pipeline_2008.pdf

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Introduction to

Offshore Pipelines and Risers

2008

Jaeyoung Lee, P.E.


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Introduction to Offshore Pipelines and Risers

PREFACE

This lecture note is prepared to introduce how to design and install offshore

petroleum pipelines and risers including key considerations, general requirements,

and terminologies, etc. The authors nearly twenty years of experience on offshore

pipelines along with the enthusiasm to share his knowledge have aided the

preparation of this note. Readers are encouraged to refer to the references listed

at the end of each section for more information.

Unlike other text books, many pictures and illustrations are enclosed in this note to

assist the readers understanding. It should be noted that some pictures and

contents are borrowed from other companies websites and brochures, without

written permit. Even though the exact sources are quoted and listed in the

references, please use this note for engineering education purposes only.

2008

Jaeyoung Lee, P.E.

Houston, Texas

[email protected]


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TABLE OF CONTENTS

1 INTRODUCTION .......................................................................................................... 7

2

REGULATIONS AND PIPELINE PERMITS ................................................................ 15

3

DESIGN PROCEDURES AND DESIGN CODES ........................................................ 19

4 PIPELINE ROUTE SELECTION ................................................................................. 31

5 FLOW ASSURANCE .................................................................................................. 39

6

UMBILICALS .............................................................................................................. 43

7

PIPE MATERIAL SELECTION .................................................................................... 49

8

PIPE COATINGS ........................................................................................................ 65

9 PIPE WALL THICKNESS DESIGN ............................................................................. 75

10 THERMAL EXPANSION DESIGN ...................... ...................... ......................... .......... 89

11

PIPELINE ON-BOTTOM STABILITY DESIGN ............................................................ 97

12

PIPELINE FREE SPAN ANALYSIS ..... ......................... ......................... .................... 101

13 CATHODIC PROTECTION DESIGN ............ ......................... ...................... .............. 109

14 PIPELINE INSTALLATION ........................................................................................ 119

15

SUBSEA TIE-IN METHODS ...................... ......................... ...................... ................. 131

16

UNDERWATER WORKS ..................... ......................... ....................... ...................... 145

17 PIPELINE WELDING ......................... ......................... ...................... ......................... 147

18 PIPELINE PROTECTION TRENCHING AND BURIAL ............................................ 153

19

PIPELINE SHORE APPROACH AND HDD ........................ ...................... ................. 161

20

RISER TYPES ..................... ......................... ......................... ......................... ........... 165

21

RISER DESIGNS ...................................................................................................... 169

22 COMMISSIONING, PIGGING, AND INSPECTION ..... ...................... ......................... 175

23

PIPELINE REPAIR ............................................ ...................... ......................... ......... 185

APPENDIX A ...................... ......................... ......................... ......................... .................... 193

APPENDIX B ...................... ......................... ......................... ......................... .................... 199


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1 INTRODUCTION

Deepwater means water depths greater than 1,000 ft or 305 m by US MMS (Minerals

Management Service) definition. Deepwater developments outrun the onshore and

shallow water field developments. The reasons are:

Limited onshore gas/oil sources (reservoirs)

Relatively larger (~20 times (oil) and 8 times (gas)) offshore reservoirs than onshore

More investment cost (>~20 times) but more returns

Improved geology survey and E&P technologies

A total of 175,000 km (108,740 mi.) or 4.4 times of the earths circumference of subsea

pipelines have been installed. The deepest flowline installed is 2,743 m (9,000 ft) in theGulf of Mexico (GOM). The longest oil subsea tieback flowline length is 43.4 miles (69.8

km) from the Shells Penguin A-E and the longest gas subsea tieback flowline length is

74.6 miles (120 km) of Norsk Hydros Ormen Lange, by 2006 [1]. The deepwater

flowlines are getting high pressures and high temperatures (HP/HT). Currently, subsea

systems of 15,000 psi and 350oF (177oC) have been developed. By the year 2005,

Statoils Kristin Field in Norway holds the HP/HT record of 13,212 psi (911 bar) and

333oF (167oC), in 1,066 ft of water.

The deepwater exploration and production (E&P) is currently very active in West Africa

which occupies approximately 40% of the world E&P (see Figure 1.1).

Figure 1.1 Worldwide Deepwater Exploration and Production [1]

North America

25%

Latin America

20%Australasia

2%

Asia

10%

Africa

40%

North Sea

3%


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Offshore field development normally requires four elements as below and as shown inFigure 1.2. Each element (system) is briefly described in the following sub-sections.

Subsea System

Flowline/Pipeline/Riser System

Fixed/Floating Structures

Topside Processing System

Figure 1.2 Offshore Field Development Components

If the wellhead is located on the seafloor, it is called a wet tree; if the wellhead is located

on the surface structure, it is called a dry tree. Wet trees are commonly used for subseatiebacks using long flowlines to save cycle time (sanction to first production). Dry trees

are useful for top tension risers (TTRs) or fixed platform risers and provide reliable well

control system, low workover cost, and better maintenance.

FL/PL/Riser

Subsea

Processing

Fixed/FloatingStructures


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1.1 Subsea System

The subsea system can be broken into three parts as follows:

Wellhead structure (Christmas tree) and manifold as needed

Control system subsea control module (SCM), umbilical, umbilical terminationassembly (UTA), flying leads, sensors

Connection system jumper, pipeline end termination (PLET)

Figure 1.1.1 Subsea System

Wellhead (typically 28-in. diameter) is a topside structure of the drilling casing (typically

36-in. diameter) above the mudline, which is used to mount a control panel with valves.

The shape of the wellhead structure with valves looks like a pine tree so the wellhead is

also called as Christmas tree. The manifold is placed to gather productions from

multiple wellheads and send the productions using a smaller number of flowlines.

The control system includes SCM, umbilical, UTA, flying leads, and sensors. SCM is a

retrievable component used to control chokes, valves, and monitor pressure,

temperature, position sensing devices, etc. that is mounted on the tree and/or manifold.

UTA allows the use of flying leads to control equipment. Flying leads connect UTAs to

subsea trees. Sensors include sand detectors, erosion detectors, pig detectors, etc.

For details on connection system, please see Subsea Tie-in Methods in Section 15.


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1.2 Flowline/Pipeline/Riser System

Oil was transported by wooden barrels until 1870s. As the volume

was increased, the product was transported by tank cars or trains

and eventually by pipelines. Although oil is sometimes shipped in 55

(US) gallon drums, the measurement of oil in barrels is based on 42

(US) gallon wooden barrels of the 1870s.

Flowlines transport unprocessed fluid crude oil or gas. The conveyed fluid can be a

multi-phase fluid possibly with paraffin, asphaltene, and other solids like sand, etc. The

flowline is sometimes called a production line or import line. Most deepwater

flowlines carry very high pressure and high temperature (HP/HT) fluid.

Pipelines transport processed oil or gas. The conveyed fluid is a single phase fluid after

separation from oil, gas, water, and other solids. The pipeline is also called an export

line. The pipeline has moderately low (ambient) temperature and low pressure just

enough to export the fluid to the destination. Generally, the size of the pipeline is greater

than the flowline.

It is important to distinguish between flowlines and pipelines since the required design

code is different. In America, the flowline is called a DOI line since flowlines are

regulated by the Department of Interior (DOI 30 CFR Part 250: Code of Federal

Regulations). And the pipeline is called a DOT line since pipelines are regulated by the

Department of Transportation (DOT 49 CFR Part 195 for oil and Part 192 for gas).

Figure 1.2.1 Flowline/Pipeline/Riser System

Flowline

Pipeline

Riser


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1.3 Fixed/Floating Structures

The transported crude fluids are normally treated by topside processing facility at the

water surface, before being sent to the onshore refinery facilities. If the water depth is

relatively shallow, the surface structure can be fixed on the sea floor. If the water depth

is relatively deep, the floating structures moored by tendons or chains are recommended

(see Figure 1.3.1).

Fixed platforms, steel jacket or concrete gravity platform, are installed in up to 1,353 ft

water depth (Shell Bullwinkle). Four (4) compliant piled towers (CPTs) have been

installed worldwide in water depths 1,000 ft to 1,754 ft. It is known that the material and

fabrication costs for CPT are lower but the design cost is higher than conventional fixedjacket platform.

Tension leg platforms (TLPs) have been installed in water depths 482 ft to 4,674 ft

(ConocoPhillips Magnolia).

Spar also called DDCV (deep draft caisson vessel), DDF (deep draft floater), or SCF

(single column floater) is originally invented by Deep Oil Technology (later changed to

Spar International, a consortium between Aker Maritime (later Technip) and J. Ray

McDermott (later FloaTEC)). Total 16 spars, including 15 in GOM, have been installed

worldwide in water depths 1,950 ft to 5,610 ft (Dominions Devils Tower).

Semi-Floating Production Systems (semi-FPSs) or semi-submersibles have been

installed in water depths ranging from 262 ft to 7,920 ft (Anadarkos Independence Hub).

Floating production storage and offloading (FPSO) has advantages for moderate

environment with no local markets for the product, no pipeline infra areas, and short life

fields. No FPSO has been installed in GOM, even though its permit has been approved

by MMS. FPSOs have been installed in water depths between 66 ft to 4,796 ft (Chevron

Agbami).

Floating structure types should be selected based on water depth, metocean data,

topside equipment requirements, fabrication schedule, and work-over frequencies.

Table 1.3.1 shows total number of deepwater surface structures installed worldwide by

2006. Subsea tieback means that the production lines are connected to the existing

subsea or surface facilities, without building a new surface structure. The advantages of

the subsea tiebacks are lower capital cost and shorter cycle time by 70% (sanction to

first production) compared to implementing a new surface structure.


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Table 1.3.1 Number of Surface Structures Worldwide [2]

Structure Types No. of

Structures

Water Depths

(ft)

Fixed Platforms (WD>1,000) ~6,000 40 - 1,353

Compliant Towers 4 1,000 1,754

TLPs 23 482 - 4,674

Spars 16 1,950 - 5,610

Semi-FPSs (Semi-submersibles) 43 262 7,920

FPSOs 148 66 4,796

Subsea Tiebacks 3,622 49 7,600

Figure 1.3.1 Fixed & Floating Structures [3]

Fixed Platform Compliant Tower

TLP Mini-TLP Spar Semi-submersible FPSO


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References

[1] SUT (Society for Underwater Technology) Subsea Tieback (SSTB) Workshop,

Galveston, Texas, 2007[2] 2006 Deepwater Solutions & Records for Concept Selection, Offshore Magazine

Poster

[3] www.mms.gov, Minerals Management Service website, U.S. Department of the

Interior

[4] Offshore Engineering - An Introduction, Angus Mather, Witherby & Company

Limited, 1995

[5] Offshore Pipeline Design, Analysis and Methods, Mouselli, A.H., Penn Well

Books, 1981

[6] Offshore Pipelines, Guo, Boyun, et. al, Elsevier, 2005

[7] Pipelines and Risers, Bai, Y., Elsevier, 2001

[8] Deepwater Petroleum Exploration and Production, Leffler, W.L., et. al., Penn

Well Books, 2003

[9] Petroleum Production Systems, Economides, Michael, et. al., Prentice Hall

Petroleum Engineering Series


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2 REGULATIONS AND PIPELINE PERMITS

Prior to conducting drilling operations, the operator is required to submit an Application

for Permit to Drill (APD) and obtain approval from the authorities. The APD requires

detailed information about the drilling program for evaluation with respect to operational

safety and pollution prevention measures. Other information including project layout,

design criteria for well control and casing, specifications for blowout preventers, and a

mud program is required.

The developer must design, fabricate, install, use, inspect, and maintain all platforms

and structures to assure their structural integrity for the safe conduct of operations at

specific locations. Factors such as waves, wind, currents, tides, temperature, and the

potential for marine growth on the structure are to be considered.

All surface production facilities including separators, treaters, compressors, and headers

must be designed, installed, and maintained to assure the safety and protection of the

human, marine, and coastal environments.

In the USA, the regulatory processes and jurisdictional authority concerning pipelines on

the Outer Continental Shelf (OCS) and in coastal areas are shared by several federal

agencies, including the Department of Interior (DOI), the Department of Transportation

(DOT), U.S. Army Corps of Engineers (COE), the Federal Energy Regulatory

Commission (FERC), and U.S. Coast Guard (USCG) [1].

The DOT is responsible for regulating the safety of interstate commerce of natural gas,

liquefied natural gas (LNG), and hazardous liquids by pipeline. The regulations are

contained in 49 CFR Part 192 (for gas pipeline) and part 195 (for oil pipeline)

(References [2] & [3]). The DOT is responsible for all transportation pipelines beginning

downstream of the point at which operating responsibility transfers from a producing

operator to a transporting operator.

The DOIs responsibility extends upstream from the transfer point described above. The

MMS is responsible for regulatory oversight of the design, installation, and maintenanceof OCS oil and gas pipelines (flowlines). The MMS operating regulations for flowlines are

found at 30 CFR Part 250 Subpart J [4].


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Pipeline permit applications to regulatory authorities include the pipeline location

profile drawing, safety schematic drawing, pipe design data to scale, a shallow hazard

survey report, and an archaeological report (if required). The proposed pipeline routesare evaluated for potential seafloor, subsea geologic hazards, other natural or manmade

seafloor, and subsurface features/conditions including impact from other pipelines.

Routes are also evaluated for potential impacts on archaeological resources and

biological communities. A categorical exclusion review (CER), environmental

assessment (EA), and/or environmental impact statement (EIS) should be prepared in

accordance with applicable policies and guidelines.

The design of the proposed pipeline is evaluated for:

Appropriate cathodic protection system to protect the pipeline from leaks resulting

from the external corrosion of the pipe;

External pipeline coating system to prolong the service life of the pipeline;

Measures to protect the inside of the pipeline from the detrimental effects, if any, of

the fluids being transported;

Pipeline on-bottom stability (that is, that the pipeline will remain in place on the

seafloor and not float);

Proposed operating pressures;

Adequate provisions to protect other pipelines the proposed route crosses over; and

Compliance with all applicable regulations.

According to MMS regulations (30 CFR Part 250), pipelines with diameters less than 8-

5/8 inches installed in water depths less than 200 ft are to be buried to a depth of at least

3 ft below the mudline. If the MMS determines that the pipeline may constitute a hazard

to other uses, all pipelines (regardless of pipe size) installed in water depths less than

200 ft must be buried. The purpose of these requirements is to reduce the movement of

pipelines by high currents and storms, to protect the pipeline from the external damage

that could result from anchors and fishing gear, to reduce the risk of fishing gear

becoming snagged, and to minimize interference with the operations of other users ofthe OCS. For pipe sizes less than 8-5/8 inches, the burial requirement may be waived if

the line is to be laid on a soft soil which will allow the pipeline to sink into the sediments

(self-burial). Any pipeline crossing a fairway or anchorage in federal waters must be

buried to a minimum depth of 10 ft below mudline across a fairway and a minimum depth

of 16 ft below mudline across an anchorage area.


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References

[1] OCS Report MMS 2001-067, Brief Overview of Gulf of Mexico OCS Oil and Gas

Pipelines: Installation, Potential Impact, and Mitigation Measures, MineralsManagement Service, U.S. Department of the Interior, 2001

[2] 49 CFR, Part 192, Transportation of Natural and Other Gas by Pipeline:

Minimum Federal Safety Standards

[3] 49 CFR, Part 195, Transportation of Hazardous Liquids by Pipeline

[4] 30 CFR, Part 250, Oil and Gas and Sulfur Operations in the Outer Continental

Shelf


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3 DESIGN PROCEDURES AND DESIGN CODES

There are typically three phases in offshore pipeline designs: conceptual study (or Pre-FEED: front end engineering & design), preliminary design (or FEED), and detail

engineering.

Conceptual study (Pre-FEED) defines technical feasibility, system constraints,

required information for design and construction, rough schedule and cost estimate

Preliminary design (FEED) defines pipe size and grade to order pipes and

prepares permit applications.

Detail engineering defines detail technical input to prepare procurement and

construction tendering.

The pipeline design procedures may vary depending on the design phases above.

Tables 3.1 and 3.2 show a flowchart for preliminary design phase and detail engineering

phase, respectively.

Design basis is an on-going document to be updated as needed as the project proceeds,

especially in conceptual and preliminary design phases. The design basis should

contain:

Pipe Size

Design Pressure (@ wellhead or platform deck)

Design Temperature

Pressure and Temperature Profile

Max/Min Water Depth

Corrosion Allowance

Required overall heat transfer coefficient (OHTC) Value

Design Code (ASME, API, or DNV)

Installation Method (S, J, Reel, or Tow)

Metocean Data Soil Data

Design Life, etc.

Fluid property (sweet or sour)


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Table 3.1 Preliminary Design (FEED) Flowchart

Scope of Work

Design Basis

Hazard Survey

Flow Assurance

Permit

Route Selection

Pipe MaterialSelection

Pipe WTDetermination

Pipe CoatingSelection

ThermalExpansion

On-bottomStability

Free Span

CathodicProtection

Installation Check

Tie-ins and ShoreApproach

Preliminary CostEstimate

Preliminary DesignDrawings

Procurement LongLead Items


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Table 3.2 Detail Engineering Flowchart

Scope of Work

Design Basis

Route Survey

Flow Assurance

Route Selection

Metallurgy &Welding Study

Pipe WT andGrade Check

Pipe CoatingSelection

ThermalExpansion

On-bottom

Stability

Free Span

CathodicProtection

Installation Check

Tie-ins and Shore

Approach

Material/ConstructionSpecifications

ConstructionDrawings

Procurement &Construction Support


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The following international codes, standards, and regulations are used for the design of

offshore pipelines and risers.

US Code of Federal Regulations (CFR)

30 CFR, Part 250 Oil and Gas and Sulfur Operations in the Outer Continental Shelf

49 CFR, Part 192 Transportation of Natural and Other Gas by Pipeline: MinimumFederal Safety Standards

49 CFR, Part 195 Transportation of Hazardous Liquids by Pipeline

American Bureau of Shipping (ABS)

ABS Fatigue Assessment of Offshore StructuresABS Guide for Building & Classing; Subsea Pipeline Systems

ABS Guide for Building & Classing; Subsea Riser Systems

ABS Guide for Building and Classing; Facilities on Offshore Installations

ABS Rules for Building and Classing; Offshore Installations

ABS Rules for Building and Classing; Single Point Moorings

ABS Rules for Certification of Offshore Mooring Chain

American Petroleum Institute (API)API Bull 2U API Bulletin on Stability Design of Cylindrical Shells, 2004

API 17J Specification for Unbonded Flexible Pipe, 2002

API 598 Standard Valve Inspection and Testing

API 600 Cast Steel Gates, Globe and Check Valves

API 601 Metallic Gaskets for Refinery Piping (Spiral Wound)

API Q1 Specification for Quality Programs for the Petroleum, Petrochemicaland Natural Gas Industry

API RP 2A Recommended Practice for Planning, Designing and ConstructingFixed Offshore Platforms - Working Stress Design

API RP 2RD Design of Risers for Floating Production Systems (FPSs) andTension-Leg Platforms (TLPs), First Edition, 1998

API RP 5C6 Welding Connections to Pipe, 1996

API RP 5L1 Recommended Practice for Railroad Transportation of Line Pipe

API RP 5L5 Recommended Practice for Marine Transportation of Line Pipe

API RP 5LW Recommended Practice for Transportation of Line Pipe on Bargesand Marine Vessels


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API RP 6FA Specification for Fire Test for Valves

API RP 14E Recommended Practice for Design and Installation of Offshore

Production Platform Piping Systems - RisersAPI RP 14H Installation, Maintenance and Repair of Surface Safety Valves and

Underwater Safety Valves - Offshore

API RP 14J Design and Hazards Analysis of Offshore Production Facilities

API RP 17A Recommended Practice for Design and Operation of SubseaProduction Systems Pipelines and End Connections

API RP 17B Recommended Practice for Flexible Pipe, 1998

API RP 17D Specification for Subsea Wellhead and Christmas Tree Equipment,1996

API RP 17G Design and Operation of Completion/Workover Riser Systems

API RP 17I Installation of Subsea Umbilicals

API RP 17J Specification for Unbonded Flexible Pipe, 1999

API RP 500C Classification of Locations for Electrical Installation at PipelineTransportation Facilities

API RP 1110 Pressure Testing of Liquid Petroleum Pipelines, 1997

API RP 1111 Recommended Practice for Design Construction, Operation, andMaintenance of Offshore Hydrocarbon Pipelines, 1999

API RP 1129 Assurance of Hazardous Liquid Pipeline System Integrity

API Spec 2B Specification for Fabricated Structural Steel PipeAPI Spec 2W Specification for Steel Plates for Offshore Structures, Produced by

Thermo-Mechanical Control Processing (TMCP).

API Spec 2C Offshore Cranes

API Spec 2Y Steel Plates, Quenched and Tempered, for Offshore Structures

API Spec 5L Line Pipe

API Spec 6A Wellhead and Christmas Tree Equipment

API Spec 6D Pipeline Valves (Gate, Plug, Ball, and Check Valves)

API Spec 6H End Closures, Connectors and SwivelsAPI Spec 14A Subsurface Safety Valve Equipment

API Spec 17E Subsea Production Control Umbilicals

API Std 1104 Standard for Welding of Pipelines and Related Facilities


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American Society of Mechanical Engineers (ASME)

ASME B16.5 Pipe Flanges and Flanged FittingsASME B16.9 Factory Made Wrought Steel Butt Welding Fittings

ASME B16.10 Face-to-Face and End-to-Ends Dimensions of Valves

ASME B16.11 Forged Steel Fittings, Socket Welding and Threaded

ASME B16.20 Ring Joints, Gaskets and Grooves for Steel Pipe Flanges

ASME B16.25 Butt Welded Ends for Pipes, Valves, Flanges and Fittings

ASME B16.34 Valves - Flanged, Threaded, and Welding End

ASME B16.47 Large Diameter Steel Flanges - NPS 26 through NPS 60

ASME B31.3 Chemical Plant and Petroleum Refinery Piping

ASME B31.4 Liquid Transportation Systems for Hydrocarbons, Liquid PetroleumGas, Anhydrous Ammonia and Alcohols, 1999

ASME B31.8 Gas Transmission and Distribution Piping Systems, 1999

ASME II Materials

ASME V Non-Destructive Examination

ASME VIII, Div 1&2 Rules for Construction of Pressure Vessels

ASME IX Welding and Brazing Qualifications

American Society of Testing and Materials (ASTM)

ASTM A6 Standard Specification for General Requirements for Rolled SteelPlates, Shapes, Sheet Piling, and Bars for Structural Use

ASTM A20/20M General requirements for Steel Plates for Pressure Vessels

ASTM A36 Standard Specification for Carbon Structural Steel

ASTM A53 Standard Specification for Steel Castings, Ferritic and Martensitic,for Pressure-Containing Parts, Suitable for Low-TemperatureService

ASTM A105 Standard Specification for Carbon Steel Forgings for PipingApplications

ASTM A185 Specification for Welded Wire Fabric, Plain for ConcreteReinforcement

ASTM A193 Standard Specification for Alloy-Steel and Stainless Steel BoltingMaterials for High Temperature or High Pressure Service and OtherSpecial Purpose Applications

ASTM A194 Standard Specification for Carbon and Alloy Steel Nuts for Bolts forHigh Pressure or High Temperature Service, or Both


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ASTM A234 Standard Specification for Piping Fittings of Wrought Carbon Steeland Alloy Steel for Moderate and High Temperature Service

ASTM A283 Low and Intermediate Tensile Strength Carbon Steel Plates,Shapes and Bars

ASTM A307 Standard Specification for Carbon Steel Bolts and Studs

ASTM A325 Standard Specification for Structural Bolts, Steel, Heat Treated,120/150 ksi Minimum Tensile Strength

ASTM A370 Standard Test Methods and Definitions for Mechanical Testing ofSteel Products

ASTM A490 Standard Specification for Heat Treated-Treated Steel StructuralBolts 150 ksi Minimum Tensile Strength

ASTM A500 Cold Formed Welded and Seamless Carbon Steel StructuralTubing in Rounds and Shapes

ASTM A615 Specification for Deformed Billet-Steel Bars for ConcreteReinforcement

ASTM A694 Standard Specification for Carbon and Alloy Steel Forgings for PipeFlanges, Fittings, Valves and Parts for High Pressure TransmissionService

ASTM B418 Cast and Wrought Galvanized Zinc Anodes (Type II)

ASTM E23 Standard Test Methods for Notched Bar Impact Testing of MetallicMaterials

ASTM E92 Standard Test Methods for Vickers Hardness of Metallic Materials

ASTM E94 Radiographic Testing

ASTM E747 Test Methods for Controlling Quality of Radiographic Testing UsingWire Penetrometers

ASTM E1290 Standard Test Method for Crack-Tip Opening Displacement(CTOD) Fracture Toughness Measurement

ASTM E1444 Standard Practice for Magnetic Particle Examination

ASTM E1823 Standard Terminology Relating to Fatigue and Fracture Testing,1996

American Welding Society (AWS)

AWS D1.1 Structural Welding Code Steel


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British Standard (BS)

BS 4515 Appendix J. Process of Welding of Steel Pipelines on Land andOffshore Recommendations for Hyperbaric Welding

BS 6899 Insulation Material Tests

BS 7608 Code of Practice for Fatigue Design and Assessment of SteelStructures, 1993

BS 8010-2 Code of Practice for Pipelines - Subsea Pipelines, 2004, BritishStandard Institution

Canadian Standards Association (CSA)

CSA-Z187 Offshore Pipelines

Det Norske Veritas (DNV)

DNV Rules for Design, Construction and Inspection of OffshoreStructures.

DNV Rules for Planning and Execution of Marine Operations - Part 1General

DNV Rules for Planning and Execution of Marine Operations - Part 2Operation Specific Requirements

DNV-CN-30.2 Fatigue Strength Analysis for Mobile Offshore UnitsDNV-CN-30.4 Foundations

DNV-CN-30.5 Environmental Conditions and Environmental Loads

DNV-OS-B101 Metallic Materials

DNV-OS-C101 Design of Offshore Steel Structures, General (LRFD method)

DNV-OS-C106 Structural Design of Deep Draught Floating Units (LRFD method)

DNV-OS-C201 Structural Design of Offshore Units (WSD method)

DNV-OS-C301 Stability and Watertight Integrity

DNV-OS-C401 Fabrication and Testing of Offshore Structures

DNV-OS-C502 Offshore Concrete Structures

DNV-OS-D101 Marine and Machinery Systems and Equipment

DNV-OS-D201 Electrical Installations

DNV-OS-D202 Instrumentation and Telecommunication Systems

DNV-OS-D301 Fire Protection

DNV-OS-E201 Oil and Gas Processing Systems


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DNV-OS-E301 Position Mooring

DNV-OS-E402 Offshore Standard for Diving Systems

DNV-OS-E403 Offshore Loading Buoys

DNV-OS-F101 Submarine Pipeline Systems, 2003

DNV-OS-F107 Pipeline Protection

DNV-OS-F201 Dynamic Risers, 2001

DNV-OSS-301 Certification and Verification of Pipelines

DNV-OSS-302 Offshore Riser Systems

DNV-OSS-306 Verification of Subsea Facilities

DNV-RP-B401 Cathodic Protection Design, 1993

DNV-RP-C201 Buckling Strength of Plated Structure

DNV-RP-C202 Buckling Strength of Shells

DNV-RP-C203 Fatigue Strength Analysis of Offshore Steel Structures

DNV-RP-C204 Design against Accidental Loads

DNV-RP-E301 Design and Installation of Fluke Anchors in Clay

DNV-RP-E302 Design and Installation of Plate Anchors in Clay

DNV-RP-E303 Geotechnical Design and Installation of Suction Anchors in Clay

DNV-RP-E304 Damage Assessment of Fibre Ropes for Offshore MooringDNV-RP-E305 On-bottom Stability Design of Submarine Pipelines, 1988

DNV-RP-F102 Pipeline Field Joint Coating and Field Repair of Linepipe Coating

DNV-RP-F103 Cathodic Protection of Submarine Pipelines by Galvanic Anodes,2006

DNV-RP-F104 Mechanical Pipeline Couplings

DNV-RP-F105 Free Spanning Pipelines, 2006

DNV-RP-F106 Factory Applied External Pipeline Coatings for Corrosion Control

DNV-RP-F107 Risk Assessment of Pipeline Protection

DNV-RP-F108 Fracture Control for Pipeline Installation Methods Introducing CyclicPlastic Strain

DNV-RP-F109 On Bottom Stability of Offshore Pipeline Systems, 2006 Draft

DNV-RP-F110 Global Buckling of Submarine Pipelines Structural Design due toHigh Temperature/High Pressure, 2007

DNV-RP-F111 Interference between Trawl Gear and Pipe-lines

DNV-RP-F202 Composite Risers


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DNV-RP-F204 Riser Fatigue, 2005

DNV-RP-F205 Global Performance Analysis of Deepwater Floating Structures

DNV-RP-G101 Risk Based Inspection of Offshore Topside Static MechanicalEquipment

DNV-RP-H101 Risk Management in Marine and Subsea Operations

DNV-RP-H102 Marine Operations during Removal of Offshore Installations

DNV-RP-O401 Safety and Reliability of Subsea Systems

DNV-RP-O501 Erosive Wear in Piping Systems

International Organization for Standardization (ISO)

ISO-9001 Quality Assurance StandardIOS-13628 Petroleum and Natural Gas Industries Design and Operation of

Subsea Production Systems

IOS-13628-1 Subsea Production Systems

IOS-13628-2 Subsea Flexible Pipe Systems

IOS-13628-4 Subsea Wellhead & Christmas Trees

IOS-13628-6 Subsea Production Control Systems

IOS-13628-8 Remotely Operated Vehicle (ROV) Interfaces on SubseaProduction Systems

IOS-13628-9 Remotely Operated Tool (ROT) Intervention Systems

IOS-14000 Environmental Management System

ISO-15589-2 Cathodic Protection of Pipeline Transportation Systems - Part 2:Offshore Pipelines, 2004, International Organization forStandardization

ISO-15590 Induction Bends


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Manufacturers Standardization Society (MSS)

MSS SP-44 Steel Pipeline FlangesMSS SP-75 Specification for High Test Wrought Butt Welding Fittings

National Association of Corrosion Engineers (NACE)

NACE MR-01-75 Sulfide Stress Corrosion Cracking

NACE RP-01-76-94 Corrosion Control of Steel Fixed Offshore Platforms Associated withPetroleum Production, 1994

NACE RP-0387 Metallurgical and Inspection Requirement for Cast SacrificialAnodes for Offshore Applications

NACE RP-0394 Application, Performance and Quality Control of Plant-Applied,Fusion-Bonded Epoxy External Pipe Coating

NACE RP-0492 Metallurgical and Inspection Requirements for Offshore PipelineBracelet Anodes

Nobel Denton Industries (NDI)

NDI-0013 General Guidelines for Marine Loadouts

NDI-0027 Guidelines for Lifting Operations by Floating Crane Vessels

NDI-0030 General Guidelines for Marine Transportations

NORSOK Standards

NORSOK G-001 Marine Soil Investigations

NORSOK L-005 Compact Flanged Connections

NORSOK M-501 Surface Preparation and Protective Coating

NORSOK M-506 Corrosion Rate Calculation Model

NORSOK N-001 Structural Design

NORSOK N-004 Design of Steel Structures

NORSOK U-001 Subsea Production Systems

NORSOK UCR-001 Subsea Structures and Piping Systems

NORSOK UCR-006 Subsea Production Control Umbilicals


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Miscellaneous

TPA IBS-98 Recommended Standards for Induction Bending of Pipe and Tube,1998, Tube & Pipe Association (TPA)

ASNT-TC-1A Personnel Qualification and Certification in Non-Destructive

Testing, American Society of Nondestructive Testing


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4 PIPELINE ROUTE SELECTION

When layout the field architecture, several considerations should be accounted for:

Compliance with regulation authorities and design codes

Future field development plan

Environment, marine activities, and installation method (vessel availability)

Overall project cost

Seafloor topography

Interface with existing subsea structures

The pipeline route should be selected considering:

Low cost (select the most direct and shortest P/L route)

Seabed topography (faults, outcrops, slopes, etc.)

Obstructions, debris, existing pipelines or structures

Environmentally sensitive areas (beach, oyster field, etc.)

Marine activity in the area such as fishing or shipping

Installability (1st end initiation and 2nd end termination)

Required pipeline route curvature radius

Riser hang-off location at surface structure

Riser corridor/clashing issues with existing risers

Tie-in methods

The required minimum pipeline route curve radius (Rs) should be determined to prevent

slippage of the curved pipeline on the sea floor while making a curve, in accordance with

the following formula [1]. If the pipeline-soil friction resistance is too small, the pipeline

will spring-back to straight line. The formula also can be used to estimate the required

minimum straight pipeline length (Ls), before making a curve, to prevent slippage at

initiation. If Lsis too short, the pipeline will slip while the curve is being made.

WTFLRs

Hss ==

Where,

Rs= Min. non-slippage pipeline route curve radius

Ls= Min. non-slippage straight pipeline length

F = Safety factor (~2.0)

TH= Horizontal bottom tension (residual tension)

Ws= Pipe submerged weight

= lateral pipeline-soil friction factor (~0.5)


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If a 16 OD x 0.684 WT pipe is installed in 3,000 ft of water depth using a J-lay method

(assuming a catenary shape), the bottom tension and the Rsand Lscan be estimated as

follows:

The submerged pipe weight, Ws= 22.6 lb/ft

Assuming the pipe departure angle () at J-lay tower as10 degrees

Top tension, T = Wsx WD / (1- sin ) = 22.6 x 3,000 / (1- sin 10) = 82,047 lb 82 kips

Bottom tension, TH= T x sin = 82 x sin 10 = 14.2 kips

ft3,000minimumUseft2,5130.522.6

1,00014.22.0

W

TFLR

s

Hss =

===

If the curvature angle () and the pipe rigidity (elastic stiffness = elastic modulus (E) x

pipe moment of inertia (I)) are considered to do a big role on the Rsand Lsestimates, the

above formula can be modified as follows:

)cos-(1R

IE

W

TFLR

2

ss

Hss

+==

Once the field layout and pipeline route is determined by desktop study using an existing

field map, the pipeline route survey is contracted to obtain site-specific information

including bathymetry, seabed characteristics, soil properties, stratigraphy, geohazards,

and environmental data.

Rs

Ls

Lay direction

Initiationpoint


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Bathymetry (hydrographic) survey using echo sounders provides water depths (sea

bottom profile) over the pipeline route. The new technology of 3-D bathymetry map

shows the sea bottom configuration more clearly than the 2-D bathymetry map (seeFigure 4.1).

Figure 4.1 Sample of Bathymetry Map

Side scan sonar is the industry standard method of providing high resolution mapping of

the seabed. It uses narrow beams of acoustic energy (sound) which is transmitted out to

the seabed topography (or objects within the water column) and reflected back to the

towfish. It is used to identify obstructions, outcrops, faults, debris, pockmarks, gas

anchor scars, pipelines, etc. Typically objects larger than 1m are accurately located and

measured (see Figure 4.2).

Figure 4.2

Side Scan Sonar Interpretation [2]

2D View

3-D View


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Soil sampling is required to calibrate and quantify geophysical and geotechnical

properties of soils. The soil sampling instruments include grabs, gravity drop corers, and

vibracorers. Drop corer or gravity corer is a device which is dropped off from a surveyvessel. And on contact with the seabed, a piston in the device is activated and takes a

shallow core (up to a meter or so in depth). This core is retained and preserved in the

device and then hauled back to the surface. The core samples collected are

photographed, logged, tested (by either Torvane or mini cone penetrometer) and

sampled onboard the survey vessel. Further sampling and geotechnical testing can be

undertaken in the laboratory. The cone penetration test (CPT) provides tip resistance,

sleeve friction, friction ratio, undrained shear strength, and relative density. Figures 4.5

and 3.6 show drop corer and Torvane shear test kit.

Figure 4.5 Drop Corer [4]

Weights(400-800 lbs)

Wireline to surface

Releasemechanism

Core

catcherWeight triggeringrelease mechanismon hitting seafloor

Barrel(10-20 ft)


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Figure 4.6 Torvane Shear Test Kit [5]

Environmental (metocean) data including wind, waves, and current along the water

depth for 1, 5 (2 or 10), and 100 year return periods are required.


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References

[1] Pipeline Manual, Chevron, 1994

[2] EGS Survey Website, http://egssurvey.com/enter_ser.htm[3] Geometrics Website, http://geometrics.com/magnetometers/Marine/G-882/g-

882.html

[4] Submarine Pipeline On-bottom Stability Analysis and Design Guidelines, AGA,

1993

[5] Earth Manual, U.S. Department of the Interior, 1998, or

http://www.usbr.gov/pmts/writing/earth/earth.pdf

[6] Simon A. Bonnel, et. al., Pipeline Routing and Engineering for Ultra-Deepwater

Developments, OTC (Offshore Technology Conference) Paper No. 10708, 1999


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5 FLOW ASSURANCE

Flow assurance is required to determine the optimum flowline pipe size based onreservoir well fluid test results for the required flowrate and pressure. As the pipe size

increases, the arrival pressure and temperature decrease. Then, the fluid may not reach

the destination and hydrate, wax, and asphaltene may be formed in the flowline. If the

pipe size is too small, the arrival pressure and temperature may be too high and

resultantly a thick wall pipe may be required and a large thermal expansion is expected.

It is important to determine the optimum pipe size to avoid erosional velocity and

hydrate/ wax/asphaltene deposition. Based on the hydrate/wax/asphaltene appearance

temperature, the required OHTC is determined to choose a desired insulation system

(type, material, and thickness.) If the flowline is to transport a sour fluid containing H2S,CO2, etc., the line should be chemically treated or a special corrosion resistant alloy

(CRA) pipe material should be used. Alternatively, a corrosion allowance can be added

to the required pipe wall thickness. Capital expense (Capex) and operational expense

(opex) using CRA, chemical injection, corrosion allowance, or combination of the above

should be exercised to determine the pipe material and wall thickness.

Figure 5.1 shows various plugged flowlines due to asphaltene, wax, and hydrate

deposition.

Figure 5.1 Plugged Flowlines

(a) Asphaltene (b) Wax (c) Hydrate


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Figure 5.2 illustrates one example of how to select pipe size from flow assurance results.

The blue solid line represents inlet pressure at wellhead and the red dotted line

represents outlet fluid temperature. The 8 ID pipe may require a heavy (thick) wall andthe 12 ID pipe may require a thick insulation coating depending on hydrate (wax or

asphaltene) formation temperature.

Figure 5.2 Inlet Pressure & Outlet Temperature vs. Flowline ID

100

150

200

250

300

350

400

450

150 170 190 210 230 250 270 290 310

Flowline ID (mm)

0

10

20

30

40

50

60

70

Pressure (bar)

Temperature(oC)

8 ID12 ID

10 ID

Standard Temperature and Pressure (STP)

Science: 0oC (273.15oK) and 1 bar (100 kPa)

Oil & Gas Industry: 60oF (15.6oC) and 14.73 psia (30 Ag or 1.0156 bar)

1 bar = 14.504 psi1 atmosphere = 14.696 psi


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References

[1] Properties of Oils and Natural Gases, Pederson, K.S., et. al., Gulf Publishing Inc.,

1989[2] The Properties of Petroleum Fluids, McCain, William, PennWell Publishing

Company, 1990

[3] A Comprehensive Mechanistic Model for Two-Phase Flow in Pipelines, Xiao, J.J.,

Shoham, O., and Brill, J.P., 65thAnnual Technical Conference & Exhibition, Society

of Petroleum Engineers, 1990

[4] CRC Handbook of Solubility Parameters and Other Cohesion Parameters, Barton,

A.F.M., CRC Press, 1991

[5] Prediction of Slug Liquid Holdup Horizontal to Upward Vertical Flow, Gomez, L.,

et. al., International Journal of Multiphase Flow, 2000

[6] Fluid Transport Optimization Using Seabed Separation, Song, S. and Kouba, G.,Energy Sources Technology Conference & Exhibition, 2000

[7] PVT and Phase Behaviour of Petroleum Reservoir Fluids, Danesh, Ali, Elsevier

Science B.V., 2001

[8] Mechanistic Modeling of Gas/Liquid Two-Phase Flow in Pipes, Shoham, O.,

Society of Petroleum Engineers, 2006

[9] Steven Cochran, Details of Hydrate Management in Deepwater Subsea GasDevelopments, Deep Offshore Technology (DOT) International Conference andExhibition, 2006

[10] Roald Sirevaag, Experience with HPHT Subsea HIPPS on Kristin, DOT 2006


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6 UMBILICALS

Umbilicals (Figure 6.1) are used to supply electric/hydraulic power to subsea valves/actuators, receive communication signal from subsea control system, and send

chemicals to treat subsea wells. The functions of umbilicals can be:

Chemical Injection

Electric Hydraulic

Electric Power

Hydraulic

Communications

Scale Squeeze

From flow assurance analysis, the type, quantity, and size of each umbilical tube are

determined. Most commonly used chemicals are: scale inhibitor, hydrate inhibitor,

paraffin inhibitor, asphaltene inhibitor, corrosion inhibitor, etc.

The umbilical terminates at subsea umbilical termination assembly (SUTA) and each

function hose or cable connects to manifold or tree by flexible flying leads.

Umbilical manufacturers include: DUCO (formerly Dunlop Coflexip, now a Technip

company), Oceaneering Multiplex, Aker Kvaener, Nexans (formerly Alcatel), JDR, etc.

Figure 6.2 shows Oceaneerings Panama City plant and Figure 6.3 shows UTAinstallation.

Figure 6.1 Umbilical Lines [1]


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Figure 6.2 Oceaneering Umbilical Plant [2]


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Figure 6.3 UTA (Umbilical Termination Assembly) Installation [3]


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Bend restrictor (or bend limiter) is commonly found at the end of cables, umbilicals, and

flexible pipes, such as surface termination, subsea Manifold or PLET termination, and in

any region where over bending is a problem. Unlike a bend stiffener, the bend restrictordoes not increase the umbilical or pipes stiffness. When the bend restrictor is at "lock

up" radius, it prevents the umbilical or pipe from over bending, kinking, or buckling.

Bend restrictors can be manufactured from polyurethane or steel. The half shell

elements are bolted together around the pipe and the next elements are bolted to

interlock with those already in place. Each element allows to move a small angular

distance and when this distance is projected over the length of the restrictor, the lock up

radius is formed. This radius is to be equal to or greater than the minimum bend radius

of the flexible.

Bending stiffeners are used at the termination point of cables, umbilicals, and flexible

pipes where the stiffness of the system undergoes a step change. This sudden stiffness

change between the flexible and rigid termination structure creates high levels of stress

when the flexible is bent. In a dynamic situation such as repeat bending, this can lead to

fatigue failure in the flexible. Bend stiffeners are utilized to increase the stiffness of the

flexible. The most common method of achieving this is to attach an molded elastomer

tapered sleeve to the flexible.

Figure 6.4 shows bend restrictor and bend stiffness configurations.

Figure 6.4 Bend Restrictor (left) [4] and Bend Stiffener (right) [5]


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References

[1] Offshore-Technology.com website, www.offshore-technology.com

[2] Oceaneering International, Inc. website, www.oceaneering.com

[3] Nexen Aspen Project, presented at Houston Marine Technology Society

luncheon meeting, 2007, www.mtshouston.org

[4] Dunlaw Engineering Ltd. website, http://www.dunlaw.com/bend_limiters.html

[5] Trelleborg CRP website, http://www.crpgroup.com/engineered_products.htm


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7 PIPE MATERIAL SELECTION

Pipe material type, i.e. rigid, flexible, or composite, should be determined considering:

Conveyed fluid properties (sweet or sour) and temperature

Pipe material cost

Installation cost

Operational cost (chemical treatment)

There are several different pipes used in offshore oil & gas transportation as follows:

Low carbon steel pipe

Corrosion resistant alloy (CRA) pipe

Clad pipe

Composite pipe

Flexible pipe

Flexible hose

Coiled tubing

7.1 Low Carbon Steel Pipe

Low carbon (carbon content less than 0.29%) steel is mild and has a relatively lowtensile strength so it is used to make pipes. Medium or high carbon (carbon content

greater than 0.3%) steel is strong and has a good wear resistance so they are used to

make forging, automotive parts, springs, wires, etc. Carbon equivalent (CE) refers to the

method of measuring the maximum hardness and weldability of the steel based on

chemical composition of the steel. Higher C (carbon) and other alloy elements such as

Mn (manganese), Cr (chrome), Mo (molybdenum), V (vanadium), Ni (nickel), Cu

(copper), etc. tend to increase the hardness (harder and stronger) but decrease the

weldability (less ductile and difficult to weld). The CE shall not exceed 0.43% of total

components, per API-5L [1], as expressed below.

0.43%15

CuNi

5

VMoCr

6

MnCCE(IIW)

++

++++=

(note: IIW = International Institute of Welding)

Pipes are graded per their tensile properties. Grade X-65 means that SMYS (specified

minimum yield strength) of the pipe is 65 ksi (see Table 7.1.1). The API-5L line pipe

specification defines two different product specification levels, PSL 1 and PSL 2. PSL 2

is commonly used for weld joint connections (see Table 7.1.2).


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Table 7.1.1 Tensile Requirements for API-5L PSL 2 Pipe

Table 7.1.2 API-5L PSL 1 vs. PSL 2


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The yield strength is defined as the tensile stress when 0.5% elongation occurs on the

pipe, per API-5L. The DNV code [2] defines the yield stress as the stress at which the

total strain is 0.5%, corresponding to an elastic strain of approximately 0.2% and aplastic (or residual) strain of 0.3%, as shown in Figure 7.1.1.

Figure 7.1.1 Yield Stress

In elastic region, when the load is removed, the pipe tends to go back to its origin. If the

load exceeds the elastic limit, the pipe does not go back to its origin when the load is

removed. Instead, the stress reduces the same rate (slope) as the elastic modulus and

reaches a certain strain at zero stress, called a residual strain.

Strain

Stress

SMYS

0.3%Residual

strain

0.2%Elasticstrain

0.5 %


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Line pipe is usually specified by Nominal Pipe Size (NPS) and schedule (SCH). The

most commonly used schedules are 40 (STD), 80 (XS), and 160 (XXS) (see Tables

7.1.3 and 7.1.4).

Table 7.1.3 Pipe Schedules

NPSOD

(inches)

Wall Thickness (inches)

SCH10s

SCH10

SCH20

SCH30

SCH40s

SCH40

SCH60

SCH80s

SCH80

SCH100

SCH120

SCH140

SCH160

10 10.75 .165 .165 .250 .307 .365 .365 .500 .500 .593 .718 .843 1.000 1.125

12 12.75 .180 .180 .250 .330 .375 .406 .500 .500 .687 .843 1.000 1.125 1.312

14 14.00 .188 .250 .312 .375 .375 .437 .593 .500 .750 .937 1.093 1.250 1.406

16 16.00 .188 .250 .312 .375 .375 .500 .656 .500 .843 1.031 1.218 1.437 1.593

18 18.00 .188 .250 .312 .437 .375 .562 .750 .500 .937 1.156 1.375 1.562 1.781

20 20.00 .218 .250 .375 .500 .375 .593 .812 .500 1.031 1.280 1.500 1.750 1.968

24 24.00 .250 .250 .375 .562 .375 .687 .968 .500 1.218 1.531 1.812 2.062 2.343

SCH 80s = 80 ksi SMYS stainless steel


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()

0.20 0.21 0.1

. 0. 0. 0.1 0.

. 0. 0.00 0.2 0.0

.2 0. 0.2 0.00 0.2 0.2 0.1 0.0 0. 0.

.2 0. 0. 0. 0.00 0.2 0.2 0.1 0.0 0.12 0. 1.000

10. 0. 0. 0. 0.00 0.2 0.2 0.1 0.12 0. 0. 1.000 1.20

12. 0. 0.0 0. 0.00 0.2 0.2 0. 0.0 0.12 0. 0. 1.000

1 0. 0.0 0. 0. 0.00 0.2 0.2 0. 0.0 0.12 0. 0.

1 0. 0.0 0. 0. 0.00 0.2 0.2 0. 0.0 0.12 0. 0.

1 0. 0.0 0. 0. 0.00 0.2 0.2 0. 0.0 0.12 0. 0.

20 0. 0. 0.00 0.2 0.2 0. 0.0 0.12 0. 0. 1.000 1.02

22 0.00 0.2 0.2 0. 0.0 0.12 0. 0. 1.000 1.02 1.12 1.1

2 0.2 0.2 0. 0.0 0.12 0. 0. 1.000 1.02 1.12 1.1 1.20

2 0.2 0.2 0. 0.0 0.12 0. 0. 1.000

2 0.2 0.2 0. 0.0 0.12 0. 0. 1.000

0 0.2 0.2 0. 0.0 0.12 0. 0. 1.000 1.02 1.12 1.1 1.20

2 0.2 0.2 0. 0.0 0.12 0. 0. 1.000 1.02 1.12 1.1 1.20

0.2 0.2 0. 0.0 0.12 0. 0. 1.000 1.02 1.12 1.1 1.20

0.2 0.2 0. 0.0 0.12 0. 0. 1.000 1.02 1.12 1.1 1.20

0.2 0.2 0. 0.0 0.12 0. 0. 1.000 1.02 1.12 1.1 1.20

0 0.2 0.2 0. 0.0 0.12 0. 0. 1.000 1.02 1.12 1.1 1.20

2 0.2 0.2 0. 0.0 0.12 0. 0. 1.000 1.02 1.12 1.1 1.20

0.2 0.2 0. 0.0 0.12 0. 0. 1.000 1.02 1.12 1.1 1.20

0.2 0.2 0. 0.0 0.12 0. 0. 1.000 1.02 1.12 1.1 1.20

()

Table 7.1.4 API-5L Standard Pipe Wall Thickness


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Depending on pipe manufacturing process, there are several pipe types as:

Seamless pipe UOE pipe or DSAW (double submerged arc welding) pipe

ERW (electric resistant welding) pipe

Seamless pipe is made by piercing the hot steel rod, without longitudinal welds. It is

most expensive but ideal for small diameter, deepwater, or dynamic applications.

Currently up to 24 OD pipe can be fabricated by manufacturers.

UOE pipe is made by folding a steel panel with U press, O press, and expansion (to

obtain its final OD dimension). The longitudinal seam is welded by double (inside and

outside) submerged arc welding. UOE pipe is produced in sizes from 18" through 80"

OD and wall thicknesses from 0.25" through 1.50". (UOE pipe is made by DSAW

Technique but spiral formed pipe can be welded by DSAW technique, so DSAW pipe is

not necessarily UOE pipe.)

ERW pipe (produced in sizes from 16 OD to 26 OD) is cheaper than seamless or

DSAW pipe but it has not been widely adopted by offshore industry, especially for sour

or high pressure gas service, due to its variable electrical contact and inadequate forging

upset. However, development of high frequency induction (HFI) welding enables to

produce better quality ERW pipes. Figure 7.1.2 shows pipe types by manufacturing

process.


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Figure 7.1.2 Pipe Types by Manufacturing Process

ExpansionO-forming

(b) UOE pipe

U-forming

(a) Seamless pipe

(c) Continuous ERW pipe


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7.2 CRA (Corrosion resistant alloy) Pipe

Depending on alloy contents, CRA pipe can be broken into follows:

Stainless steel: 316L, 625 (Inconel), 825, 904L, etc.

Chrome based alloy: 13 Cr, Duplex (22 Cr), Super Duplex (25 Cr), etc.

Nickel based alloy : 36 Ni (Invar) for cryogenic application such as LNG(liquefied natural gas) transportation (-160oC)

Titanium: Light weight (56% of steel), high strength (up to 200 ksitensile), high corrosion resistance, low elastic modulus,

and low thermal expansion, but high cost (~10 times of

steel). Good for high fatigue areas such as riser

touchdown region, stress joint, etc.

Aluminum: Light weight (1/3 of steel), low elastic modulus (1/3 ofsteel), high corrosion resistance, but low strength (only up

to 90 ksi tensile). Applications can include casing, air can,

and risers.

Some key properties of each material are introduced in Table 7.2.1.

Table 7.2.1 Material Properties

Properties Carbon Steel Stainless Steel Titanium Aluminum

Specific Gravity

(Density)

7.85

(490 lb/ft3)

8.03

(500 lb/ft3)

4.50

(281 lb/ft3)

2.70

(168 lb/ft3)

Elastic Modulus

(@ 200oF)

29,000 ksi

(200,000 Mpa)

28,000 ksi

(193,000 Mpa)

15,000 ksi

(104,000 Mpa)

10,000 ksi

(69,000 Mpa)

Thermal

Conductivity

(@ 125oC)

30 Btu/hr-ft-oF

(51 W/m-oC)

10 Btu/hr-ft-oF

(17 W/m-oC)

12 Btu/hr-ft-oF

(20 W/m-oC)

147 Btu/hr-ft-oF

(255 W/m-oC)

Thermal Expansion

Coefficient

6.5 x 10-6 /oF

(11.7 x 10-6 /oC)

8.9 x 10-6 /oF

(16.0 x 10-6 /oC)

4.8 x 10-6 /oF

(8.6 x 10-6 /oC)

12.8 x 10-6 /oF

(23.1 x 10-6 /oC)

1 ksi = 6.8948 Mpa

1 Btu/(hr-ft-oF) = 1.731 W/(m-oC)


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Depending on sour contents in the fluid, different chrome based alloy pipe should be

selected per Table 7.2.2.

Table 7.2.2 Chrome Based Alloy Pipe Selection for Sour Service

Conveyed Fluid 13% Cr 22% Cr 25% Cr

CO2 > 1% > 1% > 1%

H2S < 0.04 bar < 0.2 bar < 0.4 bar

Cl No < 3% < 5%

7.3 Clad Pipe

Clad pipe is a combination of low carbon steel (outer pipe) and CRA (inner pipe). This

pipe reduces material cost by using a thin wall CRA pipe at inner pipe wall surface to

resist internal corrosion. And the carbon steel outer pipe wall provides structural

integrity. Special caution should be addressed during clad pipe welding to the low

carbon steel pipe, since hydrogen induced cracking (HIC) can occur by dissimilar

material welding process.

7.4 Composite Pipe

A carbon-fiber or graphite material for small size pipe in low pressure application has

been developed for mostly topside piping and onshore pipeline. However, its application

is going to expand to subsea use due to its excellent corrosion resistant and low thermal

expansion.

7.5 Flexible Pipe

Flexible pipe consists of steel layers and plastic layers. Each layer is un-bonded and

moves freely from each other. It is known for excellent dynamic behavior due to its

flexibility. However, the flexible pipe size is limited by burst and collapse resistance

capacities. The maximum design temperature is 130oC due to the plastic layers limit.

The maximum pipe size made by industries is 19 (by year 2006). Flexible pipes

manufacturing limit (maximum design pressure) is shown in Figure 7.5.1.


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Figure 7.5.1 Flexible Pipe Manufacturing Limit

Each steel and plastic layer has a different function as shown in Figure 7.5.2. For a sour

service, a stainless steel carcass is required. For a water injection line, a smooth plastic

bore can be used. The smooth bore is not normally used for gas applications due to gas

permeation problem. The pressure build-up in the annulus of the pipe can occur due to

diffusion of gas through the plastic sheaths. When no carcass is present, the inner

plastic layer will collapse if the annulus pressure exceeds the bore pressure, such as

shut-off case. To avoid this problem, gas vent valves are installed at end fitting to

relieve the annulus pressure. Rough bore (with carcass) can cause noise and vibrations

at high flow velocity.

The high density polyethylene (HDPE) is good for the content temperature of up to 65oC,

Rilsan/nylon for up to 90oC, and polyvinylidene fluoride (PVDF) for up to 130oC. PVDF

is better for higher temperatures but it is stiffer than nylon (3% vs. 7% in allowable

strain). Another key component of the flexible pipe is the end fitting (Figure 7.5.3) whichis designed to hold all layers of flexible pipe at each end.

The flexible pipe manufacturers include: Technip (formerly Coflexip), Wellstream, NKT,

and DeepFlex. To reduce the flexible pipe weight (especially for dynamic riser use) and

improve corrosion resistance, a composite material, such as for tensile wires, has been

developed. DeepFlex uses a composite material (carbon fibre-reinforced polymer

(CFRP)) for all layers (Figure 7.5.4.)

Pipe ID (inch)

Design Pressure (psi)

API 17J Design Limit

200

400

600

800

1000

1200

1400

0

0 2 4 6 8 10 12 14 16 18 20

Current Industry Limit


59/200

- 59 -

Figure 7.5.2 Flexible Pipe Structure [3]

Armour Wires- Resists tensile load

Pressure Layer- Resists internal and external pressures

Carcass Resists externalcollapse pressure

Pressure Sheath (HDPE/Nylon/PVDF)- Contains internal fluid and transfers

internal pressure to pressure layer

External Sheath (HDPE)

- Protects abrasion, seawaterpenetration, and steel layer corrosion Intermediate Sheath (HDPE)

- Protects abrasion between steel layers

Figure 7.5.3 Flexible Pipe End Fitting [4]

Figure 7.5.4 Composite Flexible Pipe [5]


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7.6 Flexible Hose

Flexible hose is a single body rubber bonded (vulcanized, oven baked) structure, unlike

the flexible pipe which consists of unbonded multiple plastic and steel layers. The

flexible hose is commonly used for topside jumpers, single point mooring (SPM) risers,

and surface floating risers to offload the product from the buoy to FPSO or shuttle tanker

(see Figure 7.6.1).

Figure 7.6.1 Flexible Hose Applications

.

The built in one-piece end couplings with integral built in bend limiters and a composite

fire resistant layer provide a low minimum bend radius, a light compact construction with

excellent flexibility and fatigue resistance. However, there are some manufacturing

limits on hose size and length; the maximum hose size is 30 and the maximum length is

35 ft.

Flexible hose manufacturers include: Dunlop Oil & Marine, Bridgestone, GoodYear,

Phoenix Rubber Industrial (formerly Taurus), etc.

Figure 7.6.2 shows some pictures of flexible hose applications and factory flexibility test.

Pipeline PLEM

Risers

SPM Buoy(mooring lines

not shown)

Offloading Hose FPSO orShuttle Tanker

Seabed


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- 61 -

Figure 7.6.2 Pictures of Flexible Hose Applications and Factory Flexibility Test

(Source: www.dunlop-oil-marine.co.uk[6])

(Source: www.bridgestone.co.jp[7])


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7.7 Coiled Tubing

Coiled tubing (CT) is a continuously milled tubular product reeled on a spool during

manufacturing process. Tubing diameter normally ranges from 0.75 to 6.625 and a

single reel can hold small size tubing lengths in excess of 30,000 ft. Theworlds longest

continuously milled CT string is 32,800 ft. of 1.75 diameter. CTs yield strengths range

from 55 ksi to 120 ksi [8].

CT has been developed for well service and workover and expanded the applications to

drilling and completion. To perform remedial work on a live well, three components are

required:

CT string: a continuous conduit capable of being inserted into the wellbore

Injector head: a means of running CT string into wellbore while under pressure Stripper or pack-off: a device providing dynamic seal around the CT string at justabove the blowout preventer

Some benefits of CT applications are: safe and efficient live well intervention, rapid

mobilization and rig-up resulting in less production downtime, and reduced

crew/personnel requirements, etc.

CT technology can be used for:

Well Unloading

Cleanouts Acidizing/Stimulation

Velocity Strings

Fishing

Tool Conveyance

Well Logging (real-time & memory) Setting/Retrieving Plugs

CT Drilling

Fracturing

Deeper Wells Pipeline/Flowline, etc.

The coiled tubing manufacturers include Quality Tubing, Inc. (QTI) and Tenaris (formerly

Precision Tube Technology and Maverick Tube), etc.

Figure 7.7.1 shows a CT operation at onshore wellhead.


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Figure 7.7.1 Coiled Tubing Operation [9]

CT String

InjectorHead

Stripper


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References

[1] API 5L, Specification for Line Pipe, Section 6.2.1, American Petroleum Institute,

2004[2] DNV-OS-F101, Submarine Pipeline Systems, 2003, Sec. 5, C405

[3] Technip USA Flexible Pipe Presentation

[4] NKT Flexibles Website, www.NKTflexibles.com

[5] DeepFlex Website, www.DeepFlex.com

[6] Dunlop Oil Marine Website, www.dunlop-oil-marine.co.uk

[7] Bridgestone Website, www.bridgestone.co.jp

[8] An Introduction to Coiled Tubing History, Applications, and Benefits,International Coiled Tubing Association (ICTA), 2005

[9] http://commservices.ssss.com/Literature/documents/

STEWARTANDSTEVENSONCTU.pdf

[10] Farouk A. Kenawy and Wael F. Ellaithy, Case History in Coiled Tubing Pipeline,

OTC (Offshore Technology Conference) Paper No. 10714, 1999

[11] Tim Crome, et. al., Smoothbore Flexible Risers for Gas Export, OTC Paper

#18703, 2007

[12] Mikhail Gelfgat, New Prospects in Development of Aluminum Alloy Marine Risers,

Deep Offshore Technology (DOT) International Conference and Exhibition, 2006[13] Freddy Paulsen, Use of Composite Materials for the Protection of Subsea

Structures and Pipelines in Deepwater, DOT 2006


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8 PIPE COATINGS

8.1 Corrosion Coating

Inner surface of the pipe is not typically coated, but if erosion or corrosion protection is

required, fusion bonded epoxy (FBE) coating or plastic liner is applied. Outer surface of

the carbon steel line pipes are typically coated with corrosion resistant FBE or neoprene

coating. The three layer polypropylene (3LPP), three layer polyethylene (3LPE, see

Figure 8.1.1), or multi-layer PP or PE is used for reeled pipes to provide abrasion

resistance during reeling and unreeling process. Thermally sprayed aluminum (TSA)

coating can be used for risers especially when there is a concern on CP shielding due to

strakes or fairings. Abrasion resistant overlay (ARO) is commonly applied for the

horizontal directional drilling (HDD) pipes or bottom towed pipes.

The coating materials normal thickness and temperature limit are as follows:

Fusion Bounded Epoxy, 0.4-0.5 mm, 200oF

Polyethylene, 3-4 mm, 150oF

Polypropylene, 3-4 mm, 220oF

Neoprene, 3-5 mm, 220oF

Figure 8.1.1 3LPE Coating

Steel

Adhesive Layer

FBE Layer

HDPE Layer


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8.2 Insulation Coating

To keep the conveyed fluid warm, the pipeline should be heated by active or passive

methods. The active heating methods include, electric heat tracing wires wrapped

around the pipeline, circulating hot water through the annulus of pipe-in-pipe, etc. The

passive heating method is insulation coating, burial, covering, etc.

Glass syntactic polyurethane (GSPU), PU foam, and syntactic foam are the commonly

used subsea insulation materials (see Figure 8.2.1). Although these insulation materials

are covered (jacketed) with HDPE, they are compressed due to hydrostatic head and

migrated by water as time passes, so it is called a wet insulation.

Figure 8.2.1 GSPU (left) and Syntactic Foam Insulation (right)

OHTC or U value is used to represent the systems insulation capability. Lower U value

prvides higher insulation performance. Heat loss can occur by three processes:

conduction, convention, and radiation. Conduction is a heat transfer through a solid by

contact, and convection is a heat transfer due to a moving fluid. Radiation is a heat

exchange between two surfaces (heat is radiated to the surrounding cooler surfaces).

Good insulation can be achieved by minimizing the above heat loss processes.

Conduction is dependent on material size and thermal conductivity. Convective heat

transfer (film) coefficient can be obtained from internal and external fluid Reynolds and

Prandtl numbers.


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The OHTC or U value can be obtained using the formula below:

mm

1

1m

m

1m

1

2

3

2

1

1

2

1

1

1 h

1

r

r

r

rln

K

r

r

rln

K

r

r

rln

K

r

h

11U

+

++

+

+

=

L

Where,

h1 = internal surface convective heat transfer coefficient

hm = external surface convective heat transfer coefficient

r = radius to each component surface

K = thermal conductivity of each component

For example, the U value for a 6.625 OD x 0.684 WT pipe with a 1 GSPU coating is:

Pipe r1= 2.6285 r2= 3.3125 K1= 30 Btu/hr-ft-oF

GSPU r2= 3.3125 r3= 4.3125 K2= 0.096 Btu/hr-ft-oF

Neglect FBE corrosion coating and HDPE outer jacket and assume h1& h3 = 1,000

Btu/hr-ft2-oF.

F)ftBtu/(hr1.65

1,000

1

4.3125

2.6285

3.3125

4.3125ln

0.096

2.6285/12

2.6285

3.3125ln

30

2.6285/12

1,000

1

1U

o2 =

+

+

+

=

r1rm


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8.3 Pipe-in-Pipe

Another pipe insulation method is pipe-in-pipe (PIP) which an inner pipe is covered by a

larger outer pipe (Figure 8.3.1). The annuls between inner pipe and outer pipe are filled

with insulation materials including: micro-porous silica (Aerogel), polyurethane foam

(PUF), Wacker/Porextherm, Mineral wool, etc.

Figure 8.3.1 PIP

Aerogel

Microporous silica with a pore size of 10-9m.

Best K value 0.0139 W/m-oK at 50oC.

The density is 0.11 SG.

Developed for the reeling process and many track records exist.

Requires centralizers with a spacing of every 2m or so.

Cheaper than Wacker/Porextherm product.

PUF

2ndcheapest form of insulation. 2nd poorest K-value (0.029 W/m-oK at 50oC) of all insulation materials but used

extensively for S/J-lay projects, normally without centralizers.

Densities are in the range of 0.07 - 0.12 SG.

Use with reel-lay has been limited due to potential damage (compression and crack)

during reeling.


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Wacker/Porextherm

Fumed microporous silica with a pore size of 10-6m. Wacker is purchased by

Porextherm. Most expensive thermal insulation product.

Good K-value (0.0195 W/m-oK at 50oC).

Standard density is 0.19 SG.

Developed for the reeling process and many track records exist.

Requires centralizers with a spacing of every 2m or so.

Mineral Wool

Cheapest form of insulation.

Poorest K-value (0.037 0.045 W/m-oK at 50oC) of all insulation materials but usedextensively in the North Sea.

Densities are in the range of 0.1 - 0.12 SG.

Not good for low U value unless combined with other method such as heat tracing.

PIP system requires bulkheads, water stops, and centralizers, depending on fabrication

methods. The end bulkhead is designed to connect the inner pipe to the outer pipe, at

each pipeline termination (see Figure 8.3.2). Intermediate bulkheads may require for

reeled PIP to allow top tension to be transferred between the outer pipe and the inner

pipe, at intervals of approximately 1 km. During installation, the tensioner holds the

outer pipe only, so the inner pipe tends to fall down by its dead weight and may result inbuckling at sag bend area near seabed, if no intermediate bulkheads exist.

Figure 8.3.2 End Bulkhead

BulkheadFlange

Outer pipe

Inner pipe


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Water stops (see Figure 8.3.3) are installed to limit the pipeline length damaged in the

event that the annulus is flooded due to pipeline failure or puncture. Considering low

fabrication cost and low heat loss, it is recommended to install one or two water stopsper each stalk length. The stalk length varies, due to spool base size and pulling

capacity, typically between 500 m to 1,500 m. It should be noted that the water stops

are not a design code requirement but they are recommended for deepwater project

where recovery of the flooded pipeline is challenging.

EPDM (ethylene propylene diene monomer) rubber, Viton (a brand of synthetic rubber),

and silicone rubber have been used for the water stop material. The axial compression

for the water stops is provided by using an interlocking clamp arrangement which will

provide the radial expansion of the ring against the pipe walls.

Centralizers or spacers (see Figure 8.3.3) are polymeric rings clamped on the inner pipe

for reeled PIP:

to protect insulations abrasion damage during insertion of the inner pipe into the

outer pipe

to protect insulations crushing due to bending load while reeling

to protect insulations crushing due to thermal bucking during operation

The centralizer works as a heat sink due to its high thermal conductivity (~0.3 W/m-oK ,

10 to 20 times higher than insulation materials). Therefore, reducing the number of

centralizers by increasing the centralizer spacing (2 m typical), or centralizer-less design

can reduce both the material and fabrication/installation costs.

Figure 8.3.3 Water Stop Seal (left) [1] and Centralizer (right) [2]


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- 71 -

Outer PipeInner Pipe

InsulationNet Gap CentralizerAnnulus Gap

For the reeled PIP, the annulus gap needs to be sufficient to put insulation material,

centralizer, and clearance gap to account for the weld beads, welding misalignment,

pipe manufacturing tolerances, etc. The annulus gap should be in the range of 30 to 40mm and the net gap (between insulation and outer pipe ID) should be 15 mm or higher

(see Figure 8.3.4). The maximum reeled PIP that has been installed by Technip is 12.2

x 17 PIP for Dalia Project.

Figure 8.3.4 Reeled PIP with Centralizers

The PIP can be used for cold products such as LPG (liquefied petroleum gas) and LNG

(liquefied natural gas) to keep the product as cold as possible. For example, LNG flows

at -256F (-160C), and the LNG pipelines need to be kept below a certain temperatureand above a certain pressure to prevent vapor generation. The LNG is commonly

transported from ship carrier (LNG tanker) to onshore facility via thick insulated pipelines

installed on a jetty. Dredging may be required along the ship channel to facilitate vessel

access to the jetty. To control the pipeline contraction due to cold product temperature,

frequent expansion loops are also required.

Recently, many subsea LNG pipelines are under development. The advantages of

subsea LNG pipelines include: increase security due to pipeline buried under the

low cost of jetty construction and dredging, no expansion loops, no insulation coating

damage, and sound control of thermal cyclic fatigue, etc. Some challenges of subsea

cryogenic LNG pipelines are: effective insulation system (vaccum, Nanogel, Aerogel,

IzoFlex, etc.) and special cryogenic materials for pipe, forgings, and welding

consumables. Either 36% nickel alloy (Invar) or 9% nickel alloy is typically used for the

inner pipe of the cryogenic LNG pipelines [3]. A triple PIP (pipe-in-pipe-in-pipe) system

is introduced by ITP (InTerPipe) to transport LNG through subsea [7].


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8.5 Field Joint Coating

After the field weld is made, each pipe joint should be coated with a corrosion resistant

coating. The field joint coating (FJC) can be done by FBE, heat shrink sleeve, or PU

foam (for concrete coated pipe). Figure 8.5.1 presents one example of field joint coating

for insulation coated pipes.

Figure 8.5.1 Field Joint Coating [5]


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References

[1] Dunlaw Engineering Ltd. website, http://www.dunlaw.com/bend_limiters.html

[2] Oil & Gas Journal website,http://www.ogj.com/display_article/112253/7/ARCHI/none/none/Innovations-key-

reeled-pipe-in-pipe-flowline-for-gulf-deepwater-project/

[3] Tom Phalen, C. Neal Prescott, Jeff Zhang, and Tony Findlay, Update on Subsea

LNG Pipeline Technology, OTC (Offshore Technology Conference) paper No.

18542, 2007

[4] Bayou Companies website, http://www.bayoucompanies.com

[5] Pipeline Induction Heat website, http://www.pih.co.uk

[6] M. Delafkaran and D.H. Demetriou, Design and Analysis of High Temperature,Thermally Insulated, Pipe-in-Pipe Risers, OTC (Offshore Technology Conference)

paper No. 8543, 1997

[7] ITP website, http://www.itp-interpipe.com/


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9 PIPE WALL THICKNESS DESIGN

Pipe wall thickness (WT) should be checked for;

- internal pressure (burst)

- external pressure (collapse/buckle propagation)

- bending buckling

- combined load

Also the calculated pipe WT should be checked for thermal expansion, on-bottom

stability, free spanning, and installation stress.

9.1 Internal Pressure (Burst) Check

Pipe should carry the internal fluid safely without bursting. Design factor (inverse of

safety factor) used for burst pressure check (hoop stress) varies due to the pipe

application: oil or gas and pipeline or riser. The 0.72 design factor means a 72% of pipe

SMYS shall be used in pipe strength design. Riser is required to use a lower design

factor than the flowline/pipeline. This is because the riser is attached to a fixed or

floating structure and the risers failure may damage the structure and cost human lives,

unlike the pipeline failure. Moreover, gas riser uses lower design factor than the oil riser,

since gas is a compressed fluid so gas risers failure is more dangerous than the oil

risers.

Table 9.1.1 Design Factors [1] [3]

System Design Factor Code

Flowline 0.72

0.60 (riser)

30-CFR-250

Pipeline (Oil) 0.720.60 (riser)

49-CFR-195(ASME B31.4)

Pipeline (Gas) 0.72

0.50 (riser)

49-CFR-192

(ASME B31.8)


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Using a conventional thin wall pipe formula, as used in ASME B31.4 and B31.8, the

required pipe wall thickness (t) can be obtained as;

DFS2

DPt

Where, P = internal pressure (psi)

D = pipe OD (inch)

S = pipe SMYS (psi)

DF = design factor

For example, for a gas pipeline with a 4,000 psi internal pressure (at water surface), the

required WT for a 16 OD and X-65 grade pipe is 0.684 as below.

0.684"0.7265,0002

164,000t =

The empty pipe dry weight in air is 112.0 lb/ft and water displacement (buoyancy) is 89.4

lb/ft. Therefore, the pipe specific gravity is 1.25 (or 112.0/89.4). The submerged pipe

weight is 22.6 lb/ft (or 112.0-89.4 lb/ft).

The gas pipeline riser requires 0.985 WT pipe, using the same criteria as above but with0.5 design factor.

0.985"0.565,0002

164,000t =

For a deepwater application, the external hydrostatic pressure should be accounted for

by using P instead of P.

P = (internal pressure)max (external pressure)min= Pi_max Po_min

For the above example, the external pressure is zero at the platform, so there is no

change in WT calculation.

The above thin wall pipe formula assumes uniform hoop stress across the pipe wall and

gives a conservative result (high hoop stress). However, the hoop stress is not uniform

and it is maximum at inner surface and minimum at outer surface as shown in Figure

9.1.1. Therefore, a closed form solution of thick wall pipe (D/t


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- 77 -

( )formulapipewallThick

ab

r/PPbabPaP

22

2oi

222o

2i

h +

=

Where, a = inner pipe wall radius = Di / 2

b = outer pipe wall radius = Do / 2

r = arbitrary pipe radius (at which the hoop stress to be estimated)

By replacing r with a, the maximum hoop stress at inner pipe wall can be expressed as:

For the same example, the required pipe wall thickness per thick wall pipe formula is

0.657 as below. This means that the thin wall pipe formula (ASME B31.4/31.8)

estimates 4% more conservative than the thick wall formula (0.684). As the external

pressure increases, the conservatism of the thin wall formula results increases.

0.657"tt)(162

t(4,000)(4,000)0.5

t2

16(4,000)h =

+=

Figure 9.1.1 Pipe Hoop Stress Comparison

c

h_thin wallh_thick wall h_thick wall

wallinner@formulapipewallThickt)(D2

t)P(P)P(P0.5

t2

D)P(P oioi

oih

++

=

ab

D

Ditt

Po

Pi


78/200

- 78 -

API RP-1111 [7] burst design formula has been widely used since it gives a little more

conservative results than the thick wall formula but less conservative results than the

ASME 31.4/31.8 formula.

strength)tensile(ultimateUTSpipeU

SMYSpipeS

pressureburstP

pressurehydrotestP

pressuredesignPwhere,

f*0.80U)(S0.45

Pexp*2

D

2

Dt

t2D

DlnU)(S0.45P

riserfor0.75flowline,for0.90ff*0.80

PP

PfP0.80

P

b

t

d

d

d

b

d

d

db

bdtd

=

=

=

=

=

+

=

+=

=

For the same example, the required pipe wall thickness per API RP-1111 is 0.666 as

below. This value is only 1% more conservative than the thick wall formula (0.657).

0.666"t

0.90*0.8077,000)(65,0000.45

4,000exp*2

16

2

16t =

+

=


79/200

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9.2 External Pressure (Collapse/Buckle Propagation) Check

The deepwater pipeline shall be checked for external hydrostatic pressure for itscollapse resistance and buckle propagation resistance. Normally the buckle propagation

resistance requires heavier WT than the collapse resistance. However, if a buckle

arrestor is installed at a certain interval (typically a distance equivalent to the water

depth), the buckle propagation is prevented or stopped (arrested) and no further damage

to the pipeline beyond the buckle arrestor can occur. In this way, we can save some

pipe material and installation cost by designing the pipe for collapse resistance.

The ASME code does not provide a formula to check for collapse resistance, thus the

API RP-1111 is normally used.

)2(1

3

D

t

E2e

P

D

tS2

yP

2e

P2y

P

eP

yP

cP

cP

of

iP

oP

max

=

=

+=

Where, fo= collapse factor, 0.7 for seamless or ERW pipe

Pc= collapse pressure of the pipe, psi

Py= yield pressure collapse, psi

Pe= elastic

pipeline_2008.pdf

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