (CPA)
Multiflash (MFL There is an extensive list of equations of state available with this option. For
files) more information, see Availability of Multiflash models in PIPESIM using the
MFL file fluid mode option. (p.164)
E300 3-parameter Peng-Robinson Corrected (1978)
3-parameter Soave-Redlich-Kwong (1972)
GERG GERG-2008

Viscosity
Compositional fluid models also use viscosity models based on the corresponding states theory.
Each PVT package has a different set of viscosity models as outlined below:

PVT Package Viscosity models

Multiflash (Native) Pedersen (default)
Lohrenz-Bray-Clark (LBC)
PedersenTwu
SuperTRAPP
For more information, see Multiflash Help for details.

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PVT Package Viscosity models

Multiflash (MFL There is an extensive list of equations of state available with this option. For
files) more information, see Availability of Multiflash models in PIPESIM using the
MFL file fluid mode option. (p.164)
E300 Pedersen (default)
Lohrenz-Bray-Clark (LBC)
Aasberg-Petersen
GERG NIST Recommended

Compositional fluid models also use viscosity models based on theThe Pedersen model is a
predictive corresponding states model, originally developed for oil and gas systems. It is based on
accurate correlations for the viscosity and density of the reference substance, which is methane.
The model is applicable to both gas and liquid phases. The SuperTRAPP method is a predictive,
extended corresponding states model that uses propane as a reference fluid. It can predict the
viscosity of petroleum fluids and well-defined components, over the entire phase range from dilute
gas to the dense fluid. Overall, the SuperTRAPP method is the most versatile method for viscosity
predictions and its performance is generally better than the other methods. However, PIPESIM
uses the Pedersen method as the default, because it is also widely applicable and accurate for oil
and gas viscosity predictions. corresponding states theory. Each PVT package has a different set
of viscosity models as outlined below:
The choice you make of the Equation of State has a significant impact on the viscosities, and other
fluid properties predicted by these methods. It is important to research the equations of state
before choosing one that is recommended and most accurate for the fluid you are trying to model.
For more information, see the PIPESIM and Multiflash help for details.

Binary Interaction Parameters

Binary interaction parameters (or coefficients) are adjustable factors used to alter the predictions
from a model to match experimental data. They are usually generated by fitting experimental
vapour-liquid equilibrium (VLE) or liquid-liquid equilibrium (LLE) data, to the model. Binary
interaction coefficients apply to pairs of components, although the fitting procedure can be based
on both binary and multi-component phase equilibrium information.
PIPESIM has default sets of binary interaction coefficients and these can be overridden. You can
also supply your own data as shown in the following figure.

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Emulsion Viscosities
An emulsion is a mixture of two immiscible liquid phases. One phase (the dispersed phase) is
carried as droplets in the other (the continuous phase). In oil/water systems at low water cuts, oil is
usually the continuous phase.
As water cut increases, there comes a point where phase inversion occurs, and water becomes
the continuous phase. This is the Critical Water Cut of Phase Inversion, otherwise called the cutoff,
which occurs typically between 55% and 70% water cut. The viscosity of the mixture is usually
highest, at and just below, the cutoff. Emulsion viscosities can be several times higher than the
viscosity of either phase alone.
Emulsion viscosities can be many times higher than the viscosity of either phase alone.
A number of methods for predicting emulsion viscosity are available in PIPESIM using the
Viscosity tab of the Compositional fluid editor.

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9.2.2 Task 1: Create a Compositional Fluid Model for a Gas Well

1. Launch PIPESIM and create a new, well centric workspace.
2. On the Home tab, select Compositional from the Fluid manager option list.
3. In the Component/model settings tab of the Fluid Manager, select the PVT package and
models as below.

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Note: If you do not have the license features required to use Multiflash, select the E300 PVT
package. However, you will be unable to do certain steps in this tutorial without the Multiflash
PVT package.

4. Add the following components to the fluid template by checking the boxes next to each of them
in the Fluid Components list. There are 9 components, and they are:
Water
Methane
Ethane
Propane
Isobutane
Butane
Isopentane
Pentane
Hexane
5. Create a new C7+ pseudo-component by clicking Newat the top of the Fluid Components
section and enter only the Name, Molecular weight, and Specific gravity. All other properties
will be automatically calculated based on the properties you specified. The specified values will
have a normal (non-italicized) text style, while the calculated values will be italicized. Click OK
when complete.

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6. Go to the Fluids tab and click

to create a new fluid from the components you just added to the fluid template.
7. Double-click the row of the newly-created fluid to open the Fluid editor. Enter the moles for
each component as shown in the following table. You will notice that the phase diagram
automatically updates as you enter the moles for each component.

Component Moles
Water 0
Methane 78
Ethane 8

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Component Moles
Propane 3.5
Isobutane 1.5
Butane 1.2
Isopentane 0.8
Pentane 0.5
Hexane 0.5
C7+ 6

8. In the Flash/Tune fluid section, you may enter any pressure and temperature and the fluid will
be flashed at those conditions. The phase properties and compositions resulting from the flash
will be displayed. Flash the fluid at the reservoir conditions: 4600 psi and 280 deg F. What
phases are present? What percentage of each phase is present?.

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9. Change the number of moles of water in the fluid to 1.84. You will observe that a very small
amount of a liquid water phase appears. Change the number of moles to 1.83, and notice that
the fluid reverts to a single gas phase. The fluid is at the water dew point. It is virtually saturated
with water and cannot hold any more water in the vapor phase.

Note: Water can be carried along with the gas in the vapor phase or entrained in the gas in droplet
form. There is a maximum amount of water vapor that a gas is able to hold at any given
temperature and pressure. A gas is completely saturated when it contains the maximum amount of
water vapor for the given pressure and temperature conditions.

10.Change the number of moles of water to 1.88.

11.Close the fluid editor and return to the Fluids tab of the Fluid manager to see the GOR and
Water cut values for the fluid. They should match the ones below.

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9.2.3 Gas Well Deliverability

Based on the analysis for flow data obtained from a large number of gas wells, Rawlins and
Schellhardt (1936) presented a relationship between the gas flow rate and pressure drawdown that
can be expressed as the following:
Qsc = C(PR 2 PWF 2)n
Where:
Qsc = Gas rate (MMscf/d)
PR = Average static reservoir pressure (psia)
PWF = Flowing bottomhole pressure (psia)
C = Flow coefficient (MMScf/day/psi2)
n = Non-Darcy exponent
The exponent n is intended to account for the additional pressure drop caused by high-velocity gas
flow, such as is caused by turbulence. Depending on the flowing conditions, the exponent n can
vary from 1.0 for completely laminar flow to 0.5 for fully turbulent flow.
The flow coefficient C, in the equation, is included to account for the following parameters:
Reservoir rock properties
Fluid properties
Reservoir flow geometry
This equation is commonly called the deliverability or back-pressure equation. The coefficients of
the equation, n and C, are determined from well deliverability tests. Once they are determined, the
gas flow rate Qsc at any bottomhole flowing pressure PWF can be calculated, and an IPR curve can
be constructed.
Deliverability testing has been used for more than sixty years by the petroleum industry to
characterize gas wells and determine their flow potential.
There are essentially three types of deliverability tests:
Conventional deliverability (back-pressure)
Isochronal
Modified isochronal
Essentially, these tests consist of flowing wells at multiple rates sequentially, and measuring the
bottomhole flowing pressures as a function of time. The stabilized flow rates and bottomhole
pressures are then plotted on a log-log plot and fit with a straight line. The exponent n is calculated
as the slope of the line. The flow coefficient C is calculated from the equation itself using the

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calculated n value, as well as the rate and flowing bottomhole pressure from one stabilized well
test during the flow period.

9.2.4 Task 2: Calculate Gas Well Deliverability

In this task, you will construct a simple gas well model using the information provided, and perform
a simulation to calculate the well deliverability. The instructions that follow do not go into as much
detail as previous exercises. If you are unfamiliar with the steps for building a well model, refer to
the previous tutorial for Help. If no specification is provided for a variable, use the default PIPESIM
value.
Do the following:
1. Follow the general steps outlined in the Oil Well Performance Analysis (p.692) tutorial to
construct a simple vertical well model with the following information. Any information not
explicitly provided should be left to its default value.

Tubing Data
Casing ID 8.681 inches
Casing wall thickness 0.472 inches
Casing bottom MD 11200 ft
Casing roughness 0.001 inches
Casing Data
Tubing ID 3.476 inches
Tubing wall thickness 0.262 inches
Tubing bottom MD 10950 ft
Tubing roughness 0.001 inches
Downhole Equipment
Packer depth 10000 ft
Heat Transfer Data
Heat transfer coefficient 2 Btu/(h.degF.ft2)
Wellhead ambient temperature 30 degF
Completion Data
Completion depth 11,000 feet
IPR model Well PI
Reservoir pressure 4600 psia
Reservoir temperature 280 degF
IPR basis Gas
Gas PI 1E-06 mmscf/d/psi2
2. On the Completions tab, click the Fluid model tab and map the compositional fluid you
created in the previous task, to the completion by selecting it from the option list.

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3. Save your workspace.

4. Launch the P/T profile task from the Home tab. Select Gas flowrate as the Calculated
Variable and enter an Outlet Pressure of 800 psi. Leave the Default profile plot set to
Elevation vs. Pressure, and click Run.
5. Review the Profile results (grid and plot) and compare them with the answers in the following
table.
Inspect the plot and grid to view the results as shown in the following table.
6.

Parameter Value
Gas rate, MMScf/d 17.881
Flowing bottomhole pressure , psia 1810.8
Flowing bottomhole temperature, deg F 245.3
Flowing wellhead temperature, deg F 175.6

9.2.5 Task 3: Calibrate the Inflow Model Using Multipoint Test Data
In this task, you will use a different IPR model; the Backpressure equation. You will calibrate it with
multipoint well test data. The C and n parameters will be tuned to match the well test data.
Do the following:
1. Go to the Completions tab of the Well editor.
2. Change the IPR Model to Back pressure.
3. On the Reservoir tab, check the box Use test data, and set the Test Type to Multipoint.
4. Enter the test data in the following table.

Q (mmscf/d) Pwf (psi)

9.7 3,000
11.9 2,500
14.3 1,800
5. The IPR plot will be auto-generated as the test data is being entered and the C and n values
will be calculated and displayed, as below.

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6. Rerun the P/T profile task using the same boundary conditions from the previous task. Review
the plot and grid results and compare your answers with the answers in the following table.

Parameter Value
Gas rate, MMScf/d 14.697
Flowing bottomhole pressure, psia 1655.9
Flowing bottomhole temperature, deg F 242.6
Flowing wellhead temperature, deg F 170.4
Back Pressure Equation
Parameter C 7.98E-07 MMScf/d/psi^2n
Parameter n 1
How do the results from the calibrated back pressure IPR equation in this task compare with
those from the previous task which used an uncalibrated Well PI model?
Is the flow turbulent or laminar?

9.2.6 Erosion Prediction

Erosion has long been recognized as a potential source of problems in oil and gas production
systems. Erosion can occur in solids-free fluids, but usually, it is caused by entrained solids
(typically sand).
Currently, the API 14 E method is the only one supported in PIPESIM 2013 and newer versions for
erosion velocity calculations. However, PIPESIM Classic versions (for example, 2012 and older)
support both the API 14 E model and the Salama model.
PIPESIM 2013 uses the API 14 E method to predict the velocity at which erosion may occur.

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The API 14 E model comes from the American Petroleum Institute, Recommended Practice,
number 14 E. This is a solids-free model which calculates only an erosion velocity (not an erosion
rate). The erosion velocity Ve is calculated with the equation:

Where pm is the fluid mean density and C is an empirical constant. C has dimensions of (mass/
(length*time2)) 0.5. The following values of C in oilfield units are suggested in literature:
C = 100 for continuous, non-corrosive, solids-free service
C = 125 for intermittent, non-corrosive, solids-free service
C = 150-200 for continuous, corrosive*, solids-free service
C = 250 for intermittent, corrosive*, solids-free service
*for example, fluids treated with corrosion inhibitor or for corrosion-resistant material
The recommended value of C, which is also the PIPESIM default, is 100. It has been noted that
this is a conservative value.
The current practice for eliminating erosional problems in piping systems is to limit the flow velocity
to the erosion velocity calculated by this correlation.

9.2.7 Task 4: Select a Tubing Size

In this task, you will perform a nodal analysis to select an optimum tubing size. The available
tubing sizes are 2.441 inches, 2.992 inches, 3.476 inches, and 3.958 inches in inside diameter.
Your final decision will be based on the following criteria:
Flow rate (The higher the better, until the erosional velocity is reached because more liquid
droplets are carried at higher velocities which increases the erosion risk)
Erosional velocity ratio (<1).
Cost (Generally increases with tubing size)
Do the following:
1. Go to Home Simulation settings Erosion/Corrosion and confirm that the Erosion
velocity constant (C value) of 100 is entered for the API 14e erosion model.
2. Launch the Nodal analysis task from the Home tab.
3. Select Bottomhole as the nodal point, when prompted.
4. Enter 800 psia as the Outlet Pressure.
5. Click the Sensitivities tab and enter the tubing inside diameter options (2.441, 2.992, 3.476
and 3.958) under the Outflow Sensitivity.
6. Run the model and view the Profile results (not System results). Double-click the plot and
change the X-axis variable to Erosional Velocity Ratio. Which tubing size best meets the

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decision criteria? (Choose the smallest tubing size, unless the increase in gas rate is significant
for example, > 5%, that is free from erosion issues).
7.
Compare your results for the selected tubing with the results in the following table.

Parameter Value
Selected Tubing ID, inches 3.476
Gas rate, MMScf/d 14.7
Flowing bottomhold pressure, psia 1655.4
Flowing wellhead temperature, deg F 170.4
Max Erosional velocity ratio 0.984775

9.2.8 Choke Modeling

Wellhead chokes are used to limit production rates to stay within surface constraints, protect
surface equipment from slugging, avoid sand problems due to high drawdown, and control flow
rate to avoid water or gas coning. Placing a choke at the wellhead increases the wellhead pressure
and thus, the flowing bottomhole pressure which reduces the production rate.
Pressure drop across wellhead chokes is usually very significant, and various choke flow models
are available for critical (sonic) and sub-critical flow.
Sound waves and pressure waves are both mechanical waves. When the fluid flow velocity in a
choke reaches the traveling velocity of sound in the fluid for the in-situ condition, the flow is called
sonic flow. Under sonic flow conditions, the pressure wave downstream of the choke cannot go
upstream through the choke because the medium (fluid) is traveling in the opposite direction at the
same velocity. As a result, a pressure discontinuity exists at the choke, which means that the
downstream pressure does not affect the upstream pressure.
Because of the pressure discontinuity at the choke, any change in the downstream pressure
cannot be detected from the upstream pressure gauge. Any change in the upstream pressure
cannot be detected from the downstream pressure gauge either. This choke feature is unique and
desirable for stabilizing the well production rate and separator operating conditions.
Whether sonic flow exists at a choke depends on the downstream-to-upstream pressure ratio. If
this pressure ratio is less than a critical pressure ratio, sonic (critical) flow exists. If this pressure
ratio is greater than, or equal to, the critical pressure ratio, sub-sonic (sub-critical) flow exists.
Figure 9.2. Pressure-Flowrate Relationship Across a Choke

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The critical pressure ratio is approximately 0.55 for natural gas. A similar constant is used for oil
flow.
In some wells, chokes are installed in the lower section of tubing strings. This choke position
reduces wellhead pressure and enhances oil production rate as a result of gas expansion in the
tubing string. For gas wells, a downhole choke can reduce the risk of gas hydrates. A major
disadvantage of using downhole chokes is that replacing a choke is costly.

9.2.9 Task 5: Model a Flowline and Choke

In this task, you will modify the well from the previous task to include a flowline and choke. You will
then use the gas rate calculated in the previous exercise to determine the choke bean size that
results in a manifold (end of flowline) pressure of 710 psia.
Do the following:
1. Go to the Tubulars tab of the well editor and ensure that the tubing ID is set to the optimum
tubing size determined from the previous exercise (3.476 inches).

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2. Click the Surface equipment tab of the Well editor, and click the main Insert tab to expose the
equipment that can be added.
3. Insert a choke and a sink. Connect the choke to the wellhead using a connector and connect
the choke to the sink using a flowline, as shown in the following figure.

4. Click the choke and enter a Bean size of 1 in.

Note: You can enter any Bean size at this time. You will soon run a sensitivity to determine the
correct bean size to achieve the desired outlet pressure of 710 psia.

5. Click the flowline and configure it as shown in the following figure. Ensure you have checked
the Override global environmental data box and specified the Ambient temperature as 30
degF.

6. Launch the P/T Profile task from the Home tab. Change the branch end to the Sink to ensure
that the flowline and choke are included in the simulated profiles.

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7. Select Custom as the Calculated Variable, Choke as the Object and Bean size as the
Variable from the option lists.
8. Enter a bean size range of 1 to 3 inches and leave the Proportionality set to Direct.
9. Change the Outlet pressure (for example, at the Sink) to 710 psia and enter the Gas flowrate
obtained from the previous task (14.7 MMScf/d).
The P/T profile dialog box opens.

10.Click Run to launch the simulation.

11.Review the Profile results to get the bean size that is required to match the specified inlet,
outlet, and flowrate conditions. Compare it with the answer below.

Parameter Value
Outlet pressure 710 psia
Choke size 1.502551 inches
12.Click the choke in the Surface equipment tab of the well editor and enter the calculated choke
bean size (from the previous step).
13.Run the P/T profile task with Outlet pressure as the Calculated Variable. Review the Profile
results and verify that the calculated sink pressure is 710 psi.
14.Review the System and Profile results (plot and grid) and determine individual pressure drops
for the reservoir, tubing, choke, and flowline and compare them with the answers below.

Parameter Value
Updated choke size
Static reservoir pressure, psia 4600
Flowing bottomhole pressure, psia 1654.6
Flowing wellhead pressure, psia 799.2
Flowing pressure immediately downstream of choke, psia 712.3
Outlet pressure, psia 710.6
Pressure losses across system
Reservoir, psia 2945.4
Tubing, psia 855.4

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Parameter Value
Choke, psia 86.9
Flow-line, psia 1.74

9.2.10 Task 6: Predict Future Production Rates

In this task, you will estimate the future gas production rates based on the expected reservoir
pressure decline with time. You will do this with the System analysis task.
Do the following:
1. Deactivate the equipment downstream of the wellhead because you will run this simulation up
to the wellhead. In the Surface equipment tab of the well editor, deactivate the Choke,
Flowline, and Sink by clicking on each of them, one at a time, and unchecking their Active
boxes (Alternatively, you may right mouse button on each of them and select Deactivate).
These objects should be highlighted in red to indicate they are inactive, as shown in the
following figure.

2. Launch the System Analysis task. Select Gas flowrate as the Calculated variable.
3. Set the Outlet Pressure (wellhead) to 800 psi.
4. In the X-axis column, select System Data as the sensitivity object and Inlet pressure as the
sensitivity variable. Enter the following Inlet (reservoir) pressures:
4,600 psia
4,200 psia
3,800 psia
3,400 psia
5. Run the model and compare your results with the answers below.

Reservoir Pressure (psia) Gas Rate (mmscfd)

4600 14.697
4200 12.182

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Reservoir Pressure (psia) Gas Rate (mmscfd)

3800 9.853
3400 7.732

9.2.11 Liquid Loading

Gas wells usually produce with liquid water and/or condensate in the form of mist droplets or a film
along the pipe walls. As the gas flow velocity in the well drops due to reservoir depletion, the
carrying capacity of the gas decreases. When the gas velocity drops below a critical level, the gas
is unable to lift the liquids and they begin to accumulate in the wellbore. This is termed liquid
loading.
Liquid loading increases the flowing bottomhole pressure, which reduces the gas production rate.
A lower gas production rate implies a lower gas velocity which will ultimately cause the well to stop
producing or die.

Turner Droplet Model

In gas wells operating in the annular-mist flow regime, liquids flow as individual particles (droplets)
in the gas core and as a liquid film along the tubing wall.
By analyzing a large database of producing gas wells, Turner found that a force balance performed
on a droplet could predict whether the liquids would flow upwards (drag forces) or downwards
(gravitational forces). If the gas velocity is above a critical velocity, the drag force lifts the droplet,
otherwise the droplet falls and liquid loading occurs. This is illustrated in the following figure.
Figure 9.3. Turner Droplet model

When the drag on a droplet is equal to its weight, the gas velocity is at the critical velocity.
Theoretically, at the critical velocity, the droplet would be suspended in the gas stream, moving
neither upward nor downward. Below the critical velocity, the droplet falls and liquids accumulate in
the wellbore.
In practice, the critical gas velocity is generally defined as the minimum gas velocity in the tubing
string required to move droplets upward.

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The general form of Turner's equation is given by:

where

Note: The Turner equation applies to vertical or near vertical uphill flow and assumes a continuous
gas phase with small dispersed liquid droplets entrained in it. PIPESIM will not calculate the liquid
loading in pipe sections where these conditions are not met.

Liquid loading calculations are performed in every operation and are available for review in plots
and reports. PIPESIM calculates a Liquid Loading Velocity Ratio (LLVR), which is the minimum lift
velocity (terminal/critical velocity) divided by the fluid velocity. A LLVR > 1 indicates a liquid loading
risk because the fluid is flowing at a velocity lower than the minimum velocity required to lift the
liquids and prevent loading.
The Liquid Loading Gas Rate line can be displayed on the Nodal analysis system plot when the X-
axis is configured to display gas rate. For every point on the outflow curve, the value of the Liquid
Loading Velocity Ratio is calculated and the liquid loading gas rate line is plotted at the specific
rate where the liquid loading velocity ratio is equal to 1.

9.2.12 Task 7: Determine a Critical Gas Rate to Prevent Well Loading

In this task you will perform a Nodal Analysis to determine the critical gas rate that prevents liquid
loading and validate the result by checking the liquid loading velocity ratio along the profile.
Do the following:
1. Launch the Nodal Analysis task and delete any Sensitivities that may still be present.
2. Set the Outlet Pressure to 800 psia and run the model.
3. On the System results tab, check the box for the Liquid loading line. The plot appears as
below.

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4. Click the View data in a table icon at the bottom right of the plot, and extract the critical gas
rate, as below. Compare your result with the following answer.

Parameter Value
Critical gas rate (Nodal analysis plot), MMscf/d 3.62

For this well scenario, you can see that the operating flowrate (14.7 MMScf/d) is far above the
critical gas rate to avoid liquid loading (3.62 MMScf/d), so there is no liquid loading risk at these
conditions.
5. Validate the critical gas rate from the nodal analysis plot by performing a P/T profile task at the
same conditions (flow rate and outlet pressure). Launch the P/T profile task.
6. Select Inlet pressure as the Calculated variable. Enter a value of 800 psia as the Outlet
pressure and the critical gas flowrate value (3.62442 MMScf/d) from the previous step as the
Gas flowrate.
7. Run the task.
8. Double-click the Profile results plot and change the X-axis variable to display the Liquid
loading velocity ratio. Verify that within the outflow section, which is where the liquid loading is

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calculated (consisting of the tubing and a short section of the casing up to the mid-perforation),
the maximum liquid loading velocity ratio (LLVR) at the critical gas flow rate of 3.62442
MMScf/d, is approximately equal to 1. This means the P/T profile results are consistent with the
Nodal analysis results. Where is the LLVR highest and why?

9. To see the LLVR in the grid results on the Profile results tab, select Show grid, then click
Select columns. Filter to the variable Liquid loading velocity ratio by typing its first few letters,
as below. Check the box beside the LLVR and click Close.

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The grid displays as below with the updated LLVR.

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9.3 Subsea Tieback Design

The offshore frontier poses some of the greatest technical challenges facing the oil and gas
industry, particularly as we venture into ever deeper waters and more remote locations.
Development costs can be substantial and many new production systems must be designed to
accommodate subsea multiphase flow across long distances to be economically viable.
Managing costs over extended distances introduces a number of complex risks and reliability
becomes a key concern due to high intervention costs and potential for downtime. Characterizing
and managing these risks requires detailed multidisciplinary engineering analysis and has led to
the emergence of a new field called flow assurance.
Multiphase flow simulation is required for the design of subsea tiebacks to assure that fluids will be
safely and economically transported from the bottom of the wells all the way to the downstream
processing plant.
Four flow assurance issues are covered in this module; hydrates, heat loss, erosion, and liquid
slugging.
In this tutorial, you will perform the following tasks:
Size the Subsea Tieback and Riser (p.740)
Select Tieback Insulation Thickness (p.752)
Determine the Methanol Requirement (p.756)
Screen for Severe Riser Slugging (p.760)
Size a Slug Catcher (p.764)

9.3.1 Flow Assurance Considerations

9.3.2 Task 1: Size the Subsea Tieback and Riser

In this task, you will create a compositional fluid, build a network model, and determine the
optimum diameters for the subsea tieback and the riser. The instructions that follow do not go into
as much detail as previous exercises. If you are unfamiliar with the steps for constructing a model,
refer to the previous tutorials for Help. If no specification is provided for a variable, use the default
PIPESIM value. Do the following:

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1. Launch PIPESIM and create a new, network centric workspace. When you create a network-
centric workspace, it launches in the Network perspective, as shown below. You can easily
switch from network to well perspective and vice-versa, by selecting the perspective from the
option list.

2. Using the procedures learned in the Gas Well Performance Analysis (p.716) tutorial, create a
new, Compositional fluid with the properties listed in the following tables. Use the following
defaults:
PVT package: Multiflash
Equation of State: 3-parameter Peng-Robinson
Viscosity model: Pedersen
Salinity model: None
Binary interaction coefficients: Oil and gas 4

Note: If you do not have the license features required to use Multiflash, select the E300 PVT
package. However, you will be unable to do certain steps in this tutorial (for example, hydrates
precipitation) without the Multiflash PVT package.

Component Moles
Water 10
Methane 67.5
Ethane 5
Propane 2.5
Isobutane 1
Butane 1
Isopentane 1
Pentane 0.5
Hexane 0.5
Carbon Dioxide 2.5
C7+ 8.5

Pseudocomponent Molecular Weight Specific Gravity

C7+ 115 0.683

The fluid properties at standard conditions should be as below.

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3. In the subsequent steps, construct a PIPESIM model to replicate the network in the following
figure.

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4. From the Insert tab, place a Source, Junction and Sink on the Network schematic, as displayed
above.
5. Connect the source to the junction using a flowline from the Insert tab.
6. Connect the junction to the sink using a riser, also from the Insert tab.
7. Double-click the Source and rename it to Subsea Manifold.
8. Map the compositional fluid you created, to the Subsea Manifold (Source), by selecting it from
the Fluid option menu.
9. Enter the data for the Subsea Manifold as in the following figure.

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10.Without closing the dialog box for the Subsea Manifold, click once on the Flowline to switch the
dialog box to the Flowline editor.
11.Rename the flowline to Subsea Tieback and enter the flowline data, as in the figure below.

12.Switch the Flowline mode to Detailed so you enter more detailed heat transfer information.
13.Click the Heat transfer tab and set the U Value input option to Calculate and enter 1 layer of
insulation as in the figure below.

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Note: The Ground conductivity field is read-only because we have chosen to use the global
environment data under Home Simulation settings Environmental by leaving the
Override global environment data box unchecked. In a later step, we will review the default
global environment setting is, and change it.

14.Without closing the Flowline editor dialog box for the Subsea Tieback, click once on the Riser
to switch to the dialog box for editing it.
15.Rename the riser to Riser.
16.Change the Mode to Detailed and enter the information on the General tab, as in the figure
below.

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Note: The riser is vertical and produces up to a platform that is 60 ft above sea level.

17.Click the Heat transfer tab and set the U Value input option to Calculate and enter 1 layer of
insulation as in the figure below:

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Note: The ambient temperature and wind speed are read-only because we have chosen to use
the global environment data under Home Simulation settings Environmental, by leaving
the Override global environment data box, unchecked. In a later step, we will check review
the default global environment setting is, and change it.

18.Exit the dialog box and save your workspace.

19.Modify the global environmental settings by selecting Home Simulation settings
Environmental and change the ambient air temperature and sea water gradient as shown in
the following figure. These global values will be used for the heat transfer calculations for the
flowline and riser, because we left the Override global environmental data box unchecked in
both the flowline and riser editors.

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20. still in the Simulation settings tab, click the Flow correlations tab and select the following
While
flow correlations:
Vertical flow correlation = Hagedorn & Brown (Duns & Ros map)
Vertical flow correlation = Beggs & Brill Revised
Now, design the system based on following criteria and constraints:
Design production rate = 14,000 STB/day (normal scenario). The system should be
designed to achieve a maximum rate of 16,000 STB/day (should the wells produce more
than expected) and should simultaneously be able to handle a turn-down scenario, when the
production is expected to drop to 8000 STB/day.
For all production rates, the arrival pressure at the Sink must not drop below 400 psia.
Available flowline and riser sizes are 7.981 inches (wall thickness = 0.322 inches), 10.02
inches (wall thickness = 0.365 inches) and 12 inches (wall thickness = 0.375 inches).
Flowline and riser sizes must be the same and for all scenarios and the erosional velocity
limit must not be exceeded.

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Cost: The bigger the flowline and riser, the higher the cost, so the objective would be to
select the minimum diameter sizes that would satisfy the target rate and constraints
specified above.
21.Select the Subsea Manifold and launch the System analysis task.
22.Select Outlet pressure as the Calculated Variable and enter any value for the Liquid flowrate
(for example, the normal rate of 14,000 stb/d).
23.For the X-axis variable, select System Data as the object, and Liquid flowrate as the variable.
Enter the range of flowrates the design is being done for: 8000, 14000 & 16000 stb/d.
24.Change the Sensitivity configuration to Change in step with Variable 1 by selecting it from the
option list. For more information, see System Analysis Properties (p.224) to understand the
differences between the sensitivity configuration options.
25.Configure the additional sensitivity variables for the Subsea Tieback and Riser as in the
following figure.

26.Click Run.
27.Review the System results plot. Why are there no results for some cases?
28.Determine the minimum diameter of the tieback and riser that satisfies the arrival pressure
requirement (for example, > 400 psia) for all flowrates. Compare your result with the answer
below.

Parameter Value
Minimum Tieback and Riser diameters that satisfy the minimum arrival pressure 10.02 inches
constraint of 400 psi for all flowrates
29.Double-click the Systems plot and change the Y-axis variable to display Erosional velocity ratio
maximum.
30.Verify that the selected flowline ID does not exceed the erosional velocity ratio limit of 1.0 for
the expected flow rates. Compare your results with the answers in the following table.

Parameter Value
Selected Tieback and Riser ID based on 400 psi arrival pressure constraint, inch 10.02

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Parameter Value
Max. erosional velocity ratio for selected ID 0.754
Minimum arrival pressure for selected ID 963.1 psia
Maximum arrival pressure for selected ID 1267.3 psia

9.3.3 Hydrates
Gas hydrates are crystalline compounds with a snow-like consistency that occur when small gas
molecules come into contact with water at or below a certain temperature. The hydrate formation
temperature increases with increasing pressure, therefore the hydrate risk is greatest at higher
pressures and lower temperatures. When hydrates form inside pipelines, they can form plugs
which obstruct flow. In even worse scenarios, where the presence of a hydrate plug was
undetected, pipeline depressurization has resulted in the plug being dislodged unexpectedly,
resulting in serious injury and even fatalities. These are some of the reasons that hydrates are a
serious flow assurance concern.
Hydrate forming molecules most commonly include methane, ethane, propane, carbon dioxide,
and hydrogen sulfide.
Three hydrate crystal structures have been identified - Structures I, II, and H. The properties of
Structures I and II hydrates are well defined. Research into structure H hydrates is relatively new,
and their properties are less well defined.
Hydrates can very easily form downstream of a choke where fluid temperature can drop into the
hydrate formation region due to Joule-Thompson cooling effects.
The following figure, shows a typical gas hydrate curve which is very useful for subsea pipeline
design and operations. On the left side of the curve is the hydrate formation region. When
pressures and temperatures are in this region, hydrates will form from the water and gas
molecules.
Hydrate Curve

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Many factors impact the hydrate curve including fluid composition, water salinity and the presence
of hydrate inhibitors.

Note: Generating Hydrate curves requires the PIPESIM Multiflash Hydrate Package. Hydrate
curves cannot be generated with the E300 or GERG Flash packages.

Hydrate Mitigation Strategies

Two common strategies to mitigate hydrate formation are thermal insulation and chemical
inhibitors. Both strategies can be simulated in PIPESIM. Thermal insulation carries a higher up-
front capital cost, whereas chemical inhibition carries a higher operational cost.

Thermal insulation
The heat transfer between the fluid in the pipeline and the environment surrounding the pipeline is
dependent on the temperature gradient and the thermal conductivity of the material between the
two. There are two options for modeling the heat transfer in PIPESIM.
Input U value: This option allows you to define an overall heat transfer coefficient (U value). The
heat transfer rate per unit area is calculated based on the pipe outside diameter.
Calculate U value: This option computes the overall heat transfer coefficient based on the
following parameters:
Pipe coatings: Thickness of each pipe coating & K(Thermal conductivity) of the material
Pipe material conductivity
Ambient fluid (Air or Water)
Ambient fluid velocity (The faster fluid flows over the pipe, the greater the heat loss)
Pipe burial depth
Ground conductivity (for flowlines only)

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Chemical Inhibitors
Thermodynamic inhibitors can be used to shift the hydrate line (to the left in the curve shown
previously), thereby lowering the hydrate formation temperature and increasing the hydrate-free
operating envelope. Examples of inhibitors include methanol and ethylene glycol.
Kinetic and anti-agglomerate inhibitors comprise a category of inhibitors known as Low Dosage
Hydrate Inhibitors (LDHIs). These inhibitors do not lower the hydrate formation temperature;
instead, they help prevent the nucleation and agglomeration of hydrates to avoid blockage
formation. The effects of these types of inhibitors cannot be modeled with PIPESIM.

9.3.4 Task 2: Select Tieback Insulation Thickness

In this task, you will update the model with the tieback and riser ID selected in the previous
exercise and determine the insulation thickness required to maintain the system outside of the
hydrate formation envelope.
The worst case scenario in terms of a hydrate risk, is when the flow rate through the system is the
lowest, in which case, the heat loss will be the greatest. This scenario will be the turndown case of
8000 STB/day.
Do the following:
1. Double-click the Subsea tieback and enter the inside diameter and wall thickness determined
from the previous sizing task. Repeat this step for the Riser (ID and Wall thickness for Tieback
and Riser = 10.02 and 0.365 respectively).
2. Select Home Simulation settings Heat transfer and check the Hydrate subcooling box
to calculate the hydrate sub-cooling temperature difference, which is the difference between the
hydrate formation temperature and the flowing fluid temperature (for example Thyd Tf). If this
difference is positive, then the fluid is in the hydrate formation region at that location in the
system
3. Under Simulation settings, click the Output variables tab and change the Report template
to Flow Assurance. This template includes the important flow assurance variables; specifically
the following hydrate variables of interest.
Hydrate formation temperature (profile variable)
Hydrate sub-cooling delta temperature (profile variable)
Maximum hydrate sub-cooling temperature differential (system variable)
4. Save your workspace.
5. Click the Subsea Manifold and run the P/T profile task with Outlet pressure set as the
Calculated variable and the Liquid flowrate set to the turndown rate of 8000 STB/day.
6. Double-click the Profile results plot and change the Y-axis variable to Hydrate sub-cooling
delta temperature to display the plot. With the current insulation thickness of 0.25, is there a
hydrate risk? At what point in the system does the fluid temperature drop below the hydrate
formation temperature?

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7. Click the Subsea manifold and select Home Phase envelope to check the hydrate risk from
the phase envelope viewer. The plot displays. Observe how the calculated flowing P/T profile
line intersects with the hydrate formation line. As determined in the previous step, the system
drops into the hydrate formation region at approximately 12,672 ft, which is somewhere in the
long subsea tieback, which has a total length of 31,680 ft. Clearly, the current insulation
thickness of 0.25 is insufficient to mitigate against hydrate formation.

8.
Determine the appropriate insulation thickness by increasing it in 0.25 increments and running the
P/T profile task until the entire system is hydrate-free. Assume the same insulation thickness must
be used on both the tieback and riser.

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Note: There is currently no option to sensitize on coating thickness, in this case, insulation
thickness, in any of the tasks. You will have to manually change the insulation thickness in the
tieback and riser objects, and run the P/T profile task repeatedly until the objective is met.

Compare your results with the following table and plots.

Parameter Value
Req. insulation thickness 1 inch

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9.3.5 Task 3: Determine the Methanol Requirement

Assume the flowline and riser have been insulated, but they are under-insulated with only 0.5
inches of insulation. In this exercise, you will determine the required methanol injection rate to
ensure that hydrates do not form in the system.
Do the following:
1. Double-click on the Subsea tieback and enter an insulation thickness of 0.5 to model the
scenario where it is under-insulated. Click Riser and repeat this step.
2. Insert an Injection Point from the Insert tab and place it between the Subsea Manifold and the
Subsea Tieback. Connect the Subsea Manifold to the Injector using a Connector. Connect the
Subsea Tieback to the Injector on the left end and the Junction on the right end, as shown in
the following figure.

3. Click the Fluid manager in the Home tab.

4. Click the Component/model settings tab and add Methanol to the Fluid Components list by
checking the box beside it.
5. Click the Fluids tab and create a new fluid by clicking the

.
6. Double-click the row for the new fluid, rename it to Methanol and enter 100 moles for Methanol
in the Components grid and click Close.
7. Still on the Fluid manager, click the Fluid mapping tab and map the Methanol fluid to the
Injector by selecting it from the option list.
8. Exit the Fluid manager.
9. Double-click the Injector. Specify a fluid injector temperature of 68 degF and any liquid flowrate
(this variable will be sensitized upon later).
10.Click the Subsea manifold and launch the System Analysis task.

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11.Set Outlet Pressure as the Calculated Variable and specify a Liquid flowrate of 8,000
STB/d.
12.For the X-axis variable, change the sensitivity object to the Injector and the sensitivity variable
to Liquid flowrate by selecting them from the option list. Enter a methanol injection rate range
from 0 to 500 STB/d in increments of 50 STB/d. Remove all other sensitivity variables either by
deleting their values or unchecking the Active boxes for them, as below.

13.Click Run.
14.Double-click the System results plot and change the Y-axis variable to Maximum Hydrate sub-
cooling temperature difference. This is the maximum value of the Hydrate sub-cooling
temperature difference throughout the system for each of the cases run.
15.From the plot, determine the required Methanol injection rate to maintain the flowing fluid
temperature above the hydrate formation temperature, at every point in the system (i.e.
Maximum Hydrate sub-cooling temperature difference < 0). You may refine the range of the
methanol injection rate to more accurately determine the minimum amount required.

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Parameter Value
Tutorials Req. Methanol Injection Volume 280 STB/day
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9.3.6 Severe Riser Slugging

Severe slugging in risers can occur in a multiphase transport system consisting of a long flowline
followed by a riser. Severe slugging is a transient phenomenon that can be split into four steps, as
shown in the following figure.

Step 1: Gas velocity is insufficient to carry liquid droplets up the riser. They start to accumulate at
the base of the riser, form a slug and cause increased back-pressure on the pipeline.
Step 2: In slug production, the liquid level reaches the riser outlet, and the liquid slug begins to be
produced until gas reaches the riser base.
Step 3: In bubble penetration, gas is again supplied to the riser, so the hydrostatic pressure
decreases. As a result, the gas flow rate increases.
Step 4: This corresponds to gas blowdown. When the gas produced at the riser bottom reaches
the top, the pressure is minimal and the liquid is no longer gas-lifted. The liquid level falls and a
new cycle begins.
PIPESIM does not rigorously model severe slugging associated with risers as this is a transient
phenomenon, but it does report a dimensionless indicator of the likelihood of slugging occurring
(the Severe Slugging Indicator - Pots).

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Severe slugging is most prevalent in cases in which a long flowline precedes a riser, especially for
cases in which the flowline inclination angle is negative going into the riser (as in the diagram
above).
In cases of severe slugging, a slug catcher must be sized to be able to receive a volume of liquid at
least equal to the volume of the riser. However, severe slugging can be mitigated by measures
such as topsides choking or riser base gas lift.
The Severe Slugging Indicator is the ratio between the pressure build-up rates of the gas phase
and that of the liquid phase in a flowline followed by a vertical riser:

where,
Z = Gas compressibility factor
R = Gas universal constant
T = Temperature (K)
M = Molecular weight of gas
WG = Gas mass flow rate (kg/s)
WL = Liquid mass flow rate (kg/s)
g = Acceleration due to gravity (m/s2)
LF = Flowline length (m)

= Average flowline gas holdup

Severe slugging is expected when the Severe Slugging Indicator number is equal to, or less than,
unity. This model can be used to determine the onset of severe slugging, but the model cannot
predict how long the severe slugs will be and how fast severe slugs will be produced into the
separator. For more information, see Liquid by Sphere (p.304).

9.3.7 Task 4: Screen for Severe Riser Slugging

In this task, you will screen for severe riser slugging.
Do the following:
1. Continue with the model from the previous exercise. Deactivate the methanol injector by
double-clicking on it and uncheck the Active box. Reset the tieback/riser insulation thickness to
the value obtained earlier that prevents hydrate formation in the system (1).
2. Click the Subsea Manifold and launch the System analysis task from the Home tab (or the
Tasks pane, if it is exposed).
3. Set Outlet Pressure as the Calculated Variable, and leave the default Inlet pressure and
Liquid flowrate values.

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4. For the X-axis, select System data as the sensitivity object and Liquid flowrate as the
sensitivity variable. Enter the following flow rates: 8,000, 14,000 and 16,000 STB/d.
5. Click Run.
6. Double-click the System results plot and change the Y-axis variable to display the variable;
Severe Slugging Indicator - Pots. This represents the minimum value of the Severe Slugging
Indicator number along the subsea tieback, at the base of the riser. Compare your answers to
the answers below.

Parameter Values
Severe Slugging Indicator 8,000 stb/d 14,000 stb/d 16,000 stb/d
1.196 1.474 1.568

9.3.8 Slug Catcher Sizing

PIPESIM is frequently used to estimate the capacity requirements for slug catchers. A slug catcher
is a pressure vessel with sufficient volume to buffer the downstream process system from slugs of
liquid coming from the upstream system. For offshore platforms, the designer must balance the
high cost of adding a larger vessel to the platform against the potential of a large slug
overwhelming the liquids handling capacity and shutting down the entire system. There are three
typical scenarios to consider in the sizing of slug catchers for this type of system:
Hydrodynamic slugging
Pigging
Ramp-up

Hydrodynamic Slugging
Most multiphase production systems will experience hydrodynamic slugging. It is usually
impractical to design a pipeline system that completely avoids slugging problems. Also, because
hydrodynamic slugs grow as they progress along the pipe, long pipelines can produce very large
hydrodynamic slugs. (Severe riser slugging, which was modeled in the previous exercise, is a

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special case of hydrodynamic slugging involving a riser). PIPESIM calculates the mean slug length
as a function of distance traveled by using the SSB or Norris Correlations. A continuous
intermittent flow regime in the pipeline is required for slugs to form. A probabilistic model (based on
experimental data from Prudhoe Bay field data in Alaska) is applied to calculate the largest slug
out of 10, 100 and 1,000 occurrences. The 1/1000 (one in one thousand) slug length is often
used to determine slug catcher volume requirement. The slug prediction output from PIPESIM
yields the length and frequency for the selected slug size correlation:
Mean slug length (distribution is assumed skewed log normal)
1 in 1,000 slug length and frequency
1 in 100 slug length and frequency
1 in 10 slug length and frequency
The preceding probabilities represent various levels of confidence regarding the maximum slug
size. For example, a 1 in one thousand slug length of 50 meters indicates there is a 0.1%
probability of the maximum slug length exceeding 50 meters.

Pigging
In multiphase flow in horizontal and upwardly inclined pipe, the gas usually travels faster than the
liquid due to lower density and lower viscosity. This is called slippage. Multiphase flow correlations
predict the 'slip-ratio' which depends on many factors such as fluid properties, pipe diameter and
flow regime.
In steady-state flow, since the gas usually travels faster than the liquid, it will slip past the liquid. In
order for the volumetric flowrate to remain constant, the area of the pipe occupied by the gas must
shrink. This gives rise to a higher liquid volume fraction than if the gas traveled at the same
velocity, resulting in 'liquid holdup,' as illustrated the following figure.

Figure 9.4. Slip vs. No-Slip Liquid Holdup

During a pigging operation, a solid object with a diameter, slightly less than that of the pipeline,
which is called a pig, is sent through the line to push out liquids, soft solids such as wax, and other
debris. As the pipeline is pigged, a volume of liquid builds up ahead of the pig and is expelled into
the slug catcher as the pig approaches the exit.
PIPESIM assumes that the pig travels at the mean fluid velocity. It considers the liquid holdup in
the pipeline and uses this to determine the volume of liquid that will be swept along in front of the
pig, as it moves. This calculation is reported as the sphere generated liquid volume (SGLV).

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Figure 9.5. Pigging Operation

Ramp-up
When the flow rate into a pipeline increases, the overall liquid holdup typically decreases because
the gas can more efficiently sweep out the liquid phase. When a rate increase (ramp-up) occurs,
the liquid volume in the pipeline is accelerated resulting in a surge.
A ramp-up operation is illustrated in the following figure. PIPESIM predicts the liquid surge rate
using Cunliffes Method. For more information, see Cunliffe's Method for Ramp Up Surge (p.303).

Figure 9.6. Ramp-up Operation

For more detailed and accurate slug catcher sizing, you should also consider the drainage rates of
the primary separator and slug catcher. Additionally, you must consider the fact that hydrodynamic

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slugs and pig-generated slugs typically occur over a short duration (minutes), while the surge
created by a ramp-up operation can be a long duration (hours/days).

9.3.9 Task 5: Size a Slug Catcher

In this task, you will screen for severe slugging and determine the required size (volume) of the
slug catcher based on the largest volume of the following criteria, incorporating a safety factor of
20%.
You must design the slug catcher taking into account the following criteria:
Hydrodynamic slugging: This typically generates the largest slugs of all the scenarios. The
design is based on the statistical 1/1000th population slug size, determined using the SSB or
Norris Correlations.
Pigging volume
Transient effects, such as the requirement to handle the liquid slug generated when the
production flow is ramped up from 8,000 to 16,000 STB/D, such as a ramp-up surge.

Note: The slug-catcher will be sized to address the above scenarios only, and not severe riser
slugging. We will assume that the severe riser slugging scenario can be mitigated with topsides
choking or riser-based gas lift.

Do the following:
1. From the Home tab, select Simulations settings Output variables.
The Flow Assurance report template is selected.
2. Click Clone to make a copy, so you can customize it. Type in a name for the cloned report.
3. Click the Profile tab to see all the selected profile variables. To see the complete list of profile
variables, click the Selected tab to deactivate it. Add the following profile variables of interest
that are not included in the Flow Assurance template, by checking the box next to each of them
(Enter the first few letters of each variable in the Type to filter box, to filter the list):
Sphere-generated liquid volume from section (profile variable)
Total sphere-generated liquid volume so far (profile variable)
Cumulative liquid holdup (profile and system variables)
4. Click the System tab and add the system variables below, if missing.
Sphere generated liquid volume (system variable)
1 in 1000 slug volume (profile and system variables)
5. Exit the dialog box and save your workspace.
6. Launch the P/T profile task and set it up with Outlet pressure as the Calculated variable.
Leave the default values for the boundary conditions.
7. Select System Data as the sensitivity object and Liquid flowrate as the sensitivity variable and
enter the three liquid flowrates that have been used in the previous exercises (8,000, 14,000
and 16,000 stb/d).

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8. Click Run.
9. On the Profile results tab, select Show grid, then click Select Columns and add the following
three variables to the grid.
Total/Cumulative liquid-holdup
1 in 1000 slug volume
Total SGLV so far
10.Click Close to exit the Select columns dialog and scroll to the end of the Profile results grid to
see these variables. Change the units for all 3 variables to bbl.
11.For each sensitivity rate, extract the maximum 1/1000 Slug Volume and the Total SGLV so far
(Sphere Generated Liquid Volume) at the system outlet and record them. Compare them with
the answers below.
8,000 stb/d

14,000 stb/d

16,000 stb/d

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12.Assuming the design is based on a ramp-up volume from 8000 to 16000 stb/d, the ramp-up
volume would be the difference in total liquid holdup in the system between the 8000 stb/d and
16000 stb/d cases. Extract the total liquid holdup at 16,000 stb/d and at 8,000 stb/d and
subtract the 2 values. Compare your answer with the one below

Note: The surge associated with ramp-up occurs over a much longer time period than the other
cases. When sizing a slug catcher for a ramp-up scenario, consideration should be given to the
volume that will be discharged from the vessel during the ramp-up. For more information on how to
calculate the ramp-up duration, see Cunliffe's Method for Ramp Up Surge (p.303).

13.Determine the highest volume of the 3 scenarios and apply a safety factor of 20% to get the
design volume for the slug catcher. Compare it with the answers below.

Parameter Values
Slug Catcher Sizing 8,000 stb/d 14,000 stb/d 16,000 stb/d
1/1000 slug volume (bbl) 164.91 185.44 226.54
Sphere generated liquid volume (bbl) 456.13 424.53 413.90
Total liquid holdup (bbl) 875.44 765.19 728.25
Ramp-up volume (bbl) 875.44 - 728.25 = 147.19 bbl
Design volume for slug catcher (bbl) 456.13 * 1.2 = 547.36 bbl

9.4 Looped Gas Gathering Network

In this tutorial, you will learn how to build a gathering network and perform a network simulation to
evaluate the deliverability of the complete production system. It is necessary to model the network
as a complete system to account for the interaction of wells producing into a common gathering
system. The wellhead pressure, and by extension the deliverability of any particular well is
influenced by the backpressure imposed by the production system. Modeling the network as a
whole, allows the engineer to determine the effects of such changes as adding new wells, adding
compression, looping flowlines and changing the separator pressure.
In this tutorial, you will perform the following tasks:
Model a Pipeline Network (p.768)

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Screen the Network for Erosion Issues (p.777)

9.4.1 Model a Gathering Network

Boundary Conditions
To solve the network model, you must enter the correct number of boundary conditions. Boundary
nodes are those that have only one connecting branch, such as a production well, injection well,
source or sink.
The number of boundary conditions required for a model is determined by the model's Degrees of
Freedom, determined as follows:
Degrees of Freedom = number of wells (production and injection) + number of sources + number
of sinks
For example, a 3 production well system producing fluid to a single delivery point has 4 degrees of
freedom (3+1), regardless of the network configuration between the well and the sink.
Each boundary can be specified in terms of Pressure OR Flow rate OR Pressure/Flow rate (PQ)
curve.
Additionally, the following conditions must be satisfied:
The number of pressure, flow rate or PQ specifications must equal the degrees of freedom of
the model.
At least 1 pressure must be specified.
At each source (production well & source) the fluid temperature must be set.
PIPESIM validates that the correct number and type of boundary conditions are set before the
simulation run can be initiated.
Solution Criteria
A network has converged when the pressure balance and mass balance at each node are within
the specified tolerance. The calculated pressure at each branch entering and leaving a node is
averaged, and the tolerance of each pressure is calculated from the equation:

If all Ptol values are within the specified network tolerance, that node has passed the pressure
convergence test. This is repeated for each node.
A mass balance is also performed where the total mass flow rate into, and out of each node, is
averaged and used to compute the tolerance from the following equation:

If the Mtol value is within the specified network tolerance, that node has passed the mass
convergence test. This is repeated for each node

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The network has converged when all of the foregoing conditions are satisfied.

9.4.2 Task 1: Model a Pipeline Network

In this tutorial, your goal is to establish the deliverability of a production network. The network
consists of three producing gas wells in a looped gathering system, which delivers the commingled
streams to a single delivery point. The instructions that follow do not go into as much detail as
previous exercises. If you are unfamiliar with the steps for constructing a model, refer to the
previous tutorials for Help. If no specification is provided, use the default PIPESIM value.
Do the following:
1. Launch PIPESIM and create a new, network centric workspace.
2. From the Insert tab, add the following equipment:
3 wells (Use the Simple Vertical template for all wells).
4 junctions
1 3-phase separator
1 compressor
1 heat exchange
3 sinks
3. Rename and arrange them exactly as indicated below.

4. Connect the inserted objects using flowlines and connectors such that the network diagram
exactly matches the figure below. (Rename all the flowlines exactly as indicated below).

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Note: A connector is a line used to represent two physically-separated objects that are
connected, but have zero length between them (for example, a connector can be used to
connect a wellhead and a choke).

5. Create 2 new compositional fluids for the 3 wells based on the compositions below. Set the
PVT package to Multiflash and select the 3-parameter Peng-Robinson option as the Equation
of State. Leave all other model settings to their default values, but name the fluids as indicated
below.

Note: There are 11 components.

Component Moles
Fluid_A (Well_1 & Well_2) Fluid_B (Well 3)
Water 10 6
Methane 67.5 71
Ethane 5 6
Propane 2.5 3
Isobutane 1 1
Butane 1 1
Isopentane 1 1
Pentane 0.5 0.5
Hexane 0.5 0.5
Carbon Dioxide 2.5 4
C7+ 8.5 6
Name Molecular Weight Specific Gravity
C7+ 115 06.83

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6. After creating the 2 fluids, map Well_1 and Well_2 to Fluid_A and Well_3 to Fluid_B in the
Fluid manager, as below.

7. Save your workspace.

8. 7. In a previous step, you created all 3 wells using the Simple Vertical template. You will now
edit the default template values for each well and change them to the values specified below.

Properties Unit Well_1 Well_2 Well_3

Well type - Vertical Vertical Vertical
Casing Data
Casing (Bottom MD) ft 4700 4600 4800
Casing ID inch 6.765 6.765 6.765
Casing wall thickness inch 0.43 0.43 0.43
Tubing Data
Tubing (Bottom MD) ft 4450 4350 4550
Tubing ID inch 2.441 2.441 2.441
Tubing wall thickness inch 0.217 0.217 0.217
Roughness (casing/tubing) inch 0.001 0.001 0.001
Packer depth (MD) ft 4200 4100 4300
Wellhead ambient temperature deg F 60 60 60
Heat transfer coefficient BTU/(h.degF.ft2) 2 2 2
Completion Data
Fluid entry - Single point Single point Single point
Completion depth (MD) ft 4500 4400 4600
IPR model Well PI Well PI Well PI
Reservoir pressure psia 2900 2900 3100
Reservoir temperature deg F 130 130 140
Gas PI mmscf/d/psi2 0.0004 0.0004 0.0005

The three (3) wells display as below.

Well_1

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Well_1

Well_2

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Well_3

Well_3

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9. Click the Flowline manager on the Home tab and specify the flowline details as below.
(Double-click the Name column to sort in alphabetical order to make it easier to enter the data).

Note: To populate/fill the same value down a column (for example, the constant roughness
value of 0.0018 inches below), type the value into the top row you want to fill down from, and
press F3.

10.Exit the Flowline manager.

You will notice that all the flowlines are now valid (for example, they are no longer red).
11.Double-click the Separator (3PS) and select Gas as the Production stream. Leave the default
value of 100% for both the Gas/Oil and Water/Oil efficiencies.
12.Without exiting the separator dialog box, click the Compressor and enter a Pressure
differential of 400 psi and an Efficiency of 70%.
13.Without exiting the Compressor dialog box, select the Heat Exchanger and enter a Pressure
differential of 15 psi and Discharge temperature of 120 degF.
14.Exit the dialog box and save the workspace.
15.Go to Home Simulation settings Flow correlations and choose Beggs & Brill as the
global vertical and horizontal multiphase flow correlations.

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16.From the Home tab, launch the Network Simulation task.

17.Configure the boundary conditions for the simulation task, as shown below.

Note: The Run button is active only if the required number of P,Q specifications have been
supplied and there are no validation issues.

18.Click Run to launch the simulation.

19.View the Profile results.

Note: The GL-2_Compressor 1 branch profile is displaced in the above plot. This is a known
issue that will be resolved.

20.Plot the profile results for the flow path from Well_3 to the Gas_Sales sink as annotated below,
by selecting the highlighted branches. Observe the 400 psi pressure boost provided by the
Compressor.

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Note: The GL-2_Compressor 1 branch profile is displaced in the above plot. This is a known
issue that will be resolved.

21.Review the Node/Branch results and determine the network deliverability. Compare your
results with the answers below.

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Parameter Value
Gas flowrate to Gas Sales (MMscf/d) 49.67
Oil flowrate going to Oil Storage (STB/d) 7298.01
Water flowrate to treatment (STB/d) 748.70
22.Determine the drop in Gas production in the event of a compressor shutdown. This scenario
assumes that there is a bypass line around the compressor that allows gas production to be
maintained if the compressor goes down. Simulate this scenario by right-mouse-button clicking
on the Compressor and selecting Deactivate.
23.Rerun the Network Simulation task and compare your results with the answer below.

Parameter Value
Gas sales without compressor (MMscf/d) 45.60

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9.4.3 Task 2: Screen the Network for Erosion Issues

In this task, you will screen the network for branches that exceed the erosion velocity limit.
Do the following:
1. Re-activate the compressor by right clicking it and selecting Activate.
2. Go to Home > Simulation settings > Erosion/Corrosion and confirm that the API 14e erosion
model is selected and the default Erosional velocity constant (C value) of 100 is being used.
3. Run the Network Simulation task.
4. Go to Profile results tab and change the Y-axis variable to display Erosion velocity ratio. The
erosional velocity ratio (EVR) is calculated as below.

If EVR > 1, there is an erosion risk.

5. Display the EVR plot for all branches.
You should get a plot similar to the one displayed below.

6. Identify the branches where the EVR exceeds one and compare them to the answers below.

Branches where EVR > 1 Well_1, Well_2 & Well_3 and connected flowlines WFL-1, WFL-2 &
WFL-3 respectively

Why do these specific branches have the highest EVR? (These are the well branches. They
have the highest flowing temperatures, hence highest fluid velocities).
7. Determine possible solutions to get rid of the erosion issues and implement them in the
network.

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9.5 Manual Creation of a Simple Network Model on the GIS

Map
This tutorial covers the GIS capability that was introduced in PIPESIM 2013.1 that allows the user
to build a pipeline network model overlain on a GIS map. This feature allows you to build a model
more closely representing real world conditions, because the exact pipeline terrain profiles,
following the real route on the earth can be automatically collected by PIPESIM. The captured
elevation data are then used by PIPESIM for the pressure drop calculations.
In this tutorial, you will build the network model on a GIS map. The instructions that follow do not
go into as much detail as earlier tutorials. If something is not clear, go back to previous tutorials for
a more complete explanation. If no specification is provided for a variable, use PIPESIM's default
value.

9.5.1 Task 1: Build the Network Model on a Map

There are multiple ways to create a network on the map in PIPESIM. One way is to build the
network on the logical network canvas (as you learned in the previous tutorial). After building the
network in the logical view, you may then superimpose it on a GIS map, by launching the GIS map
and selecting the area to place it on. You would then need to reposition the equipment and pipeline
routes to replicate the actual layout. A second option is to build the network model directly on the
GIS map. This tutorial will focus on this option. A third and more advanced option, is to import a
shape file to automatically create the network. This is a feature that was introduced in PIPESIM
2014.1. For more information, see Creating a Network Model from a GIS Shapefile Automatically.
(p.23)
Do the following:
1. Create a new, network centric workspace.
2. From the Home tab, click the GIS map icon to launch the GIS map. A GIS map provided by
ESRI should automatically display, as long as you have internet access and there are no
firewalls preventing access to the ESRI site. The default map is the ESRI World Satellite map
and is one of several ESRI maps built into PIPESIM. You have the option to set up connections
to other ESRI maps or to other map services such as Bing and even corporate GIS map
services. For more information see Choosing a Basemap (p.255), Using Map Services (p.264),
and Adding Bing Basemaps. (p.256)
3. With the GIS map open, click the Format tab to display the expanded functionality available for
GIS networks.

Note: There are several ways to zoom into a particular location on the map to build the
network. You may manually zoom into an area, you may import a shape file, or you may open a
map cache of a limited map area. After zooming in on the area of interest, you may save it to
the workspace as a Bookmark so you can re-use it. Bookmarks are workspace-specific and can
be repeatedly used in the workspace they are saved in (not across workspaces). PIPESIM also
has a few built-in bookmarks.

4. Locate the Bookmarks list on the Format tab and select Northridge from the dropdown
options. The map should zoom into the Northridge area and should appear as below.

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Note: To pan the map (for example, move left/right and up/down), hold the Ctrl key down, then
select the left mouse button and move left/right and up/down.

5. Go to the Insert tab and insert a Well anywhere on the map. Select the Simple vertical template
for it, when prompted.
6. Position the well at an exact geographic location. Go to the Format Tab and click the
Equipment Locations icon. Enter the Lat-Long coordinates for the well as shown below:

7. Use the Zoom area feature on the Format tab to zoom in on an areal extent around the Well
resembling the one depicted in the figure below.

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8. Using the screenshot below as a guide, insert the following additional objects in the locations
depicted below, as closely as possible (the exact locations are unimportant).
A second well in the south-east (use the Simple Vertical template)
A choke near the first well
One junction
One sink

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9. From the Insert tab, click on the Flowline icon and draw the first flowline to connect the Choke
to the Junction, following the path depicted below as closely as possible (Trace the path of the
existing flowline in the GIS map view, which appears as a thin white line).

10.Draw the second flowline to connect the Junction to Well-1, following the path depicted below
as closely as possible (Again, trace the path of the thin white line indicated below, which
represents an existing flowline on the GIS map).

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11.Draw the third and final flowline to connect the Junction to the Sink, following the path depicted
below as closely as possible (Again, trace the path of the thin white line indicated below, which
represents an existing flowline on the GIS map).

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12.From the Insert tab, click on the Connector icon and draw a connector from the 1st well to the
Choke. Your map should now appear as below.

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13.From the Home tab, select Flowline Manager. Enter a common flowline ID of of 3.026 inch,
wall thickness of 0.216 inch and pipe roughness 0.0018 inch for all flowlines in the network (To
fill down a value in a column e.g. ID of 3.026, type the value in the 1st row and press F3).
Leave the Hor. Distance column blank, as it will be populated when we use PIPESIMs GIS
Elevation Capture feature.

14.From the Format tab, select the Cluster checkbox. This groups all of the items joined by
connectors into a single node representing the actual physical location of these objects. The
number in the node (circle) indicates the number of objects in the cluster. The unclustered
(original) and clustered views are displayed in the left and right screenshots below respectively.

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15.Capture the elevations by following these steps:

a. Check the Elevation points box in the Show/hide group of the Format tab. Notice the red
circles have been added to the flowlines. These indicate the positions along the flowlines,
that elevations will be captured from the map.
b. To capture elevations at more locations along the flowlines, change the interval from the
default value of 300 ft to 60 ft. Do this in the Interval box of the Elevation group on the
Format tab. You will notice the red circles (elevation points) along the flowlines increase.
c. On the Format tab, in the Elevation group, you will observe that there are 2 elevation data
sources available; SRTM and ASTER. Leave the default SRTM service, selected. For more
details on the data sources, refer to the topic: ASTER and SRTM Elevation Data Sources.

d. Click Capture elevation.

The elevation points will turn green, if the operation was successful. Additionally, the
flowlines will no longer be invalid. Your map should now appear as below.

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16.Check the GIS nodes box to display red square boxes at the end points of each flowline
segment corresponding to a change in direction.
17.Double-click any flowline to view the geometry profile data. You will notice that the Populate
from GIS map box is checked because the profile data was captured from the map.

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Note: If you have profile data for the flowlines from another source, you may uncheck the box
and copy-paste this data into the grid. This data is termed the logical profile data to
differentiate it from the GIS profile data captured from the map. You may store the profile data
from both sources and run the network simulation with either the logical or GIS profile data by
checking or unchecking the Populate from GIS map box before the run

18.View the GIS map locations for the various equipment (chokes, junctions, well, etc.) by clicking
Equipment locations in the Utilities group on the Format tab.

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You can reposition any object on the GIS map. In the next few steps, you will reposition the
Sink, which will also reorient the flowline connected to it.
19.On the Format tab, click Zoom out once, to view a slightly larger areal extent.
20.On the map, drag the sink from its current location (Point A) to the new location (Point B) as
indicated below.

You will notice that the flowline connected to the sink is now invalid (for example, It is red and
the dots on it representing the elevation points, have also become red). This is clearly because
you just repositioned the sink, rendering the previously-captured elevation data, invalid. You will
need to recapture the elevation, but before you do that, go to the next step to further alter the
path for this flowline.
You will now alter the path for the flowline connected to the sink.
21.To do this, from the Insert tab, click the Add node icon and add 3 intermediate nodes to the
flowline at the locations indicated below.

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22.Move the 1st 2 intermediate nodes upwards to the new positions indicated in the map below.
Also, move the Sink downwards as indicated, until the flowline trajectory resembles the one
below.

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The overall network should appear as below.

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23.From the Format tab, click Capture elevations to re-capture the elevations and save your
workspace.
24.On the Inputs pane on the left, expand the Equipment list and double-click the Choke to enter
a bean size of 1 inch. Close the choke editor.
25.Exit the GIS map by closing it.
Now, you are in the logical network view. Rearrange the equipment and flowlines, if needed.
(This will not affect the equipment locations in the GIS map view).

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26.Go to the Fluid manager on the Home tab and make sure Black oil is the selected option.
27.Launch the Fluid manager and click the green plus sign

to create a new fluid. When prompted, select the Dry gas template from the option list and click
OK.
28.Click the Fluid mapping tab and map both wells to the new black oil fluid you just created by
selecting it from the option list.
29.Exit the Fluid manager and save your workspace.
30.Launch the Network Simulation task and specify the boundary conditions below.

31.Run the task and compare your results with the answers below (On the Node/Branch results
tab, click Expand all to extract some of the results below).

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Parameter Value
Gas flowrate at Sink (MMscf/d) 45.07
Gas flowrate from Well (MMscf/d) 23.69
Gas flowrate from Well-1 (MMscf/d) 21.69
Differential pressure across Choke (psi) 305.2
Outlet Pressure from the Junction (psi) 1617.1

Note: Your answers will not exactly match those in the table above due to slight differences in
the way you laid out the flowlines in the GIS map view.

9.6 Automatic Creation of a Network Model on the GIS Map

and Investigation of the Use of Inline Heating for Wax
Mitigation
PIPESIM 2014 introduced the ability to automatically create a network from a GIS shapefile. The
objective of this tutorial is to utilize this feature to build a network, evaluate the severity of the wax
issues for the fluid that will be produced through the network, and analyze the option of using inline
heating for wax mitigation.
The network is a simple 2-well oil network in the East Texas Oil field with known wax issues.
The assumption is that you are now familiar with the basics of building a network and with the GIS
map. Consequently, the instructions that follow do not go into as much detail as previous tutorials.
If something is not clear, go back to previous tutorials for a more complete explanation. If no
specification is provided for a variable, use PIPESIM's default value.
You will require the Multiflash license features to be able to model the wax precipitation and
complete this tutorial.
You will begin by importing a shapefile representing the network, into PIPESIM. PIPESIM will then
automatically create the network elements from the features in the shapefile. For more information,
see GIS Shapefile Basics (p.262) to learn more about shapefiles. It is important to note that while
shapefiles can be imported to create networks, as will be covered in this tutorial, they can also be
added as layers to the GIS map, solely for visualization. For more information, see Using
Shapefiles. (p.263)
Do the following:
1. Go to your PIPESIM installation location (for example, C: drive) and browse to the folder: C:
\Program Files\Schlumberger\PIPESIM2014.1\Case Studies\Tutorial
Examples.
2. Extract the shapefile zipped folder named EastTexasOilfieldShapefiles.zip.
Several files will be extracted. The 3 mandatory files for the shapefile import are the ones with
the following extensions: .shp, .prj and .dbf. They must all be in the same location.
3. Create a new, network centric workspace.

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4. On the Home tab, click GIS map to launch the GIS map canvas.
5. Go to the Insert tab and select Import network and browse to the location of the East Texas
shape files.
6. Select the file EastTexasOilfield.shp and click Open.
The Import network dialog box opens.

Note: The Import network dialog box allows you to map the attributes in the shape file (if
available) to the PIPESIM properties required for simulation. The required PIPESIM properties
are the Flowline name, Pipe inside diameter, Pipe wall thickness and Pipe roughness. The
Import network dialog box also enables you to define other global environmental and flowline
settings for the entire network that will be imported. This is to facilitate network creation and
speed up the process

7. Expand the Shapefile property option list (as above) to see the attributes contained in the
shape file. They are:
FLID - Flowline inside diameter
FLName - Flowline name
8. Map FLName to Flowline name and FLID to Pipe inside diameter.

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Notice that the shapefile does not contain attributes for the Pipe wall thickness and Pipe
roughness.
9. Enter these manually by checking the Override box for these 2 properties and type in the
values 0.237 and 0.0018 inches respectively. All flowlines will be assigned these values when
the network is created.
10.In the Global Environmental Settings section, check the Update global environmental data
box and change the Air temperature from the default value to 70 deg F.
11.Change the U-Value type to Coated to assign a U-Value of 2 Btu/hr.degF.ft2 to all flowlines.
When complete, the dialog box (below) displays.

For more information on how the Global Environmental and Flowline settings entered in the
Import network dialog are populated to the workspace, see Creating a Network Model from a
Shapefile Automatically. (p.23)
12.Leave everything else as default and click OK to complete the import process.
The shapefile will be imported and the network created as below. Each "polyline" in the
shapefile represents a flowline and PIPESIM will automatically insert junctions between
separate polylines.

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Note: Currently, incremental network creation is not supported (for example, you may only
import a shapefile to create a network in a new workspace. You cannot import a shapefile to
overwrite an existing network in a PIPESIM workspace. Also, you cannot extend an existing
PIPESIM network by importing a shapefile with additional features. You will get an error if you
attempt either of these scenarios in PIPESIM.

13.Go to Format Basemaps and change the Base map to the ESRI National Geographic map
by selecting it from the option list. Zoom out a few times. You will notice this hypothetical
network is in the East Texas Oilfield.

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14.Save your workspace.

15.Go to the Flowline manager on the Home tab to review the flowline details. You will notice that
all the flowlines have been correctly populated with the mapped shapefile attributes (Name &
ID) and the specified values (Roughness, wall thickness & ambient temperature).

16.Change the wall thickness of the largest flowline (6.065) to a more appropriate value of 0.28.
17.Exit the Flowline manager.
The decision has been taken to insulate only Flowline 3 which flows the commingled production
from Junction 2 to the Sink.

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18.Double-click Flowline 3 and click the Heat transfer tab and change the U Value type to
Insulated, as below.

19.Return to the GIS map and notice that the imported network does not contain any wells.

Note:
Currently, the Import network feature only supports the import of flowlines (for example,
wells and other equipment cannot be imported at this time).
To alleviate the above limitation and aid the process of creating wells and other equipment
at specific points in the network, a junction conversion feature has been introduced. To
convert a junction, you simply right-click the junction and select Convert to from the menu.
A list of the possible objects (well or equipment) that could be placed at that particular
junction, based on the number of flowlines connected to it, will appear. You would then need
to select the object you want to convert the junction to. It is important to note that the
junction conversion process is irreversible. For more information, see Converting Junctions
to Wells, Sources, Sinks and Equipment (p.124).

20.Convert Junction 1 (near Clarksville City) to a Well.

21.Select None as the Well template, when prompted.
22.Build the well model using the following properties.

Properties Unit Well_1

Well type - Vertical
Casing Data

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Properties Unit Well_1

Casing (Bottom MD) ft 3700
Casing ID inch 5.92
Casing wall thickness inch 0.54
Tubing Data
Tubing (Bottom MD) ft 3600
Tubing ID inch 2.259
Tubing wall thickness inch 0.308
Roughness (casing and tubing) inch 0.001
Packer depth (MD) ft 3595
Heat Transfer and Completion Data
Wellhead ambient temperature deg F 70
Heat transfer coefficient Btu/(h.degF.ft2) 2
Fluid entry - Single point
Completion depth (MD) ft 3650
Reservoir pressure psia 1600
Reservoir temperature deg F 160
Liquid PI Stb/d/psi 5
Use Vogel below bubble point Yes
23.Leave all other tabs in the Well editor to their defaults.
24.Exit the Well editor .
25.Convert Junction 3 to a second well.
This second well is exactly identical to the first well you just created, so to speed up the
process, you will save the first well as a template so you can re-use it.
26.Right-click the 1st well, either in the Inputs pane on the left or on the GIS map itself.
27.From the menu that is displayed, select Save as template.
The first well has now been saved to the Well templates catalog and can be re-used.
28.View the Well templates catalog under Home Catalogs and hover the mouse over each icon
and click the Well templates catalog icon.
You will see the template you just saved.
29.Convert Junction 3 (near the Sabine river label) to a second well. When prompted, select the
new well template you just created, as below and click OK. The new well will be an exact
replica of the 1st well.

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30.Convert Junction 4 (near Nay St) to a Sink and your network should appear like below.

31.On the Format tab, in the Elevation group, you will observe that there are two (2) elevation
data sources available: SRTM and ASTER. Leave the default SRTM service, selected. For
more information on the data sources, see ASTER and SRTM Elevation Data Sources. (p.22)
32.Click Capture elevations to automatically capture the elevations for the flowlines.
For more information, see Capturing Elevation. (p.276)
33.Go to Validation pane at the bottom of the window.
You will notice two validation errors related to the fact that no fluids have been defined and
mapped to the wells. The model is un-runnable in this state.
34.You will now import a fluid file for a waxy crude that was created in the Multiflash standalone
PVT package.
For more details on the various Multiflash PVT options, see Multiflash in the Compositional
Fluid mode (native) vs Multiflash MFL files (p.146) and Availability of Multiflash models in
PIPESIM using MFL file fluid mode option (p.164).
35.Go to the Home tab and select MFL file as the option in the Fluid manager.

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36.Add a new row to the Fluids table and browse to the same PIPESIM installation directory
referenced earlier (C:\Program Files\Schlumberger\PIPESIM2014.1\Case
Studies\Tutorial Examples).
37.Select the file named Waxy.mfl and click OK to import it.
You will notice in the Fluids tab that the GOR and Water cut for this fluid are 1173 scf/stb and
0% respectively (as below).

38.Go to the Fluid mapping tab and map both wells to the same waxy fluid.
39.Return to the Fluids tab to view the phase envelope and models for the fluid by double-clicking
the fluid row.
There should be 44 components in this characterized fluid. Observe the n-paraffin components,
which have an N-prefix. They are required for a proper wax study.

Note: PIPESIM can handle a maximum of 50 components for a compositional simulation.

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Note: In addition to the above method, you have the following additional options to view the
phase envelope.
Double-click the fluid in the Inputs pane on the left of the main window.

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Click the well in the Inputs window and select Phase envelope on the Home tab. This
option is possible only after a fluid has been mapped to the well. With this option, after
running a simulation, you can see the simulated P-T profile for the selected object
superimposed on the phase envelope.

40.From the phase envelope, the wax temperature seems to be approximately 140 deg F. This is a
very waxy crude and will require a comprehensive flow assurance strategy to be able to
produce it.
41.Exit the Fluid manager.
42.Go the Home tab and click Simulation settings. Select the latest OLGA3 3-phase flow
correlations for both Vertical and Horizontal flow (if you do not have the license features for the
OLGA correlations, use the PIPESIM defaults).
43.While still on the Simulation settings, click the Output variables tab and select the Flow
Assurance report template.
44.Exit Simulation settings and save your workspace.
Exit the GIS map if you have not done so already.
45.Launch the Network simulation task and enter 200 psi as the sink boundary condition as
below.

46.Click Run and review your results and compare them to the answers below.

Parameter Value
Liquid flow rate at Sink, STB/D 3769.9
Well Liquid flow rate, STB/D 1884.8
Well 1 Liquid flow rate, STB/D 1898.8
Well Flowing BHP, psi 1172.2
Well 1 Flowing BHP, psi 1168.5

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47.You will now investigate the severity of the wax problems. Under Profile results and Node/
Branch results review plot and grid results (both node and branch) for the following variables.
Temperature and Wax Formation Temperature
Wax sub-cooling delta temperature (for example, Wax formation temperature - Fluid
temperature). A positive wax sub-cooling delta temperature is a problem, it indicates that the
fluid can precipitate wax at that point in the system
Max wax sub-cooling delta temperature.

Parameter Value
Wax Formation temperature, deg F 141
Maximum Wax subcooling DT in Well Branch, deg F 69.8
Maximum Wax subcooling DT in Well-1 Branch, deg F 68.1

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48.Identify the locations in the system where the fluid temperature drops below the wax formation
temperature ( for example, wax subcooling DeltaT > 0) the wax cold spots?

Note: To see the results at finer intervals in order to get a more accurate depth at which gas
appears, go to Home Simulation settings Advanced and check the Print computation
segment result box. Exit the dialog box and re-run the P/T profile task.

Parameter Value
Well and Well-1 Branch 1360 ft (inside the wellbore)

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Note: PIPESIM cannot currently report or plot wax variables in branches where flow is
commingled such as the Sink branch in this example. This is a known limitation.

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You have identified that there is a severe wax problem in this network, and the problem will
start in the wellbore of both wells. You will now explore the option of installing heaters inside
both wellbores to mitigate against this problem. There is no "Active Heater" equipment in the
current PIPESIM interface, but inline heating is available in the engine via keywords. To
implement this, you will insert an Engine Keyword Tool (EKT) in both wells.
49.Double-click the 1st well to launch the Well editor.
50.From the Insert tab, drag the Engine keywords object and drop it anywhere in the tubing.
The Downhole equipment tab is active.
51.Enter the depth of the wax cold spot identified earlier, but incorporate a safety margin of 100 ft.
The heating will be installed at approximately 1460 ft (=1360 + 100 ft) as below, providing a
margin for future conditions when the reservoir pressures and rates decline, and the wellbore
temperatures drop
52.Type in the keywords for inline heating, as below.
For more information on Inline Heating keywords and PIPESIM keywords in general, see PIPE:
Pipe or Tubing cross-section dimensions (Required) (p.615) and Keyword Index. (p.511)
You will begin by introducing enough heat into the wellbore to maintain its temperature at 150
degF (10 degrees above the wax formation temperature). You will do this for both wells and
determine if this is sufficient to keep the entire network above the wax formation temperature
(This is based on the assumption that the wax formation temperature in the Sink branch is
equal to the wax formation temperatures in the Well branches). If the 150 deg F minimum
temperature is insufficient, then you will increase the temperature until you arrive at the right
value for wax mitigation.

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53.Following same procedure above, double-click the 2nd well and install a heater at the same
depth 1460 ft to maintain the wellbore temperature at 150 degF.
54.Save your workspace.
55.Go to Home > Simulation settings > Output variables.
Make sure the Profile tab is active.
You will see a list of the default selected profile variables in the Flow Assurance report template
you are using. Clone this report template (as below) and name it Updated Flow Assurance, so
you can add some new variables to it.

56.Click the Selected tab to deactivate it. You will now see the complete list of profile variables.
Type "inl" in the filter box to display all the available inline profile variables. Check all of them to
include them in the simulation output for reporting and plotting.

57.Exit the Simulation settings and save your workspace.

58.Rerun the Network simulation task.
59.Review the profile resutls and answer the following question.

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Is the minimum well temperature of 150 degF in both wells sufficient to mitigate against wax
precipitation in the entire network?

Note: The Well and Well-1 wax formation temperature branch profiles are displaced in the
above plot. This is a known issue that will be resolved.

60.If the answer to the question above was No, sensitize on the minimum wellbore temperature to
be maintained by the heater, until you arrive at the required value. Use 10 deg F increments.
(You will have to go into the Engine Keywords object in the well editor and manually change the
heat duty for each sensitivity run). Compare your results with the answer below.

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Note: The Well and Well-1 wax formation temperature branch profiles are displaced in the
above plot. This is a known issue that will be resolved.

Parameter Value
Required minimum wellbore temperature in Well & Well-1 to maintain the entire 170
network above WAT, degF
61.Review the following profile plot: Inline heating power used to determine the amount of heat that
must be supplied to achieve the minimum wellbore temperature estimated from the previous
step.

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It appears that a large amount of heat is required to deal with the highly waxy crude in this
example. What other options, in addition to heating, could be used, to reduce the heat duty
required? (Thermal insulation, Wax inhibitor injection).

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10
Support
Schlumberger Information Solutions (SIS) provides a variety of options for receiving support:

10.1 SIS web support

If you have a problem that cannot be resolved using PIPESIM Help, you can send a support
request via the Schlumberger Information Solutions Support Web page. The Support Portal
provides a single, online location for all your support needs. Within the Support Portal you can
quickly search a vast knowledge base for the answers you need, participate with your peers in
discussion forums, and receive the latest news about SIS products and services.
All support requests are entered into the SIS Customer Care Center incident tracking system,
where they are resolved by local support staff. For those times when you need to speak with a
support specialist, contact numbers are provided for your local support center.

10.2 On-site support

Schlumberger Information Solutions (SIS) supplements the standard maintenance agreement by
offering extended on-site support worldwide. This enhanced level of support includes on-site
assistance, installation, troubleshooting and maintenance services of licensed SIS software.
Contact the help desk or refer to your licensing agreement for more information.

10.3 SIS Education

A large number of training courses are offered at various SIS locations, or on-site for groups or
individuals upon request. These training courses can help you increase the value you are receiving
from your SIS software products. The courses can also act as a form of preventive maintenance as
you learn to achieve smoother and more trouble-free performance with the products. See the SIS
Training Web site for more information.

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Index
0-9 automatic creationg of a network model on the GIS map
.pips workspace file .................................................. 236 tutorial ..........................................................................

A B
adding a deviation survey ........................................... 29 babu and odeh reservoir data .................................... 63

adding a gas life injection point .................................. 41 Back Pressure equation

BACKPRES keyword ............................................ 580
adding an ESP ........................................................... 44
details ................................................................... 313
adding a nodal point ................................................. 201
Beggs and Brill ......................................................... 288
adding a progressive cavity pump .............................. 46
Beggs and Robinson
adding a rod pump ..................................................... 48
Dead oil viscosity .................................................. 430
adding artificial lift ....................................................... 41 live oil viscosity ..................................................... 432
adding bing basemaps ............................................. 256 BEGIN keyword ........................................................ 550
adding casing and tubing to a detailed Benedict-Webb-Rubin-Starling ................................. 454
wellbore schematic ..................................................... 27
Bergman and Sutton
adding casing and tubing to a simple
undersaturated oil viscosity .................................. 436
wellbore schematic ..................................................... 25
binary interaction parameter ..................................... 164
adding completions .................................................... 51
Biot number .............................................................. 412
adding connections .................................................. 144
black oil .................................................................... 146
adding downhole equipment ...................................... 32
Black oil
adding heat transfer data ........................................... 49
CALIBRATE keyword ........................................... 643
adding items to the compressor catalog ................... 244
correlations ........................................................... 421
adding items to the pump catalog ............................ 246 enthalpy ................................................................ 441
adding sources and sinks ......................................... 101 fluid modeling theory ............................................. 419
adding surface equipment using the network mixing ................................................................... 442
diagram .................................................................... 102 surface tension ..................................................... 440
adding surface equipment using the Well Editor ........ 91 TPRINT Table printing .......................................... 642
adding tubular data ..................................................... 25 BLACK OIL DATA keyword ...................................... 633
adding wells .............................................................. 100 BLACKOIL keyword ................................................. 633
Ansari ....................................................................... 288 branch display mode properties ............................... 227
API14B critical flow correlation ................................. 361 BRANCH keyword .................................................... 678
Aqueous Components cubic EoS ........................ 463 Brauner and Ullman correlation ................................ 470
AQUEOUS keyword ................................................. 645 Brill and Minami ........................................................ 288
Asphaltene ............................................................... 466 bringing objects into view ........................................... 98
ASSIGN keyword ..................................................... 667 Brinkman correlation ................................................ 470
associating zones with completions ........................... 90 Bubble point

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PIPESIM User Guide

correction .............................................................. 325 CHOKE keyword ...................................................... 589

solution gas-oil ratio .............................................. 422 choosing a basemap ................................................ 255
building a PIPESIM model .......................................... 22 Coating ..................................................................... 626
COAT keyword ......................................................... 626
C Comment Statements ............................................... 519
CALIBRATE keyword ............................................... 643 COMPCRV keyword ......................................... 593, 619
Calibration COMPLETION keyword ........................................... 567
solution gas-oil ratio .............................................. 426
Compositional
capturing elevation ................................................... 276 fluid: AQUEOUS keyword ..................................... 645
CASE/ENDCASE keyword ....................................... 664 fluid: LIBRARY keyword ....................................... 652
CASE keyword ......................................................... 524 fluid: MODEL keyword .......................................... 652
Casing fluid specification .................................................. 648
standard sizes ....................................................... 478 petroleum fraction specification ............................ 653
CEMULSION keyword .............................................. 645 viscosity models for compositional fluids .............. 465
changing the display options .................................... 269 COMPOSITIONAL DATA keyword .................. 645, 654
changing the main window layout .............................. 16 compositional fluid .................................................... 146
changing the model display properties ....................... 98 COMPOSITION keyword ......................................... 648
Character Input ......................................................... 518 Compressor
theory .................................................................... 366
Chew and Connally
live oil viscosity ..................................................... 432 COMPRESSOR keyword ......................................... 595
Choke Conduction shape factor .......................................... 412
Achong critical flow correlation ............................. 361 CONETAB keyword .................................................. 579
API 14B subcritical flow correlation .................... 357 CONFIG keyword ..................................................... 631
Ashford and Pierce critical flow correlation ........... 361 configuring junctions as sources .............................. 125
Ashford and Pierce critical pressure ratio ............. 360 configuring simulation settings ................................. 177
Ashford and Pierce subcritical flow correlation ..... 357
Coning ...................................................................... 353
Baxendall critical flow correlation .......................... 361
Coning Relationship Tabulation ............................... 579
critical flow correlations ......................................... 361
critical pressure ratio ............................................. 360 CONTAMINANTS keyword ...................................... 644
Gilbert critical flow correlation ............................... 361 Convective heat transfer .......................................... 628
Mechanistic critical flow correlation ...................... 361 Conversion factors ................................................... 497
Mechanistic subcritical flow correlation ................. 357 converting junctions to wells, sources, sinks,
Omana critical flow correlation .............................. 361 and equipment .......................................................... 125
Pilehvari critical flow correlation ............................ 361 Correlation
Poetmann-Beck critical flow correlation ................ 361 options .................................................................. 633
Ros critical flow correlation ................................... 361 CORROSION keyword ............................................. 555
Sachdeva critical flow correlation ......................... 361
corrosion model)
subcritical flow correlations ................................... 357
de Waard's equation ............................................. 301
theory .................................................................... 354
CPA .................................................................. 450, 454
user-defined critical flow correlation ..................... 362

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PIPESIM User Guide

CPFLUID keyword .................................................... 642 distributed PI .............................................................. 64

creating a custom bookmark file ............................... 260 Distributed Productivity Index Method ...................... 352
creating a custom fluid template ............................... 248 Drainage radius ........................................................ 490
creating a custom unit system ...................................... 8 dry gas ...................................................................... 248
creating a custom well template ............................... 250 Duns and Ros ........................................................... 288
creating a new network model on the GIS map ....... 271 Dynamic skin ............................................................ 327
creating a VFP table ................................................. 204
creating or defining a new MFL fluid ........................ 165 E
creating or editing a network model ........................... 96 E300 Flash ............................................................... 450
creating or editing a well model .................................. 24 Editing ...................................................................... 552
CSMA ....................................................................... 454 editing an MFL fluid files ........................................... 170
Cubic Equations of State .......................................... 459 editing equipment locations ...................................... 277
Cunliffe's Method ...................................................... 303 Elbows ...................................................................... 491
CVFMD keyword .............................................. 596, 621 Electrical Submersible Pumps see ESP .............. 390
Elsharkawy and Alikhan
D dead oil viscosity ................................................... 432
Darcy live oil viscosity ..................................................... 432
equation ................................................................ 314 undersaturated oil viscosity .................................. 436

darcy's reservoir properties ........................................ 57 END keyword ........................................................... 550

Data files .......................................................... 324, 519 Energy equation ....................................................... 398

DBR flash ................................................................. 450 Engine keyword .................................................. 40, 142

dead oil ..................................................................... 248 Entity ........................................................................ 236

Dead oil viscosity ...................................................... 430 Equations of State

components of cubic ............................................. 459
defining black oil fluids ............................................. 148
components of non-cubic ...................................... 464
defining compositional fluids .................................... 156
Equations of State Cubic ..................................... 450
defining the skin ......................................................... 65
Equations of State non-cubic ............................... 454
De Ghetto
EQUIPMENT keyword .............................................. 597
correlations ........................................................... 421
dead oil viscosity ................................................... 431 EROSION keyword .................................................. 555
live oil viscosity ..................................................... 434 ESP
solution gas-oil ratio .............................................. 423 overview ................................................................ 390
undersaturated oil viscosity .................................. 435 selection/design .................................................... 396
Delimiters ................................................................. 516 system components: pumps ................................. 392

de Waard .................................................................. 301 ESP slippage factor .................................................. 186

displaying object clusters ......................................... 273 EXECUTE keyword .................................................. 553

displaying phase envelopes for Expander

compositional fluid or MFL file .................................. 173 equations .............................................................. 370
distributed completions ............................................... 60 EXPANDER keyword ............................................ 599

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Expert mode ..................................................... 511, 686 Format ........................................................................ 93

Explicit Subcodes ..................................................... 660 FRACTURE keyword ............................................... 586
extracting WMS parameters ..................................... 266 Framo
FRAMO2009 keyword .......................................... 602
F Friction and Holdup factors
Fetkovich .................................................................. 311 Moody and AGA Friction factors ........................... 296
FETKOVICH keyword .............................................. 570 Moody Friction factor ............................................ 297
filtering catalog views ............................................... 241 Friction pressure drop
Cullender and Smith ............................................. 299
First law of thermodynamics ..................................... 398
Hazen-Williams ..................................................... 300
Fittings
Panhandle A ......................................................... 299
equations .............................................................. 363
Panhandle B ......................................................... 299
FITTING keyword ................................................. 600
Weymouth ............................................................. 299
Flow .......................................................................... 564
Flow control valves G
mechanistic theory ................................................ 362
Gas compressibility .................................................. 436
FLOW CORRELATION DATA keyword ................... 554
Gas condensate reservoirs ...................................... 308
Flow correlations
Gas lift
horizontal multiphase ............................................ 283
injection valve ....................................................... 607
single phase .......................................................... 296
multiple injection ports in wells ............................. 603
Flow correlations
GASLIFT keyword .................................................... 603
valid horizontal combinations ................................ 562
Gas phase contaminants .......................................... 644
valid vertical combinations .................................... 558
vertical multiphase ................................................ 288 gas ratio .................................................................... 252
vertical options ...................................................... 557 gas ratio type ............................................................ 252
flow direction ................................................................... Gas reservoirs .......................................................... 308
Flow regimes ............................................................ 281 Gas viscosity ............................................................ 439
Fluid gas well performance analysis
property data ......................................................... 635 tutorial ..........................................................................
property table files ................................................ 469 Gas wells .................................................................. 349
specific heat capacity data .................................... 642 General Data ............................................................ 522
typical values of properties ................................... 487 General Purpose Subcodes ..................................... 663
viscosity models for compositional ....................... 465
GERG ....................................................................... 454
fluid files with same template of components ........... 164
GERG binary interaction parameter ......................... 163
FLUID keyword ......................................................... 631
Glas
fluid mapping tab ...................................................... 252 correlations ........................................................... 421
fluids ......................................................................... 251 dead oil viscosity ................................................... 431
FMPUMP keyword ................................................... 602 solution gas-oil ratio .............................................. 424
Forchheimer equation .............................................. 313 Glossary of symbols ................................................. 492
FORCHHEIMER keyword ........................................ 586 Govier and Aziz ........................................................ 288

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PIPESIM User Guide

Gray .......................................................................... 288 Hossain

dead oil viscosity ................................................... 432
H live oil viscosity ..................................................... 432
Hagedorn and Brown ............................................... 288 undersaturated oil viscosity .................................. 436
HCORR keyword ...................................................... 561 HVOGEL keyword .................................................... 586
HEADER keyword .................................................... 523 Hydrate
inhibitors ............................................................... 466
Heat Balance ............................................................ 623
model details ......................................................... 468
Heat configuration data ............................................ 631
overview ................................................................ 466
HEATER keyword .................................................... 603
Hydraulic fracture ..................................................... 586
HEAT keyword ......................................................... 623
Heat transfer I
between flowline and ground ................................ 412
Ice prediction ............................................................ 468
between well and rock .......................................... 416
IFPCRV keyword ...................................................... 576
coefficient .............................................................. 399
conductive coefficient calculations ........................ 408 IFPPSSE keyword .................................................... 571
convective coefficient calculations ........................ 410 IFPTAB keyword ...................................................... 578
IFC correlations .................................................... 402 importing a bookmarks file ....................................... 260
pipe coat thermal conductivity .............................. 628 importing a PVT file .................................................. 176
HEAT TRANSFER DATA keyword .......................... 623 importing existing MFL fluid files .............................. 167
heavy oil + gas ......................................................... 248 importing or exporting a custom unit system ................ 8
Holdup factors .......................................................... 296 Inflow Performance Curve ........................................ 576
Home .......................................................................... 92 Inflow Performance Relationships (IPRs)
horizontal completion ................................................. 60 Back Pressure equation ........................................ 313
Horizontal completion Bubble point correction ......................................... 325
Inflow Performance options .................................. 580 data file ................................................................. 324
IPRs ...................................................................... 338 Fetkovich's equation ............................................. 311
horizontal distributed geometry profile ....................... 53 Forchheimer equation ........................................... 313
horizontal completions .......................................... 338
Horizontal flow
Jones' equation ..................................................... 312
correlation abbreviations ....................................... 562
oil/water relative permeability ............................... 352
regimes ................................................................. 282
Productivity Index (PI) ........................................... 309
Horizontal flow
Pseudo steady state/Darcy ................................... 314
valid correlations ................................................... 562
solution gas-drive reservoirs ................................. 349
Horizontal flow summary for vertical completions ......................... 308
correlation options ................................................ 561 Transient IPR ........................................................ 319
Horizontal gas wells ................................................. 349 Vogel's equation ................................................... 310
Horizontal Multiphase Flow Correlations .................. 283 Inflow Performance Relationships (IPRs)
horizontal single point geometry profile ...................... 53 Multi-rate data ......................................................... 87
HORWELL keyword ................................................. 580 Inflow Performance Tabulation ................................. 578

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PIPESIM User Guide

Inflow Production Profiles ......................................... 342 undersaturated oil viscosity .................................. 435
INJFLUID keyword ................................................... 609 Kouzel
INJGAS keyword ...................................................... 609 undersaturated oil viscosity .................................. 435
INJPORT keyword .................................................... 607 Kreith ........................................................................ 402
INLET keyword ......................................................... 539
Input data ................................................................. 515
L
Input files .......................................................... 515, 520 Laplace equation ...................................................... 413

Insert .......................................................................... 93 Lasater

correlations ........................................................... 421
Inside Fluid Film Heat Transfer Coefficient .............. 402
solution gas-oil ratio .............................................. 425
Inside forced convection ................................... 372, 402
launching the results viewer ..................................... 238
IPR basis .................................................................... 64
LAYER keyword ....................................................... 582
IPRCRV keyword ..................................................... 576
layers ........................................................................ 255
IPR keyword ............................................................. 570
LBC .......................................................................... 465
IPR see Inflow Performance
Relationships (IPRs) ................................................. 349 Lee method .............................................................. 439

Iteration Data ............................................................ 537 Leviton and Leighton correlation .............................. 474
Library components cubic EoS ............................ 459
J Library components non-cubic EoS ..................... 464
JOB keyword ............................................................ 523 LIBRARY keyword .................................................... 652
Jones data ................................................................ 571 license information ....................................................... 1
Jones Equation ......................................................... 312 light oil + gas ............................................................ 248
JONES keyword ....................................................... 571 Limits ........................................................................ 477
JUNCTION keyword ................................................. 685 Liquid by sphere ....................................................... 304
Liquid-gas surface tension ....................................... 477
K Liquid holdup ............................................................ 304
Kartoatmodjo and Schmidt Liquid loading
correlations ........................................................... 421 equations .............................................................. 307
dead oil viscosity ................................................... 431 Liquid properties ....................................................... 470
live oil viscosity ..................................................... 433 Liquid viscosity
Oil Formation Volume Factor ................................ 428 and oil/water emulsions ........................................ 470
solution gas-oil ratio .............................................. 424 correlations ........................................................... 470
undersaturated oil viscosity .................................. 435 data ....................................................................... 637
KCOAT keyword ....................................................... 628 live oil viscosity ......................................................... 151
Keyword abbreviations ............................................. 517 Live oil viscosity ........................................................ 432
Keywords .................................................................. 675 locating a previously built schematic network
KFLUID keyword ...................................................... 631 on the GIS map ........................................................ 271
Khan looped gas gathering network
live oil viscosity ..................................................... 433 tutorial ..........................................................................

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PIPESIM User Guide

LVIS keyword ........................................................... 637 N

NAPLOT keyword ..................................................... 655
M NAPOINT keyword ................................................... 659
managing bookmarks ............................................... 259 navigating the GIS Map ............................................ 257
managing floating panes ............................................ 16 Network .................................................................... 236
managing flowlines and risers .................................. 251 Network-centric mode ................................................ 22
managing model data ............................................... 240 network keyword (top) .............................................. 186
managing output variable report templates .............. 185 network keywords (bottom) ...................................... 186
managing the catalogs ............................................. 240 network simulations ...................................................... 1
managing zones ....................................................... 253 NIST recommendation for pure fluid / mixture .......... 454
Map cache ................................................................ 261 Nodal Analysis
Map services ............................................................ 261 NAPLOT keyword ................................................. 655
measuring area and distance ................................... 279 NAPOINT keyword ............................................... 659
Mechanical skin ........................................................ 326 node display mode properties .................................. 227
message center .......................................................... 19 NODE keyword ......................................................... 614
MFL File ................................................................... 147 Non-cubic Equations of State ................................... 464
Mixing (Black oil) ...................................................... 442 NOPRINT keyword ................................................... 550
MODEL keyword ...................................................... 652 NOSLIP .................................................................... 288
MOODYCALC keyword ............................................ 565 NSEPARATOR keyword .......................................... 685
moving the entire network to a new map location .... 272 Numeric data ............................................................ 518
MPBOOSTER keyword ............................................ 611
Mukherjee and Brill ................................................... 288 O
MULTICASE keyword ...................................... 659, 664 Oil/water emulsions .................................................. 470
Multiflash .......................................................... 450, 454 Oil/water relative permeability .................................. 352
multiflash BIP sets .................................................... 163 Oil Formation Volume Factor (OFVF)
Multiphase ................................................................ 288 defined .................................................................. 427
saturated systems ................................................. 427
Multiphase booster
undersaturated systems ....................................... 428
efficiencies tables ................................................. 386
Oil reservoirs ............................................................ 308
Multiphase pump
MPUMP keyword .................................................. 612 Oil viscosity
black oil ................................................................. 429
Multiple case ............................................................ 665
undersaturated ...................................................... 434
Multiple injection ports .............................................. 603
oil-water mixtures ..................................................... 152
multiple MFL files ..................................................... 171
oil well performance analysis
Multiple Value Data Sets .......................................... 519
tutorial ................................................................... 692
Multi-rate .................................................................... 87
OLGAS ..................................................................... 288
operating points ........................................................ 197
Operations ................................................................ 654

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PIPESIM User Guide

OPTIMIZE keyword .................................................. 668 Pressure drop

OPTIONS keyword ................................................... 525 effect on productivity ............................................. 338
Orkiszewski .............................................................. 288 for gas ................................................................... 299
multiphase ............................................................ 342
overriding fluid phase ratios ..................................... 174
single phase .......................................................... 341
overriding the default value in a specific row ............ 190
Principle of conservation of energy .......................... 398

P printing a map ........................................................... 280

PRINT keyword ........................................................ 539
panning and zooming in the network diagram ............ 97
productivity index ........................................................ 65
panning and zooming to your map area ................... 257
Progressive cavity pump see PCP ...................... 387
Parameters ............................................................... 522
Property calibration .................................................. 643
PCP .......................................................................... 387
PROP keyword ......................................................... 635
Pedersen .................................................................. 465
Pseudo steady state
Peng-Robinson ......................................................... 450
data for equation ................................................... 571
PERMCRV keyword ................................................. 584
IPR ........................................................................ 314
Permeability .............................................................. 490 productivity ............................................................ 346
PERMTAB keyword .................................................. 585 PS-PLOT keyword .................................................... 665
PETROFRAC keyword ............................................. 653 Pump ........................................................................ 612
Petroleum fractions PUMPCRV keyword ......................................... 593, 619
for Cubic Equations of State ................................. 463
PUMP keyword ......................................................... 617
Petrosky and Farshad
PUSH keyword ......................................................... 552
correlations ........................................................... 421
PVT File .................................................................... 147
dead oil viscosity ................................................... 432
live oil viscosity ..................................................... 432 PVT package ............................................................ 252
solution gas-oil ratio .............................................. 425
undersaturated oil viscosity .................................. 436 R
physical properties ................................................... 186 Ramey model ........................................................... 416
PI RATE keyword ......................................................... 535
equations .............................................................. 309 Reciprocating compressor
Pipe coating ...................................................... 626, 627 overview ................................................................ 369
Pipe dimensions ....................................................... 615 References ............................................................... 499
PIPE keyword ........................................................... 615 REFPROP ................................................................ 454
Pipeline registering user defined equipment ................ 10, 39, 43
burial ..................................................................... 632 registering user flow correlations .................................. 9
standard sizes ....................................................... 483 REINJECTOR keyword ............................................ 620
PIPESIM modes ......................................................... 22 Relative permeability ................................................ 352
PLOTFILEDATA keyword ........................................ 553 Remote action editing ............................................... 552
PLOT keyword .......................................................... 547 Reservoir
Plotting options ......................................................... 547 layer properties ..................................................... 582

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PIPESIM User Guide

simulation data ...................................................... 666 Frac pack .............................................................. 335

RESERVOIR keyword .............................................. 584 gravel pack ........................................................... 330
reservoir pressure ...................................................... 64 partial penetration ................................................. 329
perforated well ...................................................... 331
reservoir temperature ................................................. 64
Slug .......................................................................... 557
resolving intel MPI incompatibility .............................. 12
Slug calculation ........................................................ 556
Richardson correlation ............................................. 470
Slug catcher ............................................................. 557
RODPUMP keyword ......................................... 596, 621
SLUG keyword ......................................................... 556
Roughness ............................................................... 488
Soave-Redlich-Kwong .............................................. 450
running a network simulation .................................... 208
Solution gas-oil ratio ................................................. 422
running a nodal analysis ........................................... 197
SOURCE keyword .................................................... 680
running a p/t profile ................................................... 191
Sources .................................................................... 236
running a system analysis ........................................ 224
SPHASE keyword .................................................... 564
S Standing
correlations ........................................................... 421
saving a VFP table to a file ....................................... 207
Oil Formation Volume Factor ................................ 428
selecting a standard unit system .................................. 7
solution gas-oil ratio .............................................. 425
SEPARATOR keyword ............................................. 621
startup options .............................................................. 1
setting wellstream inlet ............................................. 141
Statements ............................................................... 516
setting wellstream outlet ........................................... 140
static reservoir pressure ............................................. 64
SETUP keyword ....................................................... 676
Steady State Heat Transfer ...................................... 399
Shapefiles ................................................................. 261
Steady-State productivity ......................................... 343
showing the map legend .......................................... 279
Steam ....................................................................... 418
simple network model on the GIS map
Study ........................................................................ 236
tutorial ..........................................................................
subsea tieback design
simulation task with result record ............................. 236
tutorial ..........................................................................
single branch keywords ............................................ 186
Suggested flow correlations ..................................... 294
single branch simulations ............................................. 1
Surface tension
Single component system ........................................ 186 black oil ................................................................. 440
Single phase flow ..................................................... 564 liquid gas ............................................................... 477
Single phase flow correlations .................................. 296 water-gas .............................................................. 440
Single phase gas critical pressure ratio .................... 360 Swap angle ............................................................... 301
single point completions .................................................. Symbols glossary ..................................................... 492
SINK keyword ........................................................... 683 system analysis ...............................................................
Skin factor SYSTEM DATA keyword .......................................... 588
damaged zone ...................................................... 330 System Profile .......................................................... 522
deviation ............................................................... 329
equations .............................................................. 326

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T Vasquez and Beggs

TABLE keyword ........................................................ 666 correlations ........................................................... 421
Oil Formation Volume Factor ................................ 428
TCOAT keyword ....................................................... 627
solution gas-oil ratio .............................................. 426
Tees ......................................................................... 492
undersaturated oil viscosity .................................. 434
temperature energy balance .................................... 186
VCORR keyword ...................................................... 557
Thermal conductivities .............................................. 488
Vertical completion
Thermal conductivity ................................................ 631 IPRs ...................................................................... 308
thermal interpolation method .................................... 186 Vertical flow
three types of layers ................................................. 261 correlation abbreviations ....................................... 559
TIME ......................................................................... 670 regimes ................................................................. 281
TPRINT keyword .............................................. 642, 654 valid correlations ................................................... 558
Transient IPR VCORR keyword .................................................. 557
equations .............................................................. 319 Vertical flow
TRANSIENT keyword ............................................... 587 multiphase flow correlations ................................. 288

Tubing vertical geometry profile ............................................. 53

standard sizes ....................................................... 478 vfp sensitivity properties ........................................... 206
Turner's equation ...................................................... 307 vfp setting properties ................................................ 206
tutorials ..................................................................... 692 vfp table properties ................................................... 206
Typical values ........................................................... 487 viewing a built-in fluid template ................................ 248
viewing a built-in well template ................................. 250
U viewing or editing a custom fluid template ................ 249
undersaturated oil viscosity ...................................... 150 viewing or editing a custom well template ................ 250
Undersaturated oil viscosity ..................................... 434 viewing profile direction ............................................ 276
Units viewing surface equipment properties ...................... 142
description string ................................................... 518 Viscosity
UNITS keyword ..................................................... 524 dead oil ................................................................. 430
USERDLL keyword .......................................... 554, 566 models for compositional fluids ............................. 465
using a map cache ................................................... 268 viscosity properties ................................................... 159
using map services ................................................... 264 Vogel
using shapefiles ........................................................ 263 equation ................................................................ 310
using user defined flow correlations ........................... 10 VOGEL keyword ................................................... 570
Vogel IPR ................................................................. 314
V Volume ratio ............................................................. 470
validation .................................................................... 19
Valve W
FITTING keyword ................................................. 600 water ......................................................................... 248
typical values ........................................................ 490 Water-gas surface tension ....................................... 440
Vand correlations ..................................................... 470 water ratio ................................................................. 252

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water ratio type ......................................................... 252

Wax
overview ................................................................ 468
WAX keyword ........................................................... 670
WCOPTION keyword ............................................... 573
Well
completion data .................................................... 573
Wellbore
heat transfer between well and rock ..................... 416
Well-centric mode ....................................................... 22
WELLHEAD keyword ............................................... 622
WELL PERFORMANCE MODELING keyword ........ 566
WELLPI keyword ...................................................... 569
Well Productivity ....................................................... 569
Wells ......................................................................... 236
Woelflin correlation ................................................... 470
working with the GIS Map ........................................ 255
Workspace ................................................................. 92
WPCURVE keyword ................................................. 570

Z
zooming to a specific map coordinate or address .... 258

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