Onshore Pipeline Design Rev.00 PDF

ENI E. & P.
ON_OFFSHORE PIPELINE DESIGN COURSE 1st Ed.

“Onshore Pipeline Design”
Lecturer: Gabriele Lanza

Saipem S.p.A.
1 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 1

Index
04_Onshore Pipeline Design

- Section 0. : A brief pipeline history
- Section 1. : Codes and Design Standards
- Section 2. : Routing Design
- Section 3 : Geotechnical Design
- Section 4 : Authority Engineering
- Section 5 : Hydraulics
- Section 6 : Construction
- Section 7 : Mechanical Design
- Section 8 : Cathodic Protection
- Section 9 : Coatings

SECTION 0. : A BRIEF PIPELINE HYSTORY
In Mesopotamia and in Egypt, 5,000 years before Christ, clay

pipes were used for irrigation and drainage purposes.
In China, in the Fifth century BC, bamboo pipes wrapped in

cloth impregnated with wax were used to transport natural gas
to Beijing for the purpose of illumination.
The Romans when creating large infrastructure components

such as the aqueducts, used lead pipes in the most important
branches of the network.
USERS USERS
Schematic of the elements of a transport system, showing the various components

bamboo pipes in China
USERS USERS

clay water supply pipes lead water supply pipes
Pipes in ancient Rome

USERS USERS

A significant advance was made, in the Eighteenth century, with

the introduction of pipes in melted iron for aqueducts and sewers,
and sometimes for gas transport for lighting.
In 1879, following the discovery of an oil field in Pennsylvania, a

first pipeline was laid, with a diameter of 15 cm, for the oil
transport across the state over a distance of about 180 km.
The introduction of submerged arc welding, around the year

1920, substantially changed the scenario and from then began
the production of large diameter pipelines, which we can call
modern.
USERS USERS

Pipeline Pioneering in USA USERS

WHAT ARE ONSHORE PIPELINE TRANSPORTION SYSTEMS
WELLS
OIL / GAS TREATMENT PUMPING
COMPRESSOR
GATHERING LINES
STATIONS
TERMINAL
USERS USERS
TRUNKLINES PIPELINES PIPELINES
USERS USERS

ITALIAN PIPELINE TRANSPORT SYSTEMS
GAS IMPORT FROM FROM HOLLAND

TENP - GERMAN SECTION
GAS IMPORT FROM RUSSIA
- Nr. 3 COMPRESSOR STATIONS (181.6 MW)
OMV - AUSTRIAN SECTION
-TAG1: 383 km OD: 36”-38
TRANSITGAS - SWISS SECTION
-TAG2: 378 km OD: 42”
- TRG1 : 164 km OD: 36”-34”
- TAG LOOP II 376 km OD: 40”
- TRG2 : 164 km OD: 36”- 48”
- Nr. 14 Tunnels 43,000 m
SNAM - ITALIAN SECTION
- 1° PHASE: 215 km OD: 34”-36”
SNAM - ITALIAN SECTION
- 2° PHASE: 264 km OD: 42”
- 1° PHASE 162.5 km OD: 34”
- 3° PHASE: 201 km OD: 48”
- 2° PHASE 176 km OD: 48”
- Nr. 8 Tunnels: 9 km
- Nr. 11 Tunnels 8,000 m
GAS IMPORT FROM NORWAY

- TRG3: 55.3 km OD: 36” TRANSMEDITERRANEAN PIPELINES
- GAME A: 1,085 km OD: 48”

317 km OD: 42”
- GAME B: 1,490 km OD: 48”
ALGERIA - ITALY NATURAL GAS PIPELINE

SONATRACH - ALGERIA SECTION
- N° 2 x 48” 550 km each LIBYA - ITALY NATURAL GAS PIPELINE
MELLITAH to GELA - AGIP NORTH AFRICA
SCOGAT - TUNISIA SECTION USERS USERS
- 520 km OD: 32”
- N° 2 x 48” 368 km each Schematic of the elements of a transport system, showing the various components

PIPELINE TRANSPORT SYSTEMS
Italian Gas Network
PLANTS AND UNDERGROUND STORAGES
SNAM GAS PIPELINE NETWORK
RUSSIA
HOLLAND
Masera Malborghetto
Cinisello B.
Istrana
Settala Sergnano
Ripalta
Tresigallo
Cortemaggiore
Minerbio
S. Martino
Rimini
Terranova Recanati PIPELINE NETWORK km 29,000
Bracciolini PIPELINE NETWORK km 29,000
LNG
Gallese
Cupello
Melizzano
PIPELINE COMPRESSOR STATIONS N° 12 Montesano

PIPELINE COMPRESSOR STATIONS N° 12
STORAGE COMPRESSOR STATIONS N° 3
STORAGE COMPRESSOR STATIONS N° 3
Tarsia
PIPELINE AND STORAGE COMPRESSOR
PIPELINE AND STORAGE COMPRESSOR
STATIONS N° 6
STATIONS N° 6 Messina
Enna USERS USERS
ALGERIA

Index

- Section 0. : A brief pipeline hystory

1. : Codes and Design Standards
Pipelines and related facilities expose the operators, and potentially the general
public, to the inherent risk of high-pressure fluid transmission. As a result, national
and international codes and standards have been developed to limit the risk to a
reasonable minimum. Such standards are mere guidelines for design and
construction of pipeline systems. They are not intended to be substitutes for good
engineering practices for safe designs.
Major codes affecting pipeline design are listed in following Table. Some
governmental authorities have the right to issue regulations defining minimum
requirement for the pipeline and related facilities. These regulations are legally
binding for the design, construction, and operation of pipeline system facilities,
which are under the jurisdiction of the relevant authority.
There are also a number of other authorities (e.g., utility boards) who have
jurisdiction over specific concerns with regard to pipeline design and construction.
These authorities have the right to enforce their own regulations, setting minimum
requirements for pipeline facilities within their jurisdiction.

List of major international codes and standards affecting pipeline design, construction and operation
Acronym Organization/topic
ACI American Concrete Institute

AGA American Gas Association
ANSI American National Standard Institute
API American Petroleum Institute
ASME American Society of Mechanical Engineers
ASTM American Society for Testing Materials
CSA Canadian Standards Association
DEP Design Engineering Practice
IEEE Institute of Electronic and Electrical Engineers
IP Institute of Petroleum
ISA International Society of American
ISO International Standards Organization
MSS Manufacturers Standardization Society
NACE National Association of Corrosion Engineers
NAG Normas Argentinas de Gas
NEMA National Electrical Manufacturing Association
NFPA National Fire Protection Association
SIS Standards Institute of Sweden
SSPC Steel Structures Painting Council
ANSI B16.5 Pipe Flanges and Flanged Fittings
ASTM A 350 Pipe Flanges and Flanged Fittings Material
MSS SP-25 Standard Marking System for Valves, Fittings, Flanges, and Unions
MSS SP-44 Steel Pipe Line Flanges
API 5L API Specifications for Line Pipe
API 6D Specifications for Pipeline Valves, End Closures, Connectors, and
Swivels

(Continued)
API 1104 (NAG 100) Welding of Pipeline and Related Facilities

ASTM A 333 or ASTM A 106 Materials for Surface Installations Piping
ANSI B16.9 Butt Welding Elbows/Tees
ASTM A 234 or ASTM A 420 Butt Welding Elbows/Tees Materials
ASTM A 350 or ASTM A 105 Forged Fittings <NPS 2 Material
ANSI B16.11 Forged Fittings <NPS 2
ANSI/ASME B31.4 Pipeline Transportation Systems for Liquid Hydrocarbons and other
Liquids
ANSI/ASME B31.8 Gas Transmission and Distribution Piping Systems
ANSI B16.9 Factory-made Wrought Steel Buttwelding Fittings
ANSI B16.10 Factory-made and End-to-End Dimensions of Ferrous Valves
DEP 31.38.01.10 Piping Classes and Basis of Design
ANSI B16.34 Steel Valves, Flanges and Buttwelding Ending
ANSI B1.1 Unified Screwed Threads
ANSI B95.1 Terminology for Pressure Relief Devices
DIVISION I, Rules for Construction of ASME Boiler and Pressure Vessel Code Section VIII
Pressure Vessels
Qualification Standards for Welding
and Brazing Procedures, Welders, ASME Boiler and Pressure Vessel Code Section IX
Brazers, Welding, and Brazing
Operators

(Continued)
MSS SP-53 Quality Standard for Steel Castings and Forgings for Valves ,
Flanges and Fittings, and other Piping Components, Magnetic
Particle Examination Method
MSS SP-54 Quality Standard for Steel Castings and Forgings for Valves,
Flanges and Fittings, and other Piping Components, Radiographic
Examination Method
MSS SP-55 Quality Standard for Steel Castings for Valves, Flanges and
Fittings, and other Piping Components (Visual Method)
MSS SP-75 Specification for High Test Wrought Buttwelding Fittings
API RF 6F Recommended Practice for Fire Test for Valves
API 601 Dimensions for Spiral Wound Gaskets
API RP 520 Recommended Practice for the Design and Installation of Pressure
Relieving Systems in Refineries
API 526 Flanged Steel Safety Relief Valves
API 527 Commercial Seat Tightness of Safety Relief Valves with Metal-to-
Metal Seats
ASTM A 106 Seamless Carbon Steel Pipe for High Temperature Service
ASTM A234 Pipe Fittings or Wrought Carbon Steel and Alloy Steels for
Moderate and Elevated Temperatures
ASTM A694 Forging, Carbon and Alloy Steel, for Pipe Flanges, Fittings and
Valves, and Parts for High-Pressure Transmission
ASTM A193 Alloy Steel and Stainless Steel Bolting Materials for High-
Temperature Service
ASTM A194 Carbon and Alloy Steel Nuts and Bolts for High-Pressure and High-
Temperature Service
ASTM A370 Methods and Definitions for Mechanical Testing of Steel Products
ASTM E384 Test Method for Microhardness of Materials
CAN/CSA 2662 Oil and Gas Pipeline Systems
CAN/CSA Z245.20-M92 External Fusion Bond Epoxy Coated Steel Pipe
CAN/CSA Z245.21-M92 and DIN External Polyethylene and Thermoplastic Coating for Line Pipes
30670/din 30671

(Continued) 1. : Codes and Design Standards
API RP 5L2 Recommended Practice for Internal Coating of Line Pipe for Gas
Transmission Service
SSPC-SP1 Surface Preparation – Solvent Cleaning
SSPC-SP10 Surface Preparation Specification No.10 Near-White Blastcleaning
SSPC-VIS-1 Pictorial Surface Preparation for Painted Surfaces
SIS 05-5800-1967 Pictorial Surface Preparation Standard for Painting Steel Surfaces
SPSC-SP3 Power Tool Cleaning as per Steel Structure Painting Council
ASTM G8-72 Standard Test Methods for Cathodic Disbonding of Pipeline
Coatings
NACE RP-01-92 Control of External Corrosion on Undergroung or Submerged Piping
System
NACE RP-05-72 Design Installation. Operation, and Maintenance of Impressed
Current Deep Groundbed
NACE RP-01-77 Mitigation of Alternating Current and Lightning Effects on Metallic
Structures and Corrosion Control Systems
NACE RP-02-86 Mitigation of Alternating Current and Lightning Effects on Metallic
Structures and Corrosion Control Systems
NACE RP-02-74 High Voltage Electrical Inspection of Pipeline Coatings Prior to
Installation
IP Part I Model Code of Safe Practice, Electrical Safety Code
IP Part 15 Area Classification Code for Petroleum Installation
DEP 33.64.10.10 Electrical Engineering Guideline

API 500C Hazardous Area Classification

AGA 3 Measurement of Gas by Orifice Meters
AGA 8 Determination of Supercompressibility Factors for Natural Gas
AGA 9 Measurement of Gas by Turbine Meters
ANSI B40.1 Gauges and Pressure Indicating Dial Type, Elastic Element
IP Part 1 Model Code of Safe Practice, Electrical Ch. 3 Instrumentation
ISA Standards and Practices for Instrumentation
ASTM-A36 Structural Steel Manual of Steel Construction
ASTM-A82 Specification for Cold-Drawn Steel Wire for Concrete Reinforcement
ASTM-A184 Specifications for Fabricated Deformed Steel Bar Mats for Concrete
Reinforcement
ASTM-A185 Specification for Welded Steel Wire Fabric for Concrete
Reinforcement
ASTM-A196 Specification for Steel Wire, Deformed, for Concrete Reinforcement
ASTM-A615 Specification for Deformed and Plain Billet-Steel Bars for Concrete
Reinforcement
ASTM-C33 Specification for Concrete Aggregates
ASTM-C39 Test for Compressive Strength of Cylindrical Specimens
ASTM-C94 Specification for Ready-Mixed Concrete
ASTM-C136 Test for Sieve or Screen Analysis of Fine and Coarse Aggregates
ASTM-C150 Specification for Portland Cement
ASTM-C172 Method of Sampling Freshly Mixed Concrete
ASTM-D422 Particle Size Analysis of Soil
ASTM-D698 Moisture Density Relations of Soil and Soil Aggregate Mixtures
Using 5.5 lb. Rammer
ASTM-D1557 Test for Moisture-Density Relations of Soils and Soil Aggregate
Mixtures Using 10 lb. Rammer and 18 in Drop
ASTM-D2049 Standard Method of Test for Relative Density of Cohesion Soils
ASTM-D4318 Test for Liquid Limit, Plastic Limit and Plasticity Index of Soil
ISO 9001 Quality Systems for Design/Development Production, Installation,
and Servicing

List of major European and Italian codes and standards affecting pipeline design, construction and operation
UNI EN 14161 (2004) Petroleum and natural gas industries – Pipeline Transportation
Systems
UNI EN 1594 (2004) Gas supply systems - Pipelines for maximum operating pressure
over 16 bar - Functional requirements
UNI EN 10208-2:2009 Steel pipes for pipelines for combustible fluids – Technical delivery
conditions – Part 2: Pipes of requirement class B
UNI EN 12954:2002 Cathodic Protection of Buried or Immersed Metallic Structures -
General Principles and Application for Pipelines
D.Lgs 17 Aprile 2008 Nuove Norme Tecniche DM 14 gennaio 2008, nuove norme
tecniche sulle costruzioni. Pubblicato sulla Gazzetta Ufficiale n. 29
del 4 febbraio 2008 - Suppl. Ordinario n. 30
Decreto Interministeriale 21.03.1988, Approvazione delle norme tecniche per la progettazione,
n.449 l’esecuzione e l’esercio delle linee elettriche aeree esterne.
Nuove Norme Tecniche DM 14 Nuove norme tecniche sulle costruzioni. Pubblicato sulla Gazzetta
gennaio 2008 Ufficiale n. 29 del 4 febbraio 2008 - Suppl. Ordinario n. 30
D.Lgs. 9 Aprile 2008, n.81 Testo Unico per la Sicurezza
Attuazione dell’art.1 della legge 3 agosto 2007, n.123 in materia di
tutela della salute e sicurezza nei luoghi di lavoro.
D.Lgs. 3 Agosto 2009, n.106 Disposizioni integrative e correttive del D.Lgs. 9 Aprile 2008, n.81,
in materia di tutela della salute e della sicurezza nei luoghi di lavoro.

List of major European and Italian codes and standards affecting pipeline design, construction and operation
D.M. 4 Maggio 1998 Disposizioni relative alle modalità di presentazione ed al contenuto

delle domande per l’avvio dei procedimenti di prevenzione incendi,
nonché all’uniformità dei connessi servizi resi ai comandi provinciali
dei vigili del fuoco.
D.Lgs. 25 Febbraio 2000, n.93 Attuazione della direttiva 97/23/CE in materia di attrezzature a
pressione
Dlgs 3 aprile 2006, n. 152 e s.m.i. Norme in materia ambientale

(Ha abrogato DPR 18 aprile 1994, n.
526, DPR 12 aprile 1996, DPCM 10
agosto 1988, n. 377)
RDL 30 dicembre 1923, n. 3267 Riordinamento e riforma della legislazione in materia di boschi e di
terreni montani.
DLgs 22 gennaio 2004, n. 42 Codice dei beni culturali e del paesaggio, ai sensi dell'articolo 10
della legge 6 luglio 2002, n. 137.
DPCM 12 dicembre 2005 Codice dei beni culturali e del paesaggio.
DPR 8 settembre 1997, 357 Regolamento recante attuazione della direttiva 92/43/CEE relativa
alla conservazione degli habitat naturali e seminaturali, nonché
della flora e della fauna selvatiche.
L 6 dicembre 1991, n. 394 Legge quadro sulle aree protette
DPR 8 giugno 2001, n. 327 e s.m.i. Testo unico delle disposizioni legislative e regolamentari in materia
di espropriazione per pubblica utilità. (Testo A)
DLgs 27 dicembre 2004, n. 330 Integrazioni al Decreto del Presidente della Repubblica 8 giugno
2001, n. 327, in materia di espropriazione per la realizzazione di
infrastrutture lineari energetiche.

04_ Onshore Pipeline Design
Section 2. : Routing Design
- Section 2.1 : Routing Criteria

- Section 2.2 : Design Standard
- Section 2.3 : Crossings Design Criteria
- Section 2.4 : Route in Mountains and Steep Slopes
- Section 2.5 : Onshore Pipeline Surveys
- Section 2.6 : New technologies in Pipeline Routing
- Section 2.7 : Route design (live examples)

2.1: ROUTING CRITERIA
Routing is one of the most crucial design phase of an onshore
pipeline transportation system.
Routing is the process of selecting the most cost effective

route complying with the main constraints of crossed country,
i.e.:
• legislation;
• environmental;
• physical or man made.

2.1: ROUTING CRITERIA
Pipeline route selection is the process of defining an optimised
connection between two or more points to be linked with each
other via a pipeline transportation system.
The route optimisation is performed as an iterative process that

weighs and balances several different influences that are
encountered on a route, causing either deviations of the initial
line or the need for the implementation of specific construction
or design methods.
The starting point for every pipeline route selection process is

a straight connection between a defined start and end point,
between which a certain product has to be transported.

PIPELINE ROUTING OBJECTIVES
The strategic objectives in a pipeline route selection study are

to:
• comply with legal and regulatory requirements of

different countries;
• care for environment;
• ensure pipeline integrity;
• obtain agreements from landowners;
• obtain agreements for crossings (e.g. roads, railways,
rivers etc.);
• minimize the capital cost of the pipeline
• continuous delivery the “Oil-Gas Product”.

PIPELINE ROUTING OBJECTIVES

ROUTE SELECTION STRATEGY
The route selection is strictly connected with the design terms
of the project.
All the project bodies (owner, engineer and other consultants

contractors) have to participate with own roles and
responsibilities to the process of route selection.
Owner (company) will define the project criteria (“philosophy”),

the preliminary contour conditions, the pipeline ends (at the
available design level), authorities framework context for the
following engineering development.

The awareness of the philosophy of a pipeline project has to be

always taken into consideration during the development of the
project and firstly in the route selection in order to evaluate in
terms of cost-benefit, the issues arising from the land impact of
a pipeline.
Huge pipeline projects will have a great impact on society,

environment and economics of crossed countries.
The route selection starts as soon as the early territorial data

are collected and is carried on with implementation of relevant
data.

For pipeline projects, different alternative corridors are normally

defined at the beginning, on large scale basis i.e. on large scale
maps; hence the decision process starts based upon rough
evaluations on the basis of available data.
Only the most promising alternatives will be selected and

brought to a further design stage.
As this first phase of selection is based on rough data, hence a

good engineering practice on pointing out the related different
issues and effectiveness of decision making of the whole
organization project, is fundamental.

MAJOR COSTRAINS FOR THE PIPELINE ROUTING
• Engineering Constraints
• Environmental Constraints
• Constructability Constraints
• Health & Safety Constraints
• Security Constraints
• Geological Constraints

Engineering Constraints
• The type of Oil/Gas or product to be delivered

• H2S
• Waxing
• Process Conditions
• Temperature
• Pressure
• Materials
• Carbon Steel
• Composites
• Terrain
• Mountains
• Desert
• Swamps

Environmental Constraints
• Farm Land – Woodland – Forest – Wastland
• Site of Special Scientific Interest (SSSI)
• Industrial – Congested Services – Contaminated
• Mountains - rare habitats plants & fauna
• Desert – Sand dunes – Archaeology
• Swamp – Peat – Mongrove
• Permafrost – Sabka – Shore lines
• Cold – Rain - Erosion

Constructability Constraints
• Working width
• Access
• Terrain Slope
• Type of Soil
• Rock
• Geological
• Construction period

Health & Safety Constraints
• High Hazard Pipelines
• High Densities of Populations
• Proximity to Buildings
• Planning Constraints
• Safe in Construction

Security Constraints
• Country risks
• Political
• Health
• War
• Threats of violence
• Threats of theft
• Limited Access
• Environmental threats

Geological Constraints
• Rocky ground (blast impact)
• Soft ground; high water table/surface water
• Landslides
• Flooding & hydrology
• Seismicity, soil liquefaction, faults crossings
• Excavation, backfill & soil disposal
• Soil Erosion & restoration

ROUTE DESIGN SELECTION PROCESS
The route design selection process includes three main
design phases:
1. FEASIBILITY PHASE which includes:

a. Conceptual Design Phase: selection of the best corridor
of interest
b. Selection Design Phase: selection of the best route
c. Definition Design Phase: full definition of selected route
2. FRONT END ENGINEERING PHASE: authorization to be

obtained
3. DETAIL DESIGN PHASE: construction documentation to be

produced

Onshore pipeline route design
Pipeline routing has to be

considered an iterative design
process, as data regarding sites
likely to affect route selection can
only be obtained once input route
corridor has been given as
“starting”, “ending”, “connecting”
and “constraint” points.

Feasibility Phase: Conceptual Design Phase
The aim of the conceptual phase is to find out the best

corridor of interest for the pipeline by comparison and
screening of different solutions and alternatives.
The routing study based on a desk study is performed once

the following key information are given by the Owner:
• starting and ending points;

• strategic or intermediate fixed points (way points)
(e.g., areas or countries to be crossed by the project);
• general design statements (e.g., parallelism with
existing pipelines or other linear utilities).

Routing design – starting points
Samsun Tank Farm

Tartous mountains crossing

Route refinement for morphological reason

Different Options at ending point

The major constraints such as cities, estuaries, mountains, wet

lands and major environmental areas are identified working
along each pipeline or network link. Decisions on deviation or
crossing are formulated.
This process usually ends in a series of straight lines avoiding

major constraints and the 'corridor of interest' can then be
marked along the route. The shortest link between starting and
arrival points is not necessarily the best route. Broad cost
estimates is undertaken to support such decisions.

Route alternatives Comparison
TSB Project
.
CRR WR
Total Length site A 553+260 549+025 (- 4.3)
Total length site C 543+890 542+100 (-1.8)
PS1 Maximum Elevation 2068 m 2126 m
Peak after PRS 1730 m 1661 m
PS2
Wall thickness (ton) 20 km 25.4 mm
Better sizing
required
BTC (BTCX) 4 -
River 1 RVX1 4 RVX1
Crossings
(RVX1 & RVX2) 6 RVX2 3 RVX2
Road 4 RDX1 3 RDX1
(RDX1 & RDX2) 18 RDX2 4 RDX2
Railway (RWX) 1 1
PS3
BTC Parallelism 68 km 18 km
31.5 km 30.0 km
Hard Rock
(% 12.3) (% 11.9)
101.9 km 8.8 km
Loose Soil
Soil
(% 39.9) (% 3.5)
53.2 km 92.5 km
Loose Soil Wet
(% 20.9) (% 36.9)
68.7 km 119.7 km
Soft Rock
PS4 (% 26.9) (% 47.7)
87.7 km 112.9 km
Flat
(% 34.3) (% 45.0)
Terrain
14.8 km 28.8 km
Steep
(% 5.8) (% 11.4)
152.8 km 109.3 km
Undulated (hilly)
(% 59.9) (% 43.6)
0.2 km 0.5 km
Dense
Population
(% 0.1) (% 0.2)
24.7 km 19.5 km
Scattered Housed
(% 9.6) (% 7.8)
230.4 km 231.0 km
Uninhabited
(% 90.3) (% 92.0)
128.4 km 142.9 km
Cultivated
(% 50.3) (% 56.9)
Land Use
PRS PRS_CRR 0.6 km 16.2 km
Fruit Trees
(% 0.2) (% 6.4)
96.9 km 48.5 km
Uncultivated
(% 38.0) (% 19.4)
Legend
Forest 21 29
TSB_west_route
TSB_CRR_Route Juniperus - Cedar 4.5 13
BTC_pipeline
cmt_A Maquis 7.5 3
CMT_C
cmt_C
PS&PRS_WR
Accessibility
PRS_CRR 6 km poor 20 km very poor
CMT_A 0 10 20 40 60 80
Kilometers

The routing process starts finding out, locating and referencing
the following data:
• main existing pipelines routes and relevant facilities (e.g.

valve, traps and compression stations);
• major cities and linear utilities;
• protected areas and national parks;
• physical features of the crossed regions (mountain
chains, sand dunes, salted areas);
• geohazard areas (faults zones, swamps, flooding,
landslides, permafrost areas).

Routing design – Seismic Faults Assessment
Faults Zones Crossed
M ax. D esign
K
P N
am
e
S
lip(m) S
lip(m)
70+500 K
arayaka N
A N
A
72+700 E
rbaa-N
iksar 2.10 S
pm
:1.07
83+700 E
sencay 3.20 N
A
87+500 E
zinepazari 3.05 N
A
75+000 G
urcesm
e N
A N
A
110+100 A
lm
us 3.20 N
A
251+000 D
eliler 2.60 N
A
406+000 G
oksun 2.75 N
A
434+500 0.90 N
A
C
okak
439+000 0.80 N
A
537+700 K
aratas 3.20 N
A
171+000 A
vcipinari-1 0.15 N
A

Other key data, necessary in the early design phase, are:

• preliminary construction schedule to evaluate the
seasonal effects on construction work;
• access and delivery points for a preliminary logistic study
(e.g. harbours, roads, railway stations and
• networks).
At the end of the conceptual phase, one or more of the

alternative routes and relevant terrain profiles are
available for preliminary pipeline sizing.
The outcome results in pipeline dimensions and

compressor/pumping performance levels are integrated into an
initial investment cost estimate.

In this design phase, the following data are gathered:
Country maps (e.g. 1:500.000)

Obtained from National Mapping Agencies/commercial
Companies or use remote sensing data acquired from
Satellite platform.
Thematic maps (e.g. 1:1.000.000).

A bibliographic research has to be carried out of the available
thematic maps, with particular reference to the geology and
geomorphology features as well as land use and seismic.

Routing design – analysisAREE
ofOMOGENEE
localFRAfeatures
LA PROGRESSIVA 0 - 250 KP
TSB Project - Spread 1
PS1
.
UNDULATED [130 Km]
PS2
FLAT 68 Km]
STEEP SLOPE [78 km]
Spread 1
29%
Cultivated A
PS3
Forest F
55% Pasture P
16%
KP
Denomination Description
Position
Passing over the
1-65 Black Sea Focal Point
This area is steep, with dense vegetation (woods and forests)
and not very accessible.
Mountains
Black The first part of the Black Sea Mountains crossing is
1-6
Mountains area characterized by some deep streams with steep faces.
PS4
Main Road Crossing in Narrow point for crossing and little space for
5.4
Legend
Unye-Caybasi thrust boring.
TSB_CRR_Route
BTC_pipeline
57 Golcugez Steep river crossing
TSB_west_route
Bypassing of Tokat across the mountains located at south-east
cmt_A
Bypass of
of the town. Difficult way down in direction of the Main
cmt_C
128
Tokat.
PS&PRS_WR
PRS_CRR
Road Tokat-Sivas and crossing of the road.
0 5 10 20 30 40
Kilometers Dokmetas
251 Rough area surmounted by some small seasonal streams
0 Village

DTM (Digital Terrain Model)
During the conceptual phase, it is essential to have a fairly
accurate idea of the morphology in the study area.
DTMs will be searched on internet (resolution varying between
90 m and 1000 m).
Mapping existing pipelines

In pipeline routing, information on existing pipelines is
Fundamental from early design stage, as the tendency is to
follow the existing structures.
This information is entered in the system based either on

information provided by the Owner or derived from the available
cartography, and the existing pipelines are plotted on available
maps.
Feasibility Phase: Selection Design Phase
The aim of the concept selection phase is the “selection of

the best route” through a more accurate desk study without (or
with only few) field feedback, hence the decisional process
has to be fast but effective, avoiding surveys and every kind of
site investigations.
During the Selection Design Phase, the previously

established 'Corridor of Interest' is subject to confirmation
and refinement, in order to consolidate the corridor for the
selection of environmental baseline data and subsequent
narrowing to the `preferred route corridor'.

Routing study – intermediate plant approach

In this design phase, site visit and/or “early” reconnaissance
survey should be addressed.
Reconnaissance survey grows as importance, until in

mountainous area it is strongly recommended.
Reconnaissance survey shall be performed by

multidiscipline team covering the following issues:
• environment
• geology and geohazard;
• construction.

The route is defined in detail by narrowing the corridor up to

1:100.000 scale approx according to the following criteria:
• the most linear (and therefore the shortest) route is sought

once the compulsory passage points are set due to the
main territorial/political constrains; where possible, a route
running parallel to existing pipelines is generally preferred
and chosen to establish “technical corridors”, so that
should be easier obtaining concessions on right of way of
the new pipeline route. Nevertheless, where the route of
existing pipelines is deemed to be unfavourable or
resulted in excessive lengthening of the route, parallelism
is avoided;
>>>
• preference is given to sharing the existing pipeline plants
(i.e. compression stations and other existing
appurtenances);
• urban areas are avoided and a route that passed away

from most densely inhabited areas is selected;
• protected areas and national parks are avoided/minimized;
• areas that seem most favourable for major river crossings

are selected;
• linear infrastructures, such as road and railway networks

are taken into account in order to minimise any
interference;
Routing study – Oil Spill and geohazard criticalities

• the route through the more uneven areas (mountains

chains, sand dunes, etc.) has to run through the
plains and valleys as far as possible, or through the
most favourable ridges. Certain areas are normally
avoided in routing a pipeline due to possible instability
in the soil leading to excessive stresses in the pipes.
Such areas include landfill sites, historic shallow mining
areas, naturally unstable land slopes, sand dunes and
swamps. In these cases a new route would be selected
to take the pipeline outside the area of instability if at all
possible. In some locations this may not be possible
and engineering measures would have to be taken to
mitigate the possible problems; these measures can be
very expensive.
Feasibility Phase Selection Design Phase
These criteria represent the routing guideline normally

followed but, nevertheless, in many situations the choice
of a route is not simple, given that we are still dealing with
a desk study that is a reliable indicator of the task, from the
point of view of assessments and costs but which will
certainly be subject to changes during the subsequent
stages of project investigation.

Topography maps (e.g. 1:100.000)

For the composition of the cartographic basis, generally the
available “medium scale” topographic maps (i.e. 1:100.000 or
similar) have to be collected.
Satellite Images (HR).

The satellite data offer a more efficient, higher-confidence
route planning process. It is important to carry out design
analyses on updated land use maps at scale 1:100.000, river
and road network, urban areas.
Optical satellite remote sensing such as (Landsat, SPOT,
IRS) can be used for the design phase because they have a
spatial resolution compatible with 1:100.000 approx map
scale.

Thematic maps
In this phase, the project must be drafted on updated
thematic maps to obtain the actual situation of the pipeline
route. Commercially available maps are not always
adequately updated. As, in most cases, the updating of these
maps, or the production of new maps could not be available,
they can be achieved using high-resolution satellite images
The maps that are normally employed in this phase are:
9 state boundaries;
9 land cover with particular emphasis on major urban
areas;
9 road network including major transport infrastructures;
9 hydrographic network;
9 existing pipelines.

DTM
In this phase, it is essential that the digital terrain model
covering the examined pipeline corridor is more accurate than
the previous one. If this data are not available, it can be
produced in two different ways:
9 by integrating the existing model with contour lines and spot

elevations present on topographic maps at scale 1:100.000;
9 by carrying out a flight with laser sensor that can provide an

extremely accurate digital model, with detail greater than that
needed for this phase, but indispensable for next phase
(concept definition).

Derived maps
The combined processing of satellite images with existing
cartography provides updated information which is
consistent with the needs of the project:
• road network indicating the main infrastructures
present in the area;
• hydrographic network;
• land cover and land use;
• verification of the pipelines and other existing
structures;
• map of anthropized areas.

Feasibility Phase: Definition Design Phase
The aim of the definition design phase is the full definition of
the selected route through the collection of more detailed and
updated design data obtained by:
• acquiring detailed cartography (i.e. official topographic
maps and/or detailed satellite and/or aerial
• remotely-sensed data);
• on-site reconnaissance surveys;
• initial negotiations with public authorities and landscape
surveys.
Within the context of the concept definition phase, the
economic viability of the project is depicted on the basis of the
best alternative normally with an accuracy +/- 30 % taking into
consideration all known or estimated cost groups for
construction and operation.

The following main factors are investigated during this phase to
finalize the route:
environmentally sensitive areas:

• areas of outstanding beauty;
• areas of archaeological importance;
• areas of designated landscape;
• areas of conservation interest;
• natural resources such as water catchment areas,
reservoirs and forestry;
• aquifers and potable water supplies;

facilities:
• pipelines;
• underground and above ground services;
• tunnels;
third-party activities:
• land use;
• mineral working;
• mining;
• military zones;
• urban development plans;

environmental conditions:
geotechnical conditions:
uneven topography, outcrops and depressions;
instability like faults and fissuring;
soft and waterlogged ground;
soil corrosivity;
rock and hard ground;
flood plains;
earthquake areas;
muskeg and permafrost areas;
areas of land slippage, subsidence and differential
settlement;
infill land and waste disposal sites including those
contaminated by disease or radioactivity;
hydrographic conditions.
Before starting field reconnaissance, it is advisable to gather as

much information as possible from published sources along the
corridor of interest.
The distance from populated area should be considered,

following applicable codes, in order that the minimum distance
of the pipeline route from buildings of various types can be
taken into account in determining the pipeline route.
Local or central government offices may provide relevant

information but sufficient time should be allowed for this
exercise as it can involve visits to many different offices even if
it is known what information is available.

The field reconnaissance has to be carried out by multi-

disciplinary teams led by senior pipeline engineers and
comprising discipline specialists (i.e., geologist, environmental
and construction).
In developing countries, it may be possible to view much of the

route from a vehicle but access difficulties combined, possibly,
with the length of a long pipeline, may preclude this at this
stage. In this case aerial viewing is the best option from either a
small fixed wing plane, or preferably, a helicopter. As a result of
observations during the initial field reconnaissance, the position
of the route can be adjusted if necessary to represent a feasible
pipeline route avoiding major known constraints and complying
with the design code in relation to proximity distances.

Once a feasible preliminary route has been identified it will

usually be possible to reduce the width of the pipeline corridor
subject to further investigation and consultation. For a long
distance pipeline, the corridor width may now be reduced up to
0.5 km wide.
Constraints identified from topographic and geological maps,

codes and standards and from site reconnaissance, represent
only part of the data required to select the pipeline route.

At the earliest possible opportunity following development

of the broad corridor of interest, key Statutory Authorities
must be consulted to:
• obtain data on non-visible constraints;

• provide early notification of other project proposals.
A limited list of authorities who control sites of major

dimensions should be initially consulted.

Discussions are usually held in confidence as landowners

and occupiers will not be aware of the proposals at this
stage. Examples of key participants likely to impact route
selection are:
• Planning Authorities;
• Water Authorities (river crossings and abstraction
sources);
• Special cases depending on route location (e.g.
government departments, harbour boards etc.).
In view of the requirements for confidentiality, this initial list

has to be minimised.

Although, public utility authorities are unlikely to affect

route selection at this scale it could require the
presentation of a (Preliminary) Environmental Impact
Assessment (PEIA) which main goals are to:
• provide early identification of likely impacts or

designated sites;
• convey accurate information to Authorities and
Third parties;
• inform company management of environmental
implications.

Feasability Phase: Definition Design Phase
Detailed topographic maps (1:25.000/1:50.000)
In this phase, official updated 1:25.000 (or in alternative,
1:50.000) scale maps are the most suitable.
Satellite images (VHR)

If it is difficult to find out what mapping is available or to
obtain it in the country, fine resolution (0.7 to 10 m) images
are available from the following platforms:
• Ikonos (spatial resolution up to 1 m);

• Quick Bird (spatial resolution up to 0.70 m);
• Eros (spatial resolution up to 1 m).

Feasability Phase: Definition Design Phase
(con’t) Satellite images (VHR)

Aerial:
• digital orthophotos with resolution of 15-20
cm;
• traditional orthophotos (1:2.000 – 1:8000);
• images acquired by airborne multispectral
sensors.
Radar satellite images to define the instable areas

through the interferometric processing.

DTM (1:10.000 , 1:500)

In this design phase the DTM must ensure extreme
precision, both in the elevation and in the layout.
This DTM is produced by implementing a flight with laser
sensor. The derived model presents an accuracy in
elevation of at least 15 cm, and a spatial resolution which
depends on the flight elevation (until 0.70 cm).
Derived maps
The combined processing of detailed maps with results of
the reconnaissance survey provides updated information
which is consistent with the needs of the project.

Front End Engineering Phase
Front End Engineering takes place immediately after the full

definition of selected route when the authorization process can
start.
In this phase authorities and land owners are officially informed

about the proposed pipeline.
Most countries have legislation which covers the environmental

impact of a pipeline. In many countries, the legislation requires
an Environmental Impact Assessment (EIA) to be carried out so
that the impacts can be identified and acceptable mitigation
measures proposed.

Within the context of route surveying, comprehensive

investigations are also performed in Landowner
Agreement.
At this stage, detailed pipeline routing and negotiation with

landowners and occupiers take place to enable the route
alignment drawings to be produced and issued for
construction. These are normally based on larger scale
maps (i.e., cadastral maps). Where major pipelines affect
several hundred owners and occupiers, the importance of
maintaining uniform terms of agreement can be highly
emphasised.
.

It is essential that the authorities responsible for major

crossings, particularly railways, trunk roads,motorways and
major water courses, may appraise the proposed pipeline
route at an early stage. At least agreement in principle has
to be obtained, in writing, before the overall routing process
Has progressed too far.
Future widening, re-alignment and other general

improvements of the feature to be crossed must be
identified and allowed for in the design of the crossing.

Once agreement is obtained, detailed design can follow at a

later stage but continuous liaison must be maintained, and
where formal consent is required, this must be pursued
continuously as obtaining it can be a protracted business.

In this project stage, detailed survey are carried out to

provide data and plans for pipeline design and easement
acquisition or licensing procedures.
In sparsely populated uncultivated areas where vehicle

access is not a problem it is becoming more cost effective to
produce alignment drawings through use of GPS which
allow accurate positioning anywhere in the world to levels of
precision far in advance of anything possible previously.
Special satellites with known orbital data transmit signals
are received and evaluated by GPS receivers.

Use of this system directly provides three-dimensional

coordinates in a global surveying system (WGS – World
Geodetic System). Data involved in the required national
reference system are then produced by means of
transformations.
Within the context of route surveying, comprehensive
investigations are also performed in order to obtain
data relating to the property owners and tenants
affected by
the construction project.

Minor re-routes to accommodate the day-to-day operations

of a landowner/occupier may however be of benefit to both
parties, for example:
• unnecessary severance of major plot, requiring
several transverse;
• accesses to allow the owner to negotiate the right of
way during pipeline construction;
• routing along major land drainage collection headers
or outfalls causing-high reinstatement cost and
difficulty of repair;
• traversing established field boundaries at an acute
angle necessitating extensive renewal after
construction.

In this phase, documentation required for permits and design
purpose is produced, i.e. detailed topographical maps
(1:10.000 scale or less) with selected route, different derived
and thematic maps for EIA, cadastral maps for land
acquisition. About design, material take-offs for long lead
items are provided.
Together with the design basis data, the topographical data

constitutes the basis for producing main maps and plans.
Satellite images are largely used in this phase in combination

with topographical data. Images type and resolution are
normally the same acquired in the Definition Design Phase.

Detail Design Phase
Detailed design of a pipeline normally starts once
authorization for its construction has been obtained.
Detailed design phase may take place prior to the award of

a conventional construction contract or after award as part
of an EPC (Engineering, Procurement, and Construction)
Contract.
In this phase, detailed documentation required for

construction purpose is produced, i.e. construction plans
(alignment sheets) and final material take-offs.
Detailed surveys (topographical and soil investigation)
constitutes the basis for producing the construction plans.
The pipeline itself is indicated and surveyed (staking) by its
axis at location where it changes direction (bends).


- Section 2.4 : Route in Mountains and Steep Slopes

2.2 : ROUTING DESIGN STANDARD
Right-of-way – single pipeline (NPS 48)

Right-of-way – parallelism to existing pipeline (NPS 48)

Narrow right-of-way NPS 48

Narrow Right-of-way NPS 48 parallel to existing pipeline

Trench protection

Well Point equipment for ditch drainage

Typical shaft for thrust boring machine (1/3)



Net protection for stone fall

Typical ditch and pipe cover

Typical trench configuration (1/2)

Typical trench configuration (2/2)
Fiber optic cable laying configuration 1/2
Fiber optic cable laying configuration 2/2
PIPELINE ROUTING DESIGN CRITERIA
Typical existing high dangerous fluids pipeline crossing
Typical existing water pipeline crossing
Typical existing irrigation pipeline crossing
Typical cable crossing in duct pipe
Typical cable crossing without duct pipe
Existing gas and oil pipeline crossing
Sewage crossing
Pipeline protection: Concrete casing 1/3
Cold bend NPS 48
Hot bends NPS 48
Concrete coating for buoyancy control
Concrete coating for mechanical protection
Trench breakers

- Section 2.4 : Routing in Mountains and Steep Slopes
RIVER CROSSINGS CRITERIA
The aim of the design for buried river crossings is to
minimize the risk of pipeline exposure or damage to
the pipeline for the design flood and for the
economic life of the pipeline.
This is done via the following steps:

• computing the design flow and water level;
• assessing the potential for and magnitude of the
general and local bed scour;
• analyzing the potential for bank erosion or
channel switching or the development for new
channels across or near the pipeline; and
• if necessary, designing bank and bed structures
to protect the pipeline from the influence of the
river.
The design of elevated river crossings requires an

assessment of:
• the design flood magnitude, the design water

level and the necessary freeboard or clearance;
• scour potential for instream piers or abutments;
• potential for channel changes and the need for

and design of river training structures for the
piers or abutments.
The design of river crossings involves both quantitative and

qualitative assessments. The quantitative analysis consists
of computing the magnitude of the design flood and is
corresponding water level.
Scour or riverbed lowering is computed via quantitative

techniques and qualitative assessments.
The assessment of potential future bank erosion or channel

switches is primarily a qualitative assessment. Depending
on the magnitude of floods experienced during the
available period of airphotos, historic bank erosion, as per
comparative airphotos.
It should be noted that for smaller rivers and especially low

velocity conditions, exposure of a buried pipeline does not
necessarily result in pipeline integrity concerns.
The aim of the design should however always minimize, for

the design flood, foreseeable river conditions, and for the
life of the pipeline, the probability of and extent of pipeline
exposure.
The steps are:
• Measure the drainage area at the crossing from

topographic plans or obtain from published information
by government agencies.
• Establish the appropriate design flood criteria as

established by the owner and/or by the government
regulators.
• Compute the design water level by extrapolating historic

high water marks from known water levels at bridges, for
example, and/or by computation using river surveys (at
least three cross sections required). Computations can be
done via a simple backwater analysis or by commonly
used models such as HEC-RAS developed by the U.S.
Army Corps of Engineers. The impact of ice (breakup and
icings) on the design water level must be recognized. For
many northern rivers, a moderate flow during breakup
produces the maximum water level.
• Measure or estimate the superficial riverbed material

sizes on gravel bars or along bars at the edge of the river
(use a “by number” rather than “by weight” analysis). The
material on the surface is important is scour calculations –
the superficial material will “armor” or pave the riverbed
thus limiting the scour potential. The finer sand to silt
sizes commonly intermixed with gravel/cobbles/boulders
is not key in computing scour depth. For sand bed rivers,
containing few if any gravel or boulders sizes, undertake
a grain size analysis or a bulk sample to establish bed
material sizes.
• Compute general scour or general riverbed lowering due

to the design flood, using various empirical methods or
computer models.
• Estimate local scour that could occur at channel bends or

at confluences of channels or near bridge piers or river
training structures. From an analysis of extensive
empirical data for gravel bed rivers (where available) and
pipeline operational experience.
Local scour is generally much more significant than
general scour.
• Estimate from field and airphoto assessments, the

potential long term future bank erosion and channel
changes that could affect the crossing. Determine
whether to provide sufficient setbank of the sagbend and
thus pipe profile into the bank (or adequate length or
elevated crossings) for the potential bank erosion or
whether to armor the bank or bridge abutment, thus
protecting the pipeline crossing. The optimum method
depends on site-specific river conditions, pipeline bending
considerations and economics. For economic, pipe
bending and thermal reasons, excavation into a steep
unstable slope may not be desirable thus necessitating
bank armoring structures. The impact of construction on
the stability of the riverbanks should be considered in
establishing sagbend locations.
• Where the pipeline is parallel to, or in the main channel or

floodplain, estimate the potential bank erosion, channel
changes and the development of new channels. A
channel change upstream caused by a landslide or bank
erosion or accumulation of debris can change flow
conditions near to or over the pipeline.
Detail drawing of major river crossing
Detail drawing of minor river crossing
OTHER CROSSINGS CRITERIA
Typical rail way crossing
Detail drawing of rail way crossing
Typical rail way crossing in tunnel
Typical roads crossing
Detail drawing of road crossing
Minor road crossings (open trench)
Access roads

- Section 2.6 : New technologies in Pipeline Route Design
2.4: ROUTING IN MOUNTAINS AND STEEP SLOPES
Design criteria and experiences recommend to cross

mountains and challenging areas selecting pipeline routes
along:
• Ridges
• Valley floors
• Max slope lines
Routes along side slope sections are preferably avoided due to:
• Risk of land slides and increase of accidental loads
(Upstream)
• Risk of soil erosion by rainfall (Downstream)
• Increase of earth works for preparation of right-of-ways
• Widening of right-of-ways and increase of environmental
impact
Therefore, this solution has to be avoided specially when
crossing unstable areas, with poor mechanical characteristics
of the soil, featured by soft clays, loess, loose rocky formations,
morainic deposits and glacial drifts.
When possible, route sections in hilly areas are

preferably designed along ridges and max slope lines.
In these cases, it is necessary to adopt special solutions:
• Narrow right-of-ways
• Special handling and construction means (i.e.
cableway)
• Manual welding in the trench
• Radiographic testing on 100% welds and Ultrasonic
testing on 10% welds (min.).
NPS 48 TRANSMED GAS PIPELINE (ITALY)

CROSSING OF APENNINES CHAIN

PIPELINE ROUTE ALONG RIDGES
OD 48” TRANSMED GAS PIPELINE (ITALY)
STRINGING AND WELDING
RIDGES IN ITALY
STEEP SLOPES: DETAILS
RIDGES IN ALGERIA
SAND BAG REINFORCEMENT ON STEEP SLOPE

2.5 : ONSHORE PIPELINE SURVEYS
A pipeline system survey is sanctioned prior to

construction to obtain a complete and
comprehensive record of all physical aspects
associated with the system.
To design and construct a pipeline project the

following survey activities are required:
9Engineering survey
9Legal survey
9Construction survey
9As-built survey
2.5 : ONSHORE PIPELINE SURVEYS
Engineering survey normally includes:
9 Topographical survey
9 Soil Investigation survey
Topographical Survey
Prior to detailed engineering phase and preparartion
of detailed drawings (alignment sheets and crossing
drawings), a topographical survey is necessary to
acquire and document the following information:
9 a chainage (a measurement along the
length of pipeline) of the proposed ditch
line, taking note of all physical features,
boundaries, road, railways, utility crossings
and special points (e.g., area requiring
buoyancy control);
9 an elevation profile for the entire route;
9 detailed profiles at crossings;
9 site information at proposed facilities.
Topographical Survey
The topo survey can be conducted congruent
with legal survey. The following steps are required:
9 establishing the route

9 running the survey line
9 contour chainage
9 line profile
9 individual profiles
Topo Survey: Establishing the Route
This phase is strictly connected to the results and
knowledge acquired by pipeline engineers during the
field reconnaissance survey.
Particularly, is required the followings:
9 adherence to route established (note all

deviations)
9 maximum utilization of photo-mosaics or
“Google Map” tools
9 use of any related legal plans for paralleling
existing right-of-way
Topo Survey: Running the Survey Line
It requires the following steps:
9 run the survey along the center line of the

ditch
9 show all side bends as deflection (right or
left) and their value and direction.
9 limit all deflection angles to max pipe bend
9 use, when practical, crossings angles no less
than 70 deg at all major crossings (water
courses, roads, railways etc.)
9 verify/mantain required minimum clearance
from any obstacles (buildings, existing
facilities,…)
Topo Survey: Contour Chaining
The contour chain should be developed at no less
than 100-meter intervals and the following items
recorded at the appropriate chainage location:
9 topographical features
9 Description of forestation and vegetation
9 Centerline of roads, trails, railroads,..
9 Cultivated and pasture land, muskeg,
swamp…
9 Fences, power lines, cables
9 Pipeline and other buried utilities
9 Seismic lines
9 Creeks, rivers, steep slopes, water’s edge,
canals, banks
Topo Survey: Line Profile and Individual Profile
In order to develop line profiles it is essential to
utilize available geodetic benchmarks (railways,
highways,…).
Elevation should be taken at all benchmarks locations.
Individual profile should be correlated with adjacent

line profile elevations. Individual profiles are required
for:
9 railroad, highways, secondary roads
9 pipeline crossings
9 river, canals, irrigation ditches
Topographical survey
Topo crews in action
Basic schemes in GPS Survey
Traditional Topo Tools

(Total Station)
A Topo Survey Helping Construction
Soil Investigation Survey
The geological conditions along the route should to be
determined by a dedicated soil investigation survey during front
end or detailed engineering phase.
Boreholes or trial pits are often conveniently sited at regular

intervals along a pipeline route where land access provisionally
agreed.
Minimum design criteria requires:

9 Boreholes up to 10 m depth at every crossing to be
thrust bored and water course
9 Trial pit up to 2,5 m depth every 1000-2000 m
9 Standard laboratory tests (as necessary)
Where geological conditions are variable or particular

problems are expected (rocky areas, faults crossings,
soil liquefaction, slope stability, high water table, sink
holes…) and carry with them cost implications the
numbers/type of investigation increase accordingly.
Execution criteria are established in dedicated

international technical standard (see next pages).
Soil Investigation Survey- Main Codes
ASTM D 420 Investigating And Sampling Soil And Rock For
Engineering Purposes.
ASTM D 421 Dry Preparation Of Soil Samples For Particle-Size
Analysis And Determination Of Soil Constants.
ASTM D 422 Particle-Size Analysis Of Soil.
ASTM D 1194 Bearing Capacity Of Soil For Static Load And Spread
Footings.
ASTM D 1586 Penetration Test And Split-Barrel Sampling Of Soil.
ASTM D 1587 Thin-Walled Tube Sampling Of Soil.
ASTM D 1883 CBR (California Bearing Ratio) Of Laboratory
Compacted Soil.
ASTM D 2166 Unconfined Compressive Strength Of Cohesive Soil.
ASTM D 2216 Laboratory Determination Of Water (Moisture) Content
Of Soil, Rock And Soil-Aggregate Mixtures.
ASTM D 2217 Wet Preparation Of Soil Samples Or Particle Size
Analysis And Determination Of Soil Contents.
ASTM D 2435 One-Dimensional Consolidation Proprieties Of Soil.
Soil Investigation Survey- Main Codes
ASTM D 2487 Classification Of Soils For Engineering Purposes.
ASTM D 2488 Description And Identification Of Soils (Visual-Manual
Procedure).
ASTM-D2573 Standard test method for field vane shear test in
cohesive soil.
ASTM D 420 Investigating And Sampling Soil And Rock For
Engineering Purposes.
ASTM D 2850 Unconsolidated, Undrained Compressive Strength Of
Cohesive Soil In Triaxial Compression.
ASTM D 2938 Unconfined Compressive Strength Of Intact Rock Core
Specimen.
BS 1377 Methods Of Tests For Soil For Civil Engineering Purposes.

BS 5930 Code Of Practice For Site Investigation.
BS 1377 Methods Of Tests For Soil For Civil Engineering Purposes.
Legal Survey
The land to be purchased or leased by the pipeline

owner must be surveyed. Survey plans (e.g.,
cadastral maps) must be prepared for filing at a
land titles office and to form part of the
purchase agreement. Permanent survey
monuments are required at existing property
boundaries, points of intersection and at any
intermediate points necessary to clearly define the
boundary. The work can legitimately be completed
only by a qualified legal surveyor
Legal Survey
Typical Pipeline Cadastral Map in Italy
Construction Survey
Prior to construction, the permanent right-of-way and
temporary lands available during construction must be clearly
marked. Underground utilities and other structures requiring
protection from equipment must be identified.
After clearing and grading the right-of-way, the ditch line is

staked. Each stake will be marked with the chainage at
regular intervals (50 meters or less is common), consistent
with those on the alignment sheets.
The stakes should be offset from the work's side boundary.
The stakes must be maintained throughout the construction

period and utilized for reporting progress and directing
Construction activities.
Construction Survey
In addition, items such as pipe wall thicknesses/grade

changes, buoyancy control measures, and extra depth
requirements must be clearly staked.
In general, the work is a transfer of information from.
The construction drawings to the construction right-of-way.
Additional information, such as cut-and-fill requirements, is

marked on the stakes
As-Built Survey
As-building is the process of transferring the actual
"as-constructed" information on to drawings for future
reference. The objective is to provide an accurate
record of the completed work. The process involves
surveying and documenting the entire system,
including, but not limited to, the following:
9 changes in pipe specifications

9 actual pipe profiles at crossings
9 the location, spacing and number of buoyancy
control devices
As-Built Survey
9 Each mainline weld. The pipe joint and heat
numbers are recorded at and for each weld.
Documentation of weld locations enable future
reconnaissance of individual welds or pipe
joints, such as during in line inspections. Weld
numbers are also recorded on each radiograph.
In general, all details and dimensions given on the

construction drawings are either confirmed or revised
to form a permanent record of the facility as it was
constructed. The following is a step-by-step outline of
the construction as-built survey procedure:
As-Built Survey
The following is a step by step outline of the construction

as-built survey procedure:
9 lay out the right-of-way boundaries and foreign

line crossings
9 mark the centerline
9 consolidate the information
As-Built Survey
As-Built Survey
Information to be gathered during as built survey: reference points
As-Built Survey
Information to be gathered during as built survey: crossings
As-Built Survey
As-Built Survey

- Section 2.4 : Routing in Mountains and Steep Slope
2.6 : NEW TECHNOLOGIES IN PIPELINE ROUTING
The New Design Approach
3D Routing and
Engineering
Satellite and terrain
data acquisition
Airborne and terrain

data acquisition
2.6 : NEW TECHNOLOGIES IN PIPELINE ROUTING
• Remote Sensing
• LiDAR
• Tablet PC
• Geographic Information System (GIS)
Remote Sensing: Definition
Remote Sensing refers to

instrument-based techniques (
usually mounted onboard of a
satellite or an airplane )
employed in the acquisition and
measurement of spatially
organized of an array of target
points (pixels) within the sensed
scene that correspond to
features, objects, and materials
Remote Sensing: General
The overall process of remote sensing can be broken
down into five components:
• an energy source
• the interaction of this energy with particles in atmosphere
• subsequent interaction with the ground target
• energy recorded by sensor as data
• data displayed digitally for visual and numerical interpretation
Remote sensing sensors could be classified in :
• Passive sensors
• Active sensors
Remote Sensing: Passive Sensors
Passive sensors detect
natural radiation that is
emitted or reflected by
the object or surrounding
area being observed.
Reflected sunlight is the

most common source of
radiation measured by
passive sensors.
Examples of passive
remote sensors include
film photography,
Infrared, charge-coupled
devices, and radiometers.
Remote Sensing: Passive Sensors
Passive sensors can only be used to detect energy when the

naturally occurring energy is available. For all reflected energy,
this can only take place during the time when the sun is
illuminating the Earth.
There is no reflected energy available from the sun at night.
Energy that is naturally emitted (such as thermal infrared) can
be detected day or night, as long as the amount of energy is
large enough to be recorded.
Remote Sensing: Passive Sensors in-depth
1. Energy Source or Illumination (A) - the first requirement for remote

sensing is to have an energy source which illuminates or provides
electromagnetic energy to the target of interest.
2. Radiation and the Atmosphere (B) - as the energy travels from its source
to the target, it will come in contact with and interact with the atmosphere
it passes through. This interaction may take place a second time as the
energy travels from the target to the sensor.
3. Interaction with the Target (C) - once the energy makes its way to the
target through the atmosphere, it interacts with the target depending on
the properties of both the target and the radiation.
4. Recording of Energy by the Sensor (D) - after the energy has been
scattered by, or emitted from the target, we require a sensor (remote - not
in contact with the target) to collect and record the electromagnetic
radiation.
5. Transmission, Reception, and Processing (E) - the energy recorded by
the sensor has to be transmitted, often in electronic form, to a receiving
and processing station where the data are processed into an image
(hardcopy and/or digital).
6. Interpretation and Analysis (F) - the processed image is interpreted,
visually and/or digitally or electronically, to extract information about the
target which was illuminated.
7. Application (G) - the final element of the remote sensing process is
achieved when we apply the information we have been able to extract
from the imagery about the target in order to better understand it, reveal
some new information, or assist in solving a particular problem.
Remote Sensing: Active Sensors
Active sensors, emits
energy ( usually in the
microwave spectrum ) in
order to scan objects and
areas whereupon a
sensor then detects and
measures the radiation
that is reflected or
backscattered from the
target. RADAR is an
example of active remote
sensing where the time
delay between emission
and return is measured,
establishing the location,
height, speed and
direction of an object.
.
Remote Sensing: Active Sensors
Active sensors, provide their own energy source for
illumination. The sensor emits radiation which is directed toward
the target to be investigated. The radiation reflected from that
target is detected and measured by the sensor. Advantages for
active sensors include the ability to obtain measurements
anytime, regardless of the time of day or season.
Active sensors can be used for examining wavelengths that are

not sufficiently provided by the sun, such as microwaves, or to
better control the way a target is illuminated. However, active
systems require the generation of a fairly large amount of
energy to adequately illuminate targets. Some examples of
active sensors are a laser fluorosensor and a synthetic
Remote Sensing: Platform
satellite system
Remote sensing
instrument could operate
on orbiting satellites,
airborne platform and
airborne system ground based
instruments.
ground sensors
Remote Sensing: Satellite Platform
Polar orbits
Polar orbiting satellites follow an overhead
path around the Earth so that they pass
near the North and South Poles. They orbit
the Earth as it turns beneath them. This
means that a different part of the Earth’s
surface is viewed by the satellite on each
successive orbit. Eventually the whole globe
is covered, with some overlap at low
latitudes and a great deal of overlap at high
latitudes.
Geostationary orbits
The Earth rotates on its axis once every
twenty four hours. If a satellite is placed in
an orbit at 36,000 km above the equator,
moving in the same direction that the Earth
is turning, it appears to be stationary in
space, "hovering" over its sub-satellite point.
Remote Sensing: Data characteristics
Remote sensing data are characterized by some important

parameters such as :
• Spatial resolution. What can I see ?
• Spectral resolution. How many information do I collect ?
• Radiometric resolution. How accurate information are ?
• Temporal resolution. How often I have this information ?
Remote Sensing: Spatial resolution
Spatial resolution refers to the
Low resolution
size of the smallest object that
can be resolved on the ground. In
a digital image,
A "High Resolution" image

refers to one with a small
resolution size. Fine details can
be seen in a high resolution
image. On the other hand, a
"Low Resolution" image is one
with a large resolution size,i.e.
only coarse features can be
observed in the image.
High resolution
Remote Sensing: Spatial resolution
Remote Sensing: Spectral resolution
The Spectral resolution is

related with the wavelength
width of the different frequency
bands recorded – usually, this
is related to the number of
frequency bands recorded
by the platform. Current
Landsat collection is that of
seven bands, including several
in the infra-red spectrum,
ranging from a spectral
resolution of 0.07 to 2.1 μm.
The Hyperion sensor on Earth
Observing-1 resolves 220
bands from 0.4 to 2.5 μm, with
a spectral resolution of 0.10 to
0.11 μm per band.
Remote Sensing: Radiometric resolution
8-bit quantization (256 levels) Radiometric resolution
The number of different intensities of
radiation the sensor is able to
distinguish. Typically, this ranges from 8
to 14 bits, corresponding to 256 levels of
the gray scale and up to 16,384
intensities or "shades" of colour, in each
4-bit quantization (64 levels) band. It also depends on the instrument
noise. Radiometric Resolution refers to
the smallest change in intensity level
that can be detected by the sensing
system. The intrinsic radiometric
resolution of a sensing system depends
on the signal to noise ratio of the
1-bit quantization (2 levels) detector. In a digital image, the
radiometric resolution is limited by the
number of discrete quantization levels
used to digitize the continuous intensity
value.
Remote Sensing: Temporal resolution
Temporal resolution
The frequency of flyovers by the
satellite or plane, and is only relevant
in time-series studies or those
requiring an averaged or mosaic image
as in deforesting monitoring. This was
first used by the intelligence
community where repeated coverage
revealed changes in infrastructure, the
deployment of units or the
modification/introduction of
equipment. Cloud cover over a given
area or object makes it necessary to
repeat the collection of said location.
Remote Sensing: List of sensors
Remote Sensing example data : Landsat
Remote Sensing example data : SPOT
Remote Sensing example data : IRS - P
Remote Sensing example data : Spot 5
Remote Sensing example data : QuickBird
Remote Sensing example data : IKONOS
Remote Sensing: Considerations
Remote Sensing provides a cost effective means of surveying, monitoring
and mapping objects at or near the surface of Earth.
The practice of remote sensing has become greatly simplified by useful

and affordable commercial software, which has made numerous
advances in recent years.
Saipem uses both ERDAS and ENVI software system for remote sensing
data processing.
Satellite and airborne platforms provides local and regional perspective

views of the Earth’s surface.
These views come in a variety of resolutions and are highly accurate
depictions of surface objects.
LiDAR
What is LiDAR?
• LiDAR Stands for Light
Detection And Ranging and
is an airborne topographic
technique based on Laser
technology
• LiDAR was first developed

in the late 1960s and was
not fully commercialized
until the early 1990s
• SAIPEM owns and

operate a Lidar system
since 1997
How LiDAR works
LiDAR systems are capable of
measuring tridimensional ground
coordinates using :
• GPS signal for recording aircraft

trajectory
• Onboard inertial system ( IMU)

for calculating sensor orientation
• Laser time range for computing

accurate distance from aircraft to
the terrain.
LiDAR System Characteristics
Modern LiDAR systems are

capable to :
• Acquire data with a frequency up

to 200000 measures per seconds
• Sample the terrain with a density

up to 10 points per square meter
• Achieve a vertical accuracy of 5-

30cm ( depending on flight height )
• Fits in virtually any aircraft with a

photogrammetric place
LiDAR: Data Examples
This high density terrain

scanning allow precise
earth surface
reconstruction at a very
high scale
LiDAR : Vegetation penetration
Modern LiDAR systems are capable of
collecting up to forth return laser
pulses allowing veneration penetration
1st and precise terrain mapping
2nd
3rd
4th
First Returns
Second Returns
Third Returns
Last Returns
All Returns
LiDAR : Vegetation penetration
The capability of penetrating
vegetation permits
reconstruction of the surface
with and without the vegetation
LiDAR : Topographic feature
LiDAR data permits to :
• Obtain precise and high

scale topographic data of
large areas very quickly :
• Contour lines
• Quoted points
• TIN ( Triangular models)
• DTM ( Digital Terrain
Model)
• DEM ( Digital Elevation
Model )
• Profiles
• Volume Computation
LiDAR : LiDAR and Aerial Photo Integration
LiDAR systems integrates a
digital photo camera to
achieve an added value
image geo-referenced to the
laser data set.
This integration of
topographic and cartographic
data allow fast and cost
saving pipeline routing
LiDAR : Application for the Pipeline industry
Engineering
Because of the
narrow scanning
swath, airborne
LiDAR is particularly
suitable for rapid
topographic data
collection
of pipelines in a cost-
effective way.
LiDAR: Application for the Pipeline Industry
Lidar data has

great potential
in pipeline
safety
applications.
Using the DTM
derivative as
well as other
data
sources, we
can create a
virtual picture to
evaluate the
pipeline safety
rates.
LiDAR : Application for the Pipeline industry
Monitoring
High accuracy
LiDAR
topographic
data permits
landslide
monitoring
GIS
GIS : Definition
• A formal definition : “A system for
capturing, storing, checking,
integrating, manipulating, analysing
and displaying data which are
spatially referenced to the Earth. This
is normally considered to involve a
spatially referenced computer
database and appropriate
applications software”
• Is a technology - hardware &
software tools
• Is an information handling strategy
• The objective: to improve overall
decision making
GIS : Components
Spatial data
GIS
Computer hardware Specific applications ( SPGM )
& software tools
GIS : What makes data spatial?
Grid co-ordinate Placename
Latitude / Longitude
Postcode
Description
Distance & bearing
Pipeline are spatial data
GIS : kind of data spatial
GIS data represents real objects such as roads, land
use, elevation, trees, waterways, etc. Real objects
can be divided into two abstractions: discrete objects
(e.g., a house) and continuous fields (such as rainfall
amount, or elevations). Traditionally, there are two
broad methods used to store data in a GIS for both
kinds of abstractions mapping references : raster
images and vector.
raster images
Vector data
GIS : The Benefits of GIS
•Save Money/Cost Avoidance

•Save Time
•Increase Efficiency
•Increase Accuracy
•Increase Productivity
•Increase Communication & Collaboration
•Generate Revenue
•Support Decision Making
•Aid Budgeting
•Automate Workflow
•Build an Information Base
•Manage Resources
GIS : Saipem Pipeline GIS Module
SPGM is an ArcGis extension developed inside Saipem for pipeline routing and
engineering.
In particular main characteristic of the tool are :
•2D and 3D routing

• Automatic linear reference of the pipeline
•Creation of the altimetric profile.
• Import-Export of data for other engineering tools. ( Crossing e Sheet )
• Engineering
• Creation of Allignemet-Sheet
• Creation of other kind of drawings ( SIA )
GIS : 3D routing
The SPGM is based on a data model that
uses “linear referencing” for
locating engineering feature along
the line.
The centerline ( geometry of the pipeline )

Pipeline2D Pipeline3D is defined with tree linear feature classes :
•Pipeline ( geometry )
•Alternative ( Pipeline 2D )
•Alternative 3D ( Pipeline 3D )
•All characteristics of the line are defined

by event tables
254
Example of definition of the characteristics of the pipeline using “linear referencing”
255
Allignemet Sheets generation
256
GIS Application in Field Survey: Tablet
Tablet : Pipeline applications
Modern geomatics instrument can acquire accurate terrain data using GPS and GIS technology
Saipem PRG department

developed a tablet GIS
application for acquiring
engineering data on the
field.

- Section 2.4 : Route in Steep Slope
- Section 2.6 : New technologies in Pipeline Route Design
Index

Section 3. : Geotechnical Design
- Section 3.1 : Geohazard Design
- Section 3.2 : Restoration Design
3.1 : GEOHAZARD FOR ONSHORE PIPELINES
A pipeline for the transport of hydrocarbons is a structure with a

linear extension which covers distances in the order of several
hundred kilometres. Its construction involves the traversing of
entire regions with environmental and territorial conditions which
differ totally from zone to zone and which must be addressed
within the scope of the project. In particular, as it deals with a
structure in direct contact with the ground, the geomorphological,
geotechnical, hydraulic and seismic aspects are of fundamental
importance and have a major influence on the project
The pipeline industry has taken a reactive approach to
geohazards throughout most of its history. Incidents were viewed
as random and unpredictable, hence they were managed with
investments in technology and equipment that enabled rapid
response. Proactive risk management gained a foothold in the
mid 1980s and was well established by the mid 1990s.
Corporations that have adopted geohazard risk management
have found, to their surprise, that geohazards represent a much
higher risk exposure than was previously recognised.
Disciplines 1- EARTH SCIENCE
1 • GEOLOGY
2 • SEISMOLOGY
3 • SOIL MECHANICS /
RESPONSE ANALYSIS
4 • PIPE-SOIL INTERACTION
2 – MECHANICAL
3 – CONSTRUCTION
DESIGN
ENGINEERING
1 • SOIL PIPE INTERACTION 1 • GEOLOGY
2 • RESPONSE ANALYSIS 2 • TRENCHING AND
3 • STRENGTH CRITERIA BACKFILLING
4 • RECOMMENDATION FOR 3 • INSTALLATION
CONSTRUCTION 4 • WELDING
4 - MONITORING 5 • PRE COMMISSIONING
1 • SOIL DEFORMATIONS
2 • STRESSES/MOVEMENTS
OF THE PIPELINE
3 • FLOW ASSURANCE/LEAK
DETECTION
4 • ENVIRONMENTAL IMPACT
Geohazards affecting onshore pipelines can be divided into three
broad categories:
9Geotechnical
9Hydrotechnical
9Tectonic
Geotechnical hazards include processes such as landslides,

debris flows, ground settlement, subsidence and soil heave.
Common triggers include high intensity or duration precipitation

events, changes in groundwater conditions, erosion and over-
steepening of slopes, earthquakes, thawing of ice-rich permafrost
and freezing of frost-susceptible soils
Hydrotechnical hazards are associated with stream processes
and include scour, channel degradation, bank erosion,
encroachment, channel avulsion and debris impact on aerial
crossings.
Hydrotechnical hazards usually occur during flood events, in the

case of small streams, and are often triggered by local
precipitation cells. Disturbances to stream channels,
including the effects of landslides, change in forest cover,
degradation of permafrost or the presence of poorly designed
river control structures, can also increase the hazard potential.
Tectonic hazards include a seismic creep, coseismic ground
displacement and rupture, soil liquefaction and lateral spreading,
tsunamis and volcanic eruption.
Despite these hazards being rare, they impact large regions,

causing damage to multiple pipelines and/or multiple sections of
a single pipeline – both directly and indirectly – by spawning
secondary geotechnical and hydrotechnical hazards.
The contribution of tectonic hazards to the overall pipeline risk

can be significant.
Recent studies reviewed incident data from a variety of sources
in order to assess the significance of geohazards in relation to
other hazards affecting pipeline systems. The findings were
summarised: the European Gas Pipeline Incident Data Group
(EGIG)2 attributed 7% of all pipeline incidents in Western Europe
– between 1970 and 2001 – to geohazards (see Figure 1). The
US Department of Transportation (US DOT)3 natural gas
transmission data for the period 1984 to 2001 show that
geohazards accounted for 8.5% of incidents (see Figure 2), and
the National Energy Board of Canada (NEB)4 indicates that
about 12% of incidents affecting Canadian regulated pipelines
are caused by geohazards.
Figure 1: EGIG Pipeline Incident Data1 Figure 2: US DOT Incident Data for Gas Transmission Pipelines
These relatively low failure frequency statistics belie the risk cost
of geohazards to the industry. Geohazard -related incidents often
result in larger leaks, greater property and environmental
damage and longer periods of service disruption. Geohazards
are the second leading cause of pipeline rupture – as opposed to
holes and pinhole cracks – in Western Europe (see Figure 1).
The average cost of a rupture is greater than the cost for
incidents involving holes or small pinhole cracks – this is an
assumption that is supported by the US DOT Office of Pipeline
Safety incident data.3 In the US, property damage resulting
The relative significance of geohazards is even more pronounced

where pipelines are constructed in difficult terrain, without a full
appreciation for potential geohazards.
In South America where geohazards are clearly the leading
cause of failure, with failure frequencies approaching five per
1,000km•yr of operation observed in extreme cases. Data for a
typical Bolivian pipeline indicate that geohazards may be
responsible for as many as 50% of incidents in the South
American Andes, leading to an average failure frequency
exceeding 2.5 per 1,000km•yr. This frequency is about two
orders of magnitude greater than that experienced in Western
Europe. British Petroleum (BP) has reported similar findings for
pipelines operating in Columbia.
Figure 3: Incident Data for a Typical Andean Pipeline
Landslides and hydrological Instabilities
A landslide is a downward movement of a mass of earth on an

slope and subject to the force of gravity. The movement is
caused by a variation of any condition which is capable of
disturbing the temporary balance of the system, such as a
variation in the level of the water table, the presence of materials
which lose their own properties of resistance in the presence of
water, the structure of the material, the topography, seismic
activity, etc..
During the phase in which the route is being selected, it is of

fundamental importance to identify all the unstable or potentially
unstable slopes in order to avoid crossing them.
The type and distribution of natural landslides are very varied

and are dependent on the morphology of the terrain and its local
characteristics, in addition to the sub-soil hydraulic conditions.
Even if an aerial photograph might be of value in identifying the
areas at risk of landslides, many instabilities are too small or, in
any case, too difficult to identify using this technique. A visual
inspection is always necessary and has the objective of
identifying all the signs typically associated with active movement
of the ground or with landslides which occurred in the past and
which could recur with the installation of a pipeline
Selected ground failure associated with landsliding
Typical signs of hydro-geological instability are the presence of
steep escarpments, crevices and fissures upstream of a slope,
swellings and accumulations at the foot of a slope; the presence
of bent trees; damage or changes to the alignment of structures
(roads, telegraph or electrical poles, pipelines). These and other
signs may also contribute to the identification of the boundaries
of the area subject to landslide
The most dangerous type of landslide for a pipeline project is
when it is deep, in which the failure plane is situated a long way
below the trench bottom. This situation should be avoided, even
though, technically, it is possible to design and build a pipeline
which crosses a potentially unstable area without causing new
movements.
In this case, a stability study of the incline in question is

fundamentally important and presupposes a meticulous analysis
of the area in morphological, geological and geotechnical,
physical and hydraulic terms, with the objective of understanding
the forces which control the movement.
PIPELINE SLOPE CROSSING ENGINEERING
1- site reconnaissance; 3- pipeline strength capacity assessment;
soil data failure mode identification and limit state equation
definition
3D grid of the area
parent pipe strength capacity assessment under
ground water table operation and environmental loads
rainfall girth weld strength capacity assessment under
inclino-metric measurements operation and environmental loads
piezometric measurements
seismic environment assessment 4 - structural analysis
mapping of down-slope movements identification of soil movements profile/s
definition of causes of landslide pipe response analysis/probabilistic assessment
allowance check (limit state based)
2 - geotechnical analysis
use of data to establish cause-effect relationship 5 - remedial action recommendations
numerical modelling of the slope – trend analysis soil stabilisation
- simplified (limit equilibrium) monitoring system for the slope (inclinometers,
piezometres, rainfall, etc.)
- detailed (deformation analysis)
monitoring system for the pipe response (estensimetric
soil pipe interaction – loads transferred from/to the
sections)
pipe
“stress relieving” excavation works programme
6 - documentation for authority approval
Once the forces involved and the processes which act to improve
or disturb the existing conditions of equilibrium have been
identified, it is possible to begin the design of the pipeline and of
any work needed to stabilize the slope. Identifying the existence
of potential hydro-geological instabilities also has a determining
influence during the operation stage of the pipeline, affecting the
management and maintenance activities which often have to be
supported by an appropriate and careful monitoring programme
which controls the geotechnical and physical conditions that
underlie the forces of instability.
Interaction between instability and a pipeline

crossing a slope
In particular, an inclinometer for the direct measurement of the

shifting of the terrain and a piezometer for measuring the
variations of the underground water table are used, in
conjunction with a pluviometer for measuring the amount of
rainfall in the area under examination. The study of a landslide
often involves the use of numerical modelling which, through a
series of simulations based on different values of the model’s
basic parameters, contributes to finding the most probable
values of the parameters involved and to the understanding
of the phenomenology which characterizes the
movement of the ground.
single inclinometer: graphics of terrain movements in depth
terrain movements assessment by inclinometer
Numerical modelling is also finding significant use in the
pipeline’s operating phase: combined with the monitoring activity,
it can contribute to the prevention of damage resulting from
catastrophic events, enabling creation of a forecast analysis of
the pipeline’s possible structural response to the induced
stresses 2500
2000 BENDING MOMENT ON

1500 PIPELINE DUE TO SOIL
1000 MOVEMENTS
500
0
0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160
-500
-1000
P2 I2
Imp. Vdis. 100 mm
-1500 Imp. Vdis. 200 mm
Imp. Vdis. 300 mm
I2-I7 -2000 Imp. Vdis. 400 mm
Imp. Vdis. 500 mm
-2500
P4 I3 X [m ]
2500
V ib ra tin g W ir e S tr a in G o u g e s in s e rv ic e
C o m b in e d B e n d in g M o m e n t fo r s o il d is p l. 5 0 0 m m
B-B1 P ro p o s e d N e w S tra in G a u g e s
2000
I7 P4
LANDSLIDE 1500
ESTENSIMETRIC
AREA STATION LOCATION
1000
vs. BENDING MOMENT

500
0
30 35 40 45 50 55 60 65 70 75 80 85 90
-5 0 0
P ro g re s s iv e [m ]
The causes of geological instabilities are therefore varied and
diverse. Natural events can act in such a way as to increase the
destabilizing forces (e.g. accumulated deposits, seismic forces)
or of reducing the forces of resistance (for example, erosion at
the foot of a slope, increase of interstitial pressure, etc.). In
particular, instances of heavy rainfall can cause a massive
infiltration of water into the sub-soil, increasing the interstitial
pressure in the ground and reducing its resistance
characteristics, create serious erosion as a result of the run-off of
surface water and the increase of the flow-rate of the water
courses, and constitute a potential overload, saturating the
ground itself.
The activities connected with the construction of the pipeline can

also disturb the balance of a slope. Opening a site road for the
normal construction activities often involves excavating a stretch
of sloping ground and therefore presupposes a careful selection
of the sites for the dumping or storing of excavated material,
which could constitute an overload for the ground, sufficient to
reactivate a dormant movement. The operations to restore the
profile of the terrain to what it was before installation of the
pipeline, to reduce the visual impact on the environment, can
have a further destabilizing effect when new material is
substituted or the original material is returned having been
previously taken away and, therefore, altered.
Hydro-geological
instability Example NPS 48 gas pipeline
A crucial element in the design of an onshore pipeline is that of
checking the surface and underground drainage in the area
which falls within the strip of land along which the pipeline itself
will run and the erosive effects associated with the flow of water.
Careful planning of specific works capable of controlling the
hydraulic regime is generally effective in avoiding the
appearance of serious erosive phenomena which could expose
the pipeline to the external environment or initiate processes of
instability. Works of this type consist of diversion channels,
gabions, dykes and drains.
Landslides and Seismic Activity
One of the consequences of a seismic event is instability of

inclines and slopes. During an earthquake, a system of
acceleration waves passes through the ground, propagating from
the point of origin in the sub-soil towards the surface. The
transient dynamic load which instantly follows alters the tensional
regime which establishes the nature of the balance of a slope,
simultaneously causing an increase in the acting shear force and
a diminution of the resistance capacity of the ground, as a result
of the sudden increase of interstitial pressures.
Other factors which influence the response of a slope during a
seismic event are the magnitude of the event, its duration, the
resistance characteristics under conditions of dynamic stress of
the material of which it is composed, and the dimensions of the
slope.
There are a variety of methods for analysing the stability of a

slope under seismic conditions. The most common are the
pseudostatic limit-equilibrium method and the sliding block
analysis method perfected by Nathan M. Newmark.
The first involves modifying the conventional limit-equilibrium

analysis adding to the forces involved, a component derived from
the seismic activity which is assumed to be a fraction of the
weight of the potential landmass involved in the landslide
multiplied by the acceleration.
Newmark’s method is based on the movements of an

embankment during seismic activity. It consists of a combination
of conventional pseudostatic procedures with a background of
dynamic considerations on the movement of the ground.
Seismic Faults
Faults are fractures in the rock-mass associated with the

different movements of the two parts in contact with each other.
Deforming movements are not restricted merely to sliding along
one or more fracture surfaces but can also be accompanied by
distortion, breakage and fragmentation of the rock at the contact
surfaces generating fault breccias called mylonites. The
movements can occur suddenly, following to an earthquake, or
build-up gradually over time and constitute a serious threat to the
integrity of a pipeline which crosses a fault.
Seismic Faults
The length of the fracture and the extent of the movement
depend on the magnitude of the seismic event and the depth at
which it takes place, while the classification of the various types
of faults is based on the geometric characteristics of the sliding
(Bonilla, 1970). From the point of view of the interaction with a
pipeline, crossing a fault should be avoided inasmuch as it can
cause intolerable conditions of stress for the structural integrity
and the efficient operation of the pipeline itself.
Seismic Faults
Interaction between a fault and the pipeline which crosses it.
Seismic Faults
To create an effective design for a pipeline which will be capable

of resisting the deformation to which it might be subjected in
crossing a fault, it is necessary to know the geometry and
typology of the fault, and the size of the area in question, to know
if it involves a movement caused by an earthquake or by a stress
build-up over time (creep) and, obviously, to examine the
characteristics of the terrain. Certainly, the most important factor,
is represented by the type and extent of the sliding which can be
assessed on the basis of the characteristics of the associated
seismic event.
Seismic Faults
• Amount of relative fault movements
• Pipeline-fault crossing angle
• Depth of burial
• Trench configuration
• Soil properties
• Effective unanchored length
• Pipeline diameter and wall thickness
• Material properties
• Internal pressure and temperature
• Layout
Seismic Faults
It is very desirable to force

the pipeline to conform to
ground displacements with
tensile elongation, kept
within a reasonable bound by
adjusting the fault crossing
angle of the pipeline to suit
the particular type of fault
displacement expected
Seismic Faults
It is very desirable to force the pipeline to conform to ground
displacements minimizing axial compressive force, kept within a
reasonable bound by adjusting the fault crossing angle of the pipeline to
suit the particular type of fault displacement expected
Seismic Faults
• The fault crossing (strength) capacity of the pipeline:
- is independent of the pipeline diameter (there is a link between
maximum forces the backfilling material can apply and pipeline
bending stiffness depending on pipe diameter), and directly
dependent on the wall thickness; the higher the wall thickness the
lower the tensile strain
- is dependent on the material strain hardening capacity, so that the
higher the modulus in the plastic range the lower the potential of
strain concentration at fault crossing
- is dependent on internal pressure, which reduces the propensity
to develop hoop ovalization, increasing bending strains, and
reduces the resistance of defective girth welds
Seismic Faults
TRENCH CONCEPT
• The trench concepts are based on the principle that, when the
fault moves, the pipeline shall be capable to absorb
movements without developing excessive deformations.
• The backfilling material in the trench around the pipe offers

low restraint to the pipeline as faults move.
Seismic Faults
SAKHALIN II PROJECT
(RUSSIA) No. Name
KP
Existing
EXPERIENCE (2006-2008)
1 Alt Goromai (Piltun reroutes) 12.45
3 Kliuchevskoi (Yasnoye section) 117.68
4 Kliuchevskoi (Desiataya rechka) 180.04
5 Kliuchevskoi (South Khandasa section) 185.32
6 Kliuchevskoi (Additional Branch) 188.34
7 Kliuchevskoi (Pobedino section) 208.05
8 Kliuchevskoi (Smimikh section) 223.77
9 Kliuchevskoi (Gastello section) 300.85
10 Gastello Hanging wall 301.85
11 East Makarov - Additional 3 342.36
14 East Makarov 342.955
15 West Makarov 346.97
16 Chernaya River 480.78
17 Kirpichnaya River 492
18 Alt Kliuchevskoi (South from Sovetskoe) 508.75
20 Kliuchevskoi (West from Yushnyi ) 567.24
21 Kliuchevskoi (West from Yushnyi) 569.42
Seismic Faults
a1) Pipe section in proximity of the fault crossing within
STRIKE-SLIP FAULTS fault accuracy width (shear zone);
a2) Pipe section, approx. 50 m long on each side,
adjacent to the shear zone, where either the fault
movements are to be suitably managed (transition
zone) or the effect can be considered as
extinguishing;
a4) The pipe section starting from the end of section
a2), where the pipe moves axially up to the bends.
a3) The pipe section after a4), including the hot bends,
where horizontal pipe movements have to be
absorbed due to the bending and stretching of the
pipeline at fault.
Seismic Faults
Sakhalin II Project: A further problem was freezing of water inside the
trench.
Design solutions to avoid freezing of the backfill material during winter
and to control the pipeline buoyancy was:
• Trench sealing with geomembrane

• Surface and intra-trench drainage
• Trench thermal insulation
Seismic Faults
Sakhalin Trench Design Solutions
• Sealing of the Trench surface in all areas
• Sealing of the sides of the Trench in high soil

permeability areas
• Drainage of the backfill
• Pipeline installation in embankment where water

table is at the ground surface to facilitate drainage
Seismic Faults
Trench Design Solutions

Drained Trench
Seismic Faults

Sealed Trench
Seismic Faults
Embankment Concept
Seismic Faults in Sakhalin
Seismic Faults in Sakhalin
Seismic Faults: Best Practice
TO IMPROVE THE CAPABILITY OF THE PIPELINE TO WITHSTAND
DIFFERENTIAL MOVEMENTS ALONG THE FAULT
1. STRIKE-SLIP FAULT ⇒ where practical, orientation so that the
pipeline is in tension.
2. REVERSE FAULT ⇒ oblique as much as possible, to minimise
compression (combined to bending).
3. In the proximity of the fault, straight sections without sharp changes in
direction and elevation, particularly field bends, elbows, stub-ins, and
flanges that tend to anchor the pipeline.
3. Minimum burial depth.
4. Thick wall pipes within 200 to 300 pipe diameters each side of the
rupture line, ensuring weld integrity as well as anticorrosion
protection.
5. Use hard smooth coating such as epoxy coating.
6. Loose to medium granular soil without cobbles and boulders within
200 to 300 pipe diameters each side from the rupture line.
Seismic Activity
Seismic activity does not affect only the stability of slopes. The
reduction of the shear resistance of a terrain combined with the
increase in interstitial pressures can cause fluidization of the
soil, especially in the case of loose, saturated sands, and the
development of large and permanent deformations capable of
causing serious damage to any type of structure resting on the
affected terrain. It is possible to identify three types of movement
or breakage of the terrain associated with the process of
fluidization: widespread lateral deformation, gravitational flow
and reduction in the ground’s bearing capacity.
Seismic Activity
Other effects are subsidence, and above all the raising of an
originally buried pipeline caused by its floating in the temporarily
fluidized groundmass. Widespread lateral deformation relates
to the horizontal shifting of the upper beds of the terrain resulting
from fluidization of the underlying ground. It is a phenomenon
that occurs in areas with gentle slopes, and the associated
sliding are measured in tens of centimetres. Such movements
can have a very destructive effect on pipelines, even if the level
of damage depends on the extent of the movement and on the
characteristics of the pipeline itself.
Seismic Activity
From the point of view of planning analyses, the study of the
pipeline, with respect to widespread superficial deformations,
presents similar problems to those resulting from faults. The
deformations are concentrated in the sliding area, as happens
with the movements of a normal fault. At the base of the mass,
instead, a compression takes place similar to that of a reverse
fault.
Seismic Activity
Gravitational flows relate to the movement of fluidized masses,

occasionally containing rocks boulders which slide down steep
slopes. However, many of these occurrences are more frequent
in a sub sea environment. The reduction of the ground’s bearing
capacity can cause serious sinking in a structure built on it, such
as, for example, an embankment, and therefore, can induce
tractive forces of traction on a pipeline which crosses it or
compressive forces in the adjoining areas. To prevent the buried
pipeline from floating in the fluidized groundmass, systems for
anchoring and weighting the pipeline are used
Seismic Activity
Liquefaction susceptibility is the relative resistance of a
deposit to loss of strength when subjected to earthquake. From a
physical point of view, the potential liquefaction depends on both
the susceptibility of a deposit to liquefy and the opportunity for
ground motions to exceed a specified threshold level.
Pipeline design, hence, should taking account liquefaction
potential of the crossed areas. To do this, along the pipeline
route, screening investigations should be performed to determine
whether a given site has obvious indicators of a low potential for
liquefaction failure, or whether a more comprehensive field
investigation is necessary to determine the potential for pipeline
damaging during earthquakes.
Seismic Activity
Pipelines buried beneath the water table in liquefaction-susceptible soils can

either float up or settle down during an earthquake depending on the specific
gravity of the pipeline relative to the liquefied soil and the residual shear
strength of the liquefied soil. Above figure illustrates floatation and settlement
of a pipeline in a liquefied soil.
Seismic Activity
Pipeline floatation resulting from buoyancy forces, generally, has

not been a significant hazard to buried onshore pipelines. It can
be readily visualized that the pipeline movement will be limited to
the extent that it is buried and will generally be exposed to a
limited liquefied soil zone. Significant strains will typically not
develop as a result of floatation.
However, if the pipeline is located within a liquefiable soil that is

on a slope, then the pipeline will also tend to be deformed in the
direction of the soil flow down the slope. In addition, settling into
or floating up out of the soil can occur.
Seismic Activity
Liquefaction features typically occur during long-duration, strong

ground motion generally exceeding 0.15 g peak ground
acceleration (PGA).
The vast majority of liquefaction hazards are associated with

sandy soils and silty soils of low plasticity.
Cohesive soils are generally not considered susceptible to soil

liquefaction.
Seismic Activity
Methods that satisfy the requirements of a screening
evaluation, at least in some situations, include:
• Direct in-situ relative density measurements, such as the

ASTM D 1586-92 (Standard Penetration Test [SPT]) or
ASTM D3441-94 (Cone Penetration Test [CPT]).
• Preliminary analysis of hydrologic conditions (e.g.,

current, historical and potential future depth(s) to
subsurface water). Current groundwater level data,
including perched water tables, may be obtained from
permanent wells, driller's logs and exploratory borings.
Seismic Activity
• Historical groundwater data can be found in reports by

various government agencies, although such reports
often provide information only on water from production
zones and ignore shallower water.
• Geophysical measurements of shear-wave velocities.
"Threshold strain" techniques represent a conservative
basis for screening of some soils and some sites
(National Research Council, 1985).
These methods provide only a very conservative bound for

such screening, however, and so are conclusive only for
sites where the potential for liquefaction hazards is very
low.
Seismic Activity
Lateral spreading is the result of soil liquefaction. A
lateral spread can be particularly hazardous to pipelines
(again, particularly buried pipelines) due to the fact that
the liquefied soil layer is beneath a layer of non-liquefied
soil. The liquefaction of the lower soil strata can result in
the movement of the soil block above; even where the
ground level above is almost flat (no-slope). A pipeline
segment that is buried in a location where lateral spreads
are likely or statistically reasonably probable is at
considerable risk due to the nature of lateral spreads,
which can be very destructive to a buried pipeline. The risk
is obviously related to the degree of soil movement above
the liquefied strata and the orientation of the pipeline
relative to the movement.
Seismic Activity
Lateral spread movement is the most common and one of
the most severe earthquake hazards for buried pipelines.
Schematic depiction of a lateral spreading resulting from soil liquefaction in an earthquake
Seismic Activity
The geologic conditions conducive to lateral spreading
(gentle surface slope, shallow water table, and liquefiable
cohesionless soils) are frequently found along streams
and other waterfronts in recent alluvial or deltaic deposits,
as well as in loosely-placed, saturated, sandy fills.
Horizontal displacements in a lateral spread can range up
to several meters with smaller associated settlements.
Seismic Activity
Lateral and longitudinal soil block

movements relative to the
pipeline axis
Seismic Activity
Liquefaction and lateral spreading of (a) Gently sloping ground and (b) Toward a free face.
GEOHAZARD
AN EXAMPLE OF DEBRIS FLOW
GEOHAZARD: AN EXAMPLE OF DEBRIS FLOW
THE BASIN
EXISTING PIPELINE ROUTE
DESIGN SCHEMATIC CROSS SECTION
Some possible re-routings are under studing: Option 1 (open trench solution)
Open trench solution: cross sections
Some possible re-routings: Option 2 (tunnel solution)
Option 2: Tunnel profile & sections
Index

Section 3. : Geotechnical Design
- Section 3.1 : Geohazard Criteria
- Section 3.2 : Restoration Design Criteria
3.2 : RESTORATION DESIGN CRITERIA
343 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010

33
343
The following basic geotechnical guidelines should be taken into
consideration during the selection of a pipeline route :
9 Wherever possible, pipelines must be located so as to avoid

side or cross slopes. If a cross slope is unavoidable, the fall
line of the slope must be at 90" to the centerline of the pipe.
9 However, pipeline construction procedures require that the

working side of the right-of-way must be essentially level in
order to install and backfill the pipeline. In areas with
excessive cross slope, considerable grading is required to
construct the pipeline.
9 The centerline of the pipeline should be parallel to the fall line
of the slope in order to reduce the chance of pipe rupture due
to slope movement.
9 The alignment of the pipe should also minimize grading and
slope disturbance.
9 Wherever possible, pipelines should avoid unstable slopes.
This does not necessarily include old, inactive slides, as
many slopes will have experienced some form of instability. It
is more important to avoid slopes displaying signs of recent
movement.
9 Some of the more obvious signs of possible recent slope
movement are cracks, scarps, curved trees, evidence of toe
erosion, and the exit of groundwater onto the slope (in the
form of a spring).
9 If there is evidence of recent instability, the nature of the
mass movement must be assessed. Deep-seated movements
often require relocation of the proposed pipeline route,
particularly since the cost of slope stabilization can be
excessive and may not be reliable. In some cases, shallow
movements are not a major stabilization problem and can be
accommodated in the Design.
9 The most cost-effective approach must be taken. The cost of

stabilization measures such as grading and drainage control
(surface and subsurface) has to be compared with the cost of
rerouting the pipeline to a more stable area
9 A detailed subsurface investigation and stability analysis is
required for any slope suspected of being potentially unstable
along the preferred pipeline route.
9 One of the most important steps in the selection of a pipeline

route is the determination of river crossing locations. River
crossings can have a significant effect on both the cost of a
pipeline and the total length of the line.
9 Some of the basic rules of route selection at river crossings

are:
- It is essential to find the most suitable riverbed.
Bedrock requires expensive blasting while very
silty river beds can require large excavations.
- Pipelines should cross rivers at right angles in
order to minimize the width of the crossing and to
avoid side slopes on the approaches.
- Active bank erosion can lead to exposing and

damaging the pipeline as well as impacting the
environment.
- Fast-flowing sections of the river should be

avoided as they can make construction difficult.
- The crossing should be located in a straight

section of the river to minimize active bank erosion
Drainage padding
Subdrain
Pipeline protection
Trench breakers
Fascine bundle
Palisade
Timber retaining wall (simple)
Timber retaining wall (double)
Earth reinforced
Gabions on concrete slab
Cut stone wall
Massive stone wall
Gabions retaining wall
Concrete retaining wall
Concrete trench breaker
Concrete beam on micropiles
Concrete beam on drilled piles
RESTORATION OF SLOPE: AFTER COMPLETION
RESTORATION OF SLOPE: FEW MONTHS LATER
RESTORATION OF SLOPE: FEW YEARS LATER
NPS 48 GRIES-MASERA SECTION (ITALY)

Before Construction

During Construction

After Construction

Before Construction
NPS 48 GRIES-MASERA (ITALY)

During Construction
NPS 48 GRIES-MASERA (ITALY)

After Construction
Gas Pipeline Montalbano-Messina ND 1200 (48”) (Sicily – Italy)
Morphological and environmental reinstatement of a sharply

sloping section
The area corresponds to the peak of the left hydrographic slope

of the Macria Stream, in the territory of Messina. Photos 1/A
and 1/B present an overview of the slope indicating the position
of the existing pipelines (Ga.Me. A,B) and that of the pipeline
currently under construction (Ga.Me. C). Respectively, these
photos show the sites before and during pipeline construction
works
Photo 1/A Area prior to the works Photo 1/B View of the area during excavation
Geology:
Two distinct lithofacies have been encountered:
the pelithic-sandy facies (of sandstone, at the top of the

slope) and the arenaceous-pelithic facies, characterized
by medium-to-coarse sandstone alternating with silty-
clayey and
marly clay levels, outcropping at the middle of the slope

and near the Macria stream bed.
The presence of the sandstone makes the peak very steep and
also makes sub-vertical excavation possible
Photo 2 Front view of the excavation trench. Photo 3 Detailed view of the excavation
DESIGN SOLUTION:
a vertical, reinforced concrete wall was used (4.50 meters high). Since
it was not possible to create a surface foundation, the wall was
anchored to the ground with 14 sub-horizontal anchoring tie-rods
a geosynthetics-reinforced soil made it possible to restore the

geomechanical parameters needed by the backfill soil to create the
required sub-vertical face.
the last three meters at the top were contained by a galvanized metal
mesh gabion wall filled with gravel and with buried outer face. The
same type was used at the foot of the reinforced concrete wall to
ensure that it was “camouflaged”
1. Drilling, injection and tie-rod hardening
Photo 4 Drilling machine for tie-rods. Photo 5 Tie-rods inserted into ground.
2. Preparation of wall armature, casting reinforced concrete beam and setting
Preparation of wall armature, casting reinforced concrete beam and setting
Photo 6 Armature for beam foundation. Photo 7 Hardening of the concrete.
3/4. Beam backfilling to approximately H=4m and Tie-rod prestressing

(prestressing load 20t)
Photo 8 Beam backfilling with soil. Photo 9 Tie-rod prestressing with hydraulic jacks.
5. Construction of overlying works: reinforced soil
Details of reinforcing geosynthetics, geomat and formworks
GEOTECHNICAL DESIGN GUIDELINES
6. Construction of overlying works: gabion walls
Photo 14 Construction of second gabion wall. Photo 15 Reaching design height.
6. Construction of overlying works: gabion walls
Hydroseeding of the reinforced soil
View of slope during conclusionof the works.

Final reinstatement of the slope
Pipeline Malborghetto – Bordano NPS 48 - Client (Snam Rete Gas- Italy)
Morphological restorations by means of naturalistic engineering

techniques and vegetational restoration with seeding and plantation of
local native shrubs and trees
The pipeline Malborghetto – Bordano stretches southwards,
beginning from the Northern locations Val Canale, Canal del
Ferro, Val Gleris, Val Alba, Val Aupa, then the river-plain
Fella and Tagliamento, running along a pre-existing right of
way (ROW).
Some significant examples of morphological and
vegetational restoration of the suitable ROW for pipeline
construction will be briefly described.
The works carried out in Val Aupa are significant:

naturalistic engineering techniques were adopted here for
slope stability together with vegetational restoration
(seeding and plantation).
The slope consolidation and stabilization required the following timber

structures:
• Planted piling (double-layer timber walls with shrub

anchoring)
• Planted shrub strings
• Faggots
• Palisade
Local native sprouts of arboreous shrubs in casing were planted.
In Val Aupa the pipeline route in the north-stream end affected pinewoods of
the kind of Pinus sylvestris and mountain Pine, for a total ROW length of
approx. 2500 m and a total surface of seeding and plantation restoration of
approx. 50000m2. The aim was that to reinstate the natural vegetation made
out of deciduous-leaf hardwood trees (ostryeto ornus - manna-ash).
The composition of the plantation was:

Mountain Maple tree 10%, Ornus 20%, Dark Carpino 20%, Hazelnut Tree 10%,
Mountain Ash 10%, Barberry 10%, Raven Pear 5%, Oleaster Willow 7,5%,
Purple Willow 7,5%.
N° trees: 480
For a close up view of the naturalistic engineering works, a typical sketch of

planted shrub string is depicted:
This work is carried out following these steps: at first longitudinal timber poles
are installed, then these are secured to the ground by means of wooden pegs.
A layer of coniferous shrubs is placed on and on it a layer of soil. Cutlings are
planted perpendicular to and with conterslope with respect to the main slope.
One more retaining structure used along the ROW was the double-layer
timber wall, referred to in our drawings as planted piling (double-layer timber
walls with shrub anchoring).
Final result nowadays:
SOIL BIOENGINEERING METHODS IN

PIPELINES
THE LAST TENDENCIES DESIGN
Up until the 90s, planning criteria for gas pipelines were based on
restoration “as is”, specifically aimed at the restoration of the shape and
geometry of the places affected by the earth movements and the
repositioning of the cut forest trees, respecting the numbers, species and
original layout of the same.
Subsequently, with the focusing of attention on the environment and on the
safeguarding of biodiversity, with the introduction in the national legislative
field of the Evaluation of Environmental Impact (E.E.I), with the setting up of
the Natura 2000 Network, the establishment of Sites of Community
Importance (SCI) and impact evaluation procedures, with the adoption of
territorial protection instruments (regional and provincial landscape plans,
setting up of and implementing provisions for Parks), the approach to the
environment has gradually changed, developing into an integrated
ecosystems approach.
This has dictated new planning criteria which have changed the
aforementioned objectives, particularly as regards morphological restoration
techniques which have evolved towards:
9 towards the soil bioengineering concept (with the use of living plants
and their root systems for land stabilisation works and hydraulic
defence works) and
9 towards vegetation restoration techniques in accordance with

ecological criteria, with the use of pioneer species, shrubby species,
autochthonous species, and with the selection of specialised plant
nurseries, with planting out and maintenance of the plantations.
Since the end of the '90s, the planning of restoration and mitigation works has
therefore taken into account the the “ante operam” conditions of the habitats
affected.
To this end, phytosociological and pedological studies are carried out within the
Test Areas along the pipeline routes in stretches of particular environmental
significance. In this way, also any disturbance created in Natura 2000 Network
Sites is analysed.
In addition to these botanical and pedological studies, faunal analyses are

becoming increasingly more frequent, especially in the Special Protection Areas
and in the I.B.A. (Important Bird Areas), in the portions of territory affected by
the passage of the pipeline.
These studies were applied for the first time for the North European Gas
Pipeline DN 1200 mm (48”) in the “Passo Gries – Mortara” section.
The vegetation restoration works of the Passo Gries – Mortara
gas pipeline were carried out in the period from 2000 to 2002
and involved the planting out of trees and shrubs "in clumps"
and protected by circular fences, thereby creating the so-called
“vegetation islands”.
The purpose of restoration in clumps is to create centres of

vegetation which accelerate the natural evolutionary processes
and which cover the right of way in a structured and
irregular fashion, creating spatial discontinuity (clearings)
amidst the herbaceous and shrubby vegetation.
Also in the stretches of mature forest “pioneer” plant species

were integrated with the surrounding vegetation (e.g. Willow
and Alder trees), able to colonise the soil more rapidly and
contribute more naturally to the development of the vegetation
restored towards the forest.
Vegetation islands
Passo Gries - Mortara Gas Pipeline: Vegetation Islands
2002 2008
Passo Gries - Mortara : Vegetation Islands
2002 2008
Malborghetto – Bordano Gas Pipeline : Revegetation Techniques
2003
2005
2009
Index

Authority Engineering: Public Permits
Pipeline construction is subject to several public

authorization procedures according with local law and
regulations.
In all cases, the relevant authority will convene dedicated

meeting at which all local entities involved in the project will
be asked to participate.
Procedures may be activated on the basis of a preliminary

project including adequate maps identifying those areas
potentially affected by restrictions.
In general, documents required for initiating the procedure

are:
9 General technical report
9 Project map with urban planning resources including:

pipeline route, line stations, service easement area, areas
outside the easement area to be occupied temporarily,
location of related work;
9 Standard design plans
For projects that do not involve protected areas, the

procedure may include a preliminary "screening" phase to
determine if the project is subject to impact assessment
study. The screening procedure normally includes:
9 General technical report subdivided into three parts:
conflicts with restrictions, outline of the project and physical
characteristics of the area it will cross
9 Project maps including: pipeline route, line stations,
widening of passage areas, pipe storage areas, temporary
storage areas and location of related work;
9 Theme-related ground plans concerning resources for
local conservation and planning and urban planning,
geological characteristics and land use;
9 Standard design plans
When, either given the dimensional characteristics of the

project or the outcome of the screening, an Environmental
Impact Assessment (EIA) is normally requested.
The EIA Study is normally divided into three sections.
The sections are structured independently so that each
provides a full analysis of its topic. These topics are:
9 the “programmatic framework” outlines the report and

how the project coheres to local and sector planning and
programming requirements
9 the “project and design framework” outlines the project

and solutions adopted on the basis of research
undertaken
9 the ”environmental framework” describes the

environmental systems involved in the project and
provides a qualitative and quantitative estimate of the
impacts on the environment caused by the project
The report may also be accompanied by theme-specific

maps, a short “Non-technical Summary”.
Authority Engineering: Right-of-Way Acquisition
The acquisition of a pipeline right-of-way often raises many questions with

landowners -"Why is this the route for the pipeline? Why is the pipeline
needed? What is the procedure for acquiring approval for use of my land?
How will I be compensated? How will the land be restored after construction?
Can I use the land after the pipeline is installed?"
To answer those questions, let us look first at the process. The cornerstone of
the right-of-way acquisition process is the negotiation of an Easement
Agreement.
This agreement covers key issues such as compensation, restoration of the

land and restrictions on future use of the land. Once the pipeline route is
selected, a right-of-way agent from the pipeline company will contact each
affected landowner along the route to discuss the project and negotiate an
easement agreement.
In addition to a permanent easement the company requires to operate and

maintain its pipeline after it is constructed, the company also requires a
temporary easement during construction.
The permanent easement typically is about 20 m wide in Italy (gas pipeline

with DP >24 bar) and the temporary easement typically will range between an
additional 10 m depending on the size of pipeline, larger pipelines require the
use of bigger equipment and more room to operate. The amount of workspace
required is also dependent on the type of terrain being crossed and any
special construction requirements.
ACQUISITION OF PIPELINE RIGHT-OF-WAY
Right-of-way for gas pipeline in Italy
pipeline
20 m 20 m DP> 24 bar
8m 8m DP = 24 bar
6m 6m DP =12 bar
420 15
04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 420
Construction area
30 m for NPS 48
Materiale
di scavo
Scotico
421 15
16
The landowner is normally compensated a fair market value for the

permanent easement, which while typically allows the landowner continued
use and enjoyment of their property, but with some limitations. The
limitations typically prohibit structures and trees within the easement in
order to preserve safe access of maintenance equipment when necessary
and allows for uninhibited aerial inspection of the pipeline system.
The landowner is generally compensated a lower value for the use of the
temporary construction easement, since this land reverts back to the
landowner after construction for their full use and enjoyment without any
restrictions.
Additionally, landowners are compensated for any damages/losses they
may incur as a result of the construction across their property, such as loss
of crop revenues.
422 15
16
Sometimes, the landowner and the pipeline company may not be able to
reach agreement on the terms of an easement. If the commission
determines there is a public need for the pipeline, it will grant the pipeline
company access to the land under eminent domain - the right of the
government to take private land for public use, the same right afforded
utilities, telecommunications companies, railroads and the transportation
infrastructure in many countries.
It is important to point out that, for pipeline projects, eminent domain

applies only to the specific facilities and uses authorized by the
commission. State then supervise the fair compensation and treatment of
the landowner.
423 15
16
Index

HYDRAULICS CONTENTS
1. Types of transport pipelines and products

2. Pipeline system design – Sizing Criteria
3. Fluid physical properties
4. Hydraulic study for one phase fluids
4.1 Gas pipelines steady flow
4.2 Liquid pipelines steady flow
4.3 Gas pipelines transient flow
4.4 Liquid pipelines transient flow
5. Hydraulic study for multiphase fluids
5.1 Multiphase pipelines steady flow
5.2 Multiphase pipelines flow assurance
General Classification
A. EXPORT PIPELINES – GAS, OIL, WATER ONE-PHASE

FLOW
B. FLOWLINES – MULTIPHASE FLUIDS
(OIL+GAS+WATER) FOR GATHERING AND
INJECTION SYSTEMS
C. TRUNKLINES - MULTIPHASE FLUIDS
(OIL+GAS+WATER) FOR GATHERING AND
INJECTION SYSTEMS
D. SPECIAL TRANSPORT PIPELINES – SOLID/LIQUID
SLURRIES, WAXY CRUDE OILS
Example of Gas Export Pipeline System - Flowsheet
ANNEX 1 : CASE3 ONSHORE ROUTE THROUGH BANGLADESH - 10.2 BSCMY - OPTIMIZED SOLUTION
Myanmar-
Bangladesh Bangladesh-
CS1 / 1st Border / 2nd India Border / HRT / 4th
Metering Metering 3rd Metering Metering
Block A1 SRT Station Station CS2 Station Station
Gas Temperature in-ou °C Max. 45 25.6 26-50 48.5 33-50 33.4 29

Roughness micron 25 15 15 15 15 15 15
Pipeline Flow Rate KSCMH 1176 1176 1171 1171 1167 1167 1167
NPS inch 40 36 36 36 36 36 36
Inside Diameter mm 970.8 888.2 888.2 888.2 888.2 888.2 888.2
Inlet Pressure barg 88.8 84 65.8 92.5 65.8 67.2 46
Outlet Pressure barg 88 84 93.6 92.5 93.6 67.2 46
KP km -59 0 134 145 390 625 750
Compression Power kW - - 14700 - 15100 - -
Fuel Gas Consumption KSCMH 0 0 5 0 4 0 0
MAOP barg 98.5 98.5 98.5 98.5 98.5 98.5 98.5
MAOT °C 60 60 60 60 60 60 60
Rating ANSI 600# 600# 600# 600# 600# 600# 600#
Notes: Absorbed power refers to operated gas compressor trains

Pipeline material is : API Spc.5L, Grade X-70
Utilization factor = 1 (8760 hrs/yr)
Shown Diameters are intended as outside diameter
Outlet pressure at user location are downstream from the pressure control and metering station
The total investment cost for a metering station is 9 MUSD
Example of Onshore Gathering System
System Definition
A. The extent of the pipeline system, its functional requirements and applicable
legislation should be defined and documented.
B. The extent of the system should be defined by describing the system,

including the facilities with their general locations and demarcations and
interfaces with other facilities.
C. The functional requirements should define the required design life and design
conditions. Normal, extreme and shut-in operating conditions with their
possible ranges in flow rates, pressures, temperatures, fluid compositions
should be identified and considered when defining the design conditions.
D. The transport configuration in terms of pipeline size, wall thickness and

number of pump (or compressor) stations (if any), is determined according to
a technical-economical optimization analysis.
Work Process
Design Premises
Hydraulic Analysis Purpose
Sizing Parameters and Criteria - 1
1. Definition of Pressure Constraints : the MOP (Maximum Operating
Pressure) at the system inlets is defined on the basis of estimation of
concentrated and distributed pressure drops along the transport
system
2. Definition of Design Pressure : MOP + margin
3. Calculation of Pipeline Wall Thickness : by applying for instance ASME
code, the pipeline wall thickness t is:
Pi D
t=σ+A σ=
2 FEY
where:
Pi = Design pressure
D = Internal diameter
Y = Minimum yield strength of pipe wall material
F = Design factor
E = Weld joint factor
A = Allowances for corrosion, threading and grooving, and protective
measure
4. Steady-state flow simulations at maximum flow : they are
carried out to define the line size, by considering the
overdesign flow condition and respecting the following criteria:
a) Pipeline inlet pressure : The maximum required inlet pressure for
a pipeline shall not exceed the maximum available inlet pressure
b) Fluid velocity : The gas velocity in the pipeline should not exceed
20 m/s (optimal value : 5-10 m/s), while that for the liquid
should not exceed 4 m/s (optimal value : 1-2 m/s)
c) Erosional velocity ratio : The erosional velocity ratio shall not be
greater than unity for all pipelines
d) Absence of severe slugging for multiphase lines : The possible
slug flow conditions shall not originate severe slugging, which
could hinder a stable system operation
5. Transient flow simulations
a) Multiphase lines : The aim of transient simulations in multiphase
lines is mainly concerned with the definition of maximum slug
size and duration for slug catcher sizing
b) Liquid lines : Transients are carried out to calculate water
hammer effects caused by sudden valves closure and pump trips.
During this transient conditions surge pressures are calculated
and it is verified if they are within the limits of the applicable
code for accidental conditions. If not, adequate pipeline
protection measures shall be defined, or the line size can be
changed.
c) Gas lines : Transient simulations are performed mainly to define
operability limits as survival and packing times, or blowdown
scenarios
Phase Diagrams for a Multicomponent Mixture (Rich Gas)
120
D
100
E
80
P ressure (b ara )
60
40
F
20
G
0
-140 -120 -100 -80 -60 -40 -20 0 20 40 60
Temperature (°C)
Typical Properties Trends
Density of gas is strongly dependent on both pressure
(compressibility) and temperature (increases with pressure,
decreases with temperature)
Density of oil is significantly dependent on temperature and
weakly dependent on pressure (incompressibility) (increases
with pressure, decreases with temperature)
Gas viscosity is low (~ 0.01 cP)
Oil viscosity is strongly dependent on temperature; for normal
oils is ~ few cP, but can be much higher for heavy oils
ρ (T0 )
ρ L (T ) =
1 + β (T − T0 )
ν L (T ) = exp(exp(A + B ln(T + 273))) − 0.8
4.1 Gas Pipelines Steady Flow
1-D Flow Equations
The system of flow equations in conservative form, neglecting
gravitational contributions, are:
∂ (ρv ) 1 dS
=− ρv
∂x S dx
(
∂ ρv 2 + p)=−
1 dS 2
ρv + τ
∂x S dx
∂ (ρvH ) 1 dS
=− ρvH + qH
∂x S dx
Friction and heat transfer (based on Fanning friction factor
definition)
f
τ = − ρv 2 ^
RP q H = − h i (Taw − Twall )
Moody Diagram for Friction Factor
Effects of Compressibility and Friction in Gas Pipe Flow
200 275
180 270
160 265
140 260
Temperature (K)
Pressure (bara)
120 255
100 250 Compressible Flow

80 245 Temperature (K)
Incompressible Flow
60 Compressible Flow 240 Temperature (K)
Pressure (bara)
40 235
Incompressible Flow
Pressure (bara) 0.8
20 230
0 0.7 Compressible Flow 225

0 20 40 60 80 100
Mach Number 0 20 40 60 80 100
x (m) 0.6 x (m)
Incompressible Flow
Mach Number
0.5
Mach Number
0.4
0.3
0.2
0.1
0.0
0 20 40 60 80 100
x (m)
Friction in Gas Pipe Flow – Pressure Drop Trend
Upstream Pipe Exit Boundary
Condition with pressure PB
P0
T0
ρ0
Flow PE
P/P0 (a) Subsonic Flow

(b)
(c) Critical Flow

0
P*/P0
(d)
Distance along Pipe
P*/P0
Flow Rate
through the (d) (c) (b)
Pipe
(a)
0 1
PB/P0
Friction in Gas Pipe Flow – Flow Chart
Chocked Flow Line
0.7
K=0.1
0.6 K=0.2
K=0.5
0.5 K=1
K=2
0.4
K=5
W/W0
K=10
0.3
K=20
K=50
0.2
K=100
0.1 K=200
Chocking
Line
0
0 0.2 0.4 0.6 0.8 1
PB/P0
System Hydraulic Definition
Pressure Head Curve, including all information on pipeline
elevation profile, pressure drop at design flow conditions, head
curves at special conditions Æ determines wall thicknesses
Main head curves are:

– Design flow head curve
– Static head curve
Static head curve is relevant to pipeline shutdown condition –

Gas pipelines are usually designed to withstand a fully
pressurized gas at design pressure, thus the pipeline can be
used as a gas storage volume in order to speed up restart
operation – Wall thickness is sized according to this scenario,
and a uniform value along the route is usually selected
Gas Quality Constraints

To avoid deposits in a pipeline and to minimize the possibility
of any kind of corrosion, including internal stress corrosion, it
is essential that the gas should conform to the following:
– The water dew-point, at the working pressure, should at all times

be below the temperatures of the pipeline.
– The hydrocarbon dew-point, at the working pressure, should at

all times be below the temperature of the pipeline –this will also
ensure that the calorific value of the gas is not reduced by
condensation of hydrocarbons.
– It should be dust-free.
Gas Heating for Joule-Thompson Cooling
During operation of the pipeline system the minimum design
temperature may be violated due to high utilisation of the
system or high pressure gradients in part of the system
(Joule-Thomson effect). During normal operation heating of
the gas may be required to avoid the temperature to drop
below the minimum design temperature or other limitations
(sales agreements). In upset situations the pressure build-up
in parts of the system may cause the temperature to drop
below the minimum design temperature. Heating of the gas
may therefore be required in order to avoid the minimum
temperature to be violated.
4.2 Liquid Pipelines Steady Flow
Basic Flow Equations
P v2
Total Head Definition H = z+ +
ρg 2 g
H1 = H 2 + ΔH
Bernoulli Equation
P1 v12 P2 v22
z1 + + = z2 + + + ΔH
ρg 2 g ρg 2 g
L v2
Distributed Pressure Losses ΔH d = λ
D 2g
1 ⎛ 2.51 ε ⎞
= −2 log⎜ + ⎟
Colebrook-White Correlation λ ⎝ Re λ 3.71D ⎠
System Hydraulic Definition
Pressure Head Curve, including all information on pipeline
elevation profile, pressure drop at design flow conditions, head
curves at special conditions Æ determines wall thicknesses
Main head curves are:

– Design flow head curve
– Static head curve
– Shut-in head curve
– Relief head curve
Static head curve is relevant to inlet pumps at shut-off

Shut-in head curve is zero flow head with slack line
commencement condition
Relief head curve is the head curve relevant to outlet pressure
set-point of relief system
447 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1 Ed.– September 2010
st 447
Example of Pressure Head Curve for Oil Pipeline Design Based on
Static Head – Visualization of Different Wall Thickness
Distribution Along the Route
Hydraulic Gradient - 48" / 42" Pipeline
100 microns - X70 - Wall thickness selection based on static head curve
5000
4500
4000
3500
Elevation / H ead [m ]
3000
2500
2000
1500
1000
500
0
0 100 200 300 400 500
Profile wt=11.1 wt=11.9
Kilometric Progressive [km] wt=12.7
wt=15.9 wt=17.5 wt=19.1 wt=20.6
wt=23.8 wt=25.4 wt=27 wt=28.6
wt=31.8 1500 kBOPD gradient Design Line Selected wt
4.3 Gas Pipelines Transient Flow
Types of Transient Operations in Gas Pipeline Systems
Pipeline shut-down – Closure of two boundary valves, rarefaction
wave generated at the inlet, compression wave at the outlet – If
outlet valve not closed Æ Survival Time – If inlet valve not closed
Æ Packing
Pipeline start-up - Inlet and outlet valves are opened, inlet

compressors are restarted as well as the flow delivery to the
terminal plant, inlet compression wave and outlet rarefaction
wave generation
Pipeline or plant blowdown – Operative and emergency blowdown
Pipeline Systems Blowdown Real Conditions
Finite opening time of blowdown valves (no shock waves)
Possible strong cooling downstream orifices Æ material selection
Code requirements (depressurization in fixed time for plant
piping, Mach number limitations)
Safety area surrounding vent or flare systems
Vibrations, noise
Realistic Flow Conditions during Blowdown
Pipeline Rupture and Ductile Fracture Propagation
Resistance Curve with a higher CV

Resistance Curve with a CV giving a tangency point
Driving Curve for Perfect Gas
Pressure
Velocity
4.4 Liquid Pipelines Transient Flow
Water Hammer Scenarios
Transient or accidental operations may generate high pressure
surges
Main water hammer scenarios:
– Fast closure or opening of valves
– Pump start up
– Pump trip
These scenarios cause the generation of internal large amplitude
pressure waves propagating inside the pipeline, which can
compromise its integrity
A transient analysis must be carried out during pipeline design in
order to evaluate the need for protection systems installation
5.1 Multiphase Pipelines Steady Flow
General
The multiphase flow is the case when several fluid phases flow
simultaneously in a pipe
The oil produced by reservoirs, which is normally associated to
water, gas and sand. When free water is present it is considered
as a separate phase even if it is in the liquid status, and the flow
of oil, gas and water is defined three-phase flow. The fluid is
usually a multi-component hydrocarbon mixture.
The geometry of the flow, i.e., the geometry of the interfaces
giving the phase spatial distribution, is not known and cannot be
determined a priori, but is rather a part of the solution Æ Flow
Regime
The distribution of the phases in the pipe determines other design
parameters such as heat transfer, pressure drop, etc.; and
without knowing the one, the others cannot be calculated
Flow Regimes in Vertical Pipes
Flow Regimes in Horizontal Pipes
Slug Flow
Pressure Drop Calculations for Two-Phase Pipelines
The total pressure drop calculation for two phase pipelines is
given by different contributions:
ΔP = ΔPHH + ΔPKE + ΔPfric

The kinetic energy term is usually negligible with respect to
ΔPHH + ΔPfric
The friction term is much more variable and its form depends on
the particular flow regime that is considered
The interaction between the hydrostatic and frictional terms gives
rise to a peculiar behaviour of two-phase gas-liquid pipelines
which traverse an undulating terrain.
Pressure Drop for a Two-Phase Pipeline in Hilly Terrain
ΔPTOTAL
PRESSURE DROP
ΔPHH
ΔPf
OVERALL FLOW RATE
5.2 Multiphase Pipelines Flow Assurance
Slugging
a) Hydrodynamic slugs : they are the slugs relevant to the steady
flow belonging to the “slug flow regime”; usually they have a
smaller size with respect to other kinds of slugs
b) Terrain induced slugs : they are generated by liquid accumulation
in pipeline dips and at the base of a riser, which is suddenly
delivered when the upstream pressure increases enough to
overcome the liquid volume weight (“severe slugging”)
c) Pigging generated slugs : they are generated by the pipeline
pigging operation, when the liquid phase, is accumulated in front
of the scraper
d) Ramp-up or Start-up generated slugs : generated when a flow
increase is imposed on the line
Terrain Slugging
A. Slug formation C. Gas penetration
B.Slug production D. Gas blow-down
Severe Slugging
80 Pipeline Inlet Pressure (bara) 200
Pipeline Outlet Liquid Volume Flow (m3/h)
Pipeline Outlet Gas Volume Flow (m3/h)
75
160
Actual Volume Flow Rate (m3/h)

70
Pressure (bara)
120
65
80
60
40
55
50 0
0 0.5 1 1.5 2 2.5 3 3.5 4
Time (h)
Pigging Generated Slugging
A: Slug build-up
Gas
B. Front arrival Liquid
A B C D
Flowrate
C. Slug surface
D. Pig arrival Time
Hydrate Risk Diagram
Hydrate Risk
Hydrate Zone
Hydrate Free Zone
Hydrate Formation Curve
Hydrate Dissociation Curve
The Hydrate Problem
Prevention of Hydrate Problem
1. Keep the system pressure below the hydrate formation curve.
2. Maintain the temperature above the hydrate formation
temperature.
3. Water removal provides the best protection but often is not
feasible.
4. Change the hydrate formation curve.
5. Inhibit the formation of hydrates.
Remedial of Hydrate Problem
a) Depressurization. The preferred method to dissociate hydrate plugs
is to depressurize from both sides of the plug. An intermediate
pressure reduction rate is recommended (avoiding Joule-Thompson
cooling).
b) Chemical Injection. Large variations in elevation Æ It is unlikely that
an inhibitor will reach a plug without flow. Standard practice is to
inject inhibitor in an attempt to get the inhibitor next to the plug.
Injecting inhibitor into a line may not help with dissociating the
hydrate blockage but useful for preventing other hydrate blockages
during the remediation process and when flow resumes.
c) Heating. Is a viable option for topside hydrate plugs if they can be
located in a precise way and the process can be controlled step by
step.
d) Mechanical Approach. Standard pigs are not recommended for
removing a hydrate plug Æ “Coiled tubing”
Index

Section 6. : Construction
- Section 6.1 : Pipeline Construction

- Section 6.2 : Trenchless Technologies
- Section 6.3 : Welding
6.1 : PIPELINE CONSTRUCTION
A pipeline can be broken down in to three basic components
where different form of construction methods are normally used
as follows:
1. Open cross-country areas, where the spread technique is

used;
2. Crossings, where special crews and particularly construction

techniques are used;
3. Special sections such as build up areas, difficult terrain

sections and environmentally sensitive areas.
A pipeline construction project looks much like a moving
assembly line:
A large construction project typically is broken into manageable
lengths to be constructed by a fully equipped, highly specialized
qualified workgroup, called construction spreads.
Each spread is composed of various crews, each with its own

set of responsibilities. As one crew completes its work, the next
crew moves into position to complete its piece of the
construction process.
A construction spread may be 30 to 100 Km in length, with the

front of the spread clearing the right-of-way and the back of the
spread restoring the right-of-way.
Typical pipeline spread
The implementation of the spread technique is conditional on
the pipeline being welded above ground in maximum possible
continuous lengths between obstructions/crossings.
These welded pipe lengths are then immediately installed

trenches utilising multiple mobile lifting tractors (side-booms) in
unison.
Any breaks in the main pipeline spread activities are undertaken

by dedicated specialist crews utilising a variety of special
construction techniques.
Because a pipeline is a production line, it is essential that the

one crew causes stoppage or disruption on the preceding or
subsequent crew.
The float between the crews has to manage properly to avoid
disruption and stand by costs.
Typical pipeline construction plan (marchart)
Pre-construction activities
Pre-construction activities need to be carried out by
construction contractor prior the start of main pipeline
installation activities. These activities include mainly:
- detail design finalization

- mobilization
- notification of entry to landowners
- setting up of pipe yards and base camps
- design of land drainage in agricultural areas
- construction of temporary access roads
- pre-environmental mitigation works
- agreeing with landowner any special requirement prior to
entry onto their proprieties
Onshore Pipeline - Main Construction Equipment
Saipem
Saipem Equipments
Equipments
• 124 Cranes (10-150 Tons)
• 147 Sidebooms
• 103 Dozers and Tracker Loaders
• 147 Backhoes
• 65 Wheeled Loaders
• 152 Pay Welders
• 51 Pipe Bending Machines
• 1347 Car, Off Road Vehicle,

Truck and Buses
• Camp facilities (Beds) for 3450 people
Onshore Pipeline - Main Construction Equipment
A sideboom for pipe laying
Main Pipeline Construction Activities
Once the pre-construction activities have been completed, the main
construction works can start. Generally, operations are carried out in the
following main activities:
- pre-construction survey
- clearing and grading
- stringing and pipe bending
- trenching
- welding
- coating
- lowering in
- backfilling
- main crossings
- facilities
- hydrotesting, final tie-ins and commissioning
- restoration
Pre-construction survey
Before construction begins, Contractor surveys environmental
features along proposed pipeline segments.
Utility lines and agricultural drainages are located and marked

to prevent accidental damage during pipeline construction.
Next, the pipeline's centerline and the exterior right of way

boundaries are staked.
Pre-construction survey
(easement boundary demarcation)
Clearing and Grading

The Clearing and Grading phase leads the construction
spread. It includes removing trees, boulders and debris from
the construction right-of-way and preparing a level working
surface for the heavy construction equipment that follows. Silt
fence are installed along edges of streams and wetlands to
prevent erosion of disturbed soil. Trees inside the right-of-way
are cut down and the timber along the side of the right-of-way
are removed or stacked. Brush is shredded and properly
disposed. As may be necessary in agricultural areas, topsoil
may also be stripped to a predetermined depth and stockpiled
along the sides of the right-of-way.

(top soil strip operations)

(sod slabs removing)

(right of way side protections)
Clearing and Grading (archaeological findings)
Clearing and Grading: ice road

In Sakhalin (Russia)
Stringing
At steel rolling mills where the pipe is fabricated, pipeline
representatives will carefully inspect new pipe to assure that it
meets industry and local safety standards. For corrosion control,
the outside surface will be treated with a protective coating.
The pipe will be transported from the pipe mill to a pipe storage
yard in the vicinity of the pipeline location. The pipe lengths
typically are 12-14 m long. The pipe is moved from the storage
yard to the pipeline right-of-way using dedicated trailers. The
pipe joints are careful distributed according to the design plan
since the type of coating and wall thickness can vary based on
soil conditions and location
Stringing
Stringing in
desert areas
Stringing by tractors
Stringing in the trench
Stringing in swamp
Stringing in cold region
Pipe Bending
Once the pipe has been strung along the easement, contractor
will follow to determine the location of all bends required in
order that the pipeline can follow the contour of the land as
detailed in the design drawings.
There are two types of bends normally used:
- hot pre-formed bends which are manufactured off site in a

factory and are to a radius of 5 to 7 times the pipe diameter;
- cold bends which are to a radius of 40 times the pipe

diameter and are formed in the field.
Pipe Bending
The pipe bending crew will use a bending machine to make
slight bends in the pipe to account for changes in the pipeline
route and to conform to the topography.
The bending machine uses a series of clamps and hydraulic

pressure to make a very smooth, controlled bend in the pipe.
All bending is performed in strict accordance with project

prescribed standards to ensure integrity of the bend.
Pipe Cold Bending
Typical equipment for cold bending
Pipe Bending
The number of cold bends required depends on the route and
contours of the pipeline. Typically, they can range from 1 in 10
in developed regions to 1 in 50 in open country. The cold bend
angle that can be achieved ranges from maximum angles of 12
degrees (42” pipe) to 40 degrees (12” pipe).
Pipe Bending: gauging plate to check the “out-of-roundness”

tolerance after each pipe has been bent
Trenching
The pipe trench is dug using a wheel trencher or backhoe. The
pipe is buried a minimum of 0.9/1 m. The pipe will be buried
even deeper at stream and road crossings.
If the crew finds large quantities of solid rock during the
trenching operation, it will use special equipment or explosives
to remove the rock.
In cultivated areas the topsoil over the trench will be removed
first and kept separate from the excavated subsoil, a process
called topsoiling. As backfilling operations begin, the soil will be
returned to the trench in reverse order with the subsoil put back
first, followed by the topsoil. This process ensures the topsoil is
returned to its original position.
Trenching
Trenching in rocky areas
Trenching
Trenching
Trenching in cold weather
Trenching in swamp
Trenching in swamp
Trenching in desert areas
Welding
Welding is the process that joins the various sections of pipe
together into one continuous length.
Special pipeline equipment called side booms are used to pick

up each joint of pipe, align it with the previous joint and hold it
in place while the initial weld (first pass) is completed.
The process is then repeated to the next section to complete

each weld.
Welding
In recent years, contractors have used semi-automatic welding
units to move down a pipeline and complete the welding
process. Semi-automatic welding, done to strict specifications,
still requires qualified welders, and personnel are required to
set up the equipment and hand-weld at connection points and
crossings.
As part of the quality-assurance process, each welder must

pass qualification tests to work on a particular pipeline job, and
each weld procedure must be approved for use on that job in
accordance with federally adopted welding standards.
Welder qualification takes place before the project begins.
Welding
Each welder must complete several welds using the same type
of pipe as that to be used in the project. The welds are then
evaluated by placing the welded material in a machine and
measuring the force required to pull the weld apart. It is
interesting to note that the weld has a greater tensile strength
than the pipe itself.
A second quality-assurance test ensures the quality of the

ongoing welding operation. To do this, qualified technicians
take X-rays of the pipe welds to ensure the completed welds
meet federally prescribed quality standards.
Welding
The X-ray technician processes the film in a small, portable
darkroom at the site. If the technician detects any flaws, the
weld is repaired or cut out, and a new weld is made. Another
form of weld quality inspection employs ultrasonic technology.
Aligning two line pipe joints for welding
Welding
Manual Welding
Automatic Welding
Manual Welding
Welding: AUT EQUIPMENT
Welding: Manual UT
Coating
Line pipe is externally coated to inhibit corrosion by preventing
moisture from coming into direct contact with the steel.
Normally, this is done at the mill where the pipe is
manufactured or at another coating plant location before it is
delivered to the construction site.
All coated pipe, however, has uncoated areas three to six

inches from each end to prevent the coating from interfering
with the welding process. Once the welds are made, a coating
crew coats the field joint, the area around the weld, before the
pipeline is lowered into the ditch.
Coating
Pipeline companies use several different types of coatings for
field joints. Prior to application, the coating crew thoroughly
cleans the bare pipe with a power wire brush or sandblast to
remove any dirt, mill scale or debris.
The crew then applies the coating and allows it to dry prior to
lowering the pipe in the ditch. Before the pipe is lowered into
the trench, the coating of the entire pipeline is inspected to
ensure it is free of any defects.
Field Joint Coating
Lowering in
Lowering the welded pipe into the trench demands close
coordination and skilled operators.
Using a series of side-booms, which are tracked construction

equipment with a boom on the side, operators simultaneously
lift the pipe and carefully lower the welded sections into the
trench. Non-metallic slings protect the pipe and coating as it is
lifted and moved into position.
In rocky areas the contractor may place sandbags or foam

blocks at the bottom of the trench prior to lowering-in to protect
the pipe and coating from damage.
Lowering in: inspection with “holiday” detector
Lowering in
Lowering in
Lowering in
Lowering in (high water table ground)
Lowering in high water table ground
Lowering in cold weather
Lowering in desert areas
Backfilling
Once the pipe has been placed in the trench, the trench can be
backfilled. This is accomplished with either a backhoe or
padding machine depending on the soil makeup. As the
operations begin, the soil is returned to the trench in reverse
order, with the subsoil put back first, followed by the topsoil.
This ensures the topsoil is returned to its original position.
In areas where the ground is rocky and coarse, the backfill
material is screened to remove rocks, or bring in clean fill to
cover the pipe. Once the pipe is sufficiently covered, the
coarser soil and rock can be used to complete the backfill.
Backfilling (trench breakers)
Backfilling
Backfilling
Backfilling: trench with Fiber Optic Cable
Backfilling
Open Cut River and Stream Crossings

This crossing method involves excavating a trench across the
bottom of the river or stream to be crossed with the pipeline.
Depending on the depth of the water, the construction
equipment may have to be placed on barges or other floating
platforms to excavate the pipe trench. If the water is shallow
enough, the contractor can divert the water flow with dams and
flume pipe to allow backhoes, working from the banks or the
streambed, to dig the trench.
The contractor prepares the pipe for the crossing by stringing it
out on one side of the stream or river and then welding, coating
and hydrostatically testing the entire pipe segment.

Sidebooms carry the pipe segment into the stream bed, similar
to construction on land, or the construction crew floats the pipe
into the river with flotation devices and positions it for burial in
the trench. Concrete weights or concrete coating ensure the
pipe will stay in position at the bottom of the trench once the
contractor removes the flotation devices.

Batimetric survey and scuba diving assistance
Danubio river crossing: NPS 42/26 joint together

(y 2000)
Danubio river crossing: NPS 42/26 pulling string
Danubio river crossing: suction dredge
Danubio river crossing: pulling winch
CONSTRUCTION FOR ONSHORE PIPELINES
Wetlands
"Pipelining" in wetlands or marshes requires another special
construction technique. In one technique, crews place large
timber mats ahead of the construction equipment to provide a
stable working platform. The timber mats act much like
snowshoes, spreading the weight of the construction equipment
over a broad area. The mats make it possible to operate the
heavy equipment on the unstable soils.
Wetlands
Wetlands
Wetlands
Wetlands
Wetlands
Road Bores
For crossing most small roads pipeline contractors use the
"open-cut" method. Traffic is diverted while the contractor digs
the trench across the road and installs the pipeline. The
contractor subsequently repairs the road bed and replaces the
pavement.
For highways and major roads with heavy traffic, pipeline
contractors often use road bores to install the pipeline. Similar
to a directional drill for river crossings, the road bore is
accomplished with a horizontal drill rig, or boring machine.
Road Bores
The boring machine drills a hole under the road to allow
insertion of the pipe. In some instances a casing is first installed
in the hole, and the gas pipeline is inserted inside the casing.
The benefit of the road bore is that it allows installation of the
pipeline without disrupting traffic.
Road Bores
Road Bores
Road Bores
Pipeline Facilities
The main items consist of:
- Block valve sites

- Scraper traps
All work involved with these facilities will be co-ordinates with

the main spread activities to ensure that overall schedule for
the project is achieved.
Typical block valve station for gas pipeline
Typical block valve station for gas pipeline
Hydrostatic Testing
The pipeline is hydrostatically tested to ensure the system is
capable of withstanding the operating pressure for which it was
designed.
This process involves isolating the pipe segment with test

manifolds, filling the line with water, adding pressure to the
section to a level commensurate with the maximum allowable
operating pressure and class location, and then maintaining
that pressure for a period of 8/24 hours.
The hydrostatic test is conducted in accordance with local

regulations.
Hydrostatic Testing
Depending on the location of the pipeline, the water used in a
hydrostatic test is drawn from a local river, stream, or lake;
taken from municipal supplies; or trucked to the site. Water for
hydrostatic testing generally is obtained from surface water
sources through specific agreements with landowners and in
accordance with local regulations.
The pipeline is hydrostatically tested after completing the

backfilling and all construction work that would directly affect
the pipe. If leaks are found, the leaks are repaired and the
section of pipe retested until specifications are met.
Hydrostatic Testing
Once a test section successfully passes the hydrostatic test,
the water is emptied from the pipeline in accordance local
codes requirements.
Water used for the test is then transferred to another pipe

section for subsequent hydrostatic testing or analyzed to
ensure compliance with the local discharge permit
requirements; if necessary, it is treated and discharged.
test manifold
Pig for pipeline cleaning before hydrostatic testing
Hydrotest: Cleaning Phase
Final Tie-ins
Following successfull hydrostatic testing, test manifold are
removed and the final tie-ins are made and inspected.
The term ‘Tie-in’ is generally used to describe the connection

of a pipeline to a facility, to other pipeline systems or the
connecting together of different sections of a single pipeline.
Furthermore it can be defined as a welded joint that cannot be

carried out by the main front end welding/production during
the main line laying.
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Final Tie-ins
Principal Reasons for Tie-Ins Tie-in welds are, for instance,

required at any joint that has not been welded by the front end
welding crew.
As the construction programme and cost efficiency of the

main pipeline production will rely on close to continuous
advance and optimum utilisation of the front-line crew and
equipment then any delays to this continuous process have to
be minimised. Some joints will have been left because they
could not be physically made at the time, others because
making of particular ‘non-standard’ or awkward joints would
cause a disproportionate delay toUSERS
the main production. USERS
Typical Tie-In Welding Arrangement for new construction External alignment clamps are used which limit
the opportunity for using automated welding processes
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and welding is normally carried out manually.
Commissioning
After final tie-ins are complete and inspected, the pipeline is
cleaned and dried by using mechanical tools (pigs) that are
moved through the pipeline containing pressurized dry air.
The pipeline is dried to minimize the potential for internal
corrosion. Once the pipe has dried sufficiently, pipeline
commissioning commences. Commissioning activities involve
verifying that the equipment has been properly installed and is
working, that controls and communications systems are
functional, and that the pipeline is ready for service. In the
final step, the pipeline is prepared for service by purging the
line of air and loading the line with natural gas; in some
cases, the gas is blended at the distribution end until
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achieving a certain moisture content level.
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Hydrotest: Kaliper pig
Restoration
The final step in the construction process is restoring the land
as closely as possible to its original condition. Depending on
the project's requirements, this process typically involves
decompacting the construction work areas, replacing topsoil,
removing large rocks that may have been brought to the
surface, completing any final repairs to irrigation systems or
drain tiles, applying lime or fertilizer, restoring fences, etc.
The restoration crew carefully grades the right-of-way and in

hilly areas, installs erosion-prevention measures such as
interceptor dikes, which are small earthen mounds constructed
across the right-of-way to divert water.
Restoration
The restoration crew also installs riprap, consisting of stones or
timbers, along streams and wetlands to stabilize soils. As a
final measure the crew may plant seed and mulches the
construction right-of-way to restore it to its original condition.
Restoration
Restoration
Restoration
Restoration
Restoration

6.2 : TRENCHLESS TECHNOLOGIES
Design of long distance, large diameter pipeline systems

requires the crossing of inaccessible and challenging
sections and getting over natural and artificial obstacles.
Pipeline technologies permit to find the optimum solution,

in agreement with required safety level and in compliance
with the requirements of environmental protection for
crossing mountains, rivers, channels, rice fields, swamp
areas by means of:
• Tunnels (existing and new)

• Microtunnels
• HDD.
6.2 : TRENCHLESS TECHNOLOGIES
RE-USING OF EXISTING
TUNNELS
RE-USING OF EXISTING TUNNELS
URWEID TUNNEL
The project for the expansion of the gas pipeline system for importing gas
from Northern Europe was a transnational project that, due to its strategic
importance and the operational difficulties that characterize it, presents a true
technical, organizational and economic challenge.
The use of tunnels for crossing the Alps with gas pipelines was a very
sophisticated technical solution.
Out of the entire project, the section that is sure to be remembered as one of
the most difficult and that presented one of the biggest design and
construction challenges was the crossing of the Alps between the Rodano
river valley, in the Swiss Municipality of Obergesteln, and the Toce river
valley, in the Italian Municipality of Formazza in the Piedmont region.
URWEID TUNNEL
In this section, with a total length of 25 km, the new 1200 (48”) pipeline was
laid in replacement of the old 850 (34”) ND line reutilizing the three existing
tunnels:
the Grimsel tunnel: 12562 m long, entirely in Swiss territory;
the Obergesteln tunnel: 2348 m long, entirely in Swiss territory;
the Gries tunnel: 6148 m long, of which 2525 m in Swiss territory and 3623 m
in Italian territory;
the Antillone tunnel: 2258 m long, entirely in Italian territory.
GRIMSEL tunnel URWEID TUNNEL
LENGHT: 12.562 m
N. 4 AUXILIARY
ACCESS
SLOPE: 1-3%, 41%,

85%
MAX ELEVATION
S.L.M. 1.993 m
GAS PIPELINE HOLLAND - ITALY
SWITZERLAND - ITALY SECTION
URWEID TUNNEL
URWEID TUNNEL
NORTH ENTRY SOUTH ENTRY
0,5%
8,0%
7 5%
10
0%
2,1%
8%
TUNNEL LEVEL 2386.85 2386.85 2394.35 2306.36 1948.19 1811.11
TUNNELS LENGTH SWISS SECTION ITALIAN SECTION

2548 m 3467 m
6000 m
Expansion of the nothern Europe gas pipeline system - GRIES TUNNEL
NORTH EUROPE GAS EXPANSION
GRIES TUNNEL

REPLACEMENT
GRIES TUNNEL
GRIES TUNNEL
GRIES TUNNEL
GRIES TUNNEL
CONSTRUCTION OF NEW TUNNELS
The solution to install gas pipelines in tunnels of large

diameters excavated by TBM (Tunnel Boring Machine) or
by traditional technology is adopted to pass through high
mountains for extended lengths, where the alternative
cross country routes are not competitive, in terms of
remarkable additional lengths, construction costs, heavy
environmental impact.
The most appropriate tunnelling technology is selected

according to the characteristics of the soil:
TBM (open machine) for hard rock formations, with

circular cross section and sprayed concrete lining
TBM (shield machine) for soft soils, with circular section

and reinforced lining (segmental lining)
Drill and Blast for hard and very hard rocks.
FURCULTI TUNNEL ( Italy ) - TBM OPEN
FURCULTI TUNNEL ( Italy ) - TBM OPEN
FURCULTI TUNNEL ( Italy ) - Northern Entry
FURCULTI TUNNEL ( Italy )
TUNNELING
SORENBERG TUNNEL ( Switzerland )

TBM SIMPLE SHIELD
TUNNELING
SÖRENBERG TUNNEL
(Switzerland)
GEOLOGICAL PROFILE
(approx. 5300 m long)
TUNNELING
SÖRENBERG TUNNEL: Northern Mouth
TUNNELING
SÖRENBERG TUNNEL: TBM in place
TUNNELING
SÖRENBERG TUNNEL: internal lining
installation
TUNNELING
SÖRENBERG TUNNEL: conveyor system
Ventilation duct Conveyor belt
TUNNELING
SÖRENBERG TUNNEL: conveyor system
TUNNELING
MONTJOVET TUNNEL ( Italy )

Oil and Gas Pipelines
MICROTUNNEL
Microtunnelling is a viable solution for short lengths, soft
rocks and loose soils, enabling to:
Crossing of railroads and highways with no interferences on

traffic operations
Crossing of rivers with no intervention works on

embankments
Crossing of natural obstacles and steep rises, very sensitive

environments, strongly reducing the lengths of external
routes and the environmental impact.
CUTTING HEAD
CUTTING HEAD HYDRAULIC
MOTOR •
STEERING CYLINDERS
VOID
WATER FEEDER LINE
SLURRY LINE
FEEDER WATER PUMP
SLURRY PUMP
MAIN JACKING CYLINDER
INTERMEDIATE JACKING
CYLINDER
JACKING WALL
LASER SORCE
LASER TARGET
SLURRY TANK
HYDRAULIC POWER PACK
CONTROL CABIN
CONCRETE JACKING PIPE
LAUNCH SEAL
Microtunnel: Typical design profile
LAUNCH PIT CONSTRUCTION PHASE
LAUNCHING RING
CONCRETE JACKING PIPE
LAUNCHING PIT
DETAILS
INTERMEDIATE JACKING CYLINDER
RECEIVING PIT IN COHESIONLESS SOIL
RECEIVING PIT IN ROCK SOIL
MICROTUNNEL INTERNAL VIEW
MICROTUNNELING
TECHNICAL FEASIBILITY IN RELATION WITH GEOLOGY
ROCK FORMATION FEASIBILITY

PEAT VERY GOOD
CLAY VERY GOOD
SILT VERY GOOD
SAND GOOD
GRAVEL MAY NOT BE FEASIBLE
PEBBLES NOT FEASIBLE
SOFT ROCK GOOD
HARD ROCK NOT FEASIBLE
HORIZZONTAL DIRECTIONAL DRILLING

HDD
HDD EXECUTION
PHASES
HDD Design Profile
HDD DRIL RIG MACHINE
1-3 MOUNT MODULE

4 SLIDING DRILL HEAD
HDD DRIL RIG MACHINE
DRILLING ASSEMBLY FOR BORE HOLE
REAMING AND SWEVEL TOOLS
DRILLING FLUID MIXING UNIT
FLUID FLOW
FROM REAMERS HOLES
DURING PULLING PHASE
HDD PIPELINE PULLING

PHASE
EMBANKMENT FOR PULLING STRING
DIRECT PIPE

PIPELINE WELDING
The construction of gas pipelines and oil pipelines takes place

through the welding together of individual pipes, about 12/14 m
long, that go to make up the pipeline, carried out by welding
the pipes one after the other and advancing progressively
along the route designated in the design phase.
Today’s technology makes many welding techniques available,

so it is necessary to make a choice to select the most suitable:
the parameters that guide such a choice are generally the
diameter and the thickness of the pipe, but also the
characteristics of the place chosen for the laydown and the
working conditions.
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PIPELINE WELDING
Onshore Pipeline: welding phase – pipe jointing
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PIPELINE WELDING
Welding is used to join the edges of separate bodies that, at the

end the process, become integral parts of a single structure.
There are many welding techniques, but the ones most often
used in the pipeline field are forms of arc welding.
The common characteristic of this type of technique is that the

two edges are joined together by fusing the material of which
they are made up, through heating up to an adequate
temperature.
The heat needed for this purpose is generated by making an

electrical arc jump between the base material of the two edges
and an electrode. USERS USERS
PIPELINE WELDING
Depending on the welding technique employed, the electrode

can act as a filling material, since by melting it is mixed in the
molten pool, otherwise the filler is introduced separately in the
form of wires.
At times, however, the process can be such as not to need the

addition of filler material into the pool.
Another fundamental aspect of the welding process is the need

to protect the molten material from the gases present in the air,
e.g. oxygen and nitrogen, which are harmful to the mechanical
characteristics of the join.
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PIPELINE WELDING
Welding processes that are commonly used for pipeline

applications are:
9gas submerged arc welding (restricted to double-jointing

and fabrication);
9shielded metal arc welding (SMAW), or gas metal arc

welding (GMAW).
Either a mechanized welding technique or manual welding may

be used for mainline welding; manual welding is used for all
other requirements.
USERS USERS
PIPELINE WELDING
Welding processes that are commonly used for pipeline

applications are:
9gas submerged arc welding (restricted to double-jointing

and fabrication);
9shielded metal arc welding (SMAW), or gas metal arc
welding (GMAW).
Either a mechanized welding technique or manual welding may

be used for mainline welding; manual welding is used for all
other requirements.
USERS USERS
PIPELINE WELDING
Gas metal arc welding (GMAW) is done using
a consumable wire that melts when an arc is
struck and maintained between the wire and
the material being welded.
The welding wire is fed continuously into the

arc during the welding process.
The arc and weld pool

are shielded from the
atmosphere by a
concentric flow of gas. A
number of gases/gas
mixtures are used for
shielding, with 100%
CO2, or 75% argon and
25% CO2 being two of
The continuous nature of the wire electrode and the virtual absence of slag leadscommon.
the most to high
productivity and is ideally suited to mechanization.
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PIPELINE WELDING
Typical joint design for gas metal arc welding (GMAW)
Typical number of passes for GMAW

(number will vary with w.t.)
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PIPELINE WELDING
Shielded metal arc welding (SMAW) is done

using consumable stick electrodes that melt
when an arc is struck and maintained between
the electrode and material being welded.
These electrodes are composed of two main
parts, one being the core wire and the other the
external flux coating. The core wire, and sometimes
iron powder within the coating, provides the necessary
metal to fill the weld joint.
The flux coating is required to shield the arc and molten metal from the atmosphere, add
alloying elements to the weld metal, and provide a protective layer (slag) during and after
solidification of the weld metal. This slag is subsequently removed between passes
Shielded metal arc welding remains the most widely used and versatile process for general
pipeline applications. With the correct choice of consumable and welding technique the SMAW
process can be applied to all welding positions and will allow a wide range of mechanical
property requirements to be met.
However, the process is very dependent on the welders' manual skills for attainment of defect-
free welds with acceptable properties.
USERS USERS
PIPELINE WELDING
Shield metal arc welding joint preparation
Shield metal arc welding – typical welding passes
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PIPELINE WELDING
Shield metal arc welding joint preparation
Shield metal arc welding – typical welding passes
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PIPELINE WELDING
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Passo Welding system – GMAW
Passo welding system - GMAW
• n. 4 welding head / n. 4 welders
• Internal line-up clamp (copper shoes)-tiene fremi in pos tubi
• Coil induction pre-heating
• CO2 / Argon gas protection
• n. 12 to 14 run(numero di passate di saldatura)
• Cycle time average 11 min.
• bevel (smusso) 3 grade (narrow groove)
• Fast welding and reduced overall cycle time with root pass adequate to
withstand (resistenza)stress concentration during laying activities
• Final Repairs rate 1,34 % (tasso di saldature non ben eseguite)
Automatic Ultrasonic Testing (AUT)
Weld scanning Calibration block
Automatic Ultrasonic Testing (AUT)
• Use of ECA (Engineering Critical Assessement) as acceptance
criteria of flaw evaluation necessary for pipe structural
integrity/safety
• Reduce significantly reject/repair rate with low operational risk

and low construction costs
• Less conservative than traditional “Workmanship criterial”
• Full weld inspection (FL=zona fusa – ZTA – WM) and area

around (lamination defect detection)
• Calibration before each weld scanning
• Calibration block for each different pipe utilised
AUT scanning output
Advantages of AUT over RT
• Accured characterization of defects , essential for ECA application
• Speed of inspection (cycle time reduction)
• Is not operator subjective (accurancy of defect size and

detection)
• Absence of radiation HAZARD and chemical products to be

managed
• Fast access to acquired data (inspection output records) on

digital support
Index

Section 7. : Mechanical Design
- Section 7.1 : Wall thickness design

- Section 7.2 : Anchor blocks
- Section 7.3 : Pipeline Facilities
- Section 7.4 : Buoyance Control Design
- Section 7.5 : Stress Analysis Basic Criteria
- Section 7.6 : Steel Pipes for Pipelines
- Section 7.7 : Precommissioning & Commissioning
7.1: MECHANICAL DESIGN – Wall thickness Design
LOCATION CLASSIFICATION
The most significant factor contributing to the failure of a gas

pipeline is damage to the line caused by human activity.
Pipeline damage generally occurs during construction of other
services.
These services may include utilities, sewage systems or road

construction and will increase in frequency with larger
populations living in the vicinity of the pipeline. To account for
the risk of damage, the designer determines a location
classification based predominantly on population concentrations.
Canadian and American codes differ marginally in the
requirements for determining a specific location classification.
LOCATION CLASSIFICATION
To account for the risk of damage, the designer determines a

Location classification based predominantly on population
concentrations.
Canadian and American codes differ marginally in the

requirements for determining a specific location classification.
Next table (7-1) reflects the requirements of the relevant North

American codes.
Location Classification between ASME Standards and Italian Code
PIPELINE DESIGN FORMULA (for thin-walled pipe)
The widely used formulae for determining the

circumferential and axial stresses in a pressurized thin-
walled pipe can be developed quite easily by considering
the vertical and horizontal force equilibrium:
The following design formulae are used to calculate the wall

thickness of a pipeline:
2× S ×t
ASME B.31.8 (gas pipeline) P≡ × F × E ×T
D
Where:
P = design pressure
S = specified minimum yield strength, SMYS
t = wall thickness
D = out side diameter of pipe
F = design factor (based on location classification)
E = longitudinal joint factor
T = temperature derating factor
ASME B.31.4 (liquid pipeline)

2× S ×t
P≡ ×F×E
Where:
D
F = design factor = 0.72
E = longitudinal joint factor
The temperature derating factor is 1.0 provided that:
Where Tpipe = pipe temperature − 30°C ≤ T pipe ≤ 120°C
The maximum operating pressure (MOP) is used as the design

pressure, P,
The specified minimum yield strength S is chosen from the pipe

mills.
No equivalent factor is defined in ASME B31.4, where an

allowable stress is defined as 0.72 SMYS.
ASME B.31.4 does not include a temperature derating factor but

limits the range of applicable temperature to under 120 °C.
7.2: MECHANICAL DESIGN – Anchor Block Design
Reinforced-concrete blocks are often used to serve as anchors.
Stresses and deflections occur in pipelines at the transition

from the below-ground (fully restrained) to the above-ground
(unrestrained) condition.
An analysis of the stresses and deflections in transition areas,

resulting from internal pressureltemperature changes, is
necessary to determine anchor block requirements and pipe
size.

Longitudinal deflections are used to check if an anchor block is

required. The forces required to maintain the pipe in a fully
restrained condition are then used to size the anchor block
MLE Project (Algeria) Anchor Block

7.3: MECHANICAL DESIGN – Pipeline Facilities
PIPELINE FACILITIES AND CONTROLS
- Block valve assemblies

- Scraper trap areas
- Metering station
- Telemetry & SCADA
Block Valve Assemblies
Block valve assemblies are used to isolate sections of mainline

or long laterals when isolation is required in the event of a line
break or if maintenance in a section of the line is necessary.
Since their fiction is to provide leak tight seal, it is important that

they do not experience undue deflection.
For this reason, they are substantially stiffer than the adjacent
pipe and their stress levels are about half of the pipe
Block Valve Assemblies
Code requirements for maximum block valve spacing vary with

class location for gas pipelines.
Ease of access and site conditions should always be evaluated

when selecting a location for a valve assembly.
Block Valve Assemblies for gas: schematic diagram
Block Valve Assemblies for gas: assonometric view
Block Valve Assemblies for gas: plan and profile
Block Valve Assemblies for gas with take-off
Block Valve Assemblies for oil pls
Oil pipelines have no defined rules for block valves spacing.
Particularly, valve spacing in oil pipelines are strictly associated

with dedicated risk assessment studies arising from accidental
events associated with operational events that could cause oil
spill.
Based on dedicated studies number and location of block valves

are defined in order to minimize the oil spill volumes and reduce
the environmental risks.
To be noted that istallation of block valves or check valves

required to isolate a pipeline segment and reduce total spillage
volumes actually represents additional potential oil leakage
feature that requires evaluations.
Other pipeline features to be adressed during the assessment

risk studies are:
- corrosion faults (internal and external);
- mechanical faults (failure of pipeline and fittings);
- operating faults such as over-pressurizations;
- sabotage and vandalism;
- natural hazards (seismic faults, landslides, …);
- number, type and location of river crossings;
- man-made hazards (railways, roads, adjacent pipelines or
plants); -
Scraper Assemblies
Scrapers, commonly referred to as pigs, are used in the daily

operation and construction of pipelines.
They are used for a variety of reasons:

a. To clean a pipeline, thereby increasing the line's efficiency.
b. To gauge or survey any objectionable restrictions or pipe
deformations such as dents and buckles.
c. To remove water after hydrostatic testing of newly constructed
pipelines.
d. To separate product batches.
e. To inspect the pipeline internally, to detect any loss-of-metal
defects (caused by internal or external corrosion).
Scraper Assemblies
Pigging facilities consist of pig launching or receiving equipment

and allow the pipeline to accommodate a high-resolution internal
inspection tool.
Pigs are devices that are placed into a pipeline to perform

certain functions. Some are used to clean the inside of the
pipeline or to monitor its internal and external condition.
Launchers and receivers are facilities that enable pigs to be

inserted into or removed from the pipeline
Scraper Assemblies
There is currently no formula for determining the maximum

length of a pig run or the location of pig traps. The location of an
intermediate pig launch and receipt assembly depends upon the
quality of the pig, the quality of construction, the pig velocity, the
pig design, the interior line conditions (rough, semirough,
smooth), and the medium in which the pig is running. However,
there are some general guidelines:
Scraper Assemblies
The major components of a scraper trap assembly include:

a. Pig barrel and end closure
b. Isolation valve
c. Kickoff valve
d. Bypass valve
e. Mainline isolation valve (on mainline bypass)
f. Blowdown stack and valve (for gas service only)
g. Pig barrel drain valve (mainly for liquids)
h. Pipe bends leading to the assembly
i. Anchors and supports.
A pig launch barrel (Figure 7-27) should be at least 1% times as long as the longest pig (cleaning or pig inspection).
An exception to this rule would be for products lines where it is necessary to launch two or more pigs in succession
to separate buffer batches (batching ).
The launch barrel diameter should be one to two NPS sizes larger than the line pipe. The launch-barrel must be
equipped with connections (usually flanged) for the kickoff line and, if drainage is required, drain valves.
The kickoff connection should be located on the side of the trap close to the closure end.
For gas lines, a blowdown stack and valve are required. Welded connections for gauging, purging, and blowdown
should be included on the barrel and located on the top, close to the end closure.
A pig signal should be installed downstream from the launcher to indicate the passage of the pig into the main line.
The pig receipt barrel should be at least 2% times as long as the longest pig.
Consideration must be given to the possibility of running long inspection pigs or, for product lines, a series of pigs for
batching. When cleaning pigs are considered, attention must be given to the amount of debris expected.
The receipt barrel must be equipped with flanged connections for a bypass line and drainage outlets. The bypass
connection should be located near the mainline connection. The drain outlets should be located near the end closure.
The barrel-diameter should be one to two NPS larger than the line pipe.
The receipt barrel should also contain a connection for a pig passage indicator. This connection should be located
just upstream of the reducer
Scraper Assemblies
Scraper Assemblies
Metering Building
Elecrical Building 30“ Scraper Trap
Tie-in
Analiyser
Metering System
Vent
Metering station Isometric View
Gas Metering station
Metering stations are placed periodically along natural gas
pipelines.
These stations allow pipeline and local distribution companies

to monitor, manage, and account for the natural gas in their
pipes.
Essentially, metering stations measure the flow of gas along

the pipeline, allowing pipeline companies to track natural gas
as it flows along the pipeline.
Metering stations employ specialized meters to measure the
natural gas as it flows through the pipeline without impeding
its movement.
In essence, the metering station is the company’s “cash

register”.
A meter/regulator station typically includes meter and regulator

equipment, a filter separator, odorant equipment, and a control
building housed within a fenced perimeter.
Flow Direction
Future expansion for Pressure

Reduction System
Metering Station Piping Layout
Metering Station Piping Layout
Gas Filter Separators
Metering System
Metering System Packages including:
• Upstream US straight pipe (20 diameter in
length) including flow conditioner
• Downstream US straight pipe (5 diameter
in length) including a 20” T flanged branch
for stream 1 & 2
• Metering system calibration has to be
qualified by laboratory according to
European Community and 3rd party
inspector.
Metering System
Metering System General Arrangement
TOP-VIEW
SIDE-VIEW
Pipeline Controls: Key Components
Telemetry is the mechanism by which information is interchanged with
remotely separated locations for the purpose of monitoring and/or
control.
Telemetry ranges in complexity from systems with a couple of I/O to

complicated controlling systems of pipelines embracing more thousand
technological units.
The key components in many telemetry systems are:
9The RTU (Remote Terminal Unit);

9Communication protocol
9Physical communication network
9SCADA system (Supervisory Control and Data Acquisition)
The RTU is the remote device responsible for acquiring the “real”
information, typically from field devices. It queries the data from the field
devices and typically formats data according to requirements of
communication protocol, puts datas forward to communication network.
The RTU may acquire their information through electrical signals

connected to the RTU or from other intelligent devices via a serial data
connection. RTUs may also perform local control functions.
The RTU functions are often fulfilled by a Programmable Logical Units

(PLC).
The communication protocol is the language used in the transmitting
and receiving of data messages on the physical network.
A protocol can describe who sent the message, who it is going to, the
meaning of the data in the message, verification information to ensure
the complete message arrives and that it is error free.
Both the transmitter and receiver of the data message must use the
same protocol in order that both understands the data message

The communication network provides the physical means for the
transfer of information (message data) from an RTU to a SCADA
system, from an RTU to another RTU, and in some architectures
between multiple SCADA systems.
Choice of communication network is critical to the operation of a

telemetry system and can be a costly aspect of a telemetry system
The SCADA system is comprised of one or more computers, providing
an interface to the physical communication network (and hence to the
RTUs), and an operator interface to the data obtained from RTUs.
This data may be rebuilt, stored for later retrieval, analyzed and
transferred to other computer systems.
A SCADA system often provides a control interface for sending data to

RTUs. This can happen by operator commands and automatic
sequences based on RTU data can release commands too. Commands
can be received from other computer systems (eg. leak detection at oil
pipeline for automatic shut down pipeline gatevalves.)
Pipeline Controls: SCADA System
To manage the product that enters the pipeline and ensure
that all customers receive timely delivery of their portion of it,
sophisticated control systems are required to monitor the gas/oil
as it travels through all sections of a potentially very lengthy
pipeline network.
To accomplish the task of monitoring and controlling the natural

gas or oil that is traveling through the pipeline, centralized
control stations collect, assimilate, and manage the data
received from monitoring city gate stations and compressor
stations all along the pipeline.
Most of the data that is received by a control station is provided
by Supervisory Control And Data Acquisition (SCADA) system.
These systems are essentially sophisticated communications

systems that take measurements and collect data along the
pipeline (usually in metering or compressor stations and valves)
and transmit the data to the centralized control station.
Flow rate through the pipeline, operational status, pressure, and

temperature readings may all be used to assess the status of
the pipeline at any one time. These systems also work in real
time, so there is little lag time between taking measurements
along the pipeline and transmitting them to the control station.
Equipment status scans are taken every 6 to 90 seconds
depending on the communication technology used in the field.
This information allows pipeline engineers to know exactly what

is happening along the pipeline at all times, which permits quick
reactions to equipment malfunctions, leaks, or any other unusual
activity along the pipeline, as well as to monitoring load control.
Some SCADA systems also incorporate the ability to operate
certain equipment along the pipeline remotely, including
Compressor/pumping stations, which allows engineers in a
centralized control center to adjust flow rates in the pipeline
Immediately and easily.
Control and monitoring are conducted by using remote terminal

units (RTUs), which are placed at intervals along the pipeline, at
stations, gate/measurement stations and other related locations.
RTUs periodically collect data from field instruments that
Measure pressure, temperature, flow, and other features of
carried products.
Typical BVS RTU with 5 gate valve control
The data are transmitted from the RTUs through a
communications network that could consist of company-owned
fiber-optic lines, leased telephone lines, ground- or satellite-
based microwave, or radio communication systems.
The SCADA system is monitored 24 hours per day, 365 days a

year. SCADA systems allow the pipeline companies to control or
shut down portions of a pipeline in the event of an accident or for
other safety reasons.
SCADA Center
They also are used to collect data at different system points as
well as to feed data to other administrative function such as
billing, marketing, and monitoring cathodic protection systems
(at critical pipeline bond interconnect points and rectifiers).
In all SCADA systems, the master terminal unit and RTUs

communicate through a defined network of some type. Early
systems used wired communications, either through private
hard-wired systems owned by the operator (usually practical
only for short distances) or through the public-switched phone
network.
Today there are still many systems using public phone systems,
encompassing both wire and fiber optics technology. These
facilities allow remote monitoring of the pipeline and
communication with valves, compressors, and personnel during
operation.
Most new systems and many retrofits are using some form of
wireless communications. Many pipelines own their own
microwave infrastructure, including dedicated towers and radio
frequencies licensed by the Country Communications
Commission.
Systems using frequencies in the very high or ultrahigh

frequency (VHF and UHF, respectively) ranges are also in use.
These operators may own their own towers or lease space from
other operators. Many newer systems are making use of low-
power radio transmissions, such as spread-spectrum
technology, to avoid the licensing requirements. Satellite
communications are also used for long-distance and rugged-
terrain communications
SCADA systems can also operate on cell phone technology,

such as the Cellular Digital Packet Data network, which does not
require dedicated lines or other infrastructure such as an
antenna tower.
Some SCADA systems operate directly through the Internet,

eliminating certain maintenance concerns for the operator.

7.4: MECHANICAL DESIGN – Buoyance Control Design
Pipelines are subjected to buoyant forces when they encounter freestanding

or flowing water, and when buried in saturated soils.
The buoyant forces are counteracted by the addition of weight, such as

concrete swamp weights(saddles), river weights (bolt-on) or continuous
concrete coating.
In this way, the pipe can be backfilled and kept in place once it has been
installed.
Two other methods that can be used to keep the pipe down are the
installation of mechanical anchoring devices or backfilling and utilizing the
mass of a select material to counteract the buoyant forces.
The final selection of the type and extent of buoyancy control measures is
usually made on a site-specific basis.
For example, swamp weights are good for wet areas where the pipe will stay
on or close to the bottom of the ditch and the weights will not slide off during
installation. If the ditch is filled with water, a river weight or continuous
concrete coating may be required to keep the pipe down. The choice between
these two is usually based on which is the more economic.
The required amount of weight, or the spacing of standard-size weights, is

calculated by equating the forces due to the mass of the pipe and weights
with the buoyant forces due to the fluid displaced by the pipe and weights. In
this calculation, a factor of safety called a negative buoyancy factor is
in'troduced to ensure that the pipe will stay down. Negative buoyancy factors
between 5% and 20% are common, depending upon the fluid density of the
soillwater mixture encountered and the construction methods used.
Buoyancy control may be achieved in three ways:
(1) by a mechanical anchoring system,
(2) by backfill, and
(3) by a density anchoring system
Mechanical anchors are designed to
maintain a minimum holddown force on
the pipeline by utilizing the shear
strength of the underlying soil.
They consist of individual or pairs of

Anchors attached to the pipeline by
holddown clamps or straps.
Mechanical anchor involves the use of a

steel anchor rod with an auger at the
lower tip.
They are not commonly utilized for

large-diameter pipelines
PIPE ANCHORS - CYNTECH
PIPE ANCHORS – DESIGN STANDARD
Backfill, using either native or borrowed select material for buoyancy control,
relies on the mass of the backfill over the pipe to counteract the buoyancy
forces.
Native backfill may be considered if it consists of stable, ice-free soil that is

capable of achieving a reasonable level of strength. If the native backfill is not
adequate, select backfill can be used.
Select backfill should be of coarse-grained, fiee-draining materials exhibiting

sufficient shear strength when thawed or mixed with water. Although gravel is
undoubtedly the best material, other materials such as a mixture of gravel,
sand, clay, and silt can be used.
The stability of the ditch wall is another important factor to consider in this
method of buoyancy control. Unstable ditch walls will not provide sufficient
support for the select backfill to keep it over the pipe.
Backfilling does not be used if the ditch contains water during backfilling.
The ditch must be dewatered prior to and during the placement of any backfill.
The backfill can then be placed in a controlled manner.
This method can be used when a ditch is dry during construction but may be
subjected to buoyant forces after backfilling is complete. Subsequent buoyant
forces could be due to thawing, flooding, or a rising water table.
Select backfill can then be used in place of weights in this situation. It can
also be used in relatively impervious soils where the ditch excavation has
penetrated below the water table.
Density anchors are a system of weights added to the pipeline.
The types of anchors are usually in the form of:
9concrete and include swamp weights (saddle or set-on);
9river weights (bolt-on), and
9continuous concrete coating.
Density Anchors
saddles
PIPE SADDLES – DESIGN STANDARD
Continous concrete coating
Continous concrete coating
CONTINUOUS CONCRETE COATING – DESIGN STANDARD
Set-on-bolt
Geotextile Fabric Weight
PIPELINE ANCHOR SYSTEM
Vs CONCRETE WEIGHTS
PIPELINE CONCRETE
ANCHOURS WEIGHTS
DESIGN anchor system is designed Concrete weights typically
to provide a hold-down provide a weight of 1.1
capacity of 25 times the times the buoyant force of
buoyant force of the empty the empts pipeline.
pipeline.
SPACING Typical spacing for NPS-24 Typical spacing for NPS-24
pipeline is 33 meters. pipeline is 5.6 meters.
STORAGE Pipeline anchor materials for Concrete weights for 10
10 kilometers of NPS-24 Kilometers of NPS-24
pipeline would require 30 pipeline would require 866
square meters of storage square meters of storage
space. space.
TRANSPORTATION Pipeline anchor materials Concrete weights for 10
for 10 kilometers of NPS-24 kilometers of NPS-24
pipeline would require 3 pipeline would require 199
truckloads. truckloads.
INSTALLATION A typical anchor installation A typical weight installation
crew would consist of a 5 tor crew would consist of a
picker truck with a hydraulic backhoe, an operator and
drive unit, an operator and two laborers.
two laborers.
Design Formulae with concrete continuous coating
DownwardForce
FS = ≥ 1.15
BuoyantForce
Ws + We + Wt + (WtxCBF )
FS = ≥ 1.15
Wb
Where:
Ws = weight of bare pipe per unit length
We = weight of corrosion coating per unit length
Wt = weight of backfilling per unit length
Wc = weight of concrete coating per unit length (if any)
Being: CBF = concrete coating cut back reducing factor (if any)
We =
[(OD + 2 × Cth) 2
− (OD) 2 ] × π × γct Wb = pipeline buoyancy per unit length (as per Archimedes’ Principle)
Wt = (γ × Hd × OD ) + (γsub × Hsub × OD )
Wc =
[(OD + 2 × (Cth + th )) c
2
− (OD + 2 × Cth) 2 ] × π × γcon
4
CBF =
(Lb − Cb × 2)
Lb

INTRODUCTION
• What is the stress analysis?
– It is the strength calculation of the pipeline in accordance

with the safety requirements, to verify that the pipeline
system is capable of withstanding the loads which occur
• What is the purpose of the stress analysis?
– To ensure structural integrity of the pipeline system

– To maintain system operability
INTRODUCTION
• What we suggest from stress analysis result?
– To modify the wall thickness of the pipe to increase the

strength of the pipe.
– To introduce or modify some support of the pipe system
– To modify the pipeline geometry configuration
STRESS ANALYSIS PROCEDURE
• Definition of pipeline system for analysis
• Load Analysis
• Calculation of stress and strain at the wall of the pipe
• Load combinations
• Comparison with the admissible values
DEFINITION OF PIPELINE SYSTEM
• Depending on the type of transport pipeline system:

– Buried or surface
– Transporting oil or gas or steam, etc.
• Design Data required for stress analysis:

– General data relating to the pipeline
– Operating data
– Soil characteristics data
DEFINITION OF PIPELINE SYSTEM:
General Data Relating to the Pipeline
• Data on pipeline route:

– Pipe geometry
– location and dimension of fittings, valves,
pumps,vessels,etc
• Data of the pipe and material characteristics:
– Outer diameter
– Wall thickness
– Minimum yield strength of materials at 20oC and at design
Temp.
– Type and rating of valves
General Data Relating to the Pipeline
• Data of contents and coating or insulation:

– Density of contents
– Corrosion thickness
– Thickness of coating or insulation
– Density of coating or insulation
Operating Data
• Design internal pressure

• Operating temperature of the content and of the pipe
• Temperature during laying of the pipe
• Design life of pipeline system
• Estimated number of operating temperature and pressure
cycles during the life of the system (fatigue analyses)
Soil Data
• Angle of internal friction (sand)

• Cohesion or undrenated shear strength (clay)
• Unit weight of the soil
• Angle of friction between pipe surface and soil (sand)
• Height of water table on the soil
• Load Analysis
LOAD ANALYSIS
• What does load analysis do?

– Defines permanent and incidental loads to which the
pipeline may be subjected
• What is load?
– Load is any physical process that result in deformation and
/or stress in the pipeline material
LOAD ANALYSIS CONDITIONS
• Construction phase
• Hydraulic testing phase
• Operating phase (in, out of service)
• Operating loads
• Installation loads
• Environmental loads
LOAD ANALYSIS:
Operating Loads
• Internal pressure, either design or hydrotest pressure
• Temperature difference between construction(tie-in) and

operating phases
• Weight loads
– Weight of the pipe and its structural members
– Weight of the contents
– Coating weight
– weight of all the pipeline appurtenances
LOAD ANALYSIS:
Installation Loads
• Pipelay configuration
• Pipeline Catenaries
• Pulling loads
• Self weight
• Backfilling
LOAD ANALYSIS:
Environmental Loads
• The external loads to be considered in the stress analysis

differ for:
– Buried pipeline
– Surface supported pipelines
LOAD ANALYSIS:
Buried Pipelines
• External weight loads
– Vertical superimposed loads or live loads

• Traffic loads including impact factors or dynamic effects
– Vertical soil load or dead loads

• Soil cover
LOAD ANALYSIS:
Buried Pipelines
• Loads induced on the pipeline by:

– Permanent soil movement
• Land slides
• Faults
• Settlements due to natural ground consolidation
• Soil movement from construction work
– Dynamic soil movement

• Seismic waves on the ground
• The effect of explosions
LOAD ANALYSIS:
Surface Supported Pipelines
• Where necessary ( in relation with the site characteristics,

pipe diameter and pipe elevation), allowance shall be made
for wind force
• The effect of seismic excitation on the pipe supports shall be

considered
• Relative movement of connected components shall also be

considered
• Insulating pipe temperature as laying temperature
• Load Analysis
CALCULATION OF STRESSES AND STRAINS
• Calculation of stress and strain at the wall of the pipe:
– Pipe structural models
– Soil-pipe interaction methods
– Stress / Strain Calculation
CALCULATION OF STRESSES AND STRAINS:
Pipe Structural Models
• Ring Model
• Beam Elements (straight and curved)
• Shell Elements
Note: use for both above or underground pipelines
Pipe Structural Models: RING MODEL
• Usually used for analyzing the behavior of buried pipelines

cross-section where large external loads are envisaged
(railways and road crossing )
• For Calculation purposes :
– Load Angle
• the angle that the soil load acts on the top of the pipe
(180o)
– Bedding angle
• The angle that the soil reacts against the pipe bottom,
dependent on the construction method and the
magnitude of soil reaction )
Pipe Structural Models:
Ring Model - Load Angle and Bedding Angle
Load Angle(180o)
Bedding angle
Pipe Structural Models: BEAM MODEL
• The analysis of the entire pipeline system is usually

performed modeling the pipe as a beam in both analytical and
numerical procedures
• Complex pipeline geometry, finite element methods need to

be used for the analysis
Pipe Structural Models: Beam model
y
x
z
End J
x
z
End I
Pipe Structural Models: SHELL MODEL
• Numerical method with shell elements are usually used to

analyze local stress concentrations at tees, bends, nozzles,
supports and the local behavior of pipe wall (wrinkling, cross-
section ovalization)
Pipe Structural Models:
SOIL-PIPE INTERACTION MODEL
• Analytical method
• Finite element technique
• Simplified methods
SOIL-PIPE INTERACTION MODEL:
Analytical Method
• The analytical method involve solutions on the equations of

elastic or elasto-plastic equilibrium in the context of a soil-pipe
interaction problem
• Applied to plane problems and easy geometrical configuration

of the pipeline
Finite Element Technique
• Capabilities to handle fully three- dimensional problems
• Give exact modeling of soil-pipe interaction using very

sophisticated models of soil behavior
• Time consuming
• Expensive
• Used in the critical situations
Simplified Methods
• The soil-pipe interaction is analyzed by idealizing the overall

behavior of the soil by an one dimensional mathematical or
mechanical model(spring ) along the three directions of
movement:
– Longitudinal
– Transverse horizontal
– Transverse vertical
Simplified Methods - Pipe Movement
Vertical Vertical Transverse

Upward Downward Horizontal Longitudinal
Simplified Methods - Load Displacement relationship
Force,F
Fu
Actual
Idealized
Stiffness, k
Displacement
Critical
displacement
Simplified Methods
z z kA
kH
x
x kV y
y
Real Condition Idealized structural Model
p t q
pu tu
yu xu qu
zu
yu xu zu
pu tu
qu
Transverse horizontal Axial Transverse Vertical
Soil - Stress Deformation

780 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1 st Ed.– September 2010 780
Stress/Strain Calculations
• The main stresses that affect a pipe element are the following
:
– The longitudinal stress due to.
• Direct longitudinal stress
• stress caused by.
– Temperature Longitudinal bending difference
– Pressure
– Weight
– Other external loads (wind, landslide etc. )
Stress/Strain Calculations
– Circumferential stress due to:

• Internal pressure (Hoop stress)
• Bending circunferential stress that can effect ;
– Buried pipeline (Railroad and railway crossings)
– Above ground pipeline (Hydrostatic test whit water)
– The radial stress due to:
• Internal pressure
– The shear stress is the sum of two components:
• Torsional stress
• Direct shear stress
• Load Analysis
LOAD COMBINATION
• Stresses and deformations of the following load combinations

shall be analyzed :
– Internal Pressure ( Design pressure )
– External Loads (P=0 calculation)
– Internal pressure and external loads
• Load Analysis
COMPARISON WITH THE ALLOWABLE
STRESS VALUES
• For an Elastic analysis, the allowable stress values is

expressed as:
– Percentage of the specified minimum yield strength
(SMYS) of the line pipe material
– The percentage of SMYS represents the safety factor
• Type of pipeline
• Class location F
• ASME Pressure Piping Codes consider the stresses values
for both liquid and gas
– ASME 31.4 (liquid and liquid hydrocarbons)
– ASME 31.8 (Gas)
STRESS VALUES: ASME B31.4
• The hoop stress due to internal pressure shall be less than F

* SMYS
• For restrained line the equivalent stress due to thermal

expansion and internal pressure shall be less than 0.9 *
SMYS
• For Unrestrained line the expansion stress shall be less than

0.72 * SMYS
• The Sum of the longitudinal stress due to pressure, weight

and other sustained external loads shall not exceed 0.75 *
0.72 of the SMYS
• The sum of the longitudinal stress produced by pressure, live

and dead loads, and those produced by occasional loads,
such as wind or earthquake shall not exceed 80% SMYS
• The hoop stress due internal pressure P shall be less than F

* SMYS
• The combined stress due to thermal expansion shall be less

than 0.72 * SMYS (b)
• The longitudinal pressure stress (c)
• The longitudinal bending stresses due to external loads, such

as weight of pipes and contents, wind, etc. (d)
• The sum of the stresses , b) and c) shall not exceed the

allowable value 0.75 * SMYS
• The total stresses, b), c) and d) shall not exceed the SMYS
STRESS VALUES: Allowable Stress
• Stress due to internal pressure :

– Hoop Stress
– Longitudinal Poisson stress
– Longitudinal pressure surface stress
• Stress due to the difference of temperature
Internal Pressure Stresses
σL,v σHoop = P D/ 2 t
σHoop
σL,v = v * Hoop Stress, (v = o.3)
PS σL,PS = P S / A
σL,v+σPS A= 3.14 * (De-t)t

σHoop
S = 3.14* ((De - 2t) / 2 )2
Temperature difference stress
T1 > To
T1
To σL,DT
σL,DT = ε*E = α*DT*E
α = 1.17*10-5 1/oc
E = 206 kN/mm2
Note:
Compression for DT > 0
Tensile for DT< 0
Stress calculation
• For the stress calculations we split the pipeline in two

sections:
– Restrained lines (no bends)
– Unrestrained lines (Near bends, branches,etc. )
F = PS
Restrained Lines
• Longitudinal Stresses
σL,dT = α dT E
σL,ν = 0.3 P D / 2 t
• Circumferential stress
σHoop = P D / 2 t
Unrestrained Lines
• Longitudinal Stresses
σL,dT < σL,dT Fully
σL,ν < σL,ν Fully
σL,PS = P S / A
σb,PS = M / W = (M / y)Re = M De/ 2y
• y = π (Re4 - Ri4)/ 4
• Circumferential stresses
σΗoop
σOvalization

STEEL PIPES FOR PIPELINES
LINE PIPE MANUFACTURING ROUTES
In the majority of the countries of the world, the specifications

of materials for construction of pipelines for the transport of
hydrocarbons refer to the API 5L standard.
In its original formulation, the API 5L standard identified the

grade of a steel, i.e. its mechanical resistance by means of its
yield strength, for example X52 or X60, where the number
identified the yield strength of the material expressed in
thousands of pounds per square inch (kpsi). This means that
the symbol X52 identifies a material with a yield strength of
52,000 pounds per square inch, equal to 358 MPa.
The most recent up-date of the API 5L standard conforms to

the ISO standard adopting the measurement units of the
International System, even though in reality it is still common
practice to use the old denomination.
Although the first version of the API 5L goes back to 1920, that
document was adopted as a reference specification only from
1948 onwards. At that time, the highest grade material included
in the specification was an X42, while today the standard
includes steels up to grade X80.
The most recent up-date of the API 5L standard conforms to

the ISO standard adopting the measurement units of the
International System, even though in reality it is still common
practice to use the old denomination.
Although the first version of the API 5L goes back to 1920, that
document was adopted as a reference specification only from
1948 onwards. At that time, the highest grade material included
in the specification was an X42, while today the standard
includes steels up to grade X80.
In 1999 the API 5L was converted to the international specification

ISO 3183 that deals with the choice and use of materials for
pipeline construction with and without longitudinal welding and
spiral tubes.
At the beginning, pipes for oil and gas transport were produced with
the UOE and SAW (Submerged Arc Weld) processes starting with
low alloyed steel sheets, which were hot laminated and then
subjected to a thermic normalization treatment. The mechanical
characteristics could reach the grade API X60 and the low
temperature tenacity was not always satisfactory.
The development of steels with high mechanical characteristics

(API grades X70, X80, X100) for the construction of pipelines has
undergone a notable acceleration since the 1970s with the
introduction of the controlled lamination process and of accelerated
in line cooling.
Today, pipes in API X70 grade steel are an established product for
which qualification and installation criteria are available: in
European countries there are many installations in this type of steel.
The production of API X80 grade pipe steel has undergone a

significant acceleration since 1980. In that connection there are a
number of publications that contain the results achieved in the
refinement of experimental products (Dillinger Huttenwerke SG,
Hoesch, Sumitomo Metal Industries, Nippon Steel Corporation,
Stelco, ILVA ILP) and in the construction of the first transport
pipelines with this material.
The requirements for high resistance steels are specified in several
existing standards up to grade X80. At present there are no
specifications relative to grade API X100 and, therefore, the
requirements for pipeline material in this type of steel have to be
agreed with the manufacturer in the product definition phase.
Even though pipes in API X100 grade steel are not yet available
commercially, many international manufacturers (Nippon Steel,
NKK, Kawasaki, Europipe) have produced experimental pipeline
products, with characteristics that seem to satisfy the requirements
for high pressure natural gas transmission.
The production of pipes in API X100 grade steel is an evolution
from the API X80 grade: the mechanical resistance characteristics
of the API X100 grade are obtained starting from the chemical
composition of grade X80 with targeted additives of micro alloying
elements (manganese, niobium, titanium) and by a process of
controlled lamination and accelerated in line cooling to the utmost
limit of the most modern laminating plants’ capabilities.
The velocity of accelerated cooling employed in the production of

API X100 grade plate is greater than 20-25°C/s, compared with the
15°C/s characteristic of the production of API X80 and with the 5-
10°C/s typical of medium-low grades.
The tenacity values of the base material appear satisfactory, both
from the point of view of the CharpyV energy (200-300 J) and from
that of the ductile/fragile transition. It is held that a CharpyV energy
value of 300 J constitutes an upper limit for thermo-mechanically
laminated steels.
On the basis of the experimental production of pipes in API X100

grade steel it can be assumed that these can be produced with a
chemical composition that satisfies the 0.45% maximum equivalent
carbon requirement.
The process of lamination adopted (very low temperature at the end

of lamination and at the end of cooling) ensures that the pipes in
API X100 grade steel display very high values of the yield/failure
ratio (>0.90).
PIPE SELECTION
The choice of materials and construction type for pipes dedicated
to pipelines is imposed by economic aspects and strictly depends
upon various factors among which:
• Pipe diameter
• Operating conditions
• Pipe thickness
• Transported fluid
• Pipe weldability
PIPE SELECTION
For a fixed pipe diameter with defined operating conditions, the
higher is the steel grade, the lower is the pipe thickness.
Selection of materials shall be performed by Optimisation of Costs:
• High steel grade→ valuable material → high cost

• Low steel grade → thick wall thickness → huge weight →
high cost
For industrial applications, prices of materials often depend on

pipe availability from suppliers and market situation and trend.
Therefore, pipe wall thickness is the main factor for selection.
CORROSION:
In sour service conditions (fluids having presence of H2S and/or
C02 with free water), the pipe is subject to corrosion (pitting
corrosion, hydrogen blistering and cracking, sulphide stress
corrosion cracking) and both the construction methods and
materials must be accurately selected.
Low material as well as high (X 65 and higher) material grades
are not normally used because, on one hand, the reduction of
steel susceptibility to sour corrosion mechanisms requires major
modifications to the composition of the steel together with proper
procedures for steel making (and this is not economical for low
grades materials), while, on the other hand, hydrogen sulphide
causes embrittlement of high strength materials leading to
cracking under imposed stress.
CORROSION:
Low material as well as high (X 65 and higher) material grades are
not normally used because, on one hand, the reduction of steel
susceptibility to sour corrosion mechanisms requires major
modifications to the composition of the steel together with proper
procedures for steel making (and this is not economical for low
grades materials), while, on the other hand, hydrogen sulphide
causes embrittlement of high strength materials leading to cracking
under imposed stress.
CORROSION:
• Welded pipes should be restricted since weldings are points
of weakness for corrosion.
• Steel grades normally used for sour services are in the range
from X 52 to X 60.
• NACE tests request special tests during production process.
• For low to medium annual corrosion rates, pipe wall thickness

is generally increased by 3 mm to 6 mm corrosion allowance,
according to the design life time.
• For high corrosion rates, pipes are internally protected by

continuous injection of corrosion inhibitors and/or internal
lining by epoxy resins.
INDUSTRIAL APPLICATIONS:
• Up to now, conventional gas pipelines (with design pressures
not higher than 7.5 or 8 MPa), recently put into operation or
presently at the construction stage, are based on steel pipes
with grades up to X 70, since weldings, construction
techniques and equipment are available and their reliability is
proven and largely consolidated by feed-back from operation.
• Only few applications of gas pipelines based on X 80 steel

pipes exist, the most outstanding of which is the Ruhrgas
Project in Germany (10 MPa, X 80, 48”, 250 km).
FUTURE TRENDS:
• The future trend, based on the increasing demand of natural
gas, predicts the construction of very large capacity, long
distance gas pipelines (i.e. transport of gas from Central Asia
and Russia to China or to Europe).
• These pipelines will be designed for increased transport

pressures (more than 10 MPa up to 14 MPa) and shall be
necessarily based on the use of high grade steel pipes (X 80
to X 100), large diameter (48” and 56”) and heavy wall
thickness (28 up to 32 mm).
Typical pipeline grade cost
818
Snamprogetti

NEW PIPELINE PRECOMMISSIONING AND COMMISSIONING SEQUENCE
Construction Activities
Flooding and
Hydrotesting
NO
Precleaning Post Electronic Involvement

before installation Gauging caliper of final
installation cleaning survey product ?
YES
Flooding and
Hydrotesting
Construction Act. Precommissioning Activities
Nitrogen purging Nitrogen

Flooding and Dewatering
Drying (chemical moth-
Hydrotesting and swabbing
inhibitor batch) balling
NO
Involvement
of final
product ?
YES
Flooding and Pipeline standing idle until commissioning
Hydrotesting
Construction Act. Pre. Commissioning Activities
Baseline survey
Flooding and
Product - In with MFL intelligent
Hydrotesting
tool
NO
Involvement
of final
product ?
YES
Baseline survey
Flooding and Pipeline dewatering
with MFL intelligent
Hydrotesting while product - in
tool
NEW PIPELINE: SECTIONS SELECTION
Pipeline Elevation
350
300
250
200
Elevation [m]
Elevation
150
100
50
0
0 10000 20000 30000 40000 50000 60000 70000 80000 90000 100000
Progressive [m]
Pipeline Test Pressures
115
110
105
Pressures [bar]
Min Test Pressure

Max Test Pressure
100
95
90
0 10000 20000 30000 40000 50000 60000 70000 80000 90000 100000
Progressive [m]
125
120
115
Pressures [bar]
110
Min Test Pressure
Max Test Pressure
Test Pressure
105
100
95
90
0 10000 20000 30000 40000 50000 60000 70000 80000 90000 100000
Progressive [m]
115
110
105
Pressures [bar]
100
95
90
0 10000 20000 30000 40000 50000 60000 70000 80000 90000 100000
Progressive [m]
Min Test Pressure Max Test Pressure Test Pressure Section 1 Test Pressure Section 2 Test Pressure Section 3
1. Test Pressure
2. Line thickness differences
3. Special sections (Road crossing, river crossing, etc.)
4. Client requirements
5. Construction or Contractual requirements
TEST or ACTIVITIES MEDIA
1. Potable Water
2. Raw Water
Water
3. Sea Water
Physical Treatments
(filtration)
Laboratory Analysis
1. Client
2. Final Product
Requirements
YE
S
Chemical NO
3. Activities time
Treatment?
4. Water availability
1. Oxygen Scavenger 1. Short Activities Duration
2. Bactericide 2. No requirements of Final
3. Ion reductors (Cl, Na, etc.) Product
Laboratory Analysis
Transfer to other section
Laboratory Analysis
Disposal
PIG AND PIG LAUNCHING AND RECEIVING SYSTEMS
PIG AND PIG LAUNCHING AND RECEIVING SYSTEMS
PRE INSTALLATION CLEANING
1. Manual Cleaning
2. High pressure water retro jetting
3. High velocity air cleaning
PRE INSTALLATION CLEANING
POST INSTALLATION CLEANING
1. High pressure water retro jetting (short section)

2. High velocity air cleaning (short section)
3. Cleaning Pigs Trains driven by test media (normal method)
Typical Cleaning Pigs
1. 1st cleaning pig.
2. A batching / displacement pig.
3. A slug of 100 linear metres of water.
4. 2nd cleaning pig.
5. A slug of 100 linear metres of water.
6. A gauging pig installed with pigger and driven by water.
7. Fill entire pipeline/section with treated water. During the filling of the line
readings of pressure/water input/time will be taken every 1 hour
8. Receive filling pig, brush pig, and gauge pig at the other end of the line
9. Continue pumping until all air is expelled
10. Start pressure test
Batching Bidiractional Pig
GAUGING
The gauging pig will be bi-directional disc type pigs. Two gauging plates shall
be fitted on the gauging pig, one behind the first cup and one before the last
cup. The gauging plates shall be removable type of 6 mm thick machined
aluminium with adequately spaced radial incision. The incision shall extend
from the outside diameter of the plate to the outside circumference of the
flange of the pig. The leading edge of the gauging plate shall be chamfered for
3mm at 45°C.
All gauging plates diameter shall be 97% of the nominal internal diameter of the
24” gas pipeline system being gauged. The nominal internal diameter shall be
calculated from:
Nominal Internal Diameter = Nominal O.D. - (2 x nominal wall thickness).
Calculation shall be performed to confirm that the selected gauge plate will be
able to pass induction bends (with 3% permissible out of roundness).
KALIPER (CALIPER) PIG INSPECTION
KALIPER (CALIPER) PIG INSPECTION
FLOODING AND HYDROTEST
DEWATERING AND SWABBING
DRYING
1. Dry Oil Free Compressed Air Drying

2. Vacuum drying
3. Methanol Slug Drying
AIR DRYING
25
20
15
WDP @ p atm (°C)
10
5 WDP @ p atm (°C)
0
-5
-10
-15
-20
-25
0 1 2 3 4 5
Time (hours) 0.14
0.12
0.1
Water Content (m3)

Total Water Content in the pipeline
0.08
0.06
0.04
0.02
0
0 5 10 15 20 25
Time (hours)
VACUUM DRYING
INTELLIGENT (MFL TOOL) PIG INSPECTION
INTELLIGENT (MFL TOOL) PIG INSPECTION
Index

The incidence of corrosion
The study entitled “Corrosion Costs and Preventive Strategies in
the United States,” was conducted from 1999 to 2001 and
published by NACE.
The study aimed to determine the cost of corrosion control
methods and services and the overall economic impact of
corrosion for specific industry sectors.
Results of the study shown that the total annual estimated direct
cost of corrosion in the US is 276 billion dollars, approximately
3.1% of the US Gross Domestic Product (GDP).
Corrosion also emerged as the primary factor affecting the
longevity and reliability of networks transporting crucial energy
sources as oil and gas. The average annual corrosion-related
cost in the US is estimated in over 12 billion dollars to monitor,
replace, and maintain these assets.
The study clearly revealed that, while technological advancements

have provided many new ways to prevent corrosion, better
corrosion management can be achieved using preventive
strategies, in non technical and technical areas, identified as
follows:
9 increase awareness of significant corrosion costs and potential
cost savings
9 change the misconception that nothing can be done about
corrosion
9 change standards and management practices to increase
corrosion cost savings
9 improve education and training of staff in the recognition of
corrosion control
9 Implement advanced design practices for better corrosion

management
9 Improve corrosion technology through research, development,
and implementation.
Controlling corrosion requires significant expenditures, but the

payoff includes increased public safety, reliable performance,
maximized asset life, environmental protection, and more cost-
effective operations in the long run.
Definition of corrosion
Corrosion is the deterioration of a material that results from a
reaction with its environment. For a metal in contact with an
aqueous solution, the reaction is an electrochemical one involving
the transfer of electrical charge (electrons) across the
metal/environment interface.
Particularly, steel structures located in an electrolytic environment
i.e. buried in every type of soil or immersed in water, change in
time due to corrosion phenomena.
These phenomena originates from the natural, electrochemical
potential difference which, in the presence of an electrolytic
environment, causes the steel surface to cede or gain electrons
and then change its physical and chemical characteristics.
Definition and elements of a corrosion cell
Corrosion always takes place in the form of a corrosion cell, that

has the following four essential components:
9 an anode, where the oxidation reaction occurs
9 a cathode, where the reduction reaction occurs
9 an electronic path that allows electrons to flow from the anode to
the cathode (inside the same metal or metal-to-metal)
9 an electrolytic path that allows ions to flow between the anode
and the cathode (in the electrolyte i.e. environment surrounding
both anode and cathode, soil or water).
Definition and elements of a corrosion cell
Being oxidation the reaction in which a metal becomes more

electropositive, the anode is the electrode in the corrosion cell
which cedes electrons and corrodes.
Reversely, being reduction the reaction in which a metal becomes

more electronegative, the cathode is the electrode in the corrosion
cell which gains the electrons ceded by the anode.
Types of corrosion
Provided the presence of a corrosion cell, the actual conditions

of the metal and its environment may vary widely leading to
different types of corrosion (most common are shown below).
Uniform corrosion – anodic (A) and cathodic (C) areas are

located on the same metal surface and change locations
resulting in a general metal loss i.e. atmospheric corrosion.
Pitting corrosion – anodic areas (A) remain fixed and corrosion is
localized i.e. stainless steel in the presence of chlorides.
Crevice corrosion – anodic area (A) in the crevice is oxygen

starved while surrounding surfaces (C) have access to dissolved
oxygen i.e. overlapping structures.
Galvanic corrosion – dissimilar metals are interconnected and
exposed to a common environment i.e. cast iron water main
with copper utilities, different metal plates.
All these types of corrosion can be effectively mitigated with

cathodic protection if the structure is buried or immersed.
Common causes of corrosion of a typical oil &
gas installation
The most common causes of corrosion in a typical oil & gas

installation are:
1.presence of dissimilar metals (galvanic corrosion)
2.presence of potential gradients due to the surrounding
environment
3.presence of stray currents.
Briefly, these typical causes of corrosion will be described.
Presence of dissimilar metals
Each metal buried or immersed in an electrolyte acquires a
distinctive natural potential. Table below shows natural
potential of some metals in a neutral soil.
Potential (vs. The metals in this table (also
Metal
CSE) known as galvanic series)
↑
Pure Magnesium -1.7 V are arranged so that, when
electronegativ
e two of them are placed in the
Zinc -1.1 V
Pure Aluminium -0.8 V
same electrolyte setting up a
corrosion cell, the metal in
Bright steel (Iron) -0.5 V to -0.8 V
electropositiv
the upper line (lower
Rusty steel (Iron) -0.2 V to -0.5 V e potential) will act as an
↓ anode, while the metal in the
Lead -0.5 V
Copper -0.2 V
lower line (greater potential)
will act as a cathode.
In general, when any two metals are coupled, the more

electronegative alloy will be become the anode of a corrosion
cell.
The coupling of dissimilar metals will establish a potential
gradient between them, resulting in a current i.e. transfer of
electrical charges conventionally flowing from the cathode to
the anode in the metallic connection, and from the anode to the
cathode in the electrolyte. Hence the electrons will leave the
metal constituting the anode to cause its corrosion.
Further, the greater the potential gradient, the greater the

corrosion current.
Seldom this phenomenon may occur when aged, steel pipe lengths
or plates are replaced with same but new material. Referring to the
galvanic series table, the old, rusty metal will work as the cathode
(natural potential -0.5 V) while the new, bright metal will work as the
anode (natural potential -0.8 V) and therefore will be subject to
corrosion.
Presence of potential gradients
A potential gradient may not only be due to the coupling of
dissimilar metals but may also occur on a same, homogeneous
structure.
For instance, a bare steel pipeline, made of the same steel grade
throughout its length, may show different potentials according to
local chemical characteristics of the soil in which it is laid (over long
routes, such that of transmission pipelines, often soils vary widely).
This potential gradient causes a current to flow from the anodic
zone to the cathodic zone, resulting in corrosion of the anodic
zone.
Presence of stray currents
There are electrical installations which, while operating, drain
currents in the soil. Basically, these are:
9 traction systems, like railways, which use steel rails as a return
conductor
9 equipment which use the soil as a return conductor i.e. welding
systems, etc.
9 impressed current cathodic protection systems.
Stray currents may cause severe damage to structures.
Particularly, long horizontal structures like transmission pipelines or
sheathed cables may be in danger of this type of corrosion. Since
corrosion damage may appear after a short time of exposure to
stray currents, it is essential to make provisions for protective
measures at an early stage.Identification and measurement is
always is challenging procedure as stray currents may be either
DC or AC, and affected by a large number of factors.
A typical example of DC stray current is that of a steel pipeline

crossing an electrified railway.
As all stray currents return back to the draining point via a path with
the lowest resistivity, a steel pipeline crossing a railway usually
becomes the preferential path of railway induced stray current
because of its lower resistivity with respect to the soil. The area in
which the stray current enters the pipeline becomes the cathode
while the area from which it leaves becomes the anode and could
be subject to corrosion.
Means for corrosion control
The most practical means to control the corrosion of buried or
immersed metallic structures are:
9 insulating coating
9cathodic protection.
Coating Cathodic
protection
Although these two methods may work independently, their

combination facilitates the achievement of complete corrosion
control.
Cathodic protection
NACE defines cathodic protection as “a technique to reduce

the corrosion of a metal surface by making that surface a
cathode of an electrochemical cell”.
The theory of cathodic protection is best understood by first

considering a simple corrosion cell, modelled as an electrical
circuit, consisting of one anode and one cathode on a
structure. After the corrosion cell has reached a steady state,
the driving potential is the difference between anode and
cathode potentials and the corrosion current magnitude is
determined by Ohms Law.
Cathodic protection
Icorr = Corrosion current (A)

Ea,p = Potential of polarized anode (V)
Ec,p = Potential of polarized cathode (V)
Ra = Resistance of anode to electrolyte (Ω)
Rc = Resistance of cathode to electrolyte (Ω)
In this condition the current discharged by the anode is exactly

the same as the current collected by the cathode. Corrosion
occurs at a certain rate.
Cathodic protection
With application of cathodic protection, positive charge flows from
an external source toward the structure to be protected i.e. simple
corrosion cell, as shown below.
Icp = Cathodic protection current (A)
Now, the corrosion (or anodic) current is no longer equal to the

cathodic current. From Kirchhoffs Law, corrosion (or anodic)
current is equal to the cathodic current from the corrosion cell
minus the applied cathodic protection current.
Cathodic protection
The simple corrosion cell must now reach a new steady condition.
Since the cathode is at a more electropositive potential than the
anode, it collects current first. This cause the cathode to polarize
more in the electronegative direction (reduction reaction).
Because of increased polarization of the cathode, the driving
potential decreases as well as the magnitude of the corrosion
(anodic) current. With a smaller corrosion current discharging into
the electrolyte at the anode, the anode depolarizes becoming less
electropositive. A new steady state condition is reached with a
smaller corrosion (anodic) current due to the applied cathodic
protection current.
With additional increments of applied cathodic protection current,
the corrosion current decreases further and the anode depolarizes
more until the anode reaches its natural potential.
Cathodic protection
At this point:
9 the anode cannot depolarize further
9 the driving potential reaches zero
9 the corrosion (anodic) current reaches zero
9 the anode ceases to work as an anode
9 the cathodic current equals the cathodic protection current
9 the corrosion is stopped.
Cathodic protection
In a real corroding structure with many anodes and cathodes, more

and more anodes convert to cathodes as larger amounts of
cathodic protection current are applied. When the entire structure
polarizes to the open circuit potential of its most electronegative
anode, no further anodes exist and complete cathodic protection is
achieved.
Therefore, the true criterion for complete cathodic protection of a

corroding structure is the polarization of the cathodes on the
structure to the open circuit potential of the most electronegative
anode present on the corroding structure.
Cathodic protection
Since corrosion ceases at this point, applying additional cathodic

protection current only serves to polarize the structure more
electronegatively until, beyond a certain value, it becomes
unnecessary and wasteful.
The application of the true criterion to real corrosion problems

is not possible as it is not possible to determine in the field the
open circuit potential of the most electronegative anode on
the corroding structure. Hence surrogate criteria, based on
laboratory and field experience, are used.
Cathodic protection - Criteria
The purpose of a surrogate cathodic protection criterion is to

provide a benchmark against which the level of cathodic
protection applied to a specific structure can be compared.
International standard organizations as NACE, ISO, EN, etc.

addressed a number of applicable cathodic protection criteria
for carbon steel, considering affecting factors as temperature
and soil conditions.
Cathodic protection - Criteria
Environment Temperatur Protection potential (vs.

e CSE)
High resistivity soil ρ > 500 - -0.75 V or more negative
Ω*m
i.e. loose sand
Aerobic soil i.e. sandy soil or T<40°C -0.85 V or more negative
water
Aerobic soil i.e. sandy soil or T>60°C -0.95 V or more negative
water
Anaerobic soil i.e. clay - -0.95 V or more negative
“Aerobic” stands for oxygen rich, “anaerobic” stands for oxygen

starved.
Cathodic protection – Design basic factors and
choices
As seen in previous table most appropriate criteria changes

according to external factors like structure temperature and
environment.
For onshore oil & gas installation, main importance is covered by

surrounding environment. Particularly, soil conditions are
determining the overall cathodic protection approach as soil
corrosiveness vary widely according to its moisture or chlorides
content.
Cathodic protection – Design basic factors and choices
During a dedicated pre-design survey, these information are

gathered:
9 Soil resistivity, indicating the electrochemical corrosiveness
of the environment
9 Soil temperature, particularly seasonal high, aiding the
assessment of the optimal protection current density
9 Possibility of stray currents, either AC or DC.
A strong relationship between soil resistivity and its

corrosiveness exists, as shown in table below.
Cathodic protection – Design basic factors and choices
Soil resistivity (ρ) Corrosiveness

Up to 10 Ω*m Highly corrosive
Between 10 Ω*m and 50 Corrosive
Ω*m
Between 50 Ω*m and 100 Slightly corrosive
Ω*m
Over 100 Ω*m Weakly corrosive
Hence, the basis of preliminary design choices are these

three:
1. Soil resistivity / corrosiveness
2. Extension and shape of surfaces to be protected
3. Presence of stray currents, either AC or DC.
Cathodic protection – Sacrificial anodes
First step is choosing most appropriate method of cathodic
protection between:
1.Sacrificial anodes system
2.Impressed current system.
Cathodic protection by sacrificial anodes basically consist in

intentional coupling different metals. The sacrificial anodes are
selected in order to have a more electronegative natural
potential with respect to that of the structure to be protected
(cathode) so that it corrodes, ceding electrons to the structure
to be protected which becomes immune from corrosion.
According to the galvanic series table, most suitable alloy for

cathodic protection of steel structures are:
1. Magnesium
2. Zinc
3. Aluminium.
This application of this method, as well as the impressed
current method, has advantages and disadvantages to be
considered in the design stage.
Optimal distribution of CP current Limited driving voltage available
No electrical interference problems Limited CP current available
Not suitable in high resistivity soils

External DC source is not required
Not suitable for bare, badly coated structures

Easy and cost effective installation
Not suitable for retrofitting purposes

Land acquisition is not required
Calibration of system is not required
Maintenance costs are negligible
As anticipated, most used metal alloy as sacrificial anodes are Magnesium,

Zinc and Aluminium based, each one with distinctive range of potentials,
consumption rate, application and manufacturing shapes.
Magnesium
alloy
Natural potential Consumption rate

-1.55 V to -1.75 V 8 kg/A*year
Potable water storage tanks Soils with resistivity up to 100

and vessels internals Ω*m
Flush type Boss type Solid rod type
Zinc
alloy

-1.05 V to -1.10 V 12 kg/A*year
Deep water offshore Storage tanks and Soils with resistivity

sealines vessels internals up to 15 Ω*m
Bracelet type Boss type Solid rod type
Slender type Flush type
Aluminium
alloy

-1.05 V to -1.10 V 3 to 4 kg/A*year
Storage
Offshore tanks and
installations vessels
internals
Bracelet type Boss type
Slender type Flush type Slender type Flush type
For onshore applications, usually sacrificial anodes come to site pre-packaged in
a moisture-retaining chemical backfill, which helps the transfer of charges in the
electrolytic path.
In conclusion, sacrificial anodes are suitable to protect:

1. small extension surfaces in low resistivity soils (ρ < 100 Ω*m)
2. integrate impressed current systems in “hot-spot” location i.e. line valves
3. offshore structures.
Cathodic protection – Impressed current
Cathodic protection by impressed current basically consist in

applying to the structure to be protected a determined cathodic
protection current supplied by power source that is external to
the anode-cathode system.
Hence, a basic impressed current system consists of:

1. one DC power source i.e. transformer-rectifier, thermo-
generator, solar power generator, etc.
2. one anodic groundbed, constituted by a suitable number of
appropriate anodes
3. cables, connecting the DC power source to the structure
and the anodic groundbed.
In this method, a ground bed (artificial anode), delivering the

cathodic protection current, is installed a a suitable distance to the
structure to be protected. The negative pole of the DC power source
is connected is to the structure, the positive pole is connected to the
ground bed.
In this way, the current direction is reversed with respect to natural

flow and flows from the ground bed to the structure. Also, the
magnitude of the cathodic protection current is adjustable, from the
DC source, according to Ohm’s Law.
This eventually allows to adjust the potential on the structure as
needed.
This application of this method has advantages and

disadvantages to be considered in the design stage.
Significant driving voltage available Electrical interference problems
External DC source is required

Significant CP current available
Complex installation
Adjustable CP current and potential
Land acquisition is required
Few installations are required
Calibration of system is required
Suitable in high resistivity soils Maintenance costs are significant
Suitable for large or bare structures
Suitable for retrofitting purposes
Most important items in the system are the DC power source and
the anodes constituting the ground bed. According to local
availability of power, the most common DC source choices are:
Transformer-rectifier
Applicable where AC power grid is available.
Suitable for very high cathodic protection currents,
up to 50 A (about 3 kW).
Solar power system
Applicable where AC power grid is not available.
Suitable for small cathodic protection currents
(about 400 W).
Thermo-electric generator
Applicable where AC power grid is not available. It
burns natural gas to generate DC current. Suitable
for small cathodic protection currents (about 550
W).
According to environment and current requirement, the anodic
material most common choices are:
Silicon-Iron
Suitable for a wide range of applications. Silicon-
Iron anodes are cast in solid rods or tubular
shape. Consumption rate is about 0.5 kg/A*year.
Silicon-Iron-Chrome
Having same basic characteristics of Silicon-Iron,
the addition of Chrome enhances the resistance
to chlorides but presents some toxic hazard.
Consumption rate is about 0.2 kg/A*year.
MMO/Ti
Preferable where high current or very long design
life are required, due to negligible consumption.
MMO/Ti anodes most common manufacture shape
is tubular, ribbon or mesh.
According to required distribution of current, soil resistivity,
availability of land and Clients standard, anodic ground bed are
arranged as:
Deep well
Anodes are laid inside a drilled borehole, in
order to reach low resistivity soil layers (e.g.
in a desert area) or to avoid land acquisition.
Commonly used for pipelines systems.
Shallow horizontal
Anodes are laid horizontally in an
excavated, shallow trench in order to
ease installation. Used both for
pipelines systems, where soil resistivity
is relatively low, and plants.
Shallow vertical
Anodes are laid vertically in a number
of drilled, shallow boreholes.
Commonly used for plants narrow
locations.
Eventually, the established structure-to-soil potential of a protected
structure is to be monitored on a routine basis at significant points.
Therefore, each pipeline system cathodic protection system will be
integrated with monitoring facilities located at each:
9 main road, river or railway crossing
9 buried foreign service crossing
9 end of a parallelism with buried foreign services or HV power
lines
9 metallic casing
9 insulating device i.e. insulating joint or flange.
Basically, monitoring facilities on a pipeline are installed with a

maximum 1 km (urban area) to 3 km (desert area) interval.
Inside a plant area, monitoring facilities are installed in anticipated

hot spots.
Index

PIPELINE EXTERNAL COATING
Carbon steel is used for the construction of pipelines, piping

and pipe racks, storage tanks, etc., for cost and strength
reasons.
However, carbon steel is not inherently corrosion resistant
and needs protection from corrosion where a water layer
(condensation, immersion, etc.) is present in contact with the
steel surface.
A surface covering (coating, painting and lining) separates
the steel from water and helps to prevent corrosion.
For buried or submerged structures cathodic protection (CP)
is needed to supplement the coating at any coating defects
that will occur.
Specific Definitions:
"Coating" - An electrically insulating layer applied to a metal
surface, that affords passive protection against external
corrosion.
"Corrosion" - The electrochemical reaction of metal with its
environment, resulting in its progressive degradation or
destruction.
"Electrolyte" - A liquid or the liquid component in a composite
material such as soil in which electric current flows by movement
of ions.
"Painting" - Surface covering applied to above ground steel (and
other) structures that will have no other continuous corrosion
control measures applied.
PURPOSE OF THE SYSTEM
The purpose of the coating system is primarily to protect the

steel from the effects of a corrosive electrolyte (i.e. soil, water).
The main linepipe coating will be applied in the factory.
Field joints (over pipeline circumferential welds) will be applied

on site.
Items to be coated also include pipeline fittings (i.e., bends, tees

and valves).
COATING DESIGN
Selection of an anticorrosion coating for a particular use is related

to cost and long term stability. Factors to be considered in the
selection process:
9 adhesion and resistance to disbonding
9 resistance to chemical, physical and biological
deterioration
9 easy application, including field joints and repairs
9 operating temperature range
9 flexibility and tensile elongation
9 strength and impact resistance
9 resistance to water permeation and absorption
9 compatibility with cathodic protection
9 resistance to soil stresses
COATING SYSTEM ITEM TO BE TEMPERATURE TYPICAL
COATED RANGE (a) APPLICATION
Pipes Fittings Field joints (°C) SITE
Three layer polyethylene X - - -40/+80 Factory
Three layer polypropylene X - - -30/+120 Factory
Fusion Bonded Epoxy X X X -40/+105 Factory, field

(FBE)
Coal tar enamel X - X 0/+60 Factory, field
Cold applied Plastic tapes X X X -20/+75 Field

(PE or PVC tapes)
Heat shrinkable sleeves - - X -30/+120 (b) Field

and tapes
Liquid epoxy resin (c) X X X -30/+100 Factory, field

Notes:
(a) Max. Operating (Service) Temperature.
(b) Upper limit as declared by product Manufacturers.
(c) Thermoset coatings include epoxy and polyurethane based systems.
In all cases, environmental conditions (as established by

measurement) during surface preparation and coating need to
be within set ranges. These include:
• low wind/dust conditions (and use of habitats for field

joint coating)
• relative humidity is less than 85%
• steel surface temperature is more than 3°C above dew
point
Obtain correct surface profile after blast cleaning to ensure good

key for coating adhesion and ensure surfaces are clean and free
of contamination.
Apply coat layers to correct thickness range (not too thin or

thick), allow intermediate layers to cure fully where necessary
and apply subsequent layers within the prescribed time period.
Repair coating damage to an approved procedure (in shop and

on site).
PIPELINES COATING GLOBAL MARKET TREND (1):
Bituminous coating are being replaced all over the world by

modern coatings for
two reasons:
1 - requirements of environmental laws,
2 - decreasing of efficiency (permeation, cracking, sagging and
chemical deterioration).
European Companies prefer Polyethylene (PE) and

Polypropylene (PP) coatings.
The philosophy of “passive protection”. Extremely watertight
coating, high dielectric strength and thickness and drain a very
low Cathodic Protection current.
PIPELINES COATING GLOBAL MARKET TREND (2):
USA, UK companies prefer Fusion Bonded Epoxy (FBE)

coatings.
Cathodic Protection has higher importance in pipeline
protection.
Coatings, even with reasonable impermeability, are thinner and
more compatible to Cathodic Protection systems.
Maintenance budgets, passive protection costs and repairs have a

significant influence on the overall pipeline budget.
The cheapest solution is rarely the best one in the long term.
A slightly more expensive PE coating solution can turn out to be

the most economical after 30 years of uninterrupted service.
IN-HOUSE EXPERIENCE
FROM LATE 70’s TO DATE, THE ITALIAN GAS COMPANY HAVE INSTALLED
OVER 32,000 Km OF GAS PIPELINES, FROM 10 TO 56 INCHES.
ALL PIPES WERE EXTERNALLY COATED MAINLY WITH POLYETHYLENE

SYSTEM AND WITH THERMOSETTING EPOXY RESIN FOR BENDS AND
FITTINGS.
DURING LAST 30 YEARS, THE “Eni GROUP” HAS DEVELOPED DETAIL COATING
SPECIFICATIONS AND QUALIFIED MATERIALS AND APPLICATORS WHICH HAS
BEEN IDENTIFIED IN STANDARD SPECIFICATION AND PROCEDURES.
THE PE COATING SYSTEM IS MORE APPROPRIATE FOR PIPELINES NETWORK

BURIED IN A HIGH DENSE POPULATED (URBAN) AREAS, IN TERRAINS
COMPOSED BY COMPACT CLAYS, ROCK AND STONES (EUROPEAN GAS
NETWORK IS PROVIDED WITH PE COATING).
x – PIPELINE EXTERNAL COATING
FIELD JOINT COATING MATERIALS
FIELD JOINTS ARE THE WEAKEST POINT OF THE EXTERNAL COATING

BECAUSE OF ARSH APPLICATION CONDITION.
The most used/selected materials are Heat Shrinkable Sleeves (HSS)

coating products as field joint coating.
The most common types of this product are fairly easy to apply and are
compatible with the most commonly used pipe coatings.
Shrink coating products may be applied on top of the appropriate primers,

normally epoxy-based, in order to increase mechanical resistance and
resistance to temperature, shear stress and corrosion.
TYPICAL CAUSES OF COATING FAILURE
Common causes of coating failure are reported to be (a) :
- improper surface preparation

- improper selection of coating material
- improper coating application
- improper handling of the coated structure
- improper backfilling with soil
-improper cathodic protection
TYPICAL CAUSES OF COATING FAILURE
In addition, penetration of coating by roots, partial disbonding, of

tape coatings
in particular, and coating failure under soil stresses, for example, in
clay soils
that expand/ shrink during wet/dry cycles, can also cause
problems.
(a) Reference NACE Publication: Corrosion Prevention by

Protective Coatings
VERIFICATION OF LINE INTEGRITY
THE METHODS USED TO VERIFY THE INTEGRITY OF THE

EXTERNAL COATING ARE:
• PEARSON METHOD
• TRANSVERSAL and LONGITUDINAL DIRECT CURRENT

VOLTAGE GRADIENT
PEARSON TECHNIQUE - THE PRINCIPLE
• The pipeline CP shall be switched off.
• Uses a frequency generator (typically 4-1500 Hz).
• The signals issued by the generator is then picked up by a
dedicated receiver along the pipeline.
• Approaching the coating defect, the signal increase up to a
maximum and suddenly decrease to a minimum when the two
poles of the receiver are straddled over the defect . If no
defects are present, the signal remain approximately
constant.
• Operator shall walk along the buried pipeline.
PEARSON TECHNIQUE
PEARSON TECHNIQUE – MAIN FEATURES

PRO’S
• locates all coating defects

• gives a rough indication of defects severity
• 2 persons required (1 person with last generation
instrumentation)
CON’S
• operation/interpretation is operator dependent

• can survey up to 7-8 km per day only
• suitable for newly laid pipelines only
• must be integrated with other techniques for more accurate
results
TRANSVERSAL DC VOLTAGE GRADIENT (DCVG) SURVEY
• Uses the principle of cathodic protection to detect any coating

defect.
• The existing pipeline CP can be used.
• The CP current shall be cycled (12 sec. On, 2-3 sec. Off)
• A remote Cu-CuSO4 reference electrode (undisturbed from the
electrical field variation caused by the possible defect) shall be
put 50-100 m from the p/l right of way
• An identical Cu-CuSO4 reference electrode shall be moved along
the p/l right of way.
• The two electrodes are connected through a chart recorder or a
digital recorder
• If a coating defect is present, a potential gradient is measured via
the 2 electrodes during the on-off condition variation
remote electrodes ≥50m
Coating damage
PRO’S
• detects exact location of coating defects

• roughly assesses dimensions of coating defects
• suitable for new and old pipelines
• 1 person required
CON’S
• time consuming
• to be used as integration of other techniques (i.e. Pearson)
LONGITUDINAL DC VOLTAGE RADIENT (DCVG) SURVEY
• Uses the principle of cathodic protection to detect any coating

defect.
• The existing pipeline CP can be used.
• The CP current shall be cycled (1/3 sec. On, 2/3 sec. Off)
• Two identical Cu-CuSO4 reference electrode are placed along
the right of way through an analogic galvanometer
• Approaching the coating defect, the signal increase up to a
maximum and suddenly decrease to a minimum when the two
electrodes are straddled over the defect .
• To approx size the defect, the two electrodes configuration shall
be the same of the transversal DCVG.
LONGITUDINAL DC VOLTAGE RADIENT (DCVG) SURVEY
LONGITUDINAL DC VOLTAGE GRADIENT (DCVG) SURVEY
PRO’S
• detects exact location of coating defects

• roughly assesses dimensions of coating defects
• can assess if defects would be corroding
• suitable for new and old pipelines
• 1 person required
• not time consuming – up to 5-6 km/day
• to be used alone or as as integration of other techniques
(PEARSON)
COMPARISON TABLE AMONG DIFFERENT TECHNIQUES
Tequines No. of persons Daily Characteristics
required Investigated
length
PEARSON 2 persons up to 7-8 km /day locates all coating defects

(1 with last can give a rough indicationof defects severity
generation operation/interpretation is operator dependent
instrumentation) can survey up to 7-8 km per day
suitable only for new pipelines
must be integrated with other techniques for more precise results
PEARSON and 2 persons depending on No. more cost effective than the techniques used separately
DCVG (longitudinal (1 with last of defects: suitable only for new pipelines
or transversal) generation up to an average to be used on long pipelines
instrumentation) of 6-7 km /day on short sections only DCVG is suggested
DCVG (longitudinal) 1 person depending on No. detects exact location of coating defects
of defects: roughly assesses dimensions of coating defects
up to 5-6 km /day can assess if defects would be corroding
suitable for new and old pipelines
not time consuming – up to 5-6 km/day
to be used alone or as integration of other techniques (PEARSON)
DCVG (transversal) 1 person up to 5-6 km /day detects exact location of coating defects
roughly assesses dimensions of coating defects
suitable for new and old pipelines
to be used as integration of other techniques (PEARSON)
APPLICATION OF POLYETHYLENE (PE) / POLYPROPYLENE (PP) COATING
Polyethylene / Polypropylene coatings are applied to pipes designed to convey water, gas, oil or
any other fluid, for buried services (soil or seawater) and when the continuous temperature of the
fluid being carried does not exceed 80°C/120°C.
The pipe is preheated to eliminate humidity
The external surface is shot-blasted to remove mill

scale and rust, obtaining a metal surface which
facilitates the adhesion
The pipe is heated in a gas or induction oven at a

controlled temperature
The primer is then applied by extrusion or

electrostatic powderingImmediately afterwards,
the polymeric adhesive and PE/PP are extruded
on the pipe
After application of the PE/PP, the

pipe is cooled by spraying water.
End brushing
This coating offers the following advantages:
9 mechanical resistance at high and low temperatures
(bending does not damage this coating)
9 easy storage and shipping of coated pipes: same stacking
possibilities as for bare pipes
9 backfill possible with material of higher sieve acceptance
than that of the sand generally used for coal tar based
coatings
9 strong adhesion to steel
9 resistance to micro-organism
9 lighter cathodic protection
APPLICATION OF HEAT SHRINKABLE SLEEVE AT FIELD JOINTS
FOR PE COATED PIPES
All weld areas shall be grit or sand blasted to remove all frayed or loosened
coating at edges of the mill cutback and slightly abrade the coating sections to be
covered by the heat shrinkable sleeve (HSS).
FOR PE COATED PIPES
Heating the weld joint up to the specified heating application temperature.
FOR PE COATED PIPES
Before sleeve application, the primer, when required, shall be applied to bare steel
and adjacent abraded mill coating using supplied applicator (i.e. spatula).
Then wrapping the sleeve centrally around the weld joint. Sleeve overlap onto itself
should be not less than 150 mm. Installation of the closure patch and pressing in
position centring over the exposed sheet end
FOR PE COATED PIPES
Heating the closure patch evenly until the temperature sensitive paint
converts color and with a gloved hand, smooth the closure patch to
eliminate possible entrapped air and ensure good bonding.
Using two torches adjust flame length to approx. 50-60 cm. Finish
installation by shrinking circumferentially towards the other end.
FOR PE COATED PIPES
During and after shrinking use As installed.

rollers/gloved hand to remove air
enclosures.
As installed.
APPLICATION OF EPOXY POWDER (FBE) COATING
FBE powder coatings (i.e. Fusion Bonded Epoxy) are applied to pipes designed to convey fluids, for
buried services (soil or seawater) and when the continuous temperature of the fluid being carried does not
exceed (110-120) °C.
This type of coating is applied by spraying epoxy powder

onto preheated pipes in order to quickly cure the epoxy
The external surface is shot-blasted to remove

millscale and rust, obtaining a metal surface
which
facilitates the adhesion
The pipe is heated in a gas or induction

oven at a controlled temperature up to
approx. 220-240°C
The pipe is then covered with epoxy powder by

electrostatic guns.
After polymerization, the pipe is cooled by spraying water and then end brushed
This coating offers the following advantages:
9 mechanical resistance
9 coatings especially at high and low temperatures (bending
doesnot damage this coating)
9 easy storage and shipping of coated
9 pipes: same stacking possibilities as for bare pipes backfill
9 possible with material of higher sieve acceptance
9 to steel resistance to micro-organism lighter cathodic
protection
APPLICATION OF EPOXY LININGS
The epoxy resin lining is applied to pipes designed to convey water and gas
This type of coating is applied by spraying epoxy powder

onto preheated pipes in order to quickly cure the epoxy
This lining is applied by layering one or several coats

of liquid paint or by spraying epoxy powder.
The interior surface is shot-blasted to remove

millscale and rust, obtaining a metal surface
which facilitates the adhesion
When epoxy powder is fused, the pipe is

preheated to 238°C, in order to quickly cure
the epoxy.
The pipe is rotated and the lining is sprayed from

a set of nozzles which moves inside the
pipe.
When paint is used, it is dried by blowing hot air

through the pipe.
Epoxy lining completed

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ENI E. & P.

ON_OFFSHORE PIPELINE DESIGN COURSE 1st Ed.

Lecturer: Gabriele Lanza

1 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 1

04_Onshore Pipeline Design

2 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 2

In Mesopotamia and in Egypt, 5,000 years before Christ, clay

In China, in the Fifth century BC, bamboo pipes wrapped in

The Romans when creating large infrastructure components

3 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 3

bamboo pipes in China

4 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 4

clay water supply pipes lead water supply pipes

Pipes in ancient Rome

5 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 5

A significant advance was made, in the Eighteenth century, with

In 1879, following the discovery of an oil field in Pennsylvania, a

The introduction of submerged arc welding, around the year

6 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 6

Pipeline Pioneering in USA USERS

7 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 7

TRUNKLINES PIPELINES PIPELINES

8 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 8

GAS IMPORT FROM FROM HOLLAND

GAS IMPORT FROM NORWAY

- GAME A: 1,085 km OD: 48”

ALGERIA - ITALY NATURAL GAS PIPELINE

9 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 9

PIPELINE COMPRESSOR STATIONS N° 12 Montesano

Enna USERS USERS

10 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 10

04_Onshore Pipeline Design

11 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 11

12 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 12

ACI American Concrete Institute

13 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 13

API 1104 (NAG 100) Welding of Pipeline and Related Facilities

14 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 14

15 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 15

16 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 16

API 500C Hazardous Area Classification

17 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 17

18 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 18

D.M. 4 Maggio 1998 Disposizioni relative alle modalità di presentazione ed al contenuto

Dlgs 3 aprile 2006, n. 152 e s.m.i. Norme in materia ambientale

19 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 19

Section 2. : Routing Design

- Section 2.1 : Routing Criteria

20 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 20

Routing is the process of selecting the most cost effective

21 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 21

The route optimisation is performed as an iterative process that

The starting point for every pipeline route selection process is

22 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 22

The strategic objectives in a pipeline route selection study are

• comply with legal and regulatory requirements of

23 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 23

24 04_ON/OFFSHORE PIPELINE DESIGN COURSE 1st Ed.– September 2010 24