Group One Drilling Project 2018
Group One Drilling Project 2018
Group One Drilling Project 2018
Our gratitude goes to God Almighty for making this project a success.
We also wish to acknowledge Mr. Francis Fusier and all lecturers of IPS for the knowledge impacted
to us, their patience and dedication towards us have brought us thus far. To the Management and Staff
of the Institute of Petroleum Studies (IPS), we say thank you.
Our appreciation goes to all the team members for their contribution to the success of the project.
i
EXECUTIVE SUMMARY
The report contains an elaborate and detailed design and specifications for well COD SE 1A a deviated
development well which aims to produce 1,200,000 stm3/D of gas per day in the COD field in the
Norwegian side of the North Sea, Norway. The water depth is 72 meters and the rig proposed and
eventually selected as adequate for the purpose is the Maersk Gallant Jackup Rig.
Formation data was obtained from the appraisal well 10/30-6 drilled previously in same field. Pore
pressures, Leak-Off pressures and formations to be encountered are already known. H2S is not present
in this location. There is also no expectation of shallow gas. The gas production would be channelled
to the COD central production station (12 kms away).
The design was carried out based on the use of a 4-1/2” Liner which has an hydraulically set packer for
completions, a Tubing conveyed Perforation method was used Underbalanced to perforate. Choice of
completion equipment was selected based on an expected flow rate of 1,200,000stm3/D. The casings
to be used to complete this project are 20” 106.5# surface casing to a depth of 610mTVD, 13-3/8”
68# Intermediate casing one to a depth of 1500mTVD, 9-5/8” 43.5#intermediate casing two to a
depth of 2500mTVD and a production casing of 7”29# to a 3250mTVD.
This report contains the Wells’ architecture, mud, cement and casing design, the operational drilling
program, the completion design with running procedures and intervention methods (if required in the
late life of the well) for both the vertical and directional wells and the forecasted progress charts for the
wells until the end of completion. All possible justifications and assumptions made during the course
of the study were also highlighted.
The project will be executed and completed in 44 days asides and unforeseen conditions and the cost
would be about 3,054,754.31 USD.
It is noteworthy to state that the project is HSE compliant.
ii
LIST OF FIGURES
iii
LIST OF TABLES
iv
Table 6.30:- Summary of cement calculations ..................................................................................... 77
Table 6.31:- Component and Additives of the cement slurry ............................................................... 77
Table 6.32: Basic Information of the Production Casing ..................................................................... 78
Table 6.33:- Summary of Drilling String Parameters for Phase 4 ........................................................ 79
Table 6.34:- Drilling Parameters (Bit Type) ......................................................................................... 80
Table 6.35:- Showing the calculation of the drill string weight ........................................................... 81
Table 6.36: Showing the Pressure Loss calculation.............................................................................. 84
Table 6.37:- Production Casing: Results of Mud Volume Calculations .............................................. 88
Table 6.38: 8 1/2” Hole: Principal Additives for Saturated Salt Mud .............................................. 89
Table 6.39:- Typical Properties of the Saturated Salt Mud .................................................................. 89
Table 6.40:- Summary of cement calculations ..................................................................................... 89
Table 6.41:- Additives for cement slurry .............................................................................................. 90
Table 6.42:- Cost estimation of the project ......................................................................................... 102
Table C-1: Summary of Results- Mud calculations a) Surface casing b) Intermediate Casing 1 c)
Intermediate Casing 2 d) Production Casing ..................................................................................... 119
Table C-2:- Mud Pump Requirement a) Surface casing b) Intermediate Casing 1 c) Intermediate
Casing 2 d) Production Casing .......................................................................................................... 123
v
TABLE OF CONTENTS
ACKNOWLEDGEMENT ....................................................................................................................... i
EXECUTIVE SUMMARY ....................................................................................................................ii
LIST OF FIGURES ...............................................................................................................................iii
LIST OF TABLES ................................................................................................................................. iv
TABLE OF CONTENTS ....................................................................................................................... vi
CHAPTER 1 ........................................................................................................................................... 1
GENERAL DATA .................................................................................................................................. 1
1.1 Data about the block & license ..................................................................................................... 1
1.2 Field Development Concepts ........................................................................................................ 1
1.3 Location Map ................................................................................................................................ 2
CHAPTER 2 ........................................................................................................................................... 3
GEOLOGICAL PROGRAMME ............................................................................................................ 3
2.1 Purpose of the wells ...................................................................................................................... 3
2.1.1 Objectives .............................................................................................................................. 3
2.1.2 Results of appraisal wells....................................................................................................... 3
2.1.3 Structure ................................................................................................................................. 4
2.1.4 Reservoir ................................................................................................................................ 4
2.1.5 Stratigraphic Prognosis Description ...................................................................................... 4
2.1.6 Pressure prognosis data: Formation pressure and fracture gradients ..................................... 9
2.1.7 Formation Temperature Prognosis ....................................................................................... 10
2.2 Formation Evaluation Programme .............................................................................................. 10
2.2.1 Conventional mud logging ................................................................................................... 10
2.2.2 MWD ................................................................................................................................... 11
2.2.3 Cuttings analysis and Coring ............................................................................................... 11
2.2.4 Wire Line Logging ............................................................................................................... 11
2.2.5 DST ...................................................................................................................................... 11
CHAPTER 3 ......................................................................................................................................... 12
vi
DRILLING HAZARDS ........................................................................................................................ 12
3.1 Environment And Waste Management ....................................................................................... 12
CHAPTER 4 ......................................................................................................................................... 19
WELL DESIGN .................................................................................................................................... 19
4.1 Well Architecture with Casing’s Design .................................................................................... 19
4.2 General Considerations ............................................................................................................... 22
4.3 Recap of Rules for Casing Design .............................................................................................. 23
4.4 Casing Calculations .................................................................................................................... 25
4.5 Tubing Design ............................................................................................................................. 29
CHAPTER 5 ......................................................................................................................................... 31
WELL TRAJECTORY ......................................................................................................................... 31
5.1 Planned trajectory to meet target ................................................................................................ 31
5.2 Measured Depth Estimation ........................................................................................................ 33
5.3 Trajectory Control ....................................................................................................................... 34
CHAPTER 6 ......................................................................................................................................... 37
DRILLING OPERATIONS .................................................................................................................. 37
6.1 Phase 1 – Conductor Casing (30”) .............................................................................................. 37
6.2 Phase 2 – Surface Casing (26” Hole Section) ............................................................................. 37
6.2.1 Purpose of this phase ........................................................................................................... 38
6.2.2 Possible Challenges ............................................................................................................. 38
6.2.3 Barriers ................................................................................................................................. 38
6.2.4 Drilling Procedure ................................................................................................................ 38
6.2.5 Kick-off Procedure............................................................................................................... 39
6.2.6 Drill Strings .......................................................................................................................... 39
6.2.7 Drilling Parameters .............................................................................................................. 39
6.2.8 Power Requirement .............................................................................................................. 43
6.2.9 Drilling Fluids ...................................................................................................................... 47
6.2.10 Fast line Tension ................................................................................................................ 50
6.2.11 Cementing .......................................................................................................................... 51
6.3 Phase 3 – Intermediate Casing 1 (17-1/2” Hole Section) ........................................................... 52
vii
6.3.1 Purpose of this phase ........................................................................................................... 52
6.3.2 Possible Challenges ............................................................................................................. 53
6.3.3 Barriers ................................................................................................................................. 53
6.3.4 Drilling Procedure ................................................................................................................ 53
6.3.5 Kick-off Procedure............................................................................................................... 53
6.3.6 Drill Strings .......................................................................................................................... 54
6.3.7 Drilling Parameters .............................................................................................................. 54
6.3.8 Power Requirement .............................................................................................................. 57
6.3.9 Drilling Lines ....................................................................................................................... 62
6.3.10 Drilling Fluids .................................................................................................................... 62
6.3.11 Cementing Procedure ......................................................................................................... 64
6.4 Phase 4 – Intermediate Casing 2 (12-1/4” Hole Section) ........................................................... 66
6.4.1 Purpose of this phase ........................................................................................................... 66
6.4.2 Possible Challenges ............................................................................................................. 66
6.4.3 Barriers ................................................................................................................................. 66
6.4.4 Drilling Procedure ................................................................................................................ 66
6.4.5 Kick-off Procedure............................................................................................................... 67
6.4.6 Drill Strings .......................................................................................................................... 67
6.4.7 Drilling Parameters .............................................................................................................. 67
6.4.8 Power Requirement .............................................................................................................. 70
6.4.9 Drilling Fluids ...................................................................................................................... 75
6.4.10 Cementing Programme ...................................................................................................... 77
6.5 Phase 4 –Production Casing 2 (8-1/2” Hole Section) ................................................................. 78
6.5.1 Purpose of this phase ........................................................................................................... 79
6.5.2 Possible Challenges ............................................................................................................. 79
6.5.3 Barriers ................................................................................................................................. 79
6.5.4 Drilling Procedure ................................................................................................................ 79
6.5.5 Kick-off Procedure............................................................................................................... 79
6.5.6 Drill Strings .......................................................................................................................... 79
6.5.7 Drilling Parameters .............................................................................................................. 80
viii
6.5.8 Power Requirement .............................................................................................................. 82
6.5.9 Drilling Lines ....................................................................................................................... 87
6.5.10 Power Requirement at end of Phase .................................................................................. 88
6.5.11 Drilling Fluids .................................................................................................................... 88
6.5.12 Cementing Programme ...................................................................................................... 89
CHAPTER 7 ......................................................................................................................................... 91
WELL COMPLETIONS ...................................................................................................................... 91
7.1 Overview ..................................................................................................................................... 91
7.1.1 Running and Testing Procedure ........................................................................................... 92
7.2 Perforation Strategy .................................................................................................................... 95
7.2.1 Completion and Packer fluid ............................................................................................... 95
7.3 Wellhead type and rating ............................................................................................................ 96
7.4 Running and Testing Procedure .................................................................................................. 97
7.4.1 The following checks should be carried out on all threaded joints of the tube ................... 97
7.4.2 The following procedures should be carried out on the wellbore before running the tubing
....................................................................................................................................................... 97
7.4.3 The following techniques and equipment should be used in running the tube to the correct
depth .............................................................................................................................................. 98
7.4.4 Installing the Christmas tree ................................................................................................ 98
7.4.5 Well clean up ....................................................................................................................... 99
7.4.6 Perforation............................................................................................................................ 99
7.4.7 Cleaning the well after perforation ...................................................................................... 99
7.5 Future Interventions .................................................................................................................. 100
7.6 Project timing and costing ........................................................................................................ 102
APPENDIX A : CASING DESIGN ................................................................................................... 106
Surface Casing ................................................................................................................................ 106
Intermediate Casing 1 ..................................................................................................................... 106
Intermediate casing 2 ...................................................................................................................... 107
Production casing ............................................................................................................................ 107
APPENDIX B: DRILL STRING CALCULATIONS ........................................................................ 108
ix
APPENDIX C: MUD CALCULATIONS .......................................................................................... 118
APPENDIX D: CEMENTING PROGRAMME ................................................................................ 126
30” and 20” Casing Section (Surface Casing): Cementing to the mudline ................................ 126
20” and 13 3/8” Casing Section (Intermediate Casing I): ........................................................... 129
13 3/8” and 9 5/8” Casing Section (Intermediate Casing II): ..................................................... 133
9 5/8” and 7” Casing Section (Production Casing):.................................................................... 137
x
CHAPTER 1
GENERAL DATA
The COD field is situated in the Norwegian side of the North Sea, in block 10/30 at 150 km South
West of Stavanger (Norway). Water depth is 72 meters. The reservoir situated in the late Palaeocene
Forties Fan System. Gas and Condensate have already been produced from the COD Field.
1
Y = 6 310,909.00
Water depth = 72 meters
Height of jacket upper deck: 15.0 m above sea level.
Estimated distance MSL-RKB = 55 m
Conductor pipes OD 30” (ID = 28.75 “) will be driven and fully cemented at depth of 160 m MSL after
jacket installation (before rig positioning)
2
CHAPTER 2
GEOLOGICAL PROGRAMME
2.1.1 Objectives
The appraisal wells drilled in the COD Field had the following objectives:
• To primarily explore the reservoir extent.
• To refine the reservoir characteristics, heterogeneity and quality and other reservoir features.
• To accurately determine the reservoir interval and thickness.
• To enhance knowledge of the reservoir structure.
• To obtain reservoir fluids for analysis and tests.
The well COD S-E 1A is a deviated well (J well) to produce gas from the forties formation. Its objective
is to be optimized to produce 1,200,000 stm3/D of gas.
3
Appraisal well 10/30-6 encountered the top of the Forties reservoir sands at 2 890 m MSL and drilled
85 m of gross sand thickness. After RFT measurements, the well was found gas bearing (fluid gradient
of 0.35 g/cc) down to the base of the reservoir at 2957 m and no hydrocarbon to water contact was
observed.
Two DST were performed and DST 2 flowed at a rate of 1.500 000 Sm3/d of gas associated with 153
Sm3/d of condensate through a 40/64" choke. The reservoir pressure is 376 bars at 2 912 m MSL, giving
a gradient of 1.30 EMW. This gradient is considered constant on all the structure.
The reservoir consists of thin sand bodies (1 to 3 m) inter-bedded with thin shale stringers (0,5 to 1 m).
Some of the reservoir layers are stacked and constitute more massive sandy units (up to 12 m). Electrical
logging shows that the so-called "thin beds" effect is influencing the reading of the tools, particularly
for the resistivity measurement. Those sands are fine to medium grained, and well sorted. Core
descriptions and electrical log patterns, where typical fining upward Bouma sequences can be seen,
clearly indicate that the reservoir bodies have been deposited as distal lobes of a turbiditic system. The
petrophysical characteristics show relatively low average porosity (16 %) and permeability (20 to 30
mD) associated with a 50 % net/gross. Both N/G and porosity are in the range of what is usually found
in very distal turbidites. This is consistent with the location of the well close to the pinch-out area where
the reservoir starts.
2.1.3 Structure
COD gas condensate field lies in the southern area of the Norwegian sector of the North Sea, in block
7/11, 280km southwest of the Norwegian coast. The field is also situated in the North Sea Central
graben, 46mi (75km) north-northwest of the giant Ekofisk field (rank 98, after Carmalt and St. Johns,
1986) and a half mile (1km) east of the median line between the English and Norwegian sectors. The
water depth in the area is 230ft (70 m). COD was discovered in 1968, and the plan for development
and operation (PDO) was approved in 1973.
2.1.4 Reservoir
The COD field produces gas and condensate from the upper Paleocene sandstone of deep marine distal
turbiditic origin, located at a depth of 9400ft (2870m) subsea. The deposit has a complex structure with
several separate reservoirs at the depth of 3,000 metres. It is expected to produce more than 280 bcf of
gas and 17 million barrels of condensate. It can be further described in the table below:
The lithological prognosis for the shallow part of the wells will be adjusted / corrected in accordance
with the results of the site survey.
72 m – 122 m : Soft silty clay overlain by thin sand layer of less than 1 meter.
122 m – 220 m : Fine sand interbedded with stiff to firm clay.
220 m – 250 m: Stiff clay.
250 m – 512 m : Consolidated stiff clay with minor sand layers. Possible coarser material at the base
of the unit (base of channel).
512 m – 620 m: Hard sandy clay with layers of sand and silt.
5
3 010 m – 3 025m: Balder Fm. Claystone, varicoloured, dominantly medium – dark grey greenish and
brownish, silty, traces of tuff.
3 025 m – 3 085 m: Sele Fm. Claystone, grey - greenish grey, stringers of limestone, traces of sandstone.
3085 m – 3195 m: Forties Fm. Sandstone, light grey – light brown, very fine-fine, subangular, well
sorted, thin beds/stringers of shale, light grey, silty, sandy traces of lignite.
3195 m – 3275 m Lista Fm. Claystone, grey – becoming green - greenish grey, occasionally brick red,
stringers of sandstone.
3275m – 3 310 m (3 275 msec): Vâle Fm. Interbedded limestone, muddy, chalky, locally silty,
claystone, grey, very calcareous and marl grey.
6
7
Figure 1.1:- Lithology of COD S-E 1A
8
2.1.6 Pressure prognosis data: Formation pressure and fracture gradients
The prognosis is based on results from the discovery well 10/30-6. The prognosed gradients are quoted
in SG units of EMW, and are presented in figure 1.3 (reference level is MSL).
Nordland Group (72- 1 615 m)MSL
From seabed down to approximately 1420 m normal pressure conditions are expected. The lower part
of Nordland Group, from approx. 1420 – 1615 m is most likely representing the upper part of an
approximately 1 000 m thick undercompacted zone. The pressure gradient at base Nordland is
prognosed to be 1.40 g.cc EMW.
Hordaland Group (1615 - 3010 m)
The undercompacted zone, starting at approximately 1 466 m in Nordland Group, extends down to
about 2424 m. Maximum of undercompaction is expected between 1760 and 1860 m. In this interval,
the pressure gradient is prognosed to be in the range 1.50 – 1.55 g/cc EMW (maximum pressure
gradient: 1.57 g/cc EMW, minimum pressure gradient: 1.45 g/cc EMW).
From 1860 m down to base Hordaland, the pressure gradient should gradually drop to 1.30 – 1.35 g/cc
EMW.
Rogaland Group (3010- 3310 m)
Maximum pressure gradient at the top of the Forties reservoir should be 1.30 g/cc EMW (1.33 g/cc
EMW subsea), assuming a water gradient through the reservoir. Minimum pressure gradient at top
reservoir should be 1.30 g/cc EMW (1.31 g/cc EMW subsea) assuming the same gas-condensate
gradient as in well 10/30-6; 0.038 bar/m.
At base Rogaland Group, the pressure gradient is expected to be in the range 1.29 –1.32 g/cc EMW.
Shetland Group (3310 – 3355 m)
Pressure gradient is expected to be same as for base of Rogaland Group: 1.29 – 1.30 g/cc EM
Frac Pressure
The following LOT were made during exploration and appraisal phases:-
Table 1.1:- LOT for appraisal well
9
3040 m 1.95
3120 m 1.96
10
2.2.2 MWD
MWD with GR/Resistivity/Directional will be used after piling in the 30”Conductor Pipe down to
160m. In the reservoir, LWD will be considered depending of borehole conditions.
2.2.5 DST
A drill stem test (DST) is a procedure for isolating and testing the pressure, permeability and productive
capacity of a geological formation during the drilling of a well. It is a key method of obtaining
information on the formation fluid and establishing whether a well has found a commercial
hydrocarbon reservoir.
11
CHAPTER 3
DRILLING HAZARDS
This chapter present potential hazards that may be encountered during while drilling through the
formation from the surface to the desired depth. The hazards are determined by dividing the formation
into zones. Each zone is considered a node. Hazards relating to each node are listed. The identified
nodes comprise:
• Node 1: Pleistocene – Holocene Nodland Group (72 m – 620 m)–
• Node 2: Miocene – Pliocene Nodland Group (620 m – 1 615 m)
• Node 3: Eocene – Oligocene – Miocene Hordaland Group: 1 615 (+/-15 m) – 3 010 m (+/-20
m)
• Node 4: Rogaland Group: 3 010 (+/-20 m) – 3 310 m (+/-40 m)
The risk register in table 3.1 contains the identified causes, consequences and proposed barriers
associated with each hazard scenario.
12
Onshore disposal – cuttings and the associated fluids are collected and transported for
treatment if necessary and final disposal.
13
Table 3.1:- Risk register for the drilling operation
14
Hazard Events Description of Node Causes Consequences Controls
620 m – 780 m: Sandy clay with
interbeds of sand.
780 m – 922 m: Claystone with
minor sand interbeds.
4 Formation collapse
922 m – 962 m: Clay, silty-sandy. • Using appropriate
• Loss of tools
962 m – 1 615 m: Claystone, • Incompatibility of drilling mud.
• Damage to
greenish, slightly silty, thin shale/clay with drilling • Consistent
equipment
stringers of limestones, traces of mud, under compacted cuttings sampling.
• Injury to personnel
pyrite. zones, etc • Adopting best
• Environmental spill
620 m – 1 420 m: Normal pressure drilling practices.
Mud losses in under conditions are expected.
5
compacted zones 1 420 m - 2 410 m: Expected
under compacted shale section
(1.45 – 1.6 g/cc EMW) .
Node 3: Eocene – Oligocene – Miocene Hordaland Group: 1 615 (+/-15 m) – 3 010 m ( +/-20 m)
15
Hazard Events Description of Node Causes Consequences Controls
1615 m – 1 854 m: Claystone,
brown-greyish, moderate silty,
stringers of limestones.
1 854 m – 1 950 m:
Claystone/siltstone, light grey –
brown moderate silty, sand, very
fine-fine.
• Using
1 950 m – 2992 m: Claystone,
• Loss of tools appropriate
light-dark brown, moderate silty, • Incompatibility of
• Damage to drilling mud.
stringers of dolomite, limestones shale/clay with drilling
6 Formation collapse equipment • Consistent
and sand, traces of mica, organic mud, under compacted
• Injury to personnel cuttings sampling.
material, pyrite and microfossils. zones, etc
• Environmental spill • Adopting best
1760m - 1860 m: under
drilling practices.
compaction is expected (1.45g/cc -
1.57 g/cc EMW)
1860 m - 2992 m: 1.30 – 1.35 g/cc
EMW.
1 420 m - 2 410 m: Expected
under compacted shale section
(1.45 – 1.6 g/cc EMW) .
16
Hazard Events Description of Node Causes Consequences Controls
Mud losses in under
7
compacted zones
Node 4: Rogaland Group: 3 010 (+/-20 m) – 3 310 m (+/-40 m)
3010 m – 3025m: Balder Fm.
Claystone, varicoloured,
• Incompatibility of
dominantly medium – dark grey
8 Damage of payzone shale/clay with drilling
greenish and brownish, silty, traces
mud, etc
of tuff. • Install and testing
3025 m – 3085 m: Sele Fm. • Loss of reservoir BOP.
Claystone, grey - greenish grey, • Blowout and fire if •Using appropriate
Uncontrolled release of stringers of limestone, traces of ignited drilling mud.
9 • High formation pressure
hydrocarbon (gas or oil) sandstone. • Damage to • Install and testing
3085 m – 3195 m: Forties Fm. equipment BOP.
Sandstone, light grey to light • Injury/ death to • Consistent
brown, very fine-fine, subangular, personnel cuttings sampling.
well sorted, thin beds/stringers of • Balling of bits due to • Environmental spill • Adopting best
shale, light grey, silty, sandy traces sticky clay. drilling practices.
10 Drilling equipment failure
of lignite. • Differential sticking of
3195 m – 3275 m Lista Fm. drill string.
Claystone, grey – becoming green -
greenish grey, occasionally brick
17
Hazard Events Description of Node Causes Consequences Controls
red, stringers of sandstone.
3275m – 3 310 m (3 275 msec):
Vâle Fm. Interbedded limestone,
muddy, chalky, locally silty,
claystone, grey, very calcareous
and marl grey.
At base Rogaland Group, the
pressure gradient is expected to be
in the range 1.29 – 1.32 g/cc
EMW.
Note: H2S have not been encountered during exploration and appraisal. C02 level is expected to be very low (Less than 0.2%
volume). Hence, safety precautions against should be taken such as the use of gas detectors while drilling.
18
CHAPTER 4
WELL DESIGN
The well COD SE-1A is a vertical well optimized to produce gas at a rate of 1200000 Sm3/day
from the forties formation, based on the information obtained from the appraisal wells; Casing
shoe depths were selected based on the lithological constraints as shown and in obedience to the
casing design rules. Casing is tubing that is set inside the drilled well to protect and support the
wellstream (Rigzone, 2014).
19
Depth vsEMW
0 0.5 1 1.5 2 2.5
0
500
1000
Pore pressure
1500
frac pressure
Swab pressure
Surge pressure
2000 Mud Weight
2500
3000
3500
20
0 100 200 300 400 500 600 700
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
Pore Pressure
1600
1700 Frac Pressure
1800 swab margin
1900 surge margin
2000
hydrostatic pressure
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
21
The size of the tubing with the capacity to produce 1200000 Sm3/day of gas was selected first and
informed the choice of the production casing. Hence casing selection was done from down
upwards and the schematic is shown in Figure 4.2 below.
The type of casing (linear weight, diameter, grade, connection) was selected based on technical
considerations.
22
• Determination of optimum casing size at various intervals to ensure that the required tubing
size is feasible.
• Calculations of maximum pressure constraints (burst, collapse and tensile) on the casing
during operations and selection of casings accordingly.
For the platform wells, the Conductor Casing (30” welded) will be driven while installing the
jacket. Drilling/Completion department indicated the type of Casing (steel, thickness..) with
minimum position of Conductor Casing extremity.
It is very important to control the verticality of the Conductor Casing.
Rule 2: With the exception of deep water wells, the casing point on intermediate casings shall be
designed for the following assumptions:
“Well full of gas”:
On exploration/appraisal wells as fluid, pressures, and formation weak points are not well known,
On development gas wells which can be temporarily abandoned with possible alteration of the
hydraulic barrier (for example, subsea wells or wells drilled from jack-up or platform rigs with
possible crew evacuation due to hurricanes): over time, fluid could replace mud in the hole leading
to a cross flow situation.
On shallow development gas wells: open-hole volumes are small and no more compatible with
standard admissible kick volume.
“Unlimited kick”:
On all development wells except those mentioned above (if in accordance with local legislation).
23
Rule 3: Minimum limited kick to be considered for casing design shall be 10 m3 on fixed
installations; this minimum value should be increased in the event of downgraded conditions or in
sensitive areas.
Rule 4: With respect to the above, the collapse design factor is set at:
1.125 for surface, intermediate and test casings,
1.125 for cemented part of these casing,
1.125 for production casing, cemented or not.
Load lines to be considered include:
• Cementing operations.
• Floated casing while running.
• Partial evacuation.
• Full evacuation.
• Perforation blockage conditions.
Rule 5: For the above reasons, the burst design factor is set at 1.10.
Load lines to be considered include:
• Bullheading a well full of gas.
• Limited oil and gas kick.
• Bullheading over a surface tubing leak.
• Artificial lift.
• Thermal expansion of trapped fluid.
Rule 7: The triaxial design factor is set at 1.25; collapse shall be checked separately.
Rule 8: On HT wells (bottom hole temperature > 150°C) and/or if safety factors are close to design
factors, a derating on the minimum yield (relating to 20°C) must be applied.
A derating factor of 0.07 %/°C above 20°C on yield is a mean value for all steel grades. If necessary
more accurate figures can be supplied by equipment manufacturers.
24
4.4 Casing Calculations
1) 30’’ Conductor Pipe/Casing
No calculations were made for this phase as the conductor pipe was driven when installing the
platform to refusal to a depth of 160m.
Purpose
• To set the 30” CP at refusal depth.
• Protection of subsequent casings and isolation from seawater.
• Seal off unconsolidated formations at shallow depths.
• Stop washouts under the drilling rig.
• Protection of fresh water sands.
• To provide a good base and support for the next string of casing.
The 24” casing design follows thereafter.
2) 20’’ Surface Casing at 610m
Purpose
• Support other casings
• Protection of portable water aquifer
• Support the wellhead and BOP equipment’s
• Case unconsolidated formations
Collapse study
Worst case: During Cementing
Differential pressure at 610m = 43.03bar
Safety factor = 1.125
Final collapse constraint = 48.41 bar
Burst study
Worst case: After cementing mud weight increases
Pore pressure at 610m = 72 bar
Pore pressure at the shoe =86.12bar
Safety factor = 1.3
Final burst constraint = 18.36bar
Selected casing
25
The selected casing based on the burst and collapse calculations:
20”, 106.5 lb/ft, K55, Drift diameter=18.8” Coupling type Buttress Standard
Tension study
Casing shoe depth 1500m, mud density for the next phase 1.44
Tmax (Buttress standard) = 749KdaN
𝑇=𝑛𝑜𝑟𝑚𝑖𝑛𝑎𝑙 𝑤𝑒𝑖𝑔ℎ𝑡 ×𝑏𝑢𝑜𝑦𝑎𝑛𝑐𝑦 𝑓𝑎𝑐𝑡𝑜𝑟 ×𝑙𝑒𝑛𝑔ℎ𝑡
0.85 × 155.4 × 610
𝑊𝑚 = = 80.57𝐾𝑑𝑎𝑁
1000
Maximum pull=(𝑇𝑚𝑎𝑥⁄𝑊𝑚) > 1.6 :- 749⁄80.57 = 9.296
Tension: Safety Factor= 9.296 > 1.6 Satisfied.
3) 13-3/8’’ Intermediate Casing
Purpose
• Seal off weaker zones.
• Protect previous casing strings from higher Burst Pressure
Collapse study
Worst case: Partial emptying due to thief zone
Differential pressure at top of mud column, 975.6m = 118bar
Safety factor = 1.125
Final collapse constraint = 132.75 bar
Burst study
Worst case: Well full of gas and bull heading
Gas SG = 0.2g/cc3
Pore pressure at 1500m = 202 bar
Hydrostatic column of gas=49bar
Bull heading pressure = 35 bar
Safety factor = 1.3
Final burst constraint = 410.8 bar
Selected casing
26
The selected casing based on the burst and collapse calculations:
13-3/8”, 68 lb/ft, RT95, Drift diameter=12.27” Coupling type Buttress Standard
Tension study
Casing shoe depth 1500m, mud density for the next phase 1.44
Tmax (Buttress standard) = 788KdaN
Wm=95.14Kda𝑁
Maximum pull=(𝑇𝑚𝑎𝑥⁄𝑊𝑚) > 1.6 :- 788⁄95.14 = 8.28
Tension: Safety Factor= 8.28 > 1.6 Satisfied.
4) 9-5/8 ‘’ Intermediate Casing
Purpose
• Seal off weaker zones.
• Protect previous casing strings from higher Burst Pressure
Collapse study
Worst case: Partial emptying due to thief zone
Differential pressure at top of mud column, 860.3m = 138.323bar
Safety factor = 1.125
Final collapse constraint = 155.613 bar
Burst study
Worst case: Well full of gas and bull heading
Gas SG = 0.20g/cc3
Pore pressure at 3250m = 330 bar
Hydrostatic column of gas=63.7bar
Bull heading pressure = 35 bar
Safety factor = 1.3
Final burst constraint = 391.7 bar
Selected casing
The selected casing based on the burst and collapse calculations:
9-5/8’’, 43.5 lb/ft, L80, Drift diameter=8.6” Coupling type Vallourec VAM TOP
27
Tension study
Casing shoe depth 2500m, mud density for the next phase 1.64
Tmax (Buttress standard) = 447KdaN
Wm=86.4𝐾𝑑𝑎𝑁
Maximum pull=(𝑇𝑚𝑎𝑥⁄𝑊𝑚) > 1.6 :- 447⁄86.4 = 5.18
Tension: Safety Factor= 5.18 > 1.6 Satisfied.
5) 7” Production Casing
Purpose
• To drill through the payzone.
Collapse study
Worst case: Complete emptying below the packer
Pore pressure at 3250m = 418 bar
Safety factor = 1.125
Final collapse constraint = 470.3 bar
Burst study
Worst case: Well full of gas and tubing leak
Gas SG = 0.20g/cc3
Pore pressure at 3250m = 418 bar
Hydrostatic column of gas=63.7bar
Bull heading pressure = 35 bar
Safety factor = 1.3
Final burst constraint = 506.1bar
Selected casing
The selected casing based on the burst and collapse calculations:
7’’, 29 lb/ft, L80, Drift diameter=6.1” Vallourec VAM TOP
Tension study
Casing shoe depth 3250m, mud density for the next phase 1.36
Tmax (Buttress standard) = 301KdaN
Wm=70.29𝐾𝑑𝑎𝑁
28
Maximum pull=(𝑇𝑚𝑎𝑥⁄𝑊𝑚) > 1.6 :- 301⁄70.29 = 4.282
Tension: Safety Factor= 4.282 > 1.6 Satisfied.
Since our production casing is 7” with a drift ID=6.1” we resorted to using a WRSCSSSV (OD=5.748”)
as against TRSCSSSV (OD=6.92”) and a Baker SSD Circulating Valve (3.75”ID) was used as well.
Collapse Constraint = 295 bar
Tubing length = 3050m
Tension safety factor = 1.6
Tubing estimated maximum tension
=3050m x 18.39daN/m x 1.6 = 89.7kdaN
This tension can be handled by Grade N80 tubing
• Nominal tubing diameter: 4 ½”.
• Nominal Weight: 12.6lb/ft.
29
• Inside diameter: 3.958”.
• Drift: 3.833
Coupling
Vallourec and Mannesmann VAM PRO
Efficiency: 100%
Make-up torque: 600 daN.m
LOT Pore
Shoe OD Drift Weig Tensio Top of at pressu
Burst Collapse
Casing Depth( (Inche ID Thread Grade ht n cement shoe re
(bar) (bar)
m MSL) s) (in) (lb/ft) (kdaN) (m) (EM (EMW
W) )
Surface 610 20 18.8 API K55 106.5 18.36 48.41 749 NA 1.54 1.18
casing
Intermediate 1500 13 12.25 Buttress RT95 68 410.8 132.75 788 472.4 1.74 1.44
casing 1 3/8
Intermediate 2500 9 5/8 8.6 Buttress L80 43.5 391.7 155.6 447 301.54 1.81 1.64
casing 2
Production 3250 7 6.1 Vallourec VAM L80 29 506.1 470.3 301 600 1.88 1.36
casing TOP
Tubing NA 4½ 3.83 Vallourec N80 12.6 499 295 89.7 NA NA NA
VAM PRO
30
CHAPTER 5
WELL TRAJECTORY
Mudline 72 72 0
Kickoff 620 620 0
End of Build 932.1 950 92.44
End of Slant 2
3195 3648.2 1561.98
(Bottom of Reservoir)
31
Horizontal Displacement (m)
-200 0 200 400 600 800 1000 1200 1400 1600 1800
0
500
True Vertical Depth (mss)
1000
1500
2000
2500
3000
3500
32
1000.000
800.000
Distance Northwards
600.000
400.000
200.000
0.000
-200.000 0.000 200.000 400.000 600.000 800.000 1000.000 1200.000
-200.000
Distance Eastwards
33
IC2 Shoe 2500 2819.5 1110.7
Target 3250 3713.78 1597.7
951m
1145m
34
ΠiR
𝐿𝐸 = 𝑍𝐾 +
180
𝐿𝐸 = 950𝑚
35
𝑇𝑉𝐷 = 1500𝑚
ΠiR (TVD − 𝑇𝑉𝐷𝐸 )
𝑀𝐷 = 𝑍𝐾 + +
180 cos 𝑖
𝑀𝐷 = 1627.14𝑚
Intermediate Casing 2:
𝑇𝑉𝐷 = 2500𝑚
ΠiR (TVD − 𝑇𝑉𝐷𝐸 )
𝑀𝐷 = 𝑍𝐾 + +
180 cos 𝑖
𝑀𝐷 = 2819.5𝑚
Production Casing:
𝑇𝑉𝐷 = 3250𝑚
ΠiR (TVD − 𝑇𝑉𝐷𝐸 )
𝑀𝐷 = 𝑍𝐾 + +
180 cos 𝑖
𝑀𝐷 = 3713.8𝑚
36
CHAPTER 6
DRILLING OPERATIONS
Drilling of wells require several operations which include planning and layout of procedures for
the drilling phases, hole sizes, weight on bit, drill strings, collars, bits selection, mud Pumping,
barriers used, casing and cementing.
The summary of the phases are highlighted in the table below.
Depth
Hole Size Casing Size
Phase No Casing Name Interval
(in) (in)
(m) MSL
1 Conductor - 30 0 -160
2 Surface 26 20 160 - 610
3 Intermediate 1 17-1/2 13-3/8 610 - 1500
4 Intermediate 2 12-1/4 9-5/8 1500 - 2500
5 Production 8-1/2 7 2500 – 3250
37
Table6.2:- Basic Information of the Surface Casing
6.2.3 Barriers
No BOP stack is needed to drill this phase. A Diverter should however be installed to handle the
high concentration of background gas that might be present within the 450 – 550m MSL interval.
Barriers needed are:
• Diverter
• Inside BOP
• Gray Valve
Note: Always ensure the driller is aware of the wind direction so the correct overboard line can be
lined up as necessary.
38
• No coring activity for this section
Linear OD OD ID Cumulative
Length
Element Grade Weight No Max Body Body Length
(m)
(Kg/m) (in) (in) (in) (m)
IADC
- 1 26 - - - -
Roller Cone Bit CODE: 525
Bit sub + Float
- - 1 - 9 - - -
Valve
Stabilizer - - 3 - 25.75 - - -
MWD - - 1 - - - - -
Non- Magnetic Drill
- 323.18 5 - 9-1/2 3 9.144 45.72
Collar
Drill Collar API SPEC 323.18 2 - 9-1/2 3 9.144 18.288
Hydraulic Jar API SPEC - 1 - 9-1/2 3 - -
Drill Collar API SPEC 218.77 1 - 8 3 9.144 9.144
HWDP NC 50 74.67 1 - 5 3 9.144 9.144
G105 NC 50
32.55 64 - 5 4.276 9.144 585.216
Drill Pipe (XH)
39
• Maximum Overpull
• WOB
Using
𝑃×𝑄 1
𝑃𝐻𝑃 = ×
450
Where
40
P= Stand pipe pressure in bar = 7500psi = 517.098bar
Q= Flowrate in l/min
η = pumping efficiency (90%)
Making use of two pumps and allowing one to be on standby, the combined horsepower will be
4400hp.
Calculating the flowrate that will be achieved by the pump
𝑃𝐻𝑃 ∗ 450 ∗
𝑄=
𝑃
4400 ∗ 450 ∗ 0.9
𝑄=
517.098
𝑄 = 3446.155 𝑙/𝑚𝑖𝑛
The flowrate achieved by the pump is smaller than the required for good hole cleaning, therefore
we will have to stop at various intervals to clean the hole.
Using
𝐹𝑅
𝑉=
38.71 ∗ 𝑇𝐹𝐴
Where
FR= Flow rate in liters/min
V= Mud Velocity meters/sec
TFA = Total Flow area, 𝒊𝒏𝟐
Making use of a mud velocity of 120m/s
𝐹𝑅
𝑇𝐹𝐴 =
38.71 ∗ 𝑉
3446.155
𝑇𝐹𝐴 =
38.71 ∗ 120
𝑇𝐹𝐴 = 0.74187 𝒊𝒏𝟐
From DDH E11 we choose a drilling Bit of 3 (Three) nozzles 18/32 inch each, having a total area
of 0.7255 𝒊𝒏𝟐 . (18-18-18)
41
Table 6.5:- Showing the calculation of the drill string weight
Linear
Length Total Weight
Weight Buoyancy Factor Total Weight (kg)
(m) (T)
(Kg/m)
Drill Collar 323.18 73.152 0.85 23641.26336 23.64126336
Drill Collar 218.77 9.144 0.85 2000.43288 2.00043288
HWDP 74.67 9.144 0.85 682.78248 0.68278248
Drill Pipe 32.55 585.216 0.85 19048.7808 19.0487808
Total = 45.37325952
6.2.7.4 WOB
Since this phase is very soft
1
𝑊𝑂𝐵 ≈ 𝑎 𝑡𝑜𝑛 𝑝𝑒𝑟 𝑖𝑛𝑐ℎ 𝑜𝑓 𝑏𝑖𝑡 𝑖𝑛 𝑠𝑜𝑓𝑡 𝑓𝑜𝑟𝑚𝑎𝑡𝑖𝑜𝑛
2
0.5𝑡𝑜𝑛𝑠
→ 𝑊𝑂𝐵 = 26′′ × = 13𝑡𝑜𝑛𝑠
𝑖𝑛𝑐ℎ
42
𝑐𝑜𝑛𝑣𝑒𝑟𝑡𝑖𝑛𝑔 𝑡ℎ𝑒 𝑊𝑂𝐵 𝑡𝑜 𝑑𝑎𝑁;
𝑑𝑎𝑁
𝑊𝑂𝐵 = 13 × 0.981 × 1000
𝑘𝑔
∴ 𝑊𝑂𝐵 = 12,753𝑑𝑎𝑁 = 𝟏𝟐. 𝟕𝟓𝟑𝒌𝒅𝒂𝑵
DP – L2, L5
DC – L3, L4
𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝐿𝑜𝑠𝑠, Pr = (𝑁 + 𝐿2 𝑁2 + 𝐿3 𝑁3 + 𝐿4 𝑁4 + 𝐿5 𝑁5 ) × 𝐵 + 𝑝𝑑 𝑑
𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝐿𝑜𝑠𝑠, Pr = (𝑁 + 𝐿2 𝑁2 + 𝐿′2 𝑁3 +𝐿3 𝑁3 + 𝐿4 𝑁4 + 𝐿′5 𝑁5 + 𝐿5 𝑁5 ) × 𝐵 + 𝑝𝑑 𝑑
𝑃𝑑 = 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑑𝑟𝑜𝑝 𝑖𝑛 𝑛𝑜𝑧𝑧𝑙𝑒𝑠 𝑓𝑜𝑟 𝑑 = 1, (𝑘𝑃𝑎)
𝑘𝑔⁄
𝑑 = 𝑠𝑝𝑒𝑐𝑖𝑓𝑖𝑐 𝑔𝑟𝑎𝑣𝑖𝑡𝑦, ( 𝑙)
𝑁1 = 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑙𝑜𝑠𝑠 𝑐𝑜𝑒𝑓𝑓𝑖𝑐𝑖𝑒𝑛𝑡 𝑖𝑛 𝑡ℎ𝑒 𝑠𝑢𝑟𝑓𝑎𝑐𝑒 𝑒𝑞𝑢𝑖𝑚𝑒𝑛𝑡, (𝑘𝑃𝑎⁄100𝑚)
43
𝑁2 = 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑙𝑜𝑠𝑠 𝑐𝑜𝑒𝑓𝑓𝑖𝑐𝑖𝑒𝑛𝑡 𝑖𝑛 𝑡ℎ𝑒 𝑑𝑟𝑖𝑙𝑙 𝑝𝑖𝑝𝑒𝑠, (𝑘𝑃𝑎⁄100𝑚)
Nozzle 18-18-19
N1 426.1541 kPa/100m G30
N2 267.46 kPa/100m G41
N3 1324.3 kPa/100m G46
N4 1 kPa/100m G62
N5 1 kPa/100m G67
L2 585.216 m
L2' 9.144 m
L3 73.152 m
L4 73.152 m
44
L5' 9.144 m
L5 585.216 m
Pd 8000.3 Kpa G52
d 1.2
B 2.11 G24
Case: 3
Q 3446.155 l/min
Ptotal= 16115.82 Kpa
Pumping requirement:
• Assuming a volumetric efficiency ηv=0.97
• Assuming a mechanical efficiency ηm=0.90
Hydraulic power =
𝑃×𝑄
𝑃𝐻𝑃 (ℎ𝑝) =
44750
16115.82 × 3446.155
𝑃𝐻𝑃 (ℎ𝑝) =
44750
𝑃𝐻𝑃 (ℎ𝑝) = 1241.1 ℎ𝑝
𝐻𝑦𝑑𝑟𝑎𝑢𝑙𝑖𝑐 𝑃𝑜𝑤𝑒𝑟
Mechanical Power= 𝜂𝑚
1241.1
=
0.9
= 1378.96 ℎ𝑝
45
𝐹×𝑉 1
𝑃𝐻𝑃 = ×
77.5
Where:
F, Total Hoisted Weight (String + Block +Hook + Over pull)
V, Pulling up Speed, meters/sec
, Overall Hoisting Efficiency
Assumptions
Weight of 25 Tons for Block + Hook,
Speed of 0.3 meters/second
Using 12 lines and roller bearing, we obtain a reeving efficiency of 0.782 (DDH F3)
From previous calculations,
String load in air = 44.5 Tons
Margin of Over pull = 139.24𝑇
Therefore:
F = 45.4+25+139.24𝑇
F = 184.64 Tons (184.64 X103 kg)
184.64 × 103 × 0.3 1
𝑃𝐻𝑃 = ×
77.5 0.782
𝑃𝐻𝑃 = 913.7 𝐻𝑃
46
Minimum Torque for a 5” X 4.276” Drill Pipe with nominal weight of 32.55 kg/m is (connection
= API, NC 50).
Minimum Make up Torque = 2,969 daN.m DDH B22
Using a safety factor of 80%,
𝐶 = 0.8 × 2969
𝐶 = 2375.2 𝑑𝑎𝑁. 𝑚
47
Depth : 160m – 610m measured depth
Section length drilled : 450m
Drilled well volume : 154,138.14 litres
Required total mud : 291,195.21litres
volume
48
Table 6.8:- 26” Hole: Principal Additives for Sea Water and Spud Mud
Concentration, Quantity
Additive Function
lb/bbl Needed (kg)
Bentonite 30 Viscosity, filtration control 24,945.93
Seawater/freshwater 1 831.53
Lime 1 Flocculent 831.53
Caustic soda pH to 10.0
Source: Amoco Production Company drilling fluids manual
Parameter Value
Mud weight 1.44
Plastic viscosity 16 – 18 cP
Yield point 10- 14 (lb/100 ft2)
API Filtrate 6-10 cm3
Funnel Viscosity 70 - 130 sec
Source: Amoco Production Company drilling fluids manual
Where;
𝐷 = liner diameter of stroke (in)
49
𝐿 = length of stroke (in)
𝑛 = maximum speed of pump (strokes/min)
𝑒 = efficiency of pump
Two pumps will be used to drill each phase. Each will run at 50% output. The third pump will
serve as backup for the rig.
Pump data (each):
Name - 3 X LTV Emsco FC-2200
Description - Single acting triplex driven by 2 each Hi-
torque DC motors
Maximum rated Horsepower
(hp) - 2,200
Length of stroke (in) - 10
Maximum liner diameter of
stroke (in) - 9
Strokes per minute
(strokes/min) - 150
Suction Connection (in) - 12
Discharge Connection - 5-1/8" 5,000 psi Flange
Gear Ratio - 3.512:1
Valve Pot: - API #8
Approximate Weight (ibs) - 64,815
Efficiency of pump - 0.90
Pump output @50% (l/stroke) 19.70
Pump circulation rate (l/min) 2,068.25
Where;
F = Hook Load
50
N = Number of lines
ηm = reeving efficiency
165.3019
𝑇𝑓𝑙 =
0.782 ∗ 12
𝑇𝑓𝑙 = 17.6 𝑡𝑜𝑛𝑛𝑒𝑠
6.2.11 Cementing
Cemented Length in conductor casing = 160m MSL less water depth of 72m = 88m
51
After having run the 20 ‘’ casing, cementing procedure is;
• Pump 10 m3 of spacer of 1.23 S.G.
• Pump 105.80 m3 Class G lead slurry 1.28 S.G.
• Pump 12.70 m3 Class G Tail slurry 1.54 S.G.
• Displace cement with 93.44 m3 of 1.44 S.G. mud
Cement Composition: G cement + Chemical wash +Dispersant +Retarder +Bentonite+ FLAC
For Lead cement, 40.22 tons is mixed with 91.71m3 Fresh water with 4% pre-hydrated
Bentonite.
For Tail cement, 9.82 tons is used mixed with 9.49 m3 Fresh water with 2.5% pre-hydrated
Bentonite.
The section will involve directional drilling through the Nordland group, the section is planned to
have a build-up of 33.0ᵒ, having the kick-off point at 620m MSL. The casing shoe will be placed
at 1500m TVD MSL (1627.2m MD MSL).
A rotary steerable system will be used to drill this section to enable the kick-off at 620m MSL and
a building inclination of 1.0ᵒ/10m up to a depth of 932.078m TVD MSL (950m MD MSL), the
52
drilling thereafter will continue on a tangent (slant) to the section TD of 1500m TVD MSL
(1627.2m MD MSL). The section will be drilled with Synthetic based Mud (SBM).
6.3.3 Barriers
The drilling fluid (1.44 SG, WBM) will be the primary control; A Blow out Preventer will be
installed to control the borehole pressure from the underlying formation.
53
6.3.6 Drill Strings
Linear OD OD ID Cumulative
Length
Element Grade Weight No Max Body Body Length
(m)
(Kg/m) (in) (in) (in) (m)
Roller Cone Bit IADC CODE: 535 - 1 17-1/2 - - - -
Motor/ Bit sub + Float
- - 1 - 9 - - -
Valve
Stabilizer - - 3 - 17.25 - - -
MWD - - 1 - - - - -
Non- Magnetic Drill
- 323.18 5 - 9-1/2 3 9.144 45.72
Collar
Drill Collar API SPEC 323.18 3 - 9-1/2 3 9.144 27.432
Hydraulic Jar API SPEC - 1 - 9-1/2 - -
Drill Collar API SPEC 218.77 1 - 8 3 9.144 9.144
HWDP NC 50 74.67 1 - 5 3 9.144 9.144
Drill Pipe G105 NC 50 (XH) 32.55 174 - 5 4.276 9.144 1591.056
54
IADC Code 535
Using
𝑃×𝑄 1
𝑃𝐻𝑃 = ×
450
Where
P= Stand pipe pressure in bar = 7500psi = 517.098bar
Q= Flowrate in l/min
η = pumping efficiency (90%)
Making use of two pumps and allowing one to be on standby, the combined horsepower will be
4400hp.
Calculating the flowrate that will be achieved by the pump
𝑃𝐻𝑃 ∗ 450 ∗
𝑄=
𝑃
55
4400 ∗ 450 ∗ 0.9
𝑄=
517.098
𝑄 = 3446.155 𝑙/𝑚𝑖𝑛
The flowrate achieved by the pump is smaller than the required for good hole cleaning; therefore
we will have to stop at various intervals to clean the hole.
Using
𝐹𝑅
𝑉=
38.71 ∗ 𝑇𝐹𝐴
Where
FR= Flow rate in liters/min
V= Mud Velocity meters/sec
TFA = Total Flow area, 𝒊𝒏𝟐
Making use of a mud velocity of 110m/s
𝐹𝑅
𝑇𝐹𝐴 =
38.71 ∗ 𝑉
3446.155
𝑇𝐹𝐴 =
38.71 ∗ 110
𝑇𝐹𝐴 = 0.8093 𝒊𝒏𝟐
From DDH G56 we choose a drilling Bit of 3 (Three) nozzles 18-19-19, having a total area of
0.8023 𝒊𝒏𝟐 .
Linear
Length Buoyancy Total Total Weight
Weight
(m) Factor Weight (kg) (T)
(Kg/m)
Drill Collar 323.18 82.296 0.817 26596.42128 26.59642128
Drill Collar 218.77 9.144 0.817 2000.43288 2.00043288
HWDP 74.67 9.144 0.817 682.78248 0.68278248
Drill Pipe 32.55 1591.056 0.817 51788.8728 51.7888728
Total = 81.06850944
56
MOP = Maximum Tension on DP – weight of Drill String
Weight of Drill String in mud = (DC weight + HWDP weight + DP weight) * buoyancy factor
Total Drill stem Weight =81.06 Tonnes
Weight of Drill String in mud = 81.06 Tonnes * 0.817 = 66.23Tonnes
Tensile Yield Strength on DP = 193.8kdaN DDH B15
𝑆𝑎𝑓𝑒𝑡𝑦 𝑓𝑎𝑐𝑡𝑜𝑟 = 90%
≈ 0.9
𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑇𝑒𝑛𝑠𝑖𝑜𝑛 = 𝑇𝑒𝑠𝑖𝑙𝑒 𝑦𝑖𝑒𝑙𝑑 𝑠𝑡𝑟𝑒𝑛𝑔𝑡ℎ × 𝑆𝑎𝑓𝑒𝑡𝑦 𝑓𝑎𝑐𝑡𝑜𝑟
= 0.9 𝑥 193.8
= 174.42 𝑘𝑑𝑎𝑁
≈ 177.8𝑇
Maximum Overpull = 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑇𝑒𝑛𝑠𝑖𝑜𝑛 − Total Drillstem Weight
= 177.8𝑇 − 81.06 𝑇
= 96.74𝑇
57
DP – L2, L5
HWDP – L2’,
L5 ’
DC – L3, L4
𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝐿𝑜𝑠𝑠, Pr = (𝑁 + 𝐿2 𝑁2 + 𝐿3 𝑁3 + 𝐿4 𝑁4 + 𝐿5 𝑁5 ) × 𝐵 + 𝑝𝑑 𝑑
𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝐿𝑜𝑠𝑠, Pr = (𝑁 + 𝐿2 𝑁2 + 𝐿′2 𝑁3 +𝐿3 𝑁3 + 𝐿4 𝑁4 + 𝐿′5 𝑁5 + 𝐿5 𝑁5 ) × 𝐵 + 𝑝𝑑 𝑑
𝑃𝑑 = 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑑𝑟𝑜𝑝 𝑖𝑛 𝑛𝑜𝑧𝑧𝑙𝑒𝑠 𝑓𝑜𝑟 𝑑 = 1, (𝑘𝑃𝑎)
𝑘𝑔⁄
𝑑 = 𝑠𝑝𝑒𝑐𝑖𝑓𝑖𝑐 𝑔𝑟𝑎𝑣𝑖𝑡𝑦, ( 𝑙)
𝑁1 = 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑙𝑜𝑠𝑠 𝑐𝑜𝑒𝑓𝑓𝑖𝑐𝑖𝑒𝑛𝑡 𝑖𝑛 𝑡ℎ𝑒 𝑠𝑢𝑟𝑓𝑎𝑐𝑒 𝑒𝑞𝑢𝑖𝑚𝑒𝑛𝑡, (𝑘𝑃𝑎⁄100𝑚)
58
𝐿3 = 𝐼𝑛𝑡𝑒𝑟𝑛𝑎𝑙 𝑙𝑒𝑛𝑔𝑡ℎ 𝑜𝑓 𝐷𝐶 𝑠𝑒𝑐𝑡𝑖𝑜𝑛, (100𝑚)
𝐿4 = 𝐸𝑥𝑡𝑒𝑟𝑛𝑎𝑙 𝑙𝑒𝑛𝑔𝑡ℎ 𝑜𝑓 𝐷𝐶 𝑝𝑖𝑝𝑒 𝑠𝑒𝑐𝑡𝑖𝑜𝑛, (100𝑚)
𝐿′5 = 𝐸𝑥𝑡𝑒𝑟𝑛𝑎𝑙 𝑙𝑒𝑛𝑔𝑡ℎ 𝑜𝑓 𝐻𝑊𝐷𝑃 𝑑𝑟𝑖𝑙𝑙 𝑝𝑖𝑝𝑒 𝑠𝑒𝑐𝑡𝑖𝑜𝑛, (100𝑚)
𝐿5 = 𝐸𝑥𝑡𝑒𝑟𝑛𝑎𝑙 𝑙𝑒𝑛𝑔𝑡ℎ 𝑜𝑓 𝐷𝑟𝑖𝑙𝑙 𝑝𝑖𝑝𝑒 𝑠𝑒𝑐𝑡𝑖𝑜𝑛, (100𝑚)
Typically Plastic viscosity is about twice of mud weight in pounds per gallon
Therefore:
𝑃𝑉 = 2 × 1.44 × 8.33
𝑷𝑽 = 𝟐𝟑. 𝟗𝟗 𝑪𝒑
Nozzle 18-18-19
N1 426.1541 kPa/100m G30
N2 267.46 kPa/100m G41
N3 1324.3 kPa/100m G46
N4 1 kPa/100m G62
N5 1 kPa/100m G67
L2 1591.056 m
L2' 9.144 m
L3 82.296 m
L4 82.296 m
L5' 9.144 m
L5 1591.056 m
Pd 10779 Kpa G52
d 1.44
B 2.53 G24
Case: 3
Q 3446.155 l/min
Ptotal= 30472.43 Kpa
Pumping requirement:
• Assuming a volumetric efficiency ηv=0.97
• Assuming a mechanical efficiency ηm=0.90
59
6.3.8.1 Hydraulic Power
Hydraulic power =
𝑃×𝑄
𝑃𝐻𝑃 (ℎ𝑝) =
44750
30472.43 × 3446.155
𝑃𝐻𝑃 (ℎ𝑝) =
44750
𝑃𝐻𝑃 (ℎ𝑝) = 2346.65 ℎ𝑝
6.3.8.1.1 Mechanical Power
𝐻𝑦𝑑𝑟𝑎𝑢𝑙𝑖𝑐 𝑃𝑜𝑤𝑒𝑟
Mechanical Power= 𝜂𝑚
2346.65
=
0.9
= 2607.39 ℎ𝑝
Where:
F, Total Hoisted Weight (String + Block +Hook + Over pull)
V, Pulling up Speed, meters/sec
, Overall Hoisting Efficiency
Assumptions
Weight of 25 Tons for Block + Hook,
Speed of 0.3 meters/second
Using 12 lines and roller bearing, we obtain a reeving efficiency of 0.782 (DDH F3)
From previous calculations,
String load in air = 81.06 Tons
Margin of Over pull = 96.74 𝑇𝑜𝑛𝑛𝑒𝑠
60
Therefore:
F = 81.06+25+96.74
F = 202.8 Tons (202.8 X103 kg)
202.8 × 103 × 0.3 1
𝑃𝐻𝑃 = ×
77.5 0.782
𝑃𝐻𝑃 = 1003.9 𝐻𝑃
Where
C, Torque (daN.m)
, Rotating Efficiency (0.9)
𝐶 = 𝑆𝑎𝑓𝑒𝑡𝑦 𝐹𝑎𝑐𝑡𝑜𝑟 × 𝑀𝑖𝑛𝑖𝑚𝑢𝑚 𝑇𝑜𝑟𝑞𝑢𝑒
The minimum torque is obtained from DDH B22
Minimum Torque for a 5” X 4.276” Drill Pipe with nominal weight of 32.55 kg/m is (connection
= API, NC 50).
Minimum Make up Torque = 2,969 daN.m DDH B22
Using a safety factor of 80%,
𝐶 = 0.8 × 2969
𝐶 = 2375.2 𝑑𝑎𝑁. 𝑚
61
6.3.8.4 Total Power Requirement
62
Table 6.17:- 13 3/8 ” Hole: Results of Mud Volume Calculations
Quantity
Concentration,
Additive Function Needed
lb/bbl slurry
(kg)
Bentonite 20 Viscosity, filtration control 25,486.74
Lignosulfonate 4 Deflocculant 5,097.35
Gypsum 4 Inhibition, alkalinity control 5,097.35
Caustic Soda pH 9.5 - 11.0 Alkalinity control
Caustic Potash Inhibition, alkalinity control
DESCO (sulfonated tannin) Deflocculant 2,548.67
Starch 4 Filtration control 5,097.35
63
Viscosity (increase in yield 318.58
PAC 0.25
point), Filtration Control
Barite 190 Weighting agent 242,124.03
Source: Amoco Production Company drilling fluids manual
Parameter Value
Mud weight 1.44
Plastic 15-20 cP
viscosity
Yield point 2-15 (lb/100 ft2)
API Filtrate 6-8 cm3
pH 2-3
Source: Amoco Production Company drilling fluids manual
6.3.10.2Kick Control
Kick is controlled by adopting the driller’s method;
𝑆𝐼𝐷𝑃𝑃×10.2 (3)
𝐾𝑖𝑙𝑙𝑀𝑢𝑑 𝑊𝑡. = 𝑃𝑟𝑒𝑣𝑖𝑜𝑢𝑠 𝑚𝑢𝑑 𝑤𝑡 + +
𝑑
64
Table 6.21:- Component and Additives of the cement slurry
65
For Lead cement, 76.82 tons is mixed with 74.19 m3 Fresh water with 2.5% pre-hydrated
Bentonite.
For Tail cement, 6.12 tons is mixed 3.79 m3 Fresh water with 0.75% pre-hydrated Bentonite.
6.4.3 Barriers
The drilling fluid (1.64 SG, WBM) will be the primary control; A Blow out Preventer will be
installed to control the borehole pressure from the underlying formation.
66
• No coring activity for this section
• This is a slant section of the well, therefore we limit the deviation of the well to 1ᵒ from the
trajectory
Linear OD ID Cumulative
OD Max Length
Element Grade Weight No Body Body Length
(in) (m)
(Kg/m) (in) (in) (m)
Roller Cone Bit IADC CODE: 725 - 1 12-1/4 - - - -
Bit sub + Float Valve - - 1 - 9 - - -
Stabilizer - - 3 - 12-1/4 - - -
MWD - - 1 - - - - -
Non- Magnetic Drill
- 323.18 5 - 9-1/2 3 9.144 45.72
Collar
Drill Collar API SPEC 323.18 6 - 9-1/2 3 9.144 54.864
Hydraulic Jar API SPEC - 1 - 7.75 - - -
Drill Collar API SPEC 323.18 1 - 8 3 9.144 9.144
HWDP NC 50 74.67 1 - 5 3 9.144 9.144
Drill Pipe G105 NC 50 (XH) 32.55 302 - 5 4.276 9.144 2761.488
67
6.4.7.1 Bit type
The Bit selection is made based on the nature of the formations to be encountered. The drill bit
parameters are shown below
Using
𝐹𝑅
𝑉=
38.71 ∗ 𝑇𝐹𝐴
Where
FR= Flow rate in liters/min
V= Mud Velocity meters/sec
TFA = Total Flow area, 𝒊𝒏𝟐
Making use of a mud velocity of 100m/s
1881
𝑇𝐹𝐴 =
38.71 ∗ 𝑉
1881
𝑇𝐹𝐴 =
38.71 ∗ 100
𝑇𝐹𝐴 = 0.48592 𝒊𝒏𝟐
68
From DDH G56 we choose a drilling Bit of 3 (Three) nozzles 14-14-15, having a total area of
0.4732 𝒊𝒏𝟐 .
Linear
Length Buoyancy Total Total Weight
Weight
(m) Factor Weight (kg) (T)
(Kg/m)
Drill Collar 323.18 100.584 0.791 32506.73712 32.50673712
Drill Collar 218.77 9.144 0.791 2000.43288 2.00043288
HWDP 74.67 9.144 0.791 682.78248 0.68278248
Drill Pipe 32.55 2761.488 0.791 89886.4344 89.8864344
Total = 125.0763869
Maximum Overpull (MOP)
MOP = Maximum Tension on DP – weight of Drill String
Weight of Drill String in mud = (DC weight + HWDP weight + DP weight) * buoyancy factor
Total Drill stem Weight =125.1 Tonnes
Weight of Drill String in mud = 125.1 Tonnes * 0.791 = 98.95 Tonnes
Tensile Yield Strength on DP = 193.8kdaN
𝑆𝑎𝑓𝑒𝑡𝑦 𝑓𝑎𝑐𝑡𝑜𝑟 = 90%
≈ 0.9
𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑇𝑒𝑛𝑠𝑖𝑜𝑛 = 𝑇𝑒𝑠𝑖𝑙𝑒 𝑦𝑖𝑒𝑙𝑑 𝑠𝑡𝑟𝑒𝑛𝑔𝑡ℎ × 𝑆𝑎𝑓𝑒𝑡𝑦 𝑓𝑎𝑐𝑡𝑜𝑟
= 0.9 𝑥 193.8
= 174.42 𝑘𝑑𝑎𝑁
≈ 177.8𝑇
Maximum Overpull = 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑇𝑒𝑛𝑠𝑖𝑜𝑛 − Total Drillstem Weight
= 177.8𝑇 − 98.95 T
= 78.85𝑇
6.4.7.4 WOB
69
𝑡𝑜𝑛𝑠
→ 𝑊𝑂𝐵 = 12 − 1/4′′ × 2 𝑥 cos 33.06 = 20.53𝑡𝑜𝑛𝑠
𝑖𝑛𝑐ℎ
𝑐𝑜𝑛𝑣𝑒𝑟𝑡𝑖𝑛𝑔 𝑡ℎ𝑒 𝑊𝑂𝐵 𝑡𝑜 𝑑𝑎𝑁;
𝑑𝑎𝑁
𝑊𝑂𝐵 = 20.53 × 0.981 × 1000
𝑘𝑔
∴ 𝑊𝑂𝐵 = 20134𝑑𝑎𝑁 = 𝟐𝟎. 𝟏𝟑𝟒𝒌𝒅𝒂𝑵
DP – L2, L5
DC – L3, L4
𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝐿𝑜𝑠𝑠, Pr = (𝑁 + 𝐿2 𝑁2 + 𝐿3 𝑁3 + 𝐿4 𝑁4 + 𝐿5 𝑁5 ) × 𝐵 + 𝑝𝑑 𝑑
70
𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝐿𝑜𝑠𝑠, Pr = (𝑁 + 𝐿2 𝑁2 + 𝐿′2 𝑁3 +𝐿3 𝑁3 + 𝐿4 𝑁4 + 𝐿′5 𝑁5 + 𝐿5 𝑁5 ) × 𝐵 + 𝑝𝑑 𝑑
𝑃𝑑 = 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑑𝑟𝑜𝑝 𝑖𝑛 𝑛𝑜𝑧𝑧𝑙𝑒𝑠 𝑓𝑜𝑟 𝑑 = 1, (𝑘𝑃𝑎)
𝑘𝑔⁄
𝑑 = 𝑠𝑝𝑒𝑐𝑖𝑓𝑖𝑐 𝑔𝑟𝑎𝑣𝑖𝑡𝑦, ( 𝑙)
𝑁1 = 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑙𝑜𝑠𝑠 𝑐𝑜𝑒𝑓𝑓𝑖𝑐𝑖𝑒𝑛𝑡 𝑖𝑛 𝑡ℎ𝑒 𝑠𝑢𝑟𝑓𝑎𝑐𝑒 𝑒𝑞𝑢𝑖𝑚𝑒𝑛𝑡, (𝑘𝑃𝑎⁄100𝑚)
Nozzle 14-14-15
N1 136.34 kPa/100m G30
N2 90.1 kPa/100m G40
N3 445.02 kPa/100m G45
N4 36.24 kPa/100m G62
N5 2 kPa/100m G67
L2 2761.488 m
L2' 9.144 m
71
L3 109.728 m
L4 109.728 m
L5' 9.144 m
L5 2761.488 m
Pd 5917 Kpa G48
d 1.64
B 2.89 G26
Case: 3
Q 1881 l/min
Ptotal= 19092.40027 Kpa
Pumping requirement:
• Assuming a volumetric efficiency ηv=0.97
• Assuming a mechanical efficiency ηm=0.90
The Maersk Gallant rig has 3 pumps (3 X LTV Emsco FC – 2200) single acting with a power of
2200HP rated for 7500psi.
Taking an overall pumping efficiency of 90% (η= 0.9)
Using
𝑃×𝑄 1
𝑃𝐻𝑃 = ×
450
Where
P= Stand pipe pressure in bar
Q= Flowrate in l/min
η = pumping efficiency (90%)
72
6.3.8.2 Hydraulic Power
Hydraulic power =
𝑃×𝑄
𝑃𝐻𝑃 (ℎ𝑝) =
44750
19092.40027 × 1881
𝑃𝐻𝑃 (ℎ𝑝) =
44750
𝑃𝐻𝑃 (ℎ𝑝) = 802.52 ℎ𝑝
𝐻𝑦𝑑𝑟𝑎𝑢𝑙𝑖𝑐 𝑃𝑜𝑤𝑒𝑟
Mechanical Power= 𝜂𝑚
802.52
=
0.9
= 891.7 ℎ𝑝
Where:
F, Total Hoisted Weight (String + Block +Hook + Over pull)
V, Pulling up Speed, meters/sec
, Overall Hoisting Efficiency
Assumptions
Weight of 25 Tons for Block + Hook,
Speed of 0.3 meters/second
Using 12 lines and roller bearing, we obtain a reeving efficiency of 0.782 (DDH F3)
From previous calculations,
String load in air = 125.1 Tons
Margin of Over pull = 78.85 𝑇𝑜𝑛𝑛𝑒𝑠
73
Therefore:
F = 125.1 +25+78.85
F = 228.95 Tons (228.95 X103 kg)
230.054 × 103 × 0.3 1
𝑃𝐻𝑃 = ×
77.5 0.782
𝑃𝐻𝑃 = 1133.32 𝐻𝑃
Where
C, Torque (daN.m)
, Rotating Efficiency (0.9)
𝐶 = 𝑆𝑎𝑓𝑒𝑡𝑦 𝐹𝑎𝑐𝑡𝑜𝑟 × 𝑀𝑖𝑛𝑖𝑚𝑢𝑚 𝑇𝑜𝑟𝑞𝑢𝑒
The minimum torque is obtained from DDH B22
Minimum Torque for a 5” X 4.276” Drill Pipe with nominal weight of 32.55 kg/m is (connection
= API, NC 50).
Minimum Make up Torque = 2,969 daN.m DDH B22
Using a safety factor of 80%,
𝐶 = 0.8 × 2969
𝐶 = 2375.2 𝑑𝑎𝑁. 𝑚
74
6.4.8.6 Total Power Requirement
2nd Intermediate
Measured Parameter
Hole
Volume
Total drill string volume (l) 25,533.56.91
Total Annular volume (l) 226,220.11
75
Total circulating volume (l) 251,753.67
Mud pit volume @ 50% of total circulating volume (l) 125,876.84
Total volume needed (l) 377,630.51
Circulating Time- 2 pumps@ 50% each
Total pump output ((l/stroke) 39.40
Total pump circulation rate (l/min) 4,136.49
Total circulation time (min) 60.86
Table 6.28:- 9 5/8 ”Hole: Principal Additives for Inhibitive Gypsum Polymer Mud
Quantity
Concentration,
Additive Function Needed
lb/bbl slurry
(kg)
Bentonite 20 Viscosity, filtration control 21,503.70
Lignosulfonate 4 Deflocculant 4,300.74
Gypsum 4 Inhibition, alkalinity control 4,300.74
Caustic Soda pH 9.5 - 11.0 Alkalinity control
Caustic Potash Inhibition, alkalinity control
DESCO (sulfonated
Deflocculant 2,150.37
tannin)
Starch 4 Filtration control 4,300.74
Viscosity (increase in yield
PAC 0.25 268.80
point), Filtration Control
As required for
Barite Weighting agent 263,420.36
density
Source: Amoco Production Company drilling fluids manual
76
Table 6.29:- Typical Properties of the Inhibitive Gypsum Polymer Mud
Parameter Value
Mud weight 1.64
Plastic 15-20 cP
viscosity
Yield point 2-15 (lb/100 ft2)
API Filtrate 6-8 cm3
pH 2-3
Source: Amoco Production Company drilling fluids manual
77
Chemical Wash - - 3.18 m3
Spacer (100m) - - 3.12 m3
Retarder (0.1-1.5) % 0.06 0.05 0.11 Tons
BWOC
Loss Circulation 0.18 0.01 0.19 Tons
Additive (0.3-0.4) %
BWOC
Total Required Water - - 53.18 m3
Antifoam (0.01 – 0.02) 0.05 0.01 0.06 m3
gal/sk
78
6.5.1 Purpose of this phase
The purpose of this phase is to drill using Synthetic based mud (SBM) from the second
intermediate casing to the depth of 3250m MSL and case-off the hole safely. The hole will pass
through the Rogaland group and the Shetland group (Paleocene – Early Eocene and the Danian
Formations).
The hole section will be passing through the reservoir.
6.5.3 Barriers
The drilling fluid (1.44 SG, SBM) will be the primary control; A Blow out Preventer will be
installed to control the borehole pressure from the underlying formation
Linear OD ID Cumulative
OD Max Length
Element Grade Weight No Body Body Length
(in) (m)
(Kg/m) (in) (in) (m)
IADC CODE:
- 1 8-1/2 - - - -
PDC Bit M432
79
Bit sub + Float
- - 1 - 6-3/4 - - -
Valve
Stabilizer - - 3 - 8-1/2 - - -
MWD - - 1 - - - - -
Non- Magnetic - 145.43 5 - 6-3/4 3 9.144 45.72
Drill Collar
Drill Collar API SPEC 145.43 12 - 6-3/4 3 9.144 109.728
Hydraulic Jar API SPEC - 1 - 6-3/4 - - -
HWDP NC 50 74.67 1 - 5 3 9.144 9.144
G105 NC 50
32.55 395 - 5 4.276 9.144 3611.88
Drill Pipe (XH)
80
● For hard formation annular velocity between 25 and 30 m/min
Annular Mud Velocity = 25 m/min
Annular Capacity OH – DP = 23.3 l/m DDH D14
𝐴𝑛𝑛𝑢𝑙𝑎𝑟 𝐹𝑙𝑜𝑤 𝑟𝑎𝑡𝑒, 𝑄 = 𝐴𝑛𝑛𝑢𝑙𝑎𝑟 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦, 𝐶𝑎 × 𝐴𝑛𝑛𝑢𝑙𝑎𝑟 𝑉𝑒𝑙𝑜𝑐𝑖𝑡𝑦, 𝑉𝑎
𝑙 𝑚 𝐿
∴ 𝑄 = 23.3 × 25 = 582.5
𝑚 𝑚𝑖𝑛 𝑚𝑖𝑛
Using
𝐹𝑅
𝑉=
38.71 ∗ 𝑇𝐹𝐴
Where
FR= Flow rate in liters/min
V= Mud Velocity meters/sec
TFA = Total Flow area, 𝒊𝒏𝟐
Making use of a mud velocity of 90m/s
𝑄
𝑇𝐹𝐴 =
38.71 ∗ 𝑉
582.5
𝑇𝐹𝐴 =
38.71 ∗ 90
𝑇𝐹𝐴 = 0.1672 𝒊𝒏𝟐
From DDH G56 we choose a drilling Bit of 3 (Three) nozzles 8-8-9, having a total area of
0.1603 𝒊𝒏𝟐 .
Linear
Length Buoyancy Total Weight Total Weight
Weight
(m) Factor (kg) (T)
(Kg/m)
Drill Collar 145.45 155.448 0.817 22609.9116 22.6099116
HWDP 74.67 9.144 0.817 682.78248 0.68278248
Drill Pipe 32.55 3611.88 0.817 117566.694 117.566694
Total = 140.8593881
81
MOP = Maximum Tension on DP – weight of Drill String
Weight of Drill String in mud = (DC weight + HWDP weight + DP weight) * buoyancy factor
Total Drill stem Weight =140.9 Tonnes
Weight of Drill String in mud = 140.9 Tonnes * 0.817 = 115.12 Tonnes
Tensile Yield Strength on DP = 193.8kdaN
𝑆𝑎𝑓𝑒𝑡𝑦 𝑓𝑎𝑐𝑡𝑜𝑟 = 90%
≈ 0.9
𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑇𝑒𝑛𝑠𝑖𝑜𝑛 = 𝑇𝑒𝑠𝑖𝑙𝑒 𝑦𝑖𝑒𝑙𝑑 𝑠𝑡𝑟𝑒𝑛𝑔𝑡ℎ × 𝑆𝑎𝑓𝑒𝑡𝑦 𝑓𝑎𝑐𝑡𝑜𝑟
= 0.9 𝑥 193.8
= 174.42𝑘𝑑𝑎𝑁
≈ 177.8 𝑇
Maximum Overpull = 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑇𝑒𝑛𝑠𝑖𝑜𝑛 − Total Drillstem Weight
= 177.8 𝑇 − 140.9T
= 36.9 𝑇
6.5.7.4 WOB
82
DP – L2, L5
DC – L3, L4
𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝐿𝑜𝑠𝑠, Pr = (𝑁 + 𝐿2 𝑁2 + 𝐿3 𝑁3 + 𝐿4 𝑁4 + 𝐿5 𝑁5 ) × 𝐵 + 𝑝𝑑 𝑑
𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝐿𝑜𝑠𝑠, Pr = (𝑁 + 𝐿2 𝑁2 + 𝐿′2 𝑁3 +𝐿3 𝑁3 + 𝐿4 𝑁4 + 𝐿′5 𝑁5 + 𝐿5 𝑁5 ) × 𝐵 + 𝑝𝑑 𝑑
𝑃𝑑 = 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑑𝑟𝑜𝑝 𝑖𝑛 𝑛𝑜𝑧𝑧𝑙𝑒𝑠 𝑓𝑜𝑟 𝑑 = 1, (𝑘𝑃𝑎)
𝑘𝑔⁄
𝑑 = 𝑠𝑝𝑒𝑐𝑖𝑓𝑖𝑐 𝑔𝑟𝑎𝑣𝑖𝑡𝑦, ( 𝑙)
𝑁1 = 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑙𝑜𝑠𝑠 𝑐𝑜𝑒𝑓𝑓𝑖𝑐𝑖𝑒𝑛𝑡 𝑖𝑛 𝑡ℎ𝑒 𝑠𝑢𝑟𝑓𝑎𝑐𝑒 𝑒𝑞𝑢𝑖𝑚𝑒𝑛𝑡, (𝑘𝑃𝑎⁄100𝑚)
83
𝐿5 = 𝐸𝑥𝑡𝑒𝑟𝑛𝑎𝑙 𝑙𝑒𝑛𝑔𝑡ℎ 𝑜𝑓 𝐷𝑟𝑖𝑙𝑙 𝑝𝑖𝑝𝑒 𝑠𝑒𝑐𝑡𝑖𝑜𝑛, (100𝑚)
Typically Plastic viscosity is about twice of mud weight in pounds per gallon
Therefore:
𝑃𝑉 = 2 × 1.44 × 8.33
𝑷𝑽 = 𝟐𝟒 𝑪𝒑
Nozzle 8-8-9
N1 17.3 kPa/100m G30
N2 11.3 kPa/100m G40
N3 54.2 kPa/100m G45
N4
15.95 kPa/100m G60
N5 3.65 kPa/100m G67
L2 3611.88 m
L2' 9.144 m
L3 155.448 m
L4 155.448 m
L5' 9.144 m
L5 3611.88 m
Pd
5917 Kpa G48
d 1.44
B 2.53 G26
Case: 3
Q 582.5 l/min
Ptotal= 10219.65997 Kpa
Pumping requirement:
• Assuming a volumetric efficiency ηv=0.97
• Assuming a mechanical efficiency ηm=0.90
84
6.5.8.1 Pump power
The Maersk Gallant rig has 3 pumps (3 X LTV Emsco FC – 2200) single acting with a power of
2200HP rated for 7500psi.
Taking an overall pumping efficiency of 90% (η= 0.9)
Using
𝑃×𝑄 1
𝑃𝐻𝑃 = ×
450
Where
P= Stand pipe pressure in bar
Q= Flowrate in l/min
η = pumping efficiency (90%)
Hydraulic power =
𝑃×𝑄
𝑃𝐻𝑃 (ℎ𝑝) =
44750
10219.65997 × 582.5
𝑃𝐻𝑃 (ℎ𝑝) =
44750
𝑃𝐻𝑃 (ℎ𝑝) = 133.8 ℎ𝑝
𝐻𝑦𝑑𝑟𝑎𝑢𝑙𝑖𝑐 𝑃𝑜𝑤𝑒𝑟
Mechanical Power= 𝜂𝑚
133.8
=
0.9
= 144.66 ℎ𝑝
85
6.5.8.4 Hoisting Power
The hoisting power is evaluated for each of the phases using the equation below.
𝐹×𝑉 1
𝑃𝐻𝑃 = ×
77.5
Where:
F, Total Hoisted Weight (String + Block +Hook + Over pull)
V, Pulling up Speed, meters/sec
, Overall Hoisting Efficiency
Assumptions
Weight of 25 Tons for Block + Hook,
Speed of 0.3 meters/second
Using 12 lines and roller bearing, we obtain a reeving efficiency of 0.782 (DDH F3)
From previous calculations,
String load in air = 140.9 Tons
Margin of Over pull = 36.9 𝑇𝑜𝑛𝑛𝑒𝑠
Therefore:
F = 140.9+25+36.9
F = 202.77 Tons (202.77 X103 kg)
202.77 × 103 × 0.3 1
𝑃𝐻𝑃 = ×
77.5 0.782
𝑃𝐻𝑃 = 1003.73 𝐻𝑃
86
, Rotating Efficiency (0.9)
𝐶 = 𝑆𝑎𝑓𝑒𝑡𝑦 𝐹𝑎𝑐𝑡𝑜𝑟 × 𝑀𝑖𝑛𝑖𝑚𝑢𝑚 𝑇𝑜𝑟𝑞𝑢𝑒
The minimum torque is obtained from DDH B22
Minimum Torque for a 5” X 4.276” Drill Pipe with nominal weight of 32.55 kg/m is (connection
= API, NC 50).
Minimum Make up Torque = 2,969 daN.m DDH B22
Using a safety factor of 80%,
𝐶 = 0.8 × 2969
𝐶 = 2375.2 𝑑𝑎𝑁. 𝑚
87
ηm = reeving efficiency
202.77
𝑇𝑓𝑙 =
0.782 ∗ 12
𝑻𝒇𝒍 = 𝟐𝟏. 𝟔 𝒕𝒐𝒏𝒏𝒆𝒔
Production
Measured Parameter
Casing
Volume
Total drill string volume (l) 33,438.10
Total Annular volume (l) 144,028.03
Total circulating volume (l) 177,466.13
Mud pit volume (l) @ 50% of total circulating volume 88,528.58
Total volume of mud needed (l) 265,585.73
Circulating Time- 2 pumps @ 50% each
Total pump output ((l/stroke) 39.40
Total pump circulation rate (l/min) 4,136.49
Total circulation time (min) 42.90
88
Table 6.38: 8 1/2” Hole: Principal Additives for Saturated Salt Mud
Concentration, Quantity
Additive Function
lb/bbl slurry Needed (kg)
Viscosity, filtration
Pre-hydrated Bentonite 10 10,751.85
control
Caustic Soda pH 9 - 11.0 Alkalinity control 1,233
Inhibition, calcium
Soda ash 1 1,075.19
removal
Salt (NaCl) 125 Weight Material 134,398.14
Starch 4 Filtration control 4,300.74
Viscosity, Filtration
PAC 0.25 268.80
Control
Source: Amoco Production Company drilling fluids manual
Parameter Value
Mud weight 1.44
Plastic viscosity 15-20 cP
Yield point 15 - 18 (lb/100 ft2)
API Filtrate 6-8 cm3
pH 2-3
Source: Amoco Production Company drilling fluids manual
89
Table 6.41:- Additives for cement slurry
90
CHAPTER 7
WELL COMPLETIONS
7.1 Overview
The successful production and depletion of a reservoir depends on the quality of the completion
operations applied to the well. Completion, in petroleum engineering, is the process of making a
well ready for production (or injection). This primarily involves preparing the bottom of the hole
to the required specifications, cementing the casing, running in the production tubing and it’s
associated down hole tools, perforating and stimulating as required. The wellbore provides the
only path from the reservoir to the surface. In most establishments, it is the production engineer’s
responsibility to design and supervise the completion operations.
91
The completion program starts after the 7” casing was cemented. The well was filled up with the
1.36 SG drilling fluid (by design).
• Between the 30” and 20” casings: hardened set and a plastic seal.
• Between the 20” annulus and the 13 3/8” casing: set cement and plug.
• Between the 13 3/8” and 9 5/8" casings: set cement and pack-off.
• The well: cemented 9 5/8" casing, cemented 7” casing and 10,000 psi rated BOP in place.
Preparation are made to run the log twice, the reason for the first is to ensure good cement job, the
second, being after a remedial cementing this is done to achieve selectivity of fluids, and ensure
that water production is delayed and can be controlled in future by plugging and re-perforating as
well as prevention of early gas cusping. Areas of concentration are the casing supporting the
casing, the casing and the production zone itself. The production zone refers to the zones from the
top of the reservoir to the gas water level and proper cementation of this zone is essential.
4) Perforating:
92
After the packers were inflated, the well was perforated at the stated intervals with guns from
down to top.
6) Well Kill:
Well was killed with 1.1S.G completion fluid in preparation for running in hole with completion
assembly.
93
Figure 7.1:- Completion diagram
94
13) Well Activation:
Opened Sliding Side Door (SSD) with slickline, and pumped in light completion fluid (1.1S.G)
inside the annulus to reduce hydrostatic. Confirmed well had started unloading, and then closed
Sliding Side Door (SSD).
95
this concentration is about –15ºF. There is very little likelihood of solids precipitation since the
temperature at sea floor is 10ºC and increases with depth.
Filtered brine weighted with CaCO3.
Completion Fluid Brine I: 1.40g/cc mud weight
(Heavy completion fluid for displacing the drilling mud)
Completion Fluid Brine II: 1.10g/cc mud weight.
(Light completion fluid for displacing the heavy
completions fluid through the SSD, in order to activate the
well)
Packer Fluid Brine I: 1.40g/cc mud weight.
96
Figure 7.2:- Wellhead to be used for the CODSE 1A
7.4.2 The following procedures should be carried out on the wellbore before running the tubing:
• Evaluate the cement job by GR/CCL/CBL-VDL/CET.
• Bit and Scrapper run for wellbore hole cleaning particularly at the packer setting depth.
• Use the brine (completion fluid CaCl2 of SG 1.4) to displace the drilling mud.
• Perform correlation log to obtain a proper reference point for the depth of packer and
perforations. The parker depth should be chosen so that the packer is set opposite a well-
cemented zone.
• Rig up the wire line well control equipment and the shooting nipple.
• Perforation gun assemble and at accurate interval.
▪ Conduct several runs of the tubing to ensure the perforation interval is covered.
▪ Observe well to ensure overbalance and not flowing before Pull-Out-Of-Hole.
97
▪ Ensure Pull-Out-Of-Hole is done at an adequate rate to avoid swabbing or formation
damage.
• Run-in-Hole the production tubing with accessories following the description on the
completions diagram.
• Land tubing with the tubing hanger in the tubing head spool and pressure test tubing.
• Set the Packer with the specified surface pressure and pressure test.
• Nipple down the landing joint and set Back-Pressure-Valve (BPV), nipple down the Blow-
out-Preventer (BOP) with tested appropriate rams.
• Nipple up the Christmas tree and pressure test the well
7.4.3 The following techniques and equipment should be used in running the tube to the correct
depth:
A hydraulically set retrievable packer was selected for this completions program, which is a tubing
conveyed packer. The equipment to be assembled on the tubing string includes:
• Landing nipple.
• Tubing retrievable surface controlled subsurface safety valve (TRSCSSV).
• Tubing
Procedure:
• Conduct visual examination of the assembly of equipments including the tubing based on the
running order.
• Screw the tubing to the landing nipple and tubing hanger and run in hole. Caution should be
taken when the tubing string approaches the top of the liner to avoid damaging the packer
setting mechanism.
• Pressure test tubing assembly above the packer while running in hole at 320bar.
• Set the packer.
• Land the tubing hanger on the tubing head spool.
• Test the tubing (production) string at 320bar.
98
• Mount the adaptor on the upper flange of the tubing head spool.
• Install the Christmas tree on top of the adaptor.
• Test the production wellhead.
Procedure:
• Test seal between the tubing hanger at 320bar.
• Test the surface controlled subsurface safety valve (SCSSV) control line.
• Replace the back-pressure valve with a two-way check valve and perform an overall
production wellhead test.
• Perform a valve-by-valve pressure test on the adapter plus Christmas tree assembly
7.4.6 Perforation
The perforation is carried out underbalanced using the CWOK process using the through tubing gun
technique on slickline after the completion equipment have been run. The Christmas tree installed
and the well is filled with inhibited water (Light weight completion fluid).
99
7.5 Future Interventions
Well intervention operations are carried out in order to extend the producing life of the well by either
improving its performance or providing access to addition/stranded hydrocarbon reserves
(AkerSolution, 2011). Well intervention operation could be heavyweight (HW) or light weight (LW)
depending on the objection of the operation and production state of the well. The heavy weight (HW)
operation requires the mobilization of a rig unit while the mobilization of a rig unit is not needed for
light weight (LW) intervention operations. Typical well intervention operations services include:
Replacement of all or part of the completion equipment above the packer. The completion
equipment that could be replaced above the packer are:
• Christmas tree/wellhead equipment (LW). Possible problems are:
▪ Valve leaks.
▪ Tubing hanger or tie down screws.
▪ Back pressure valve (BPV) seat.
▪ SCSSV control line outlet
• Leaks on circulating sleeve (LW)
• Stuck/faulty TRSCSSV (HW)
• Faulty control line (HW)
• Tubing repairs (HW)
Replacement of equipment below the packer or the packer itself. The possible equipments that
could be replaced are:
• Damaged/leaking retrievable packer (HW)
• Damaged/leaking slips joints and locators (HW)
• Accidentally unseated packer (HW)
Bottom hole data gathering. This includes temperature and pressure logging using the respective
gauges attached to a wireline using lubricator.
Perforation plugging and re-perforation in order to carry out water/gas shut off. Plugging and
re-perforating the perforation interval is performed in order to shut of water when production water
exceeds limit (water-oil-ratio) or shut off gas when the produced gas exceeds the limit (Gas-oil ratio).
100
A squeeze job is done by placing an inflatable bridge beneath the perforations and injecting slurry in
squeeze mode through a stinger under low pressure. The well is usually killed before carrying put a
squeeze job.
Well stimulation by acid job. A light weight operation using coiled tubing and skid-mounted pumps
should be used to inject chemicals downhole. Procedure are as follows:
• A coiled tubing is recommended to minimize tubing movement.
• A hydrochloric based acid is recommended.
• A pre flush of about 5% HCl is used to treat the reservoir zone
• Main treatment of about 1m3 mud acid/m reservoir height can be used
• An after flush of mineral oil can be used
• The well should be cleaned up immediately after the after flush has been pumped.
101
7.6 Project timing and costing
102
Bit Surface 2 each Bits Required 8.5 17 5000 10,000
Hole
26" HOLE - 20" Surface Mud 560 Cubic Meter Cost/m3Water 50 28,000
CSG and Chemicals out
103
Interval=2500m Intermediate 227 Cubic Cost/m3 500 113,500
Mud & Metre
Invert out
Chemical
104
Perforation 1 TCP guns 25,500 25,500
105
APPENDIX A : CASING DESIGN
Surface Casing
Burst Pressure @Shoe
610 × 1.44
𝑃𝑖 = = 86.12𝑏𝑎𝑟
10.2
Pe=72bar
ΔP= 86.12-72=14.12bar
Collapse Pressure @ Shoe
610 × 1.18
𝑃𝑖 = = 70.6𝑏𝑎𝑟
10.2
610 × 1.9
𝑃𝑒 = = 113.63𝑏𝑎𝑟
10.2
ΔP= 113.63-70.6=43.03bar
Safety factor consideration
Burst pressure = 14.12 x 1.3 = 18.356bar= 1.8356MPa
Collapse pressure= 43.03 x 1.125 = 48.41bar= 4.841MPa
Intermediate Casing 1
Collapse Pressure (Partial emptying)
For height of mud in casing column :-
2500 × 1
𝑃𝑖 = = 245.1𝑏𝑎𝑟
10.2
245.1 × 10.2
ℎ= = 1524.4𝑚
1.64
Depth=2500-1524.4=975.61m
ℎ × 1.9 (1500 − ℎ) × 1.44
+ = 258𝑏𝑎𝑟
10.2 10.2
h=1027.6m
H (top of cement)=1500-1027.6=472.4m
ΔP @ mud level=118bar
(1500−975.6)×1.64
ΔP @ shoe=202- 10.2
= 117.68𝑏𝑎𝑟
106
Collapse pressure = 118 x 1.125 = 132.75bar = 13.3MPa
Burst pressure = 315.98 x 1.3 = 410.77bar = 41.1MPa
Intermediate casing 2
Collapse pressure (partial emptying)
For height of mud in casing column :-
3250 × 1
𝑃𝑖 = = 318.63𝑏𝑎𝑟
10.2
318.3 × 10.2
ℎ= = 2389.71𝑚
1.36
Depth=3250-2389.71=860.3m
ℎ × 1.9 (2500 − ℎ) × 1.64
+ = 458𝑏𝑎𝑟
10.2 10.2
h=2198.456m
H (top of cement)=2500-2198.456=301.54m
860.3 ×1.64
ΔP @ mud level= 10.2
= 138.32bar
(2500−860.3)×1.36
ΔP @ shoe=330- = 111.37𝑏𝑎𝑟
10.2
107
APPENDIX B: DRILL STRING CALCULATIONS
108
59.15 𝑚
=
9.144 𝑚
= 6.5 ≃ 7𝑝𝑐𝑠
For a good transmission of weight and maintaining the Section Modulus less than 5.5 a drill
collar with specification DC (8” X 3”) will incorporated in the drill String
• One Drill collar with specification DC (8” X 3”) ≃ 218.77 kg/m will be used.
To ensure smooth transition from the rigid and compressed DC’s to the flexible and in tension
DPs, HWDP are used. This also acts as a safety such that the DP’s are never in compression as
the HWDP can with stand a considerable compression force. The section modulus of less than
5.5 is targeted between DC and HWDP and also between HWDP and DP
Section modulus
DC (9.5” X 3”) and DC (8” X 3”) = 1.69 <5.5 Okay
DC (8”X3”) and HWDP (5” X 3”) = 4.6 <5.5 Okay
HWDP (5” X 3”) and DP (5” X 4.276”) = 1.87 < 5.5 Okay
HWDP specifications
HWDP (5” X 3”) ≃ 74.67 kg/m
109
= 72 pcs
DP specification
5” X 4.276” 19.5 lb/ft,
Tool joint G105, NC50 (XH)
Approximate weight with tool joint = 32.55 kg/m
110
17.5” OPEN HOLE (1500m MSL)
Weight on bit
Weight on bit = 1 ton per inch for very soft formations
= 1 × 17.5 𝑥 cos 33.06 = 14.67 𝑇𝑜𝑛𝑛𝑒𝑠
Taking 80% of Drill collar weight to be on the bit
Therefore Drill collar weight in mud equals
14.67𝑇
=
0.8
111
= 8𝑝𝑐𝑠
For a good transmission of weight and maintaining the Section Modulus less than 5.5 a drill
collar with specification DC (8” X 3”) will incorporated in the drill String
• One Drill collar with specification DC (8” X 3”) ≃ 218.77 kg/m will be used.
To ensure smooth transition from the rigid and compressed DC’s to the flexible and in tension
DPs, HWDP are used. This also acts as a safety such that the DP’s are never in compression as
the HWDP can with stand a considerable compression force. The section modulus of less than
5.5 is targeted between DC and HWDP and also between HWDP and DP
Section modulus
DC (9.5” X 3”) and DC (8” X 3”) = 1.69 <5.5 Okay
DC (8”X3”) and HWDP (5” X 3”) = 4.6 <5.5 Okay
HWDP (5” X 3”) and DP (5” X 4.276”) = 1.87 < 5.5 Okay
HWDP specifications
HWDP (5” X 3”) ≃ 74.67 kg/m
= 1591.056m
Drill pipe length is taken as 30ft ≃ 𝟗. 𝟏𝟒𝟒𝒎
Total Number of Drill Pipes =
1591.056m
=
9.144 𝑚
112
= 174 pcs
DP specification
5” X 4.276” 19.5 lb/ft,
Tool joint G105, NC50 (XH)
Approximate weight with tool joint = 32.55 kg/m
Weight on bit
Weight on bit = 2 ton per inch for very soft formations
= 2 × 12.25 𝑋 cos 33.06 = 20.53 𝑇𝑜𝑛𝑛𝑒𝑠
Taking 80% of Drill collar weight to be on the bit
Therefore Drill collar weight in mud equals
20.53𝑇
=
0.8
113
32448.8 𝑘𝑔
=
323.18 𝑘𝑔/𝑚
= 100.4𝑚
Each length of Drill Collar is taken as 30ft = 9.144m
Number of drill collars required =
100.4 𝑚
=
9.144 𝑚
= 11 𝑝𝑐𝑠
For a good transmission of weight and maintaining the Section Modulus less than 5.5 a drill
collar with specification DC (8” X 3”) will incorporated in the drill String
• One Drill collar with specification DC (8” X 3”) ≃ 218.77 kg/m will be used.
To ensure smooth transition from the rigid and compressed DC’s to the flexible and in tension
DPs, HWDP are used. This also acts as a safety such that the DP’s are never in compression as
the HWDP can with stand a considerable compression force. The section modulus of less than
5.5 is targeted between DC and HWDP and also between HWDP and DP
Section modulus
DC (9.5” X 3”) and DC (8” X 3”) = 1.69 <5.5 Okay
DC (8”X3”) and HWDP (5” X 3”) = 4.6 <5.5 Okay
HWDP (5” X 3”) and DP (5” X 4.276”) = 1.87 < 5.5 Okay
HWDP specifications
HWDP (5” X 3”) ≃ 74.67 kg/m
114
= Depth MSL + Rig Height depth (55m) – Total length of DCs – Total length of HWDP
= 2761.488 m
Drill pipe length is taken as 30ft ≃ 𝟗. 𝟏𝟒𝟒𝒎
Total Number of Drill Pipes =
2761.488 𝑚
=
9.144 𝑚
= 302pcs
DP specification
5” X 4.276” 19.5 lb/ft,
Tool joint G105, NC50 (XH)
Approximate weight with tool joint = 32.55 kg/m
115
8.5” OPEN HOLE (2500m MSL)
Weight on bit
Weight on bit = 2 ton per inch for very soft formations
= 2 × 8.5 𝑥 cos 33.06 = 14.24 𝑇𝑜𝑛𝑛𝑒𝑠
Taking 80% of Drill collar weight to be on the bit
Therefore Drill collar weight in mud equals
14.24𝑇
=
0.8
116
= 16.3 𝑝𝑐𝑠 ≃ 𝟏𝟕𝒑𝒄𝒔
To ensure smooth transition from the rigid and compressed DC’s to the flexible and in tension
DPs, HWDP are used. This also acts as a safety such that the DP’s are never in compression as
the HWDP can with stand a considerable compression force. The section modulus of less than
5.5 is targeted between DC and HWDP and also between HWDP and DP
Section modulus
DC (6.75” X 3”) and HWDP (5” X 3”) = 2.72 < 5.5 Okay
HWDP (5” X 3”) and DP (5” X 4.276”) = 1.87 < 5.5 Okay
HWDP specifications
HWDP (5” X 3”) ≃ 74.67 kg/m
= 395pcs
DP specification
5” X 4.276” 19.5 lb/ft,
Tool joint G105, NC50 (XH)
Approximate weight with tool joint = 32.55 kg/m
117
APPENDIX C: MUD CALCULATIONS
= 0.5067 × 𝐷2 (4)
118
(12)
= ∑ (𝑡𝑜𝑡𝑎𝑙 𝑎𝑛𝑛𝑢𝑙𝑎𝑟 𝑣𝑜𝑙𝑢𝑚𝑒 𝑜𝑓 𝑒𝑎𝑐ℎ 𝑠𝑒𝑐𝑡𝑖𝑜𝑛)
Where the depth of OH (open hole), CH (cased hole), HWDP (heavy weight drill pipe), DP
(drill pipe) and DC (drill collar) are in metres.
3) Total Circulating Volume
a) Total circulating volume (litres);
Where,
𝐴𝑉 = annular velocity, ft/min,
𝑊 = mud weight, lb/gal,
𝐾 = viscosity (the cxonsistency, K, in the Power Law model), cP
SUMMARY OF RESULTS
Table C-1: Summary of Results- Mud calculations a) Surface casing b) Intermediate Casing 1 c) Intermediate Casing 2 d)
Production Casinga) Surface casing
Surface
Measured Parameter
Casing
Estimated distance MSL-RKB 55
Measured shoe depth (m) mud line 538
Outer diameter of Casing (in) 20
Inner diameter of Casing (in) 18.73
Outer diameter of drill pipe (in) 5
Internal diameter of drill pipe (in) 4.276
Length of drill pipe (m) 582.70
Outer diameter of HWDP (in) 5
Internal diameter of HWDP (in) 3
Length of each HWDP (m) 9.14
Number of HWDP used 1
Number of drill collar used 8
Outer diameter of 7 drill collar above jar from surface 1 (in) 9.5
Outer diameter of drill collar below jar from surface 2 (in) 8
119
Internal diameter of drill collar (in) 3
Length of drill collar (m) 9.14
Diameter of open hole (in) 26
Inner diameter of previous cased hole (in) 29
Volume
Capacity of drill pipe (l/m) 9.05
Capacity of each HWDP (l/m) 4.56
Capacity of drill collar 1 (l/m) 4.56
Capacity of drill collar 2 (l/m) 4.56
Volume of drill pipe (l) 5,273.47
Volume of HWDP (l) 41.70
Volume of drill collar (l) 333.60
Total drillstring volume (l) 5,648.77
Annular capacity: drill pipe and cased hole (l/m) 413.47
Annular capacity: (drill pipe + HWDP) and open hole (l/m) 329.86
Annular capacity: drill collar 1 and open hole (l/m) 296.80
Annular capacity: drill collar 2 and drill pipe (l/m) 310.10
Annular capacity: riser and drill pipe to RKB (l/m) 413.47
Annular volume: drill pipe and cased hole (l) 36,385.11
Annular volume: (drill pipe + HWDP) and open hole(l) 76,807.64
Annular volume: drill collar 1 and open hole (l) 18,997.54
Annular volume: drill collar 2 and open hole (l) 3,780.74
Annular volume: conductor pipe and drill pipe to RKB (l) 52,510.33
Total Annular volume (l) 188,481.37
Total circulating volume (l) 194,130.14
b) Intermediate Casing 1
1st Intermediate
Measured Parameter
Casing
Estimated distance MSL-RKB 55
Measured shoe depth (m) mud line 1,555.20
Outer diameter of Casing (in) 13.375
Inner diameter of Casing (in) 12.41
Outer diameter of drill pipe (in) 5
Internal diameter of drill pipe (in) 4.276
Length of drill pipe (m) 1,591.06
Outer diameter of HWDP (in) 5
Internal diameter of HWDP (in) 3
Length of each HWDP (m) 9.14
Number of HWDP used 1
Outer diameter of the 8 drill collar above jar from surface 1
(in) 9.5
Outer diameter of 1 drill collar below jar from surface 2 (in) 8
Internal diameter of drill collar (in) 3
Length of drill collar (m) 9.14
120
Diameter of open hole (in) 17.5
Inner diameter of previous cased hole (in) 18.73
Volume
Capacity of drill pipe (l/m) 9.05
Capacity of each HWDP (l/m) 4.56
Capacity of drill collar 1 (l/m) 4.56
Capacity of drill collar 2 (l/m) 4.56
Volume of drill pipe (l) 14,399.06
Volume of HWDP (l) 41.70
Volume of drill collar (l) 375.29
Total drill string volume (l) 14,816.05
Annular capacity: drill pipe and cased hole (l/m) 165.09
Annular capacity: (drill pipe + HWDP) and open hole (l/m) 142.51
Annular capacity: drill collar 1 and open hole (l/m) 109.45
Annular capacity: drill collar 2 and drill pipe (l/m) 122.75
Annular capacity: conductor pipe and drill pipe to RKB (l/m) 413.47
Annular volume: drill pipe and cased hole (l) 88,818.10
Annular volume: (drill pipe + HWDP) and open hole(l) 133,232.58
Annular volume: drill collar 1 and open hole (l) 8,006.28
Annular volume: drill collar 2 and open hole (l) 1,122.41
Annular volume: conductor pipe and drill pipe to RKB (l) 52,510.33
Total Annular volume (l) 283,689.70
Total circulating volume (l) 298,505.76
C) Intermediate Casing 2
2nd Intermediate
Measured Parameter
Casing
Estimated distance MSL-RKB 55
Measured shoe depth (m) mud line 2747.5
Outer diameter of Casing (in) 9.625
Inner diameter of Casing (in) 8.75
Outer diameter of drill pipe (in) 5
Internal diameter of drill pipe (in) 4.276
Length of drill pipe (m) 2,761.49
Outer diameter of HWDP (in) 5
Internal diameter of HWDP (in) 3
Length of each HWDP (m) 9.14
Number of HWDP used 1
Outer diameter of the 11 drill collars above jar from surface 1
(in) 9.5
Outer diameter of 1 drill collar below jar from surface 2 (in) 8
Internal diameter of drill collar (in) 3
121
Length of drill collar (m) 9.14
Diameter of open hole (in) 12.25
Inner diameter of previous cased hole (in) 12.41
Volume
Capacity of drill pipe (l/m) 9.05
Capacity of each HWDP (l/m) 4.56
Capacity of drill collar 1 (l/m) 4.56
Capacity of drill collar 2 (l/m) 4.56
Volume of drill pipe (l) 24,991.47
Volume of HWDP (l) 41.70
Volume of drill collar (l) 500.39
Total drill string volume (l) 25,533.56
Annular capacity: drill pipe and cased hole (l/m) 65.37
Annular capacity: (drill pipe + HWDP) and open hole (l/m) 63.37
Annular capacity: drill collar 1 and open hole (l/m) 30.31
Annular capacity: drill collar 2 and open hole (l/m) 43.61
Annular capacity: conductor pipe and drill pipe to RKB (l/m) 413.47
Annular volume: drill pipe and cased hole (l) 101,660.94
Annular volume: (drill pipe + HWDP) and open hole(l) 68,601.69
Annular volume: drill collar 1 and open hole (l) 3,048.40
Annular volume: drill collar 2 and open hole (l) 398.75
Annular volume: conductor pipe and drill pipe to RKB (l) 52,510.33
Total Annular volume (l) 226,220.11
Total circulating volume (l) 251,753.67
d) Production Casing
Production
Measured Parameter
Casing
Estimated distance MSL-RKB 55
Measured shoe depth (m) mud line 3642
Outer diameter of Casing (in) 7
Inner diameter of Casing (in) 6.18
Outer diameter of drill pipe (in) 5
Internal diameter of drill pipe (in) 4.276
Length of drill pipe (m) 3,611.88
Outer diameter of HWDP (in) 5
Internal diameter of HWDP (in) 3
Length of each HWDP (m) 9.14
Number of HWDP used 1
Outer diameter of the 17 drill collars (in) 6.75
Internal diameter of drill collar (in) 3
Length of drill collar (m) 9.14
122
Diameter of open hole (in) 8.5
Inner diameter of previous cased hole (in) 8.75
Volume
Capacity of drill pipe (l/m) 9.05
Capacity of each HWDP (l/m) 4.56
Capacity of drill collar 1 (l/m) 4.56
Volume of drill pipe (l) 32,687.51
Volume of HWDP (l) 41.70
Volume of drill collar (l) 708.89
Table C-2:- Mud Pump Requirement a) Surface casing b) Intermediate Casing 1 c) Intermediate Casing 2 d) Production
Casinga) Surface casing
Surface
Pump Data- Emsco F-2200 Parameter
Casing
Liner diameter of stroke (in) 9 Total pump output ((l/stroke) 39.40
Total pump circulation rate
Length of stroke (in) 14 (l/min) 4,136.49
Strokes per minute (strokes/min) 105 Total circulation time (min) 46.93
Number of pumps 2
Efficiency of pump 0.9
Pump output (l/stroke) @50% 19.70
Pump circulation rate (l/min) @50% 2,068.25
Total pump output ((l/stroke) 39.40
Total pump circulation rate (l/min) 4,136.49
b) Intermediate Casing 1
123
1st
Pump Data- Emsco F-2200- Intermediate
Parameter Intermediate
1
Casing
Total pump output
Liner diameter of stroke (in) 9 ((l/stroke) 39.40
Total pump circulation rate
Length of stroke (in) 14 (l/min) 4,136.49
Strokes per minute (strokes/min) 105 Total circulation time (min) 72.16
Number of pumps 2
Efficiency of pump 0.9
Pump output (l/stroke) @50% 19.70
Pump circulation rate (l/min)
@50% 2,068.25
Total pump output ((l/stroke) 39.40
Total pump circulation rate
(l/min) 4,136.49
c) Intermediate Casing 2
2nd
Pump Data- Emsco F-2200 Parameter Intermediate
Casing
Liner diameter of stroke (in) 9 Total pump output ((l/stroke) 39.40
Total pump circulation rate
Length of stroke (in) 14 (l/min) 4,136.49
Strokes per minute (strokes/min) 105 Total circulation time (min) 58.39
Number of pumps 2
Efficiency of pump 0.9
Pump output (l/stroke) @50% 19.70
Pump circulation rate (l/min)
@50% 2,068.25
Total pump output ((l/stroke) 39.40
Total pump circulation rate (l/min) 4,136.49
d) Production Casing
Pump Data- Emsco F-2200- Production Production
Parameter
Casing Casing
Liner diameter of stroke (in) 9 Total pump output ((l/stroke) 39.40
Total pump circulation rate
Length of stroke (in) 14 (l/min) 4,136.49
Strokes per minute (strokes/min) 105 Total circulation time (min) 42.90
Number of pumps 2
Efficiency of pump 0.9
124
Pump output (l/stroke) @50% 19.70
Pump circulation rate (l/min) @50% 2,068.25
Total pump output ((l/stroke) 39.40
Total pump circulation rate (l/min) 4,136.49
125
APPENDIX D: CEMENTING PROGRAMME
30” and 20” Casing Section (Surface Casing): Cementing to the mudline
Volume Calculations
126
Lead Slurry S.G. = Mud Weight + 0.1 S.G.
Lead Slurry S.G. = 1.28
Tail Slurry S.G. = Fracture Gradient at Shoe
Tail Slurry S.G. = 1.44
Preparation of 1 m3 Class G cement:
Bentonite weight (kg);
𝑑
100 (1 − ) − (𝑑 − 1)𝑒
𝑏= 3.15
1
𝑑 ( + 𝑍) − (𝑍 + 1)
2.65
Water Volume (liters);
𝐸 = 𝑒 + 𝑧𝑏
Slurry Volume (liters);
100 𝑏
𝑣= + + 𝑒 + 𝑧𝑏
3.15 2.65
LEAD
For 100kg of Cement;
d = 1.28
e = 44liters
z = 21.2 for pre-hydrated bentonite
𝑏 = 8.86𝑘𝑔
𝐸 = 228 𝑙𝑖𝑡𝑒𝑟𝑠
𝑣 = 263.04 𝑙𝑖𝑡𝑒𝑟𝑠
If 100kg of cement = 263.04 liters of slurry,
Therefore105.80m3 of slurry = 40.22 Tons of Cement
Similarly,
1 𝑠𝑎𝑐𝑘 𝑜𝑓 𝑐𝑒𝑚𝑒𝑛𝑡 = 94𝑙𝑏 = 42.64𝐾𝑔
40.22Tons 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 = 943.2 𝑠𝑎𝑐𝑘𝑠
We thus require 943 sacks of cement for the lead.
Similarly,
100 𝐾𝑔 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 𝑟𝑒𝑞𝑢𝑖𝑟𝑒 8.68 𝐾𝑔 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒
𝑇ℎ𝑢𝑠 40.22 𝑇𝑜𝑛𝑠 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 = 3.49 𝑇𝑜𝑛𝑠 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒
127
Furthermore,
1 𝑠𝑎𝑐𝑘 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒 𝑐𝑜𝑛𝑡𝑎𝑖𝑛𝑠 1𝑇𝑜𝑛
3.49 𝑇𝑜𝑛𝑠 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒 = 3.49 𝑠𝑎𝑐𝑘𝑠
We thus require 3.49 sacks of bentonite.
Similarly,
263.04 𝑙𝑖𝑡𝑟𝑒𝑠 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 𝑆𝑙𝑢𝑟𝑟𝑦 𝑟𝑒𝑞𝑢𝑖𝑟𝑒𝑠 228.016 𝑙𝑖𝑡𝑟𝑒𝑠 𝑜𝑓 𝑊𝑎𝑡𝑒𝑟
𝑇ℎ𝑢𝑠 105.80𝑚3 of slurry = 91.71𝑚3 𝑜𝑓 𝑊𝑎𝑡𝑒𝑟
TAIL
For 100kg of Cement;
d = 1.54
e = 44liters
z = 21.2 for pre-hydrated bentonite
𝑏 = 2.48𝑘𝑔
𝐸 = 96.57 𝑙𝑖𝑡𝑒𝑟𝑠
𝑣 = 129.26 𝑙𝑖𝑡𝑒𝑟𝑠
If 100kg of cement = 129.26 liters of slurry,
Therefore12.70 m3 of slurry = 9.82 Tons of Cement
Similarly,
1 𝑠𝑎𝑐𝑘 𝑜𝑓 𝑐𝑒𝑚𝑒𝑛𝑡 = 94𝑙𝑏 = 42.64𝐾𝑔
9.82Tons 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 = 230.37 𝑠𝑎𝑐𝑘𝑠
We thus require 231 sacks of cement for the tail.
Similarly,
100 𝐾𝑔 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 𝑟𝑒𝑞𝑢𝑖𝑟𝑒 2.48 𝐾𝑔 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒
𝑇ℎ𝑢𝑠 9.82 𝑇𝑜𝑛𝑠 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 = 0.24 𝑇𝑜𝑛𝑠 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒
Furthermore,
1 𝑠𝑎𝑐𝑘 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒 𝑐𝑜𝑛𝑡𝑎𝑖𝑛𝑠 1𝑇𝑜𝑛
0.24 𝑇𝑜𝑛𝑠 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒 = 0.24 𝑠𝑎𝑐𝑘𝑠
We thus require 0.24 sacks of bentonite.
Similarly,
129.26 𝑙𝑖𝑡𝑟𝑒𝑠 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 𝑆𝑙𝑢𝑟𝑟𝑦 𝑟𝑒𝑞𝑢𝑖𝑟𝑒𝑠 96.57𝑙𝑖𝑡𝑟𝑒𝑠 𝑜𝑓 𝑊𝑎𝑡𝑒𝑟
𝑇ℎ𝑢𝑠 12.70𝑚3 of slurry = 9.49𝑚3 𝑜𝑓 𝑊𝑎𝑡𝑒𝑟
128
Spacer Volume
The spacer exists in the casing – casing annular section with a length of 46.25m, therefore:
0.5067(𝐼𝐷2 − 𝑂𝐷2 )
𝑉𝑜𝑙𝑢𝑚𝑒 = × 𝐿𝑒𝑛𝑔𝑡ℎ (𝑚3 )
1000
𝑉𝑜𝑙𝑢𝑚𝑒 = 10𝑚3
Total Water Required;
= 𝑀𝑖𝑥𝑒𝑑 𝐻2 𝑂 𝑓𝑜𝑟 𝑐𝑒𝑚𝑒𝑛𝑡 + 20% 𝑆𝑎𝑓𝑒𝑡𝑦 + 𝑊𝑎𝑡𝑒𝑟 𝑓𝑜𝑟 𝑐ℎ𝑒𝑚𝑖𝑐𝑎𝑙 𝑤𝑎𝑠ℎ
+ 20 𝐵𝑎𝑟𝑟𝑒𝑙𝑠 𝑚𝑖𝑛𝑖𝑚𝑢𝑚 (𝑝𝑟𝑖𝑚𝑖𝑛𝑔 𝑎𝑛𝑑 𝑤𝑎𝑠ℎ𝑖𝑛𝑔
𝑀𝑖𝑥𝑒𝑑 𝐻2 𝑂 𝑓𝑜𝑟 𝐶𝑒𝑚𝑒𝑛𝑡 = 101.80 𝑚3
20% 𝑆𝑎𝑓𝑒𝑡𝑦 = 20.24𝑚3
𝑊𝑎𝑡𝑒𝑟 𝑓𝑜𝑟 𝑐ℎ𝑒𝑚𝑖𝑐𝑎𝑙 𝑤𝑎𝑠ℎ = 3.179𝑚3
20𝑏𝑏𝑙𝑠 𝑓𝑜𝑟 𝑝𝑟𝑖𝑚𝑖𝑛𝑔 𝑎𝑛𝑑 𝑤𝑎𝑠ℎ𝑖𝑛𝑔 = 3.179𝑚3
𝑉𝑜𝑙𝑢𝑚𝑒 𝑜𝑓 𝐻2 𝑂 𝑟𝑒𝑞𝑢𝑖𝑟𝑒𝑑 = 127.80𝑚3
Displacement
Volume from the float collar to the top of the casing:
𝑉𝑜𝑙𝑢𝑚𝑒 = 0.5067(𝐼𝐷2 ) × (538 − 90 ∗ 0.3048), 𝑚3
𝑉𝑜𝑙𝑢𝑚𝑒 = 93.44𝑚3
Displacement Time
93440
Displacement: barrels : 10 bbls per min = 0.97 Hours
159
129
Outside Diameter (OD) of Intermediate Casing I = 13 3/8”
Length = 50m into the previous casing
From DDH D1
0.5067(𝐼𝐷2 − 𝑂𝐷2 )
𝑉𝑜𝑙𝑢𝑚𝑒 = × 𝐿𝑒𝑛𝑔𝑡ℎ (𝑚3 )
1000
𝑉𝑜𝑙𝑢𝑚𝑒 = 4.62 𝑚3
130
𝑑
100 (1 − ) − (𝑑 − 1)𝑒
𝑏= 3.15
1
𝑑 ( + 𝑍) − (𝑍 + 1)
2.65
Water Volume (liters);
𝐸 = 𝑒 + 𝑧𝑏
Slurry Volume (liters);
100 𝑏
𝑣= + + 𝑒 + 𝑧𝑏
3.15 2.65
LEAD
For 100kg of Cement;
d = 1.54
e = 44liters
z = 21.2 for pre-hydrated bentonite
𝑏 = 2.48 𝑘𝑔
𝐸 = 96.57 𝑙𝑖𝑡𝑒𝑟𝑠
𝑣 = 129.26 𝑙𝑖𝑡𝑒𝑟𝑠
If 100kg of cement = 129.26 liters of slurry,
Therefore, 99.29m3 of slurry = 76.82 Tons of Cement
Similarly,
1 𝑠𝑎𝑐𝑘 𝑜𝑓 𝑐𝑒𝑚𝑒𝑛𝑡 = 94𝑙𝑏 = 42.64𝐾𝑔
76.82 Tons 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 = 1081.53 𝑠𝑎𝑐𝑘𝑠
We thus require 1082 sacks of cement for the lead.
Similarly,
100 𝐾𝑔 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 𝑟𝑒𝑞𝑢𝑖𝑟𝑒 2.48 𝐾𝑔 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒
𝑇ℎ𝑢𝑠 76.82 𝑇𝑜𝑛𝑠 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 = 1.90 𝑇𝑜𝑛𝑠 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒
Furthermore,
1 𝑠𝑎𝑐𝑘 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒 𝑐𝑜𝑛𝑡𝑎𝑖𝑛𝑠 1𝑇𝑜𝑛
1.90 𝑇𝑜𝑛𝑠 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒 = 1.90 𝑠𝑎𝑐𝑘𝑠
We thus require 1.9 sacks of bentonite.
Similarly,
129.26 𝑙𝑖𝑡𝑟𝑒𝑠 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 𝑆𝑙𝑢𝑟𝑟𝑦 𝑟𝑒𝑞𝑢𝑖𝑟𝑒𝑠 96.57 𝑙𝑖𝑡𝑟𝑒𝑠 𝑜𝑓 𝑊𝑎𝑡𝑒𝑟
131
𝑇ℎ𝑢𝑠 99.29𝑚3 of slurry = 74.19𝑚3 𝑜𝑓 𝑊𝑎𝑡𝑒𝑟
TAIL
For 100kg of Cement;
d = 1.74
e = 44liters
z = 21.2 for pre-hydrated bentonite
𝑏 = 0.80𝑘𝑔
𝐸 = 60.85 𝑙𝑖𝑡𝑒𝑟𝑠
𝑣 = 92.9 𝑙𝑖𝑡𝑒𝑟𝑠
If 100kg of cement = 92.9 liters of slurry,
Therefore5.69m3 of slurry = 6.12 Tons of Cement
Similarly,
1 𝑠𝑎𝑐𝑘 𝑜𝑓 𝑐𝑒𝑚𝑒𝑛𝑡 = 94𝑙𝑏 = 42.64𝐾𝑔
6.12 Tons 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 = 143.53 𝑠𝑎𝑐𝑘𝑠
We thus require 144 sacks of cement for the tail.
Similarly,
100 𝐾𝑔 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 𝑟𝑒𝑞𝑢𝑖𝑟𝑒 0.80 𝐾𝑔 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒
𝑇ℎ𝑢𝑠 6.12 𝑇𝑜𝑛𝑠 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 = 0.05 𝑇𝑜𝑛𝑠 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒
Furthermore,
1 𝑠𝑎𝑐𝑘 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒 𝑐𝑜𝑛𝑡𝑎𝑖𝑛𝑠 1𝑇𝑜𝑛
0.05 𝑇𝑜𝑛𝑠 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒 = 0.05 𝑠𝑎𝑐𝑘𝑠
We thus require0.05 sacks of bentonite.
Similarly,
92.9 𝑙𝑖𝑡𝑟𝑒𝑠 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 𝑆𝑙𝑢𝑟𝑟𝑦 𝑟𝑒𝑞𝑢𝑖𝑟𝑒𝑠 60.85 𝑙𝑖𝑡𝑟𝑒𝑠 𝑜𝑓 𝑊𝑎𝑡𝑒𝑟
𝑇ℎ𝑢𝑠 5.69𝑚3 of slurry = 3.72 𝑚3 𝑜𝑓 𝑊𝑎𝑡𝑒𝑟
Spacer Volume
The spacer exists in the casing – casing annular section with a length of 108.3m, therefore:
0.5067(𝐼𝐷2 − 𝑂𝐷2 )
𝑉𝑜𝑙𝑢𝑚𝑒 = × 𝐿𝑒𝑛𝑔𝑡ℎ (𝑚3 )
1000
𝑉𝑜𝑙𝑢𝑚𝑒 = 10𝑚3
Total Water Required;
132
= 𝑀𝑖𝑥𝑒𝑑 𝐻2 𝑂 𝑓𝑜𝑟 𝑐𝑒𝑚𝑒𝑛𝑡 + 20% 𝑆𝑎𝑓𝑒𝑡𝑦 + 𝑊𝑎𝑡𝑒𝑟 𝑓𝑜𝑟 𝑐ℎ𝑒𝑚𝑖𝑐𝑎𝑙 𝑤𝑎𝑠ℎ
+ 20 𝐵𝑎𝑟𝑟𝑒𝑙𝑠 𝑚𝑖𝑛𝑖𝑚𝑢𝑚 (𝑝𝑟𝑖𝑚𝑖𝑛𝑔 𝑎𝑛𝑑 𝑤𝑎𝑠ℎ𝑖𝑛𝑔
𝑀𝑖𝑥𝑒𝑑 𝐻2 𝑂 𝑓𝑜𝑟 𝐶𝑒𝑚𝑒𝑛𝑡 = 77.91 𝑚3
20% 𝑆𝑎𝑓𝑒𝑡𝑦 = 15.58 𝑚3
𝑊𝑎𝑡𝑒𝑟 𝑓𝑜𝑟 𝑐ℎ𝑒𝑚𝑖𝑐𝑎𝑙 𝑤𝑎𝑠ℎ = 3.179𝑚3
20𝑏𝑏𝑙𝑠 𝑓𝑜𝑟 𝑝𝑟𝑖𝑚𝑖𝑛𝑔 𝑎𝑛𝑑 𝑤𝑎𝑠ℎ𝑖𝑛𝑔 = 3.179𝑚3
𝑉𝑜𝑙𝑢𝑚𝑒 𝑜𝑓 𝐻2 𝑂 𝑟𝑒𝑞𝑢𝑖𝑟𝑒𝑑 = 99.85𝑚3
Displacement
Volume from the float collar to the top of the casing:
𝑉𝑜𝑙𝑢𝑚𝑒 = 0.5067(𝐼𝐷2 ) × (1552.14 − 90 ∗ 0.3048), 𝑚3
𝑉𝑜𝑙𝑢𝑚𝑒 = 119.14𝑚3
Displacement Time
11940
Displacement: barrels : 10 bbls per min = 1.25 Hours
159
133
𝑉𝑜𝑙𝑢𝑚𝑒 = 0.94 𝑚3
134
Slurry Volume (liters);
100 𝑏
𝑣= + + 𝑒 + 𝑧𝑏
3.15 2.65
LEAD
For 100kg of Cement;
d = 1.74
e = 44liters
z = 21.2 for pre-hydrated bentonite
𝑏 = 0.80 𝑘𝑔
𝐸 = 60.85 𝑙𝑖𝑡𝑒𝑟𝑠
𝑣 = 92.90 𝑙𝑖𝑡𝑒𝑟𝑠
If 100kg of cement = 92.90 liters of slurry,
Therefore, 56.99 m3 of slurry = 61.34 Tons of Cement
Similarly,
1 𝑠𝑎𝑐𝑘 𝑜𝑓 𝑐𝑒𝑚𝑒𝑛𝑡 = 94𝑙𝑏 = 42.64𝐾𝑔
61.34 Tons 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 = 1438.52 𝑠𝑎𝑐𝑘𝑠
We thus require 1439 sacks of cement for the lead.
Similarly,
100 𝐾𝑔 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 𝑟𝑒𝑞𝑢𝑖𝑟𝑒 0.80 𝐾𝑔 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒
𝑇ℎ𝑢𝑠 61.34 𝑇𝑜𝑛𝑠 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 = 0.49 𝑇𝑜𝑛𝑠 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒
Furthermore,
1 𝑠𝑎𝑐𝑘 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒 𝑐𝑜𝑛𝑡𝑎𝑖𝑛𝑠 1𝑇𝑜𝑛
0.49 𝑇𝑜𝑛𝑠 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒 = 0.49 𝑠𝑎𝑐𝑘𝑠
We thus require 0.49 sacks of bentonite.
Similarly,
92.9 𝑙𝑖𝑡𝑟𝑒𝑠 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 𝑆𝑙𝑢𝑟𝑟𝑦 𝑟𝑒𝑞𝑢𝑖𝑟𝑒𝑠 60.85 𝑙𝑖𝑡𝑟𝑒𝑠 𝑜𝑓 𝑊𝑎𝑡𝑒𝑟
𝑇ℎ𝑢𝑠56.99 𝑚3 of slurry = 37.33 𝑚3 𝑜𝑓 𝑊𝑎𝑡𝑒𝑟
TAIL
For 100kg of Cement;
d = 1.87
e = 44liters
135
z = 21.2 for pre-hydrated bentonite
𝑏 = 0.14𝑘𝑔
𝐸 = 46.94 𝑙𝑖𝑡𝑒𝑟𝑠
𝑣 = 78.73 𝑙𝑖𝑡𝑒𝑟𝑠
If 100kg of cement = 78.73 liters of slurry,
Therefore, 2.84 m3 of slurry = 3.60 Tons of Cement
Similarly,
1 𝑠𝑎𝑐𝑘 𝑜𝑓 𝑐𝑒𝑚𝑒𝑛𝑡 = 94𝑙𝑏 = 42.64𝐾𝑔
3.60 Tons 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 = 84.45 𝑠𝑎𝑐𝑘𝑠
We thus require 85 sacks of cement for the tail.
Similarly,
100 𝐾𝑔 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 𝑟𝑒𝑞𝑢𝑖𝑟𝑒 0.14 𝐾𝑔 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒
𝑇ℎ𝑢𝑠 3.60 𝑇𝑜𝑛𝑠 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 = 0.005 𝑇𝑜𝑛𝑠 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒
Furthermore,
1 𝑠𝑎𝑐𝑘 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒 𝑐𝑜𝑛𝑡𝑎𝑖𝑛𝑠 1𝑇𝑜𝑛
0.005 𝑇𝑜𝑛𝑠 𝑜𝑓 𝐵𝑒𝑛𝑡𝑜𝑛𝑖𝑡𝑒 = 0.005 𝑠𝑎𝑐𝑘𝑠
We thus require0.005 sacks of bentonite.
Similarly,
78.73 𝑙𝑖𝑡𝑟𝑒𝑠 𝑜𝑓 𝐶𝑒𝑚𝑒𝑛𝑡 𝑆𝑙𝑢𝑟𝑟𝑦 𝑟𝑒𝑞𝑢𝑖𝑟𝑒𝑠 46.94 𝑙𝑖𝑡𝑟𝑒𝑠 𝑜𝑓 𝑊𝑎𝑡𝑒𝑟
𝑇ℎ𝑢𝑠 2.84 𝑚3 of slurry = 1.69 𝑚3 𝑜𝑓 𝑊𝑎𝑡𝑒𝑟
Spacer Volume
The spacer exists in the casing – casing annular section with a length of 100m, therefore:
0.5067(𝐼𝐷2 − 𝑂𝐷2 )
𝑉𝑜𝑙𝑢𝑚𝑒 = × 𝐿𝑒𝑛𝑔𝑡ℎ (𝑚3 )
1000
𝑉𝑜𝑙𝑢𝑚𝑒 = 3.12𝑚3
Total Water Required;
= 𝑀𝑖𝑥𝑒𝑑 𝐻2 𝑂 𝑓𝑜𝑟 𝑐𝑒𝑚𝑒𝑛𝑡 + 20% 𝑆𝑎𝑓𝑒𝑡𝑦 + 𝑊𝑎𝑡𝑒𝑟 𝑓𝑜𝑟 𝑐ℎ𝑒𝑚𝑖𝑐𝑎𝑙 𝑤𝑎𝑠ℎ
+ 20 𝐵𝑎𝑟𝑟𝑒𝑙𝑠 𝑚𝑖𝑛𝑖𝑚𝑢𝑚 (𝑝𝑟𝑖𝑚𝑖𝑛𝑔 𝑎𝑛𝑑 𝑤𝑎𝑠ℎ𝑖𝑛𝑔
𝑀𝑖𝑥𝑒𝑑 𝐻2 𝑂 𝑓𝑜𝑟 𝐶𝑒𝑚𝑒𝑛𝑡 = 39.02 𝑚3
20% 𝑆𝑎𝑓𝑒𝑡𝑦 = 7.80 𝑚3
𝑊𝑎𝑡𝑒𝑟 𝑓𝑜𝑟 𝑐ℎ𝑒𝑚𝑖𝑐𝑎𝑙 𝑤𝑎𝑠ℎ = 3.179𝑚3
20𝑏𝑏𝑙𝑠 𝑓𝑜𝑟 𝑝𝑟𝑖𝑚𝑖𝑛𝑔 𝑎𝑛𝑑 𝑤𝑎𝑠ℎ𝑖𝑛𝑔 = 3.179𝑚3
𝑉𝑜𝑙𝑢𝑚𝑒 𝑜𝑓 𝐻2 𝑂 𝑟𝑒𝑞𝑢𝑖𝑟𝑒𝑑 = 53.18𝑚3
136
Displacement
Volume from the float collar to the top of the casing:
𝑉𝑜𝑙𝑢𝑚𝑒 = 0.5067(𝐼𝐷2 ) × (2747.5 − 90 ∗ 0.3048), 𝑚3
𝑉𝑜𝑙𝑢𝑚𝑒 = 105.70 𝑚3
Displacement Time
105697
Displacement: barrels : 10 bbls per min = 1.11 Hours
159
137
𝑉𝑜𝑙𝑢𝑚𝑒 = 36.68 𝑚3
Open hole excess = 50%
𝑉𝑜𝑙𝑢𝑚𝑒 = 55.09𝑚3
138
𝑇ℎ𝑢𝑠 15.24 𝑚3 of slurry = 8.85 𝑚3 𝑜𝑓 𝑊𝑎𝑡𝑒𝑟
Spacer Volume
The spacer exists in the casing – casing annular section with a length of 150m, therefore:
0.5067(𝐼𝐷2 − 𝑂𝐷2 )
𝑉𝑜𝑙𝑢𝑚𝑒 = × 𝐿𝑒𝑛𝑔𝑡ℎ (𝑚3 )
1000
𝑉𝑜𝑙𝑢𝑚𝑒 = 2.10 𝑚3
Total Water Required;
= 𝑀𝑖𝑥𝑒𝑑 𝐻2 𝑂 𝑓𝑜𝑟 𝑐𝑒𝑚𝑒𝑛𝑡 + 20% 𝑆𝑎𝑓𝑒𝑡𝑦 + 𝑊𝑎𝑡𝑒𝑟 𝑓𝑜𝑟 𝑐ℎ𝑒𝑚𝑖𝑐𝑎𝑙 𝑤𝑎𝑠ℎ
+ 20 𝐵𝑎𝑟𝑟𝑒𝑙𝑠 𝑚𝑖𝑛𝑖𝑚𝑢𝑚 (𝑝𝑟𝑖𝑚𝑖𝑛𝑔 𝑎𝑛𝑑 𝑤𝑎𝑠ℎ𝑖𝑛𝑔
𝑀𝑖𝑥𝑒𝑑 𝐻2 𝑂 𝑓𝑜𝑟 𝐶𝑒𝑚𝑒𝑛𝑡 = 8.85 𝑚3
20% 𝑆𝑎𝑓𝑒𝑡𝑦 = 1.77 𝑚3
𝑊𝑎𝑡𝑒𝑟 𝑓𝑜𝑟 𝑐ℎ𝑒𝑚𝑖𝑐𝑎𝑙 𝑤𝑎𝑠ℎ = 3.179𝑚3
20𝑏𝑏𝑙𝑠 𝑓𝑜𝑟 𝑝𝑟𝑖𝑚𝑖𝑛𝑔 𝑎𝑛𝑑 𝑤𝑎𝑠ℎ𝑖𝑛𝑔 = 3.179𝑚3
𝑉𝑜𝑙𝑢𝑚𝑒 𝑜𝑓 𝐻2 𝑂 𝑟𝑒𝑞𝑢𝑖𝑟𝑒𝑑 = 16.98 𝑚3
Displacement
Volume from the float collar to the top of the casing:
𝑉𝑜𝑙𝑢𝑚𝑒 = 0.5067(𝐼𝐷2 ) × (3713.78 − 90 ∗ 0.3048), 𝑚3
𝑉𝑜𝑙𝑢𝑚𝑒 = 71.47 𝑚3
Displacement Time
105697
Displacement: barrels : 10 bbls per min = 0.75 Hours
159
139