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Introduction to Offshore Pipelines and Risers 2008 Jaeyoung Lee, P.E.
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Page 1: Pipeline 2008

Introduction to

Offshore Pipelines and Risers

2008

Jaeyoung Lee, P.E.

Page 2: Pipeline 2008

-

Page 3: Pipeline 2008

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 terminologies, general requirements, key

considerations, etc. The author‟s nearly twenty years of experience on offshore

pipelines and risers 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. 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.

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TABLE OF CONTENTS

1 INTRODUCTION ............................................................................................................... 5

2 REGULATIONS AND PIPELINE PERMITS .................................................................... 13

3 PIPELINE ROUTE SELECTION AND SURVEY............................................................. 17

4 DESIGN PROCEDURES AND DESIGN CODES ........................................................... 25

5 FLOW ASSURANCE ....................................................................................................... 35

6 UMBILICAL LINE ............................................................................................................ 39

7 PIPE MATERIAL SELECTION ........................................................................................ 45

8 PIPE COATINGS ............................................................................................................ 61

9 PIPE WALL THICKNESS DESIGN ................................................................................. 71

10 THERMAL EXPANSION DESIGN .................................................................................. 83

11 PIPELINE ON-BOTTOM STABILITY DESIGN ............................................................... 89

12 PIPELINE FREE SPAN ANALYSIS ................................................................................ 93

13 CATHODIC PROTECTION DESIGN .............................................................................. 96

14 PIPELINE INSTALLATION............................................................................................ 101

15 SUBSEA TIE-IN METHODS ......................................................................................... 113

16 UNDERWATER WORKS .............................................................................................. 127

17 OFFSHORE PIPELINE WELDING ............................................................................... 129

18 PIPELINE PROTECTION – TRENCHING AND BURIAL ............................................. 135

19 PIPELINE SHORE APPROACH AND HDD .................................................................. 143

20 RISER TYPES ............................................................................................................... 147

21 RISER DESIGNS .......................................................................................................... 151

22 COMMISSIONING AND PIGGING ............................................................................... 155

23 INSPECTION ................................................................................................................ 161

24 PIPELINE REPAIR ........................................................................................................ 165

DEFINITIONS ........................................................................................................................ 173

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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 earth‟s circumference of subsea

pipelines have been installed. The deepest flowline installed is 2,743 m (9,000 ft) in the

Gulf of Mexico (GOM). The longest oil subsea tieback flowline length is 43.4 miles (69.8

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

74.6 miles (120 km) of Norsk Hydro‟s 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,

Statoil‟s Kristin Field in Norway holds the HP/HT record of 3,212 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 in Figure 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 subsea

tiebacks 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/Floating Structures

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1.1 Subsea System

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

Wellhead

Controls

Flowline Connection

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 Christmas tree (control

panel with valves).

The control system includes a subsea control module (SCM), umbilical termination

assembly (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 flowline connection, please see Subsea Tie-in Methods in Section 15.

Wellhead

Flowline Connection

Controls

Mudline

Wellhead

Drilling casing

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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).

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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 fixed

jacket 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 (Dominion‟s 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 (Anadarko‟s 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 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-FPS FPSO

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1.4 Topside Processing System

As mentioned earlier, the crude is normally treated by topside processing facilities before

being sent to the onshore. Due to space and weight limit on the platform deck, topside

processing facility is required to be compact, so its design is more complicated than that

of an onshore process facility.

Requirements on topside processing systems depend on well conditions and future

extension plan. General topside processing systems required for typical deepwater field

developments are:

Well control unit

Hydraulic power unit (HPU)

Uninterruptible power supply (UPS)

Control valves

Multiphase meter

Umbilical termination panel

Crude oil separation

Emulsion breaking

Pumping and metering system

Heat exchanger (crude to crude and gas)

Electric heater

Gas compression

Condensate stabilization unit

Subsea chemical injection package

Pigging launcher and receiver

Pigging pump, etc.

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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 and obtain

approval for an Application for Permit to Drill (APD) 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

preventors, 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 DOI‟s responsibility extends upstream from the transfer point described above. The

MMS is responsible for regulatory oversight of the design, installation, and maintenance

of 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

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

hazard survey report, and an archaeological report (if required). The proposed pipeline

routes are 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 of

the 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, Minerals

Management 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 PIPELINE ROUTE SELECTION AND SURVEY

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 Ls is too short, the pipeline will slip while the curve is being made.

μW

TFLR

s

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 Rs and Ls can 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 = Ws x 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

ft 3,000 minimum Useft2,5130.522.6

1,00014.22.0

μW

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 Rs and Ls estimates, the

above formula can be modified as follows:

)cos-(1R

IE

μW

TFLR

2s

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

Initiation point

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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 (see

Figure 3.1).

Figure 3.1 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

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

located and measured (see Figure 3.2).

Figure 3.2

Side Scan Sonar Interpretation [2]

2D View

3-D View

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An acoustic sub-bottom profiler is a tool to measure geological characteristics i.e.

subsurface strata (stratigraphy), faults, sediment thickness, etc. Figure 3.3 shows one

example of sub-bottom profile and its interpretation.

Figure 3.3 Sub-bottom Profile [2]

Magnetometer (Figure 3.4) is a tool to locate cables, anchors, pipelines, and other

metallic objects. It is near-bottom towed by a cable from a survey vessel.

Figure 3.4 Geometrics G-882 Magnetometer [3]

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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 survey

vessel. 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 3.5

and 3.6 show drop corer and Torvane shear test kit.

Figure 3.5 Drop Corer [4]

Weights (400-800 lbs)

Wireline to surface

Release mechanism

Core catcher

Weight triggering release mechanism on hitting seafloor

Barrel (10-20 ft)

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Figure 3.5 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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4 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 4.1 and 4.2 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 4.1 Preliminary Design (FEED) Flowchart

Scope of Work

Design Basis

Hazard Survey

Flow Assurance

Permit Application

Route Selection

Pipe Material Selection

Pipe WT Determination

Pipe Coating Selection

Thermal Expansion

On-bottom Stability

Free Span

Cathodic Protection

Installation Check

Tie-ins and Shore Approach

Preliminary Cost Estimate

Preliminary Design Drawings

Procurement Long Lead Items

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Table 4.2 Detail Engineering Flowchart

Scope of Work

Design Basis

Route Survey

Flow Assurance

Route Selection

Metallurgy & Welding Study

Pipe WT and Grade Check

Pipe Coating Selection

Thermal Expansion

On-bottom Stability

Free Span

Cathodic Protection

Installation Check

Tie-ins and Shore Approach

Material/Construction Specifications

Construction Drawings

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: Minimum Federal Safety Standards

49 CFR, Part 195 Transportation of Hazardous Liquids by Pipeline

American Bureau of Shipping (ABS)

ABS Fatigue Assessment of Offshore Structures

ABS 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 RP 2A Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms - Working Stress Design

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

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

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

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

API RP 6FA Specification for Fire Test for Valves

API RP 14E Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems - Risers

API RP 17A Recommended Practice for Design and Operation of Subsea Production Systems – Pipelines and End Connections

API RP 17B Recommended Practice for Flexible Pipe, 1998

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

API RP 1110 Pressure Testing of Liquid Petroleum Pipelines, 1997

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

API RP 1129 Assurance of Hazardous Liquid Pipeline System Integrity

API Spec 2B Specification for Fabricated Structural Steel Pipe

API Spec 2W Specification for Steel Plates for Offshore Structures, Produced by Thermo-Mechanical Control Processing (TMCP).

API Spec 2C Offshore Cranes

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

API Spec 5L Specification for Line Pipe

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

API Spec 6H Specification for End Closures, Connectors and Swivels

API Std 1104 Standard for Welding of Pipelines and Related Facilities

American Society of Mechanical Engineers (ASME)

ASME B16.5 Pipe Flanges and Flanged Fittings

ASME 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 Petroleum Gas, 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

Page 30: Pipeline 2008

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American Society of Testing and Materials (ASTM)

ASTM A6 Standard Specification for General Requirements for Rolled Steel Plates, 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-Temperature Service

ASTM A105 Standard Specification for Carbon Steel Forgings for Piping Applications

ASTM A185 Specification for Welded Wire Fabric, Plain for Concrete Reinforcement

ASTM A193 Standard Specification for Alloy-Steel and Stainless Steel Bolting Materials for High Temperature or High Pressure Service and Other Special Purpose Applications

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

ASTM A234 Standard Specification for Piping Fittings of Wrought Carbon Steel and 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 A490 Standard Specification for Heat Treated-Treated Steel Structural Bolts 150 ksi Minimum Tensile Strength

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

ASTM A615 Specification for Deformed Billet-Steel ars for Concrete Reinforcement

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

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 and Offshore– Recommendations for Hyperbaric Welding

BS 7608 Code of Practice for Fatigue Design and Assessment of Steel Structures, 1993, British Standard Institution

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

Canadian Standards Association (CSA)

CSA-Z187 Offshore Pipelines

Det Norske Veritas (DNV)

DNV Rules for Design, Construction and Inspection of Offshore Structures.

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

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

DNV-CN-30.2 Fatigue Strength Analysis for Mobile Offshore Units

DNV-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

DNV-OS-E301 Position Mooring

DNV-OS-E402 Offshore Standard for Diving Systems

DNV-OS-E403 Offshore Loading Buoys

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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 Mooring

DNV-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 Cyclic Plastic Strain

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

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

DNV-RP-F202 Composite Risers

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 Mechanical Equipment

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

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

Manufacturers Standardization Society (MSS)

MSS SP-44 Steel Pipeline Flanges

MSS SP-75 Specification for High Test Wrought Butt Welding Fittings

National Association of Corrosion Engineers (NACE)

NACE RP-0176-94 Corrosion Control of Steel Fixed Offshore Platforms Associated with Petroleum Production, 1994

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

Tube & Pipe Association (TPA)

TPA IBS-98 Recommended Standards for Induction Bending of Pipe and Tube, 1998

Page 34: Pipeline 2008

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Page 35: Pipeline 2008

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5 FLOW ASSURANCE

Flow assurance is required to determine the optimum flowline pipe size based on

reservoir 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 and

the 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” ID 12” ID

10” ID

Page 37: Pipeline 2008

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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., 65th Annual 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

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 psi 1 atmosphere = 14.696 psi

Page 38: Pipeline 2008

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Page 39: Pipeline 2008

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6 UMBILICAL LINE

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

• Seismic, etc.

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 Oceaneering‟s Panama City plant.

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 restrictor

does not increase the umbilical or pipe‟s 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]

Page 43: Pipeline 2008

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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

Page 44: Pipeline 2008

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Page 45: Pipeline 2008

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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 low

tensile 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

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 a

plastic (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 Strain

Stress

SMYS

0.3% Residual

strain

0.2% Elastic strain

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

NPS OD

(inches)

Wall Thickness (inches)

SCH 10s

SCH 10

SCH 20

SCH 30

SCH 40s

SCH 40

SCH 60

SCH 80s

SCH 80

SCH 100

SCH 120

SCH 140

SCH 160

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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NPS OD Table 7.1.4 API-5L Standard Pipe Wall Thickness

(inch) (inch) (inch)

4 4 0.250 0.281 0.318

4.5 4.5 0.337 0.438 0.531 0.674

5 5.563 0.375 0.500 0.625 0.750

6 6.625 0.375 0.432 0.500 0.562 0.625 0.719 0.750 0.864 0.875

8 8.625 0.375 0.438 0.438 0.500 0.562 0.625 0.719 0.750 0.812 0.875 1.000

10 10.75 0.365 0.438 0.438 0.500 0.562 0.625 0.719 0.812 0.875 0.938 1.000 1.250

12 12.75 0.375 0.406 0.438 0.500 0.562 0.625 0.688 0.750 0.812 0.875 0.938 1.000 1.062 1.125 1.250

14 14 0.375 0.406 0.438 0.469 0.500 0.562 0.625 0.688 0.750 0.812 0.875 0.938 1.000 1.062 1.125 1.250

16 16 0.375 0.406 0.438 0.469 0.500 0.562 0.625 0.688 0.750 0.812 0.875 0.938 1.000 1.062 1.125 1.188 1.250

18 18 0.375 0.406 0.438 0.469 0.500 0.562 0.625 0.688 0.750 0.812 0.875 0.938 1.000 1.062 1.125 1.188 1.250

20 20 0.438 0.469 0.500 0.562 0.625 0.688 0.750 0.812 0.875 0.938 1.000 1.062 1.125 1.188 1.250 1.312 1.375

22 22 0.500 0.562 0.625 0.688 0.750 0.812 0.875 0.938 1.000 1.062 1.125 1.188 1.250 1.312 1.375 1.438 1.500

24 24 0.562 0.625 0.688 0.750 0.812 0.875 0.938 1.000 1.062 1.125 1.188 1.250 1.312 1.375 1.438 1.500 1.562

26 26 0.562 0.625 0.688 0.750 0.812 0.875 0.938 1.000

28 28 0.562 0.625 0.688 0.750 0.812 0.875 0.938 1.000

30 30 0.562 0.625 0.688 0.750 0.812 0.875 0.938 1.000 1.062 1.125 1.188 1.250

32 32 0.562 0.625 0.688 0.750 0.812 0.875 0.938 1.000 1.062 1.125 1.188 1.250

34 34 0.562 0.625 0.688 0.750 0.812 0.875 0.938 1.000 1.062 1.125 1.188 1.250

36 36 0.562 0.625 0.688 0.750 0.812 0.875 0.938 1.000 1.062 1.125 1.188 1.250

38 38 0.562 0.625 0.688 0.750 0.812 0.875 0.938 1.000 1.062 1.125 1.188 1.250

40 40 0.562 0.625 0.688 0.750 0.812 0.875 0.938 1.000 1.062 1.125 1.188 1.250

42 42 0.562 0.625 0.688 0.750 0.812 0.875 0.938 1.000 1.062 1.125 1.188 1.250

44 44 0.562 0.625 0.688 0.750 0.812 0.875 0.938 1.000 1.062 1.125 1.188 1.250

46 46 0.562 0.625 0.688 0.750 0.812 0.875 0.938 1.000 1.062 1.125 1.188 1.250

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

Seamless pipe

DSAW (double submerged arc welding) pipe or UOE 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.

DSAW or 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. DSAW pipe is produced in sizes from 18"

through 80" OD and wall thicknesses from 0.25" through 1.50".

ERW pipe 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

U-forming Expansion O-forming

(b) UOE pipe

(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 ksi

tensile), 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 of

steel), 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)

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 as shown in 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 layer‟s limit.

The maximum pipe size made by industries is 19” (by year 2006). Flexible pipe‟s

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) which

is 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

2000

4000

6000

8000

10000

12000

14000

0

0 2 4 6 8 10 12 14 16 18 20

Current Industry Limit

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Figure 7.5.2 Flexible Pipe Structure [3]

Armour Wires - Resists tensile load

Pressure Layer - Resists internal and external pressures

Carcass – Resists external collapse pressure

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

internal pressure to pressure layer

External Sheath (HDPE) - Protects abrasion, seawater penetration, 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]

Page 56: Pipeline 2008

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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 & Maine, 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 or Shuttle Tanker

Seabed

Page 57: Pipeline 2008

- 57 -

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])

Page 58: Pipeline 2008

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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. The world‟s longest

continuously milled CT string is 32,800 ft. of 1.75” diameter. CT‟s 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

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.

Page 59: Pipeline 2008

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Figure 7.7.1 Coiled Tubing Operation [9]

CT String

Injector Head

Page 60: Pipeline 2008

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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

Page 61: Pipeline 2008

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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

Page 62: Pipeline 2008

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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 commonly 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 system‟s 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 Reynold‟s and

Prandtl numbers.

Page 63: Pipeline 2008

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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

1

1U

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

r1 rm

Page 64: Pipeline 2008

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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 U 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

2nd cheapest form of insulation.

2nd poorest U-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.

Page 65: Pipeline 2008

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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 U-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 U-value (0.037 – 0.045 W/m-oK at 50oC) of all insulation materials but used

extensively 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 in

buckling at sag bend area near seabed, if no intermediate bulkheads exist.

Figure 8.3.2 End Bulkhead

Bulkhead Flange

Outer pipe

Inner pipe

Page 66: Pipeline 2008

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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 by pipeline failure or puncture. Considering low

fabrication cost and low heat loss, it is recommended to install one or two water stops

per 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 insulation‟s abrasion damage during insertion of the inner pipe into the

outer pipe

to protect insulation‟s crushing due to bending load while reeling

to protect insulation‟s 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]

Page 67: Pipeline 2008

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Outer Pipe Inner Pipe

Insulation Net Gap Centralizer Annulus 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 40

mm 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 -256°F (-160°C), and the LNG pipelines need to be kept below a certain temperature

and 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

seabed, 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].

Page 68: Pipeline 2008

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8.4 Concrete Weight Coating

Concrete weight coating (Figure 8.4.1) is applied to make the pipe stable under the

water. One inch is the minimum concrete coating thickness that fabricator can put on. It

should be evaluated if concrete coating is the most cost effective option to increase pipe

weight. Increasing the pipe wall thickness may be more efficient considering pipe

transportation and project management cost for the concrete weight coating.

Figure 8.4.1 Concrete Weight Coating [4]

The polyethylene outer wrap in the above picture is removed after the concrete coating

is cured. Each pipe end is left without concrete coating for welding and welding

inspection. No coating is applied near the pipe end for automatic welding and automatic

ultrasonic test (AUT), as indicated in Figure 8.4.2. The concrete coating stop distance

from the pipe end is also called concrete cut-back length.

Figure 8.4.2 Coating Cut-Back Length

(Lengths shown below are for reference use only and can vary by contractor and project.)

Bare Steel FBE Concrete

15”

6”

Page 69: Pipeline 2008

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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]

Page 70: Pipeline 2008

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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/

Page 71: Pipeline 2008

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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 riser‟s 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 riser‟s failure is more dangerous than the oil

riser‟s.

Table 9.1.1 Design Factors [1] – [3]

System Design Factor Code

Flowline 0.72

0.60 (riser)

30-CFR-250

Pipeline (Oil) 0.72

0.60 (riser)

49-CFR-195

(ASME B31.4)

Pipeline (Gas) 0.72

0.50 (riser)

49-CFR-192

(ASME B31.8)

Page 72: Pipeline 2008

- 72 -

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 with

0.5 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<20) formula should be

used if more accurate hoop stress is required [6].

Page 73: Pipeline 2008

- 73 -

formulapipewallThick

ab

r/PPbabPaPζ

22

2

oi

222

o

2

ih

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 = a, the maximum hoop stress at inner pipe wall can be expressed as;

Figure 9.1.1 Pipe Hoop Stress Comparison

c

h_thin wall h_thick wall h_thick wall

CodeBoiler&B31.3ASME)P(P0.4t2

D)P(Pζ

2RDRPAPIPt2

D)P(Pζ

:belowlistedarecodesanotherinformulasstresshoopthereference,aAs

wallinner@formulapipewallThickt)(D2

t)P(P)P(P0.5

t2

D)P(Pζ

oioi

h

ioi

h

oioi

oih

a b

D

Di t t

Po

Pi

Page 74: Pipeline 2008

- 74 -

9.2 External Pressure (Collapse/Buckle Propagation) Check

The deepwater pipeline shall be checked for external hydrostatic pressure for its

collapse 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 [7].

)2ν(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 collapse pressure of the pipe, psi

E = pipe elastic modulus, psi

M = possion‟s ratio (0.3 for steel)

Page 75: Pipeline 2008

- 75 -

For example, for a 4,000 psi internal pressure gas pipeline in 3,000 ft water depth

(1,333.3 psi), the 16” OD x 0.684” WT, X-65 grade seamless pipe can resist collapse

pressure, as calculated below.

okayPfPP

psi1,333.3PP

operationduringpsi2,666.74,0001,333.3PP

pipe)(emptyoninstallatiduringpsi1,333.301,333.3PP

psi2,6073,7240.7Pf

psi3,7244,9805,558

4,9805,558P

psi4,980)0.3(1

16

0.684

29,000,0002P

psi5,55816

0.68465,0002P

comaxio

maxio

io

io

co

22c

2

3

e

y

Buckle propagation pressure (Pp) should be computed and checked with differential

pressure per API RP-1111 formula. If the buckle propagation pressure is higher than the

differential pressure, buckle will not propagate (travel). However, buckle will propagates

if the calculated buckle propagation pressure is less than the differential pressure.

requiredisarrestorbucklethen,P0.8PPIf

2.4

D

tS24P

pmaxio

p

Page 76: Pipeline 2008

- 76 -

As shown in the below calculations, the 16” OD x 0.684” WT, X-65 grade pipe requires

buckle arrestors in water depths greater than 1,453 ft (equivalent to 646 psi).

requiredisarrestorbuckleP0.8PP

psi1,333.3PP

psi6468080.8P0.8

psi8082.4

16

0.68465,00024P

pmaxio

maxio

p

p

There are several types of buckle arrestors available; slip-on ring type and integral type

(Figure 9.2.1). Some contractors prefer thick wall pipe joint to buckle arrestor.

Figure 9.2.1 Buckle Arrestors

(a) Slip-on Type (b) Integral Type

Steel ring

Epoxy grouting

Welding Forged ring

Page 77: Pipeline 2008

- 77 -

9.3 Bending Buckling Check

Pipe WT should be checked for bending buckling during installation and operation per

API RP-1111.

ovalityDD

DDδ

δ)20(1δg

D2

operationfor0.003on,installatifor0.005strainbendingε

δgP

PP

ε

ε

minmax

minmax

1-

b

c

io

b

The same pipe as above with 1.0% ovality satisfies the bending buckling requirement as

calculated below.

okayδg

P

PP

ε

ε

operationduring0.7023,724

2,666.7

0.214

0.003

P

PP

ε

ε

oninstallatiduring0.3813,724

1,333.3

0.214

0.005

P

PP

ε

ε

0.8330.01201δ)20(1δg

0.0214162

0.684

D2

c

io

b

c

io

b

c

io

b

11-

b

Page 78: Pipeline 2008

- 78 -

If the pipe is to be installed by a reel-lay method, the pipe WT needs to be checked for

buckling during reeling. For a reel drum radius of R, the required pipe WT for reeling is

estimated as:

R

D1.25t

2

For a 31.5‟ reel drum radius (Technip Deep Blue), the required pipe WT for the 16” OD

pipe is 0.847” as below:

0.847"1231.5

161.25t

2

9.4 Combined Load Check

The combined stress of hoop stress (Sh) and longitudinal (axial compression or tension)

stress (SL) should not exceed 90% of the pipe SMYS during operation, per ASME B31.8.

There is no maximum combined stress limit for hydrotesting in this code, but it is allowed

by industry to use 100% SMYS during hydrotest.

Table 9.4.1 Design Factors (ASME B31.8)

Hoop Stress, F1 Longitudinal Stress, F2 Combined Stress, F3

0.72 (pipeline)

0.50 (riser)

0.80 0.90 (operation)

1.00 (hydrotest)

The combined stress can be calculated using Von Mises formula as below, neglecting

torsional (tangential) stress:

SMYSFSSSSStressMisesVon 3

2

LhL

2

h

The longitudinal stress comes from tension and bending loads due to installation, route

curvature, free span, thermal expansion, etc. As shown in Figure 9.4.1, the maximum

allowable Von Mises Stress curve gives less conservative results than the Tresca stress

curve. If the calculated Von Mises stress falls inside of the curve, the pipe is considered

safe in terms of combined resultant stress.

Page 79: Pipeline 2008

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It should be noted that, for the same tensional and compressive stress at a positive hoop

stress, the pipe may not be safe for the compression (see point B in Figure 9.4.1).

Figure 9.4.1 Von Mises Stress Curve [6]

L

h

(Tresca Stress)

Von Mises Stress

L

h

B (unsafe) A (safe)

Page 80: Pipeline 2008

- 80 -

9.5 Definition of MADOP

It is important to understand the term of “differential pressure” in deepwater applications.

In shallow water applications, the external hydrostatic head due to water depth (column)

is neglected. However, as the water depths and production pressures increase, heavier

wall pipes are required and it becomes natural to consider the benefit of external

pressure in pipe wall thickness determination.

The pipeline and riser system used to be designed for maximum allowable operating

pressure (MAOP) in shallow water applications. To account for the external pressure

effect, the pipeline and riser system should be designed for the maximum allowable

differential operating pressure (MADOP). For example, if a flowline is to be designed for

a 5,000 psi MAOP at subsea wellhead located in 3,375 ft water depth (equivalent to

1,500 psi external pressure), the burst resistant required pipe wall thickness can be

determined using the MADOP of 3,500 psi.

If a riser is required in the above example, the riser should be designed for the MADOP

along the riser length. At the riser bottom, the MADOP is 3,500 psi assuming the same

water depth as at the subsea well. And at the riser top, the MADOP is 5,000 psi – 1,275

psi (assuming 0.85 SG oil contents) or 3,725 psi. Thus, the riser should be designed for

the MADOP of 3,725 psi. If there is no subsea isolation valve at flowline and riser

connection, the flowline needs to be designed for the MADOP of the whole system which

is 3,725 psi due to hydrotesting requirement.

Figure 9.5.1 illustrates the applications of MADOP when MAOP is specified at subsea

wellhead (typical flowlines) and at water surface (typical pipelines).

Page 81: Pipeline 2008

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Figure 9.4.2 Applications of MADOP

MAOP = Max. Allowable Operating Pressure Pd = Design Pressure = MAOP

MADOP = Max. Allowable Differential Operating Pressure Pe = External Pressure = rw g h

rw = Seawater Density rc = Contents Density Pc = Contents Hydrostatic Head = rc g h

water surface P_surface = Pd - Pe - rc g h = Pd - rc g h

CASE 1 - MAOP specified at subsea wellhead (ex: flowline)

Pipe should be designed for the maximum P:

MADOP = Max(P_surface, P_seabed) = Pd - rc g h

h

seabed

Pd = MAOP at subsea wellhead

P_seabed = Pd - Pe = Pd - rw g h

Pd = MAOP at water surface

water surface P_surface = Pd - Pe = Pd

CASE 2 - MAOP specified at water surface (ex: export line)

Pipe should be designed for the maximum P:

MADOP = Max(P_surface, P_seabed) = Pd

h

seabed

P_seabed = Pd - Pe + Pc = Pd - (rw -rc) g h

Page 82: Pipeline 2008

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References

[1] 49 CFR, Part 192, Transportation of Natural and Other Gas by Pipeline:

Minimum Federal Safety Standards

[2] 49 CFR, Part 195, Transportation of Hazardous Liquids by Pipeline

[3] 30 CFR, Part 250, Oil and Gas and Sulfur Operations in the Outer Continental

Shelf

[4] ASME B31.4, Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum

Gas, Anhydrous Ammonia and Alcohols, 1999

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

[6] Advanced Mechanics of Materials, Arthur P. Boresi, Richard J. Schmidt, and

Omar M. Sidebottom

[7] API RP-1111, Recommended Practice for Design Construction, Operation, and

Maintenance of Offshore Hydrocarbon Pipelines, 1999

[8] API RP 2RD, Design of Risers for Floating Production Systems (FPSs) and

Tension-Leg Platforms (TLPs), First Edition, 1998

[9] ASME B31.3, Chemical Plant and Petroleum Refinery Piping

[10] DNV-OS-F101, Submarine Pipeline Systems, 2003

[11] Alexander Blake, “Practical Stress Analysis in Engineeering Design,” Marcel

Dekker, Inc., 1990

[12] Joseph E. Shinley and Larry D. Mitchell, “Mechanical Engineering Design,”

McGraw-Hill Book Company, 1983

[13] C.P. Sparks, “The Influence of Tension, Pressure and Weight on Pipe and Riser

Deformations and Stresses,” Journal of Energy Resources Technology,

Transactions of the ASME, March 1984

[14] Jaeyoung Lee and Don Herring, "Improved Pipe Hoop Stress Formula,"

Deepwater Pipeline & Riser Technology Conference, Houston, Texas, 2000

[15] Jaeyoung Lee, "Modified Thin Wall Pipe Formula for Deep Water Application,"

International Society of Offshore and Polar Engineering (ISOPE) Conference,

Canada, 1998

Page 83: Pipeline 2008

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10 THERMAL EXPANSION DESIGN

Thermal expansion is an important issue in deepwater flowlines design since flowlines

normally carry very high pressure and temperature fluid, unlike export pipelines. The

thermal elongation is a function of the pipe material‟s thermal expansion coefficient (),

differential temperature (T) between the conveyed fluid temperature and the ambient

temperature when the pipe is welded, and the pipeline length (L). If a 1.0 miles of

carbon steel pipe (= 6.5 x 10-6 /oF) is operated at 100oF differential temperature, the

pipeline end elongation (L) will be:

ft3.45280100106.5LδTαδL -6

However, the pipe/soil friction force resists the pipeline expansion, so the above

estimated pipeline end elongation will be reduced significantly. The thermal expansion

analysis is not simple and FEA (finite element analysis) tools are commonly used to

handle sea bottom irregularities, flowline route curvatures, and pressure and

temperature variance along the route. Snaking (lateral displacement) or upheaval

buckling (vertical displacement) can occur due to excessive flowline enlogation when

both ends are restrained and are not allowed to move freely.

Figure 10.1 Snaking and Upheaval Buckling

(Source: www.jee.co.uk)

(a) Snaking

(a) Upheaval Buckling

Page 84: Pipeline 2008

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To control or mitigate the thermal expansion problems, such methods can be adopted as

follows (also see Figure 10.2):

Snake lay

Expansion loop

Flexible jumper

Inverted “U” or “M” shape rigid jumper

Sliding PLET

Random buckle initiators (sleepers, buoyancies, etc.)

Random buckle arrestors (random rock dumping, burial, anchor, etc.)

Figure 10.2 Thermal Expansion Mitigation Methods

(a) Sliding PLET

(b) A Sleeper under the Flowline

Page 85: Pipeline 2008

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Figure 10.2 Thermal Expansion Mitigation Methods (continued)

(c) Distributed Buoyancies

Flowline tends to expand (elongate) to each end of the flowline while the soil holds the

axial movement of the flowline. At a certain point, the soil friction resistance equals or

exceeds the flowline expansion load. Beyond this point, called a virtual anchor point, the

flowline will not move. The flowline walking can occur when the virtual anchor point

moves between when flowline is warmed (operation) and when it is cooled down (see

Figure 10.3). Repeated shutdowns and startups cycles may cause the axial walking and

require anchor pile to hold back the flowline from walk-away. Otherwise, a steel

catenary riser (SCR) may buckle due to reduced sag bend radius at seabed due to

accumulated pipeline walking.

Plan View – with Distributed Buoyancy

Plan View - without Buoyancy

(Shorter Wave Length – Smaller Curvature Radius – Higher Stress)

(Longer Wave Length – Less Curvature- Lower Stress)

L

L

Distributed Buoyancy

Page 86: Pipeline 2008

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Figure 10.3 Flowline Walking Phenomenon

Tension

Compression

Flowline distance

Operation

Shutdown

Moved virtual anchor point

< Walking occurs >

Flowline end

Riser end

Before

After

Diagram

Flowline/Riser Profile

Page 87: Pipeline 2008

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References

[1] Jee web site, www.jee.co.uk

[2] Han S. Choi, Expansion Analysis of Offshore Pipelines Close to Restraints,

ISOPE (International Society of Offshore and Polar Engineering) Conference,

1995

[3] C. J. M. Putot, Localized Buckling of Buried Flexible Pipelines, OTC (Offshore

Technology Conference) Paper No. 6155, 1989

[4] I. R. Colquhoun, et.al., Maximum Allowable Temperature Differentials in Buried

Pipelines, OMAE (Offshore Mechanics and Arctic Engineers) Conference, 1992

[5] I. G. Craig, et. al., Upheaval Buckling : A Practical Solution Using Hot Water

Flusing Technique, OTC (Offshore Technology Conference) Paper No. 6334,

1990

[6] A. C. Palmer, et. al., Design of Submarine Pipelines Against Upheaval Buckling,

OTC (Offshore Technology Conference) Paper No. 6335, 1990

[7] M. Finch, Upheaval Buckling and Floatation of Rigid Pipelines: The Influence of

Recent Geotechnical Research on the Current State of the Art, OTC (Offshore

Technology Conference) Paper No. 10713, 1999

[8] R. Bruschi, et. al., Lateral Snaking of Hot Pressurized Pipelines Mitigation for

Troll Oil Pipeline, 1996 OMAE, 1996

[9] James G. A. Croll, A Simplified Analysis of Imperfect Thermally Buckled Subsea

Pipelines, International Journal of Offshore and Polar Engineering, Vol. 8, No. 4,

1998

[10] R.R. Hobbs and F. Liang, “Thernal Buckling of Pipelines Close to Restraints,”

International Conference on OMAE (Offshore Mechanics and Arctic Engineering)

1989

[11] Jie Zheng, Xinhai Qi, and Mark Brunner, “Effects of Soil Resistance on Lateral

Buckling of Pipelines,” DOT (Deep Offshore Technology) 2002

[12] Mark Brunner, Xinhai Qi, and Jun Chao, “Challenges and Solutions for

Deepwater HP/HT Flowlines,” DOT (Deep Offshore Technology) 2003

Page 88: Pipeline 2008

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Page 89: Pipeline 2008

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11 PIPELINE ON-BOTTOM STABILITY DESIGN

Pipeline laid on the sea floor should be stable during installation, after installation, and

during operation. If the pipe is too light during installation, it will be hard to control the

pipe since it behaves like a noodle due to waves & current and installation vessel‟s

motion. Most installation contractors require a minimum 1.15 pipe SG (specific gravity)

to avoid pipe buckling which may occur due to pipe‟s excessive movement during

installation.

After installation, before the pipe is filled with water or product fluid, the pipe should be

checked for 1 year return period waves and current conditions. If the pipe is laid as

empty for a long period before commissioning, a 2-year, 5-year, or 10-year return period

metocean data should be used. During operation, the pipe should be stable for a 100-

year return period metocean data.

The soil data is very important to estimate the pipeline on-bottom stability. If no soil data

is available, use the following data for the pipe-soil lateral friction coefficients per DnV-

RP-F109, On Bottom Stability of Offshore Pipeline Systems:

Clay 0.2

Sand 0.6

Gravel 0.8

To keep the pipeline stable, the soil resistance should be greater than the hydrodynamic

force induced on the pipeline.

ForceInertiaACρ4

DπF

ForceDragVVCDρ2

1F

ForceLiftVCDρ2

1F

Where,

FFFWμ

Mw

2

I

DwD

2

LwL

IDLs

Hydrodynamic Force

Soil Resistance

Eq. 11.1

Page 90: Pipeline 2008

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is the soil friction coefficient as mentioned in the previous paragraph; WS is the pipe

submerged weight (lb/ft); rw is the water mass density (64 lb/ft3); V is the near-bottom wave

& current velocity; and A is the water particle acceleration corresponding to the V. The

recommended lift, drag, and inertia force coefficient (CL, CD, and CM) is 0.9, 0.7, and 3.29

respectively.

The AGA pipeline on-bottom stability program [1] is widely used by industries. The

program has three modules:

Level 1 – Simple and quick static analysis using a linear wave theory and Morison

equations as above, without accounting for pipe movement or self-

embedment.

Level 2 - Reliable quasi-static analysis using a non-linear wave theory and

numerous model test results considering pipe‟s self-embedment.

Level 3 - Complicated dynamic time domain analysis using series of linear waves

and allowing some pipeline movements. Compare the computed pipe

stresses and deflections with allowable limits.

Level 2 is recommended for most cases. Level 3 can be used to predict pipeline

movements especially for dense sand or stiff clay where the pipe embedment does not

take a big role. However, Level 3 takes a long computer running time and it is difficult to

estimate how far the pipeline will move over the design life. Therefore, Level 3 is not

recommended unless small savings of concrete coating can affect the project cost

significantly.

In Level 2 analysis, it is noted that the vertical safety factor in the output should be

treated as a reference use only. This is because the lift force is already considered in

the horizontal stability check (see Eq. 11.1) and the lift force is calculated based on the

pipe sitting on the seabed. Once the pipe is lifted off the seabed, the water will start to

flow underneath the pipe. The underneath flow velocity is faster than the upper flow,

thus the underneath pressure is less than the upper pressure. This pressure differential

tends to push the pipeline back to the seabed and drastically reduces the lift force.

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The following methods (also see Figure 11.1) can be adopted to keep the pipeline stable

on the sea floor:

• Heavy (thick) wall pipe

• Concrete weight coating

• Trenching

• Burial

• Rock dumping (covering)

• Concrete mattress or bitumen blanket

• Concrete block

Figure 11.1 Some of Pipeline On-bottom Stability Mitigation Methods

Trenching Concrete Mattress

Rock Dumping Concrete Block

Page 92: Pipeline 2008

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References

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

American Gas Association, 1993

[2] C.P. Ellinas, et. al., Prevention of Upheaval Buckling of Hot Submarine Pipelines

by Means of Intermittent Rock Dumping, OTC (Offshore Technology Conference)

Paper No. 6332, 1990

[3] Submar Website, www.submar.com, for concrete mattress

[4] Van Oord Website, www.vanoord.com, for rock dumping

[5] Jaeyoung Lee and Keh-Han Wang, "Stability of Pipeline under Oblique Waves,"

Oceans 2001, Honolulu, Hawaii, 2001

[6] Guideline for the Design of Buried Steel Pipe, ASCE, 2001,

http://www.americanlifelinesalliance.org/pdf/buried_pipe.pdf

[7] Guidelines for the Seismic Design of Oil and Gas Pipeline Systems, ASCE, 1984

[8] SeaMark Systems, http://www.seamarksystems.com, for concrete/bitumen

mattress

[9] Pipeshield International Ltd., http://www.pipeshield.co.uk, for concrete block and

mattress

[10] Pro-Dive Marine Services, http://www.prodive.ca, for mattress and fabric

formwork

[11] SLP Engineering, http://www.slp-eng.com/Submat/Grout-Bags.asp, for grout bag

and bitumen mattress

Page 93: Pipeline 2008

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12 PIPELINE FREE SPAN ANALYSIS

Pipeline free spans could exist at irregular seabed terrain or fault areas. The best way is

to avoid free spans but if not avoidable, it is necessary to check if the anticipated free

span length is acceptable for static and dynamic loads. The static loads include dead

weight of the pipe and waves & current induced hydrodynamic load. Figure 12.1 shows

one example of static pipe stress near free span areas. The dynamic loads come from

vortex induced vibration (VIV, see Figure 12.2) and fatigue damage.

Figure 12.1 Static Free Span Stress

Figure 12.2 Dynamic VIV Loads

Wave & current

Inline-flow vibration Cross-flow vibration

(small amplitude) (large amplitude)

Wave & current

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The DnV-RP-F105 (Free Span Pipelines, 2006) and DnV‟s FatFree Program can be

used to check for the maximum allowable free span length. If the actual free span length

exceeds the maximum allowable free span length, the free span should be corrected

using one of the mitigation methods below (also see Figure 12.3):

Alteration of seabed (cut-off high seabed spots by plough or trencher)

Concrete mattress or sand-cement bags

Mechanical support

Strakes or fairings

Figure 12.3 Examples of Free Span Mitigation Methods

(a) Mechanical support

(b) Strakes

(c) Fairings

Page 95: Pipeline 2008

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References

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

American Gas Association, 1993

[2] B.M. Sumer and J. Fredsoe, A Review on Vibrations of Marine Pipelines, ISOPE

(International Society of Offshore and Polar Engineers) Conference, 1994

[3] L.Lee and D.W. Allen, “The Dynamic Stability of Short Fairings,” OTC Paper

#17125, 2005

[4] CRP Website, www.crpgroup.com/cable_protection.htm

[5] Mark Tool & Rubber Co. Inc. Website, www.marktool.com

Page 96: Pipeline 2008

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13 CATHODIC PROTECTION DESIGN

Corrosion is a deterioration of a material due to reaction with its environment (oxidation

or chemical reaction). It is a natural tendency of a refined material (steel) to return to its

original state (iron ore). A corrosion resistance coating is applied to prevent corrosion,

but a cathodic protection (CP) system using anodes is used as a supplemental corrosion

protection system. This is because the corrosion coating can be damaged during pipe

transportation and installation.

For the pipeline CP system, half shell anodes are tied-on the pipe outer surface at

certain intervals. Typically 75 to 115 lb aluminum alloy anodes are installed at 200 to

1,000 ft intervals. Structural anodes can also be installed at PLET, to reduce offshore

anode installation time and to keep the anode from being buried into the soil. For the

case of installing the anodes on the PLET, attenuation calculation is needed to check if

the anode current can flow to the designated distance.

Design guidelines can be found at DNV-RP-F103 (Cathodic Protection of Submarine

Pipelines by Galvanic Anodes, 2006), DNV-RP-B401 (Cathodic Protection Design,

2005), and ISO-15589-2 (Petroleum and Natural Gas Industries – Cathodic Protection of

Pipeline Transportation Systems – Part 2: Offshore Pipelines, 2004) (Ref. [1] - [3]).

There are four components in CP system (see Figure 13.1) as follows:

(1) Anode (lower electrical potential) – the point that corrosion occurs (oxidation or

production of electrons)

(2) Cathod (higher electrical potential) – the point that consumption of electrons occurs

(3) Electrolyte – electrically conductive fluid (water or air)

(4) Return Circuit (metallic path) – electrons move from anode to cathode

Figure 13.1 CP System Components

Anode (-) e

Current

Cathod (+)

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Galvanic or sacrificial anodes are made of zinc, magnesium, and aluminum. The

electrochemical potential, current capacity, and consumption rate of these alloys are

superior for CP than iron. The driving force for CP current flow is the difference in

electrochemical potential between anode and cathode. Table 13.1 shows some

materials‟ electrochemical potentials.

Table 13.1 Electrochemical Potential - Galvanic Series

Materials Electrochemical Potential (-V)

Pure magnesium 1.75

Magnesium alloy 1.6

Zinc 1.1

Aluminum alloy (5% zinc) 1.05 Anode

Pure aluminum 0.8

Mild steel 0.5 to 0.8 Cathod

Mild steel (rusted) 0.2 to 0.5

Cast iron 0.5

Mild steel in concrete 0.2

Copper, brass, bronze 0.2

Anodes types to be used for pipeline CP system are shown in Figure 13.2 below. A

concrete mattress with integrated anodes embedded in concrete blocks has been

developed to provide both pipeline stabilization and a local CP source.

Page 98: Pipeline 2008

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Figure 13.2 Anode Types for Pipeline CP System

Square End Bracelet (for concrete coated pipe)

Tapered End Bracelet (for non-concrete coated pipe)

CP Mattress (Source: www.stoprust.com [4])

Structural Anode (for PLET)

Page 99: Pipeline 2008

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Table 13.2 Tapered Bracelet Anode Dimensions [5]

Please refer to www.galvotec.com for non-tapered bracelets for concrete coated pipes.

Page 100: Pipeline 2008

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References

[1] DNV-RP-F103, Cathodic Protection of Submarine Pipelines by Galvanic Anodes,

2006

[2] DNV-RP-B401, Cathodic Protection Design, 2005

[3] ISO-15589-2, Petroleum and Natural Gas Industries – Cathodic Protection of

Pipeline Transportation Systems – Part 2: Offshore Pipelines, 2004

[4] CP-Mat Catalogue, by Deepwater Corrosion Services, Inc (www.stoprust.com)

and Submar, Inc. (www.submar.com)

[5] Galvotec website, www.galvotec.com

Page 101: Pipeline 2008

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14 PIPELINE INSTALLATION

14.1 Pipeline Installation Methods

In early days, the pipeline was fabricated at beach and towed to the project field by a tug

boat. Most widely used installation method is using a pipeline installation vessel which

can weld pipe joints on the deck and lower the pipes by releasing the pipes from the

tensioners while moving the vessel. Depending on the pipeline‟s profile from the vessel

to the sea floor, it is called S-lay or J-lay. Another installation method is to fabricate the

pipeline at spool base near beach and reel the pipe onto the reel ship. Then the reel

ship carry the reeled pipe to the project field and lay by un-spooling the pipes.

The four (4) pipeline installation methods are listed below and illustrated in Figure

14.1.1.

Towing – bottom tow, near bottom tow, mid-depth tow, and surface tow

S-Lay

J-Lay

Reel-Lay

Figure 14.1.1 Pipeline Installation Methods

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In shallow waters, an anchor moored barge cab be used but a dynamic position (DP)

vessel is widely used for deepwater installation. Details of each installation method are

listed below.

(1) Towing

• Made up of a carrier pipe (up to 60” to date) with several components (bundle) inside

near beach

• Limitations on length that can be fabricated (beach size limit) and installed (towing

limit)

• Carrier pipe provides a corrosion free environment internally

• Requires several support vessels (cheaper ones than S/J/Reel-lays)

(2) S-Lay

• Pipeline is fabricated on the vessel using single, double, or triple joints

• Requires a “stinger” up to 100m long, either single section or two/three articulated

sections

• Deeper water requires longer stinger and higher tension resulting in more risk

• Typical lay rate is approximately 3.5km per day

• Maximum installable pipe size is 60”OD by AllSeas Solitaire

(3) J-Lay

• Welding is done on vessel, but at one station, so is slower

• Pipe has a departure angle very close to vertical, so less tension is required

• Principal application is for deep water

• Stinger is not required

• Typical lay rate is approximately 1 - 1.5 km per day

• Maximum installable pipe size is 32”OD by Saipem S-7000

(4) Reel-Lay

• Pipe welded onshore in a controlled environment and spooled onto vessel in

continuous length until complete or maximum capacity is reached

• Much lower tension and therefore more control than S lay

• Limited on coating types – no concrete coating or stiff insulation coating

• Limitations on reeling capacity by volume or weight

• Typical lay rate is 14 km per day

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Typical S-lay tensioner and stinger are shown in Figure 14.1.2. S-lay and J-lay

configuration is shown in Figure 14.1.3 and Figure 14.1.4 respectively. There are

multiple welding stations in S-lay, depending on pipe size and pipe WT. Therefore, it is

important to control the time spending at each station. If one station spends 10 minutes

while the others spend 5 minutes, the pipe lay rate is reduced by 50%. For example, if

each station takes 7 minutes to connect one pipe joint (40 ft), the lay rate would be 1.6

miles per day as below:

(24 x 60 min/day) / (7 min/40 ft) = 8,230 ft/day = 1.6 miles/day

The J-lay has only one welding station but can weld multiple pipe joints such as triple to

hex joints (120 ft to 240 ft).

Pipe strain or curvature variance during reel-lay is presented in Figure 14.1.5. The pipe

strain is near zero when the pipe departs the stinger. The pipe is reeled on a spool at

spooling base as shown in Figure 14.1.6. The maximum reelable pipe size is 18” OD

due to pipe strain and tension limit during reeling. The combined strain during reeling

process will reach approximately 3% to 4% (note: yield is 0.5% and ultimate tensile is

5%). The reeled pipe WT needs to be thick enough to avoid wrinkle (see Section 9.3).

Figure 14.1.2 S-Lay Tensioner and Stinger

Tensioner [1]

Stinger

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Figure 14.1.3 S-Lay Configuration

Figure 14.1.4 J-Lay Configuration

Welding Station #1

Welding Station #2

Welding Station #3 Welding

Inspection Station

Tensioner

Stinger 40-ft or 80-ft Pipe Joints

Installation Vessel

Tensioner

Stinger

Rollers

Plan

Profile

Fixed tensioner

Rollers

Triple or quadruple joints (120-ft or 160-ft) with a collar installed in the middle of the last joint

Installation Vessel

Traveling tensioner

J-lay tower

Welding/inspection station

Page 105: Pipeline 2008

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Figure 14.1.5 Pipe Moment-Curvature Changes during Reel-Lay

Figure 14.1.6 Spooling Base

curvature

moment

5

5 1

1

2

2

3

3

4

4

Page 106: Pipeline 2008

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14.2 Pipeline Installation Vessels

There are many offshore pipeline installation vessels available worldwide [2]. Some

deepwater installation vessels are shown in Figure 14.2.1.

As a reference, some dynamically positioned (DP) vessels which can lay pipes in water

depth greater than 3,600 ft are listed in Table 14.2.1. Table 14.2.2 presents several

reel-lay vessels‟ reeling capabilities.

Figure 14.2.1 Deepwater Pipeline Installation Vessels

Allseas, Lorelay (S-Lay)

Subsea 7, Skandi Navica (Reel-lay)

Page 107: Pipeline 2008

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Table 14.2.1 Deepwater Pipeline Installation Vessels

Contractor Vessel Tension capacity

Max. pipe OD Max. water depth*

Lay method

(kips) (inch) (ft)

Allseas Lorelay 360 30 10000+ S

Solitaire 1200 60 (S) / 18 (Reel) 10000+ S

Audacia 1155 44 10000+ S (2007)

Helix (Cal Dive)

Intrepid 268 12 8000 S / Reel

Express 352 14 ? J / Reel

Caesar 891 36 6560 S / J

Global Hercules 1200 60 (S) / 18 (Reel) 8000+ S / Reel

Chickasaw 180 12 6000 S/Reel

Heerema Balder 1250 32 10000 J

J. Ray McDermott

DB50 775 (J)

100 (Reel) 20 10000 J / Reel

DB16 300 (S/J)

100 (Reel) 48 (S/J)/10 (Reel) 10000 S / J / Reel

Saipem S-7000 1160 32 10000 J

FDS 881 (J)

551 (Reel) 20 10000 J / Reel

Acergy (Stolt)

Falcon 300 14 9840 J

Kestrel 265 12 5000 J / Reel

Polaris 529 60 (S/J)/18 (Reel) 7000 S / J / Reel

Sapura 3000

528 60 6560 S / J (2007)

Technip Deep Blue 1697 28 (J)/18 (Reel) 10000 J / Reel

Apache 440 16 5000 Reel

Constructor 440 14 5000 J / Reel

Torch Midnight Express

160 12 10000 S / J / Reel

Subsea 7 Skandi Navica

500 19 9500+ Reel

Fennica 500 19 6500 Reel

Seven Oceans

880 16 ? Reel

* Maximum water depth for small pipe sizes. The installable water depth varies with pipe size

and weight.

Page 108: Pipeline 2008

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Table 14.2.2 Reeling Capacity

Contractor Cal Dive Global Subsea

7 Technip Technip

Vessel Name Intrepid Hercules Skandi Navica

Deep Blue

Apache

Reel flange diameter (ft) ? 116 82 101.7 82

Reel hub diameter (ft) ? 59 54 64 54

Reel width between flanges (ft) ? 23.5 22 17.06 21.3

Pipe weight capacity (short ton) 1700 6500 2750 3080 2200

Number of reels (ea) 1 1 1 2 1

Page 109: Pipeline 2008

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14.3 Pipeline Installation Analysis

Pipe structural integrity should be checked for during installation operation, including

initiation, normal lay, and termination. Also, abandonment & recovery (A&R), single

point lift (SPL), and davit lift analysis should be performed for contingency occasions.

To determine whether the designed pipe can be installed by any installation vessel

currently available in the industry, at least the normal installation analysis should be

done before the pipe ordered. The installation vessel‟s limit such as tensioner, stinger,

etc. should be checked in pipeline installability evaluation. Several programs available

for pipeline installation analysis are: Offpipe, Orcaflex, Flexcom, etc.

The pipe stress limit during installation is not specified in any industry codes or

standards. However, industry uses 72% SMYS at sagbend and 85% SMYS at

overbend. At sagbend, the pipe is hard to control, like at stinger, so more stringent

stress limit (lower stress limit) is applied. For the dynamic analysis, higher stress limits

are used since more severe environment and vessel motion are considered. If strain

criteria are used, a 0.15% and 0.20% strain can be used at sagbend and overbend,

respectively. Figure 14.3.1 shows one example of pipe stress analysis results.

Overbend: 85%SMYS (static) 100%SMYS (dynamic)

Sagbend: 72%SMYS (static) 96%SMYS (dynamic)

Figure 14.3.1 Example of Pipe Stress Analysis Results

Page 110: Pipeline 2008

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Figure 14.3.2 illustrates A&R procedures. For abandonment, the A&R cable from a

winch on the vessel is attached to the pipe pull- head. While moving the vessel, the

A&R cable is lowered to the sea floor. Recovery follows the reversed order of the

abandonment procedures.

Single point lift (SPL) is similar to the A&R operation except no-use of stinger. The SPL

cable from a crane or davit on the vessel is free hanged vertically, at side of the vessel.

Multiple davits can be used to minimize the pipe stress during lifting and lowering the

pipeline, as shown in Figure 14.3.3.

Figure 14.3.2 Abandonment and Recovery Sequence

Abandonment Recovery

Pipeline

A&R cable

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Figure 14.3.2 Davit Lift

Davit cables

Pipeline

Davits

Page 112: Pipeline 2008

- 112 -

References

[1] Dominique Perinet and Ian Frazer, “J-Lay and Steep S-Lay: Complementary Tools for Ultradeep Water,” OTC 18669, 2007

[2] Offshore magazine poster, or

www.pennwellpetroleumgroup.com/resourcecenter/os_poster_series.cfm

[3] Tim Crome, “Reeling of Pipelines with Thick Insulation Coating, Finite-Element

Analysis of Local Buckling,” OTC (Offshore Technology Conference) Paper No.

10715, 1999

[4] Ruxin Song and Paul Stanton, “Deepwater Tie-back SCR: Unique Design

Challenges and Solutions,” OTC 18524, 2007

[5] E.P. Heerema, “Recent Achievement and Present Trends in Deepwater Pipe-lay Systems,” OTC Paper #17627, 2005

[6] Brett Champagne, Derek Smith, et al., “The BP Bombax Pipeline Project – Design for Construction,” OTC Paper #15271, 2003

Page 113: Pipeline 2008

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15 SUBSEA TIE-IN METHODS

Unlike onshore tie-ins, it is difficult to make subsea tie-ins in terms of material handling,

pipe cutting, welding, etc. Subsea tie-in is typically made by diver-assisted flange

connectors for shallow water pipelines and diverless remotely operated vehicle (ROV)

connectors for deepwater pipelines.

There are three types of connectors available: flange, clamp (Graylok type), and collet

connectors. Clamp or collet connector is more favorable over the flange connector due

to ROV operability, offshore connection time, and available tie-in tools from contractors.

Flange connector is industry proven technology and can be easily procured from

vendors‟ shelf. However, due to lengthy subsea connection time, unfriendly ROV

operation, and limited availability of connection tools/systems, the flange connector is

not recommended for deepwater application.

Clamp connector is compact and widely used for deepwater tie-ins. A single bolt with

hinge system clamp connector is preferable for the diverless ROV connection. The seal

ring between two hubs provides very secure mechanical sealing as the internal pressure

is energized.

Collet connector is more expensive and complicated than any other connectors.

Hydraulic pressure is used to close the fingers of collets and set the drive ring which

locks the collets. There are two types of collet connectors; integral and non-integral. An

integral collet connector has a self-contained actuator and is much larger and more

expensive than a non-integral collet connector. A non-integral collet connector requires

an external, reusable actuator that is deployed and retrieved by a running tool. Non-

integral collet connector is more compact than integral collet connector and economical

when more than three collet connectors are required (if only one running tool is

required).

Figures 15.1 and 15.2 show each connector components and collet connector assembly

sequence, respectively. Table 15.1 shows each connector type‟s advantages,

disadvantages, and available vendors.

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Figure 15.1 Connector Types

Compact Flange (top) and ANSI Flange (bottom) Flange Components

Clamp

HubSeal Ring

Clamp

HubSeal Ring

Four Bolts Clamp Connector Clamp Connector Components Single Bolt Clamp Connector

Collet Connector Components

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Figure 15.2 Collet Connector Assembly Sequence

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Table 15.1 Pros and Cons of Each Connector

Flange Clamp Collet

- Industry proven

- Least expensive connector

- Least procurement time

(standard components)

- Long installation time (16-20

hrs for 12-inch connector)

- Industry proven

- Diverless single or dual

bolting system

- Quick connection time

- Lighter than other

connectors

- OSI RAC (Remote

Articulated Connector) can

accommodate some

misalignment (~5o)

- More expensive than flange

- Industry proven

- No bolt required

- Quick connection time

- Accommodate some

misalignment (+2o)

- Most expensive and

complicated connector

- Conventional ANSI Flange:

Numerous vendors

- Compact Flange:

Vector (SPO)

Oceaneeriong/ReFlange

Destec (Desflex)

LTS

… and others

Oceaneering (Grayloc)

Vetco Gray (GSR)

Vector (Techlok, Optima)

ReFlange/Oceaneering (R-

Con)

Aker Kvaener

Destec (G-Range, GSB)

LTS

FMC

Oil States Industries

… and others

Oil States Industries (OSI)

Cameron

FMC

Vetco

Aker Kvaener

… and others

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Maximum allowable pressure and temperature ratings for steel pipe flanges and flanged fittings according to the American National Standard ANSI B16.5 (Pipe Flanges and Flanged Fittings, 2003) are presented in Table 15.2 below.

Table 15.2 Pressure Ratings per ANSI B16.5

Temperature

(oF) 150 300 400 600 900 1500 2500

-20 to 100 285 740 990 1480 2220 3705 6170

200 260 675 900 1350 2025 3375 5625

300 230 655 875 1315 1970 3280 5470

400 200 635 845 1270 1900 3170 5280

500 170 600 800 1200 1795 2995 4990

Pressure Class (lb.)

Generally, three diverless subsea pipeline connection methods have been used in the

offshore industry. These methods are:

Pull-in Connection

Vertical or Horizontal Jumper Connection

Stab and Hinge-over (S&HO) Connection

The pull-in connection is a cost-effective method for both 1st end and 2nd end

connections. However, this method is known to take more offshore time than jumper

connection due to subsea pull-in operation.

Both vertical and horizontal jumper connections have been widely used for 2nd end

connection. The vertical jumper connection is more attractive than the horizontal jumper

connection because of easy installation and competitive hardware tool cost. However,

the abrupt vertical elevation difference by the vertical bends may cause a hydrate

formation (slug). The disadvantages of the horizontal jumper are difficulty in adjusting

misalignment and possible residual tension on the pipe due to horizontal stroking.

The stab and hinge-over connection is ideal for 1st end connection because of easy and

simple installation without any other pipe lay initiation support. The material and

fabrication cost may be higher but its offshore installation time is less than the jumper

connection.

Figures 15.3 through 15.6 illustrate each tie-in method. Table 15.3 summarizes the

advantages and disadvantages of each tie-in system.

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Figure 15.3

Pull-in Connection Method

(by Aker Kvaener)

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Figure 15.4

Vertical Jumper Connection Method

(by FMC (top) and Aker Kvaner(bottom))

Inverted “U” Shape “M” Shape

Flexible Pipe with Goose Neck

(1) The connector module is lowered by guide wire.

(2) The module is landed onto the manifold hub.

(3) ROV makes up the connection using hot-stab on torque tool.

(1)

(2)

(3)

FLOWLINE

GUIDE WIRE

Page 120: Pipeline 2008

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Figure 15.5

Horizontal Jumper Connection Method

(by FMC)

(JSS (Jumper Stroking System) by ABB)

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Figure 15.6

Stab and Hinge-over Connection Method (by OSI)

(1) Connector assembly is lowered. (2) Connector assembly lands in receiver structure.

(3) Connector assembly hinges over. (4) ROV makes the connection.

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Table 15.3 Pros and Cons of Each Connection Method

Tie-in

Method

Advantages Disadvantages

Pull-in

Connection

- No jumpers/PLETs required

- Less connections – lower leak risk

- Deflect-to connect for 2nd end tie-

in

- Direct pull-in connect for 1st and

2nd end tie-ins

- Need to hold the pipeline installation

vessel until the tie-in is made

- Lengthy installation (pull-in) time

- Surface or subsea pull-in winch or

sheave required

- ROV docking space required

Vertical

Jumper

Connection

- Ideal for 2nd end connection

- Easier installation than horizontal

jumper connection

- PLET/jumper fabrication and sling

required

- Vertical bends may cause slug flow

problems

Horizontal

Jumper

Connection

- Ideal for 2nd end connection

- No (vertical) bends required

- Provide optimal flow to prevent

hydrate formation (slug)

- PLET/jumper fabrication and sling

required

- Jumper might be in tension due to

horizontal stoking

- Hard to adjust misalignment

Stab and

Hinge-over

Connection

- Ideal for 1st end connection and

lay-away without initiation support

- Eliminate jumper/PLET for 1st end

lay-away

- Short installation time (simple

tooling required)

- Connection base with receptacle to be

installed first

- Low flexibility in installation sequence

- High material/fabrication cost

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To make deepwater connections, several tools and systems are required in addition to

connectors. Followings are typical tie-in tools required for deepwater diverless tie-ins:

ROV

ROV running tool, seal replacement tool, actuator, etc.

Pull-in skid with winch (for pull-in connection)

Alignment funnel & sleeve (for jumper connection)

ROV control panel (for Collet connector)

Stab pin unit & receptacle base (for stab & hinge-over)

Many connector manufacturers and installation contractors offer their connection tools

and systems. The tie-in systems available for pull-in connection include:

DMaC (Diverless Maintained Cluster) by Subsea Offshore

UTIS (Universal Tie-in System) and ROVCON (ROV Connection) by FMC

DFCS (Diverless Flowline Connection System) by Sonsub

McPAC (McEvoy Pull-in And Connection) by Cameron

ICARUS by ABB

RTS (Remote Tie-in System) and BBRTS (Big Brother RTS) by Aker Kvaener

Flexconnect II by Technip, and many others

All systems above can make connections using either clamp or collet connectors, except

McPAC and ICARUS which only can use clamp connectors.

Figure 15.7 shows the pull-in connection systems offered by industry.

There exist many tie-in systems available for jumper connection and S&HO connection

as listed below. Figure 15.8 shows some systems available for these connections.

BRUTUS by Sonsub for horizontal jumper connection

VCS (Vertical Connection System) and GHO (Guide and Hinge-over) system by Aker

Kvaener

STABCON (Stab and Connect) connection system by FMC for horizontal jumper

connection

S&HO system by OSI, and many others

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Figure 15.7

Pull-in Connection Systems

FMC ROVCON Aker Kvaerner RTS

ABB Icarus

Subsea DMaC

Sonsub DFCS Technip Flexconnect II

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Figure 15.8 Other Connection Systems

Sonsub Brutus (Horizontal jumper connection)

Aker VCS (Vertical jumper connection)

OSI S&HO System FMC STABCON

(Horizontal jumper connection)

Page 126: Pipeline 2008

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References

[1] FMC Technologies, Subsea Tie-in Systems Catalogue,

www.fmctechnologies.com/subsea

[2] Destec Engineering Ltd., Compact Flange and G-Range Pipe Connectors

Catalogue, www.destec.co.uk

[3] Technip Flexconnect II Presentation, 2006

[4] Vetco, Vertical Clamp Connection System – VCCS Presentation, 2006 and

www.vetcogray.com

[5] Aker Kvaener, Subsea Tie-in, Tools and Connection Systems Catalogue,

www.akerkvaener.com

[6] Cameron Vertical Connection (CVC) System Catalogue, www.c-a-

m.com/contents/products

[7] MATIS Remote Flange Connection System, Stolt Offshore Limited, Subsea

Conference 2001

[8] ReFlange A-CON Variable Alignment Connector Catalogue

[9] Vector Optima Subsea Connector Catalogue, www.vectorint.com

[10] KOSCON Tie-in Systems, Kongsberg Offshore

[11] Framo RL Connector Technical Bulletin, 1999, Framo Engineering AS

[12] Brutus – Horizontal Jumper Connection System, Presentation by Sonsub

[13] The ICARUS Tie-in System, Outline Description, ABB Offshore Systems AS, 1999

[14] The HydroTech Diverless Collet Connector System Catalogue, Oil States

Industries, Inc.

[15] LTS Compact Flange Presentation, www.ltsusa.com

[16] Morgrip Diverless Technology, Repair Connector Presentation by Hydratight

Sweeney

Page 127: Pipeline 2008

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16 UNDERWATER WORKS

To perform subsea works such as tie-ins, inspections, and repairs, underwater works are

required. In shallow waters, divers using air or helium gas can do the underwater works

but in deepwaters special devices are required such as saturation diving chamber

(SDC), atmospheric diving suit (ADS), remotely operated vehicle (ROV), and

autonomous underwater vehicle (AUV).

Surface diving - air diving (O2), 0-120 fsw, 120-180 fsw for short simple task

Gas diving - 10% to 16% O2 balanced helium, 120-180 fsw, 180-300 fsw for short

simple task. Helium is better than nitrogen and lowers decompression sickness

(bends) incidents

Saturation diving - 180-650 fsw , divers remain under pressure for the duration of

the project. Divers are pressurized and de-pressurized slowly in a chamber (Figure

16.1)

ADS - ~1,200 fsw or deeper (2,200 fsw), divers works in atmospheric pressure in

ADS (Figure 16.2)

ROV/AUV - Deepwater or harsh environment, AUV is self propelled (no need for

power supply or communication cables) and useful for short duration underwater

survey.

Figure 16.1 Saturation Diving

Lower SDC (Saturation Diving Chamber)

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Figure 16.2 ADS and ROV

ADS (~1,200 fsw) ADS (~2,200 fsw) ROV

Two main categories of underwater welding techniques are wet underwater welding and

dry underwater welding, both are classified as hyperbaric welding.

In wet underwater welding, shielded metal arc welding (SMAW or stick welding) is

commonly used, using a waterproof electrode.

In dry underwater welding, the weld is performed in a chamber filled with a gas mixture

sealed around the structure (pipeline) being welded. Gas tungsten arc welding (GTAW

or TIG welding) is commonly used, and where here high strength is necessary, dry

underwater welding is most commonly used. The dry underwater welding is very

expensive and takes long offshore time. Research for dry underwater welding at depths

of up to 1000 m is ongoing [1].

Certified welder-divers are required for underwater welding in accordance with the AWS

D3.6, Specification for Underwater Welding Specification for Underwater Welding, and

other weld-related activities.

References

[1] http://en.wikipedia.org/wiki/Underwater_welding

[2] Oceaneering website, www.oceaneering.com

Page 129: Pipeline 2008

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17 OFFSHORE PIPELINE WELDING

Line pipes can be connected by mechanical connectors or welding. Threaded and

coupling (T&C) or pin and box connectors are used for drilling riser and top tensioned

riser connections. However, welding is more commonly used for offshore pipelines due

to its proven technology and lower cost than mechanical connectors. Advantages of

connectors are: use of high grade pipes (up to 125 ksi SMYS), fast make-up, no welding

(no heat-affected zone, no welding inspection), no field joint coating, etc. Disadvantages

of connectors are: high material cost, leak test for each connection, weak for torsion and

fatigue, etc. Integral connectors, without requiring twist the pipe or connector, have

been developed. The available integral connectors are Jetair PSC, Hydil 2000, OSI

Merlin, etc.

The maximum pipe grade which can be welded offshore is X-70. Pipe grade higher than

X-70 requires induction heat treatment which is impossible for continuous long pipeline

welding. The induction heat treatment is normally done in an oven so it is limited by the

welded products‟ size and length.

There are diversity of welding processes such as solid state welding (resistance, cold,

friction, ultrasonic, etc.), soldering/brazing, and fusion welding. Soldering/brazing melts

only filler materials not base materials. However, the fusion welding involves partial

melting of base material (called heat affected zone, see Figure 17.1). Electrical energy

(electrode) is commonly used for the fusion welding. The most widely used welding

types in offshore industries are listed next page and illustrated in Figure 17.2.

Figure 17.1 Heat Affected Zone

Fusion zone/weld pool (base metal melt + filler melt)

Heat affected zone

Base metal

Temperature

Welding filler

Melting point of base metal

Temperature at which base material microstructure is affected

Original temperature at base material

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SMAW or Stick Welding

Shielded Metal Arc Welding (SMAW) is frequently referred to as stick welding. The

flux covering the electrode melts during welding and this forms the gas and slag to

shield the arc and molten weld pool. The slag must be chipped off the weld bead

after welding.

GMAW or MIG Welding

Gas metal arc welding (GMAW) uses an arc between a consumable constant filler

metal electrode and the weld pool. Shielding is provided by an externally supplied

shielding gas. This method is also known as metal inert gas (MIG) welding or metal

active gas (MAG, i.e. carbon dioxide or oxygen) welding.

GMAW consists of a DC arc burning between a thin bare metal wire electrode and

the work piece. The arc and weld area are encased in a protective gas shield. The

wire electrode is fed from a spool, through a welding torch which is connected to the

positive terminal. The technique is easy to use and fast (high productivity) and there

is no need for slag-cleaning since no flux is used. The MAG process is suitable for

steel, low-alloy, and high-alloy based materials. The MIG process, on the other

hand, is used for aluminum and copper materials.

GTAW or TIG Welding

Gas tungsten arc welding (GTAW) is more commonly known as tungsten inert gas

(TIG) welding. It is an arc welding process that uses a non-consumable tungsten

electrode to produce the weld. The electrode used in GTAW is made of tungsten,

because tungsten has the highest melting temperature among metals. As a result,

the electrode is not consumed during welding, though some erosion (called burn-off)

may occur.

GTAW is most commonly used to weld thin sections of stainless steel and light

metals such as aluminum, magnesium, and copper alloys. The process is known for

creating stronger and higher quality welds than SMAW and GMAW. However,

GTAW is comparatively more complex and difficult to master. It is also significantly

slower than most other welding techniques.

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Figure 17.2 Welding Types

In-continuous

consumable weld

Good for C-Mn only

Simple and portable

Slow

Slag and rough surface

No good for root welding

Continuous consumable weld

Good for C-Mn and 13Cr

Fast, automatic- most efficient

Good for high strength

material

Commonly used for pipeline

welding

Non-consumable weld

Good for all C-Mn and

CRAs

Good for root welding

Highest quality and cost

Good for thin material

Slow and high skill factor

SMAW, “Stick” (Shielded metal arc welding)

GMAW, “MIG” (Gas metal arc welding)

GTAW, “TIG” (Gas tungsten arc welding)

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Each welding should be examined for its completeness and quality by non-destructive

test (NDT). Generally four (4) NDT methods are widely used in welding inspection as

shown in Table 17.1.

Table 17.1 Non-Destructive Test

Radiography Test Ultrasonic Test Magnetic Particle Dye Penetrant

X-ray/gamma-ray

passes through pipe

to film

Mechanical vibration

emitted, reflected,

and received

Detect disturbed

magnetic field

Detect by dye

penetration

Detects volumetric

defects, porosity,

and concavity

Detects planar

defects and lack of

fusion

Safer than

Radiography

Detects surface

and near-surface

cracks

Detects surface

cracks of

stainless steels

Figure 17.3 shows each inspection NDT method and its principals. The radiography test

is commonly used to find defects (such as voids and cracks) but it can not show the

depth of the defects (see Figure 17.3 (a)). Therefore automatic ultrasonic test (AUT) is

used to check the exact size of the defects, as necessary.

Figure 17.3 Non-Destructive Test

(a) Radiographic Test (RT)

Radiation

Specimen (pipe)

Void

Film after Processing

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Figure 17.3 Non-Destructive Test (continued)

(b) Automatic Ultrasonic Test (AUT)

A. Sample before testing

B. Liquid penetrant applied

C. Surplus wiped off leaving penetrant in crack

D. Developer powder applied, dye soaks into powder

E. View colored indications, or UV lamp shows fluorescent indications

(c) Magnetic Particle Test (MPT)

(d) Dye (Liquid) Penetrant Inspection (DPI)

Page 134: Pipeline 2008

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References

[1] Technip Presentation on Offshore Welding Methods

[2] Field Welding Inspection Guide,

http://www.dot.state.oh.us/testlab/StructuralSteel/Field-Welding-Inspection-

Guide.pdf

Page 135: Pipeline 2008

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18 PIPELINE PROTECTION – TRENCHING AND BURIAL

18.1 Soil Properties

The Unified Soil Classification System defines soils such as:

Gravel 76.2 mm to 4.75 mm

Sand 4.75 mm to 0.075 mm

Silt & Clay < 0.075 mm

Sand soils are defined by friction angle among solids and cohesive clay soils are defined

by shear strength as in Table 18.1, per DNV RP-F105, “Free Spanning Pipelines,” 2006.

Table 18.1 Soil Properties

Soil Type Submerged Weight, sub

(kN/m3)

Angle of Friction,

(Degrees)

Shear Strength, Su

(kN/m2)

Loose sand 8.5 – 11.0 28 - 30 -

Medium sand 9.0 – 12.5 30 - 36 -

Dense sand 10.0 – 13.5 36 - 41 -

Very soft clay 4.0 – 7.0 - < 12.5

Soft clay 5.0 – 8.0 - 12.5 – 25

Firm clay 6.0 – 11.0 - 25 - 50

Stiff clay 7.0 – 12.0 - 50 – 100

Very stiff clay 10.0 – 13.0 - 100 – 200

Hard clay 10.0 – 13.0 - > 200

Soil stiffness or soil spring constant is widely used in pipe-soil interaction problems. The

static soil stiffness is governed mainly by the maximum reactions. The dynamic soil

stiffness is governed by the unloading and re-loading cycles. The soil stiffness should

be computed for each loading direction, as required: vertical, axial, and lateral direction.

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The static vertical stiffness is a secant stiffness representative for pipeline penetration

condition. If no data are available, use following values in Table 18.2 for the static

vertical stiffness per DNV RP-F105.

Table 18.2 Static Vertical Soil Stiffness

Soil Type Kv (kN/m/m)

Loose Sand 250

Medium Sand 530

Dense Sand 1350

Stiff Clay 1000-1600

Very stiff Clay 2000-3000

Hard Clay 2600-4200

Very Soft Clay 50-100

Soft Clay 160-260

Firm Clay 500-800

Static vertical soil stiffness, Kv (kN/m/m), can be computed by:

2uo

2s

sV

SD49

Wz

z

WK

Where, Ws = Pipe submerged unit weight (kN/m)

z = Pipe embedment (m)

Do = Pipe outside diameter (m)

Su = Undrained soil shear strength (kN/m2)

For example, Ws = 8.5 kN/m, Do = 1.22 m, Su = 4.0 kPa;

clay)softvery(kN/m/m1120.076

8.5K

m0.0764.01.2249

8.5z

V

2

2

Page 137: Pipeline 2008

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The above formula is modified from the 1995 OMAE paper [1]. Please see references

[2] to [4] for more information on soil stiffness.

18.2 Trenching and Burial

The offshore pipelines are trenched for such conditions and requirements as:

Physical protection from anchor dropping or trawl dragging (see Figure 18.2.1)

On-bottom stability

Approval authorities

The open trench could be covered by natural sedimentation depending on soil conditions

and currents near sea bottom. However, backfilling after the trenching or burial is

required for additional protection and thermal insulation purposes.

Figure 18.2.1 Fishing Trawl

Trenching equipment should be selected based on sea floor soil conditions. Followings

are available trenching equipment in the industry (also see Figure 18.2.2):

Ploughing – all types of soil

Jetting –sand and soft clay

Mechanical digging & cutting – stiff clay and rock

Dredging – all types of soil

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Figure 18.2.2 Trenching Equipment

(a) Plough (b) Water Jet Trencher

(c) Mechanical Trencher

(d) Dredger

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A mass flow excavation (by suction or blow out the seawater) has been developed by

GTO [5] and Rotech [6]. Generally, soils in the range of 25 to 50 kPa strength are well

within the economical working range of the mass flow excavation tools. Any soils above

80kPa require high pressure Jetting to break up the conglomerated material which will

then need to be removed by sand pump, or mechanical means. Soils above 500 kPa

need mechanical means such as plows or dredgers.

Figure 18.2.2 Mass Flow Excavators

GTO ROV Suction Dredger [5]

Rotech Mass Flow Excavator [6]

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Burial could be done by backfill the soil by cutting each top side of the open trench (see Figure 18.2.3) using the same jet trencher used for trenching.

Figure 18.2.3 Backfilling

Without burial, pipelines can be covered with rocks or concrete mattress (see Figure 18.2.4). This method is good for a pipeline laid on a hard rock sea bottom which is difficult to be buried.

Figure 18.2.4 Rock Dumping (top) and Mattress Covering (bottom)

Required burial depth

Cut section

Page 141: Pipeline 2008

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References

[1] “A Soil Resistance Model for Pipelines and Placed on Clay Soils,” Verley, R. and

Lund, K.M., OMAE paper, 1995

[2] Free Spanning Pipelines, DND RP-F105, 2006

[3] Guidelines for the Design of Buried Steel Pipe, ASCE , July 2001

[4] SPAN User‟s Manual (Rev. 9.2), Southwest Applied Mechanics, Inc.

[5] http://www.gto.no/go/gto-technology/gto-rov-dredge for GTO ROV suction dredger

[6] http://www.rotech.co.uk/www/subsea/sub_index.htm for Rotech mass flow excavator

[7] Trenching Considerations – Pipelines, www.oes.net.au/optc_pipelines.htm

[8] Talon Deepwater Trenching System Brochure, Stolt Offshore

[9] Fred Hettinger and Jon Machin, Cable and Pipeline Burial at 3,000 Meters, Oceans 2005

[10] R.D. Koster, Trenching of Offshore Pipelines and Cables using the SeaJet Trencher, Ingeokring Newletter, Vol. 9 No. 1, 2003

[11] Palmer, A.C., “The Speed Effect in Seabed Ploughing,” Fourth Canadian Conference on Marine Geotechnical Engineering, 1993

[12] P.G. Allan, “Geotechnical Aspects of Submarine Cables,” IBC Conference on Subsea Geotechnics, 1998

[13] Soil Machine Dynamics Ltd Hydrovision website, www.smdhydrovision.com

[14] Advanced Multipass Plough Spread – AMP5 CTC Marine Projects Ltd. Website, www.ctcmarine.com

Page 142: Pipeline 2008

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Page 143: Pipeline 2008

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19 PIPELINE SHORE APPROACH AND HDD

Pipelines transport gas or oil from offshore platforms to onshore storages or refinery

facilities. Also, pipelines are used to transport onshore gas or oil to offshore for

offloading to a shuttle tanker. Either case, the pipeline needs to cross the coastal lines.

If no environmental concerns exist, the most cost effective beach crossing method is an

open cut using dredge or trencher. If the beach crossing area is an environment

sensitive area, such as oyster field, turtle shelter, coral (tour) area, etc., and excessively

strong current occurs, horizontal directional drilling (HDD) is recommended.

Figure 19.1 shows a pipeline initiation from beach by using an open cut method. The

sheet piles are installed both sides of the trench to protect the trench from backfilling

during pipeline pulling operation.

Figure 19.1 Shore Approaching by Open Cut Method

Pullhead

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The HDD is used to install pipeline beneath obstructions, such as rivers or shorelines. It

is considered the most effective environmental conservation method, but more

expensive than open cut & backfill method (see Figure 19.2).

Figure 19.2 Shore Crossing HDD

HDD is not suitable for all types of soil. Depending on soil types, the HDD time and cost

vary significantly (references [1] & [2]).

Clay or sand: Good to excellent

Gravelly sand: Marginally acceptable

Sandy gravel: Questionable

Gravel or rock: Unacceptable

Figure 19.3 shows the HDD sequence. The entry and exit angles are varied due to soil

types but typically less than 10 degrees from horizontal plane. The drilling mud used

during drilling operation penetrates into the soil and pastes the drilling hole surface, to

prevent collapse of the drilling hole.

HDD contractors include:

HDI (Horizontal Drilling International)

Mears

Laney Directional Drilling

Nacap, etc.

Page 145: Pipeline 2008

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Figure 19.3 HDD Sequence [3]

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References:

[1] Installation of Pipelines by Horizontal Directional Drilling, An Engineering Design

Guide, PRCI (Pipeline Research Council International, Inc.), April 1995

[2] Guideline, Planning Horizontal Directional Drilling for Pipeline Construction,

CAPP (The Canadian Association of Petroleum Producers), Sep 2004

[3] DCCA (Drilling Crossing Contractors Association) poster

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20 RISER TYPES

Risers transport products from subsea wells, via flowlines, to topside facilities (import

riser) or topside facilities, via pipelines, to onshore facilities (export riser). There are

fixed static risers, free standing dynamic risers, or combination of both (called hybrid

riser). Risers are classified as follows (see Figures 20.1 and 20.2) due to material type

and its application:

Rigid pipe – Fixed (clamped) riser

J-tube riser

Fixed (clamped) catenary riser

Top tension riser (TTR)

Steel catenary riser (SCR)

Rigid + Flexible – Hybrid riser

Flexible pipe – Simple catenary riser

Lazy wave riser (with distributed buoys)

Pliant wave riser (chain anchored lazy wave)

Steep wave riser (vertical connection at seabed)

Lazy S riser (with an arch buoyancy structure)

Pliant S riser (chain anchored lazy S)

Steep S riser (vertical connection at seabed)

The steep wave (or S) riser is suitable when seabed space is limited. The pliant or

compliant riser is regarded as a hybrid of lazy and stiff wave (or S) risers.

The hybrid riser uses a rigid pipe for the vertical free standing portion and a flexible pipe

for the near surface dynamic motion region. Top tension riser is used to hold a vertical

riser when the well is underneath the floating structure. A pre-tension is applied to the

riser, so the riser pipe will not be in compression when the floating structure moves

down. Figure 20.3 shows hydropneumatic tensioner of which the piston cylinder in each

tank work like a shock absorber of automobile.

Bend stiffener is placed at flexible pipe end to increase the pipe stiffness and thus to

prevent fatigue damage caused by repeated bending (dynamic use). Bend restrictors

are installed at flexible pipe end to limit (restrict) the bend radius thus to prevent bending

buckling (static use).

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Figure 20.1 Rigid Riser Types

Conventional Fixed

J-Tube Riser (Pulling the riser through pre-

installed oversized J-tube)

Subsea tie-in

Pre-installed riser with clamps

Clamped Catenary

Riser

TTR (Top Tension Riser)

SCR (Steel Catenary Riser)

Hybrid Riser

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Figure 20.2 Flexible Riser Types

Figure 20.3 Riser Top Tensioner

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References:

[1] Pipeline Riser System Design and Application Guide, PR-178-622, PRCI

(Pipeline Research Council International, Inc.), 1987

[2] Ruxin Song and Paul Stanton, “Deepwater Tie-back SCR: Unique Design

Challenges and Solutions,” OTC 18524, 2007

[3] API RP-2RD, Design of Risers for Floating Production Systems (FPSs) and

Tension-Leg Platforms (TLPs), 1998

[4] DNV OS-F201, Dynamic Risers, 2001

[5] Brian McShane and Chris Keevill, “Getting the Risers Right for Deepwater Field

Developments,” Deepwater Pipeline and Riser Technology Conference, 2000

[6] K.Z. Huang, “Composite TTR Design for an Ultradeepwater TLP,” OTC Paper

#17159, 2005

[7] A.C. Walker and P. Davies, “A Design Basis for the J-Tube Method of Riser

Installation,” Journal of Energy Resources Technology, Sept. 1983

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21 RISER DESIGNS

Riser designs should be done per API RP 2RD - Design of Risers for Floating

Production Systems (FPSs) and Tension Leg Platforms (TLPs). The general procedures

are as follows:

Riser type and material selection

WT sizing

Static analysis

Dynamic vortex induced vibration (VIV) analysis

Fatigue analysis

Interference analysis

Steel riser is stiff, but if its length (L) is very long and the elastic stiffness (EI) is very

small), the steel riser can be treated as a catenary (the word originated from chain).

lengthstic characteri W

IE C where 5,

C

L if Catenary

1/3

s

The 16” OD x 0.684” WT pipe in 3,000 ft water depth will behave like a catenary, as

shown below.

Catenary514.6205

3,000

C

L

ft205in2,46022.6/12

96729,000,000

W

IE C

1/31/3

s

The catenary formula is as below:

weightpipesubmergedisW

(residual)tensionbottomhorizontalisT

Where,

W

Ta

a

x cosh aY

s

H

s

H

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The horizontal pipe tension is constant along the water depths, and can be estimated by

top tension multiplied by sin , where is the hang-off angle at surface. Converting the

above formula to obtain a free hanging catenary riser configuration gives;

a

SsinhaXtouchdown,todistanceHorizontal

Y

a21YStouchdown,tolengthspanfreeRiser

W

Taconstant,Catenary

sinαTTtension,Bottom

sinα1

YWYWsinαTYWTTtension,Top

1

s

H

H

sssH

*

If a riser pipe of 22.6 lb/ft submerged weight is installed with a 10-degree hang-off angle

in 3,000 ft of water;

ft1,536630.41

3,575sinh*630.41

a

Ssinh*aXtouchdown,todistanceHorizontal

ft3,5753,000

630.41213,000

Y

a21YStouchdown,tolengthspanfreeRiser

630.4122.6

1,00014.2

W

Taconstant,Catenary

kips14.210sin82sinαTTtension,Bottom

kips82.010sin1

3,00022.6

sinα1

YWTtension,Top

11

s

H

o

H

o

s

The above equations can be used to estimate J-lay configuration – top and bottom

tensions, touchdown point distance from the vessel, etc.

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The touchdown area of the catenary riser is subject to fatigue damage due to its

movement against sea bottom as the host platform moves. To avoid this problem,

especially in harsh environment, flexible pipe is adopted using intermediate buoyancies

attached on the pipe. The slack of the flexible pipe absorbs the platform‟s motions.

Dynamic VIV and Fatigue could be an issue when we design a dynamic riser. DnV and

API fatigue curves can be used for the fatigue damage check. Special care in pipe

procurement (tighter tolerance than line pipe specification) and welding procedures

should be addressed. Special pipe materials like titanium can be used for fatigue

sensitive areas. Strakes or fairings can be used to surpass VIV (see pictures in Section

12).

Determination of tension factor (TF) in top tension riser (TTR) design is very important.

Depending on host platform‟s response amplitude operator (RAO) and riser pipe

properties, a 1.5 TF is commonly used in Gulf of Mexico. When the riser is in

compressed mode (platform moves down), the TF should not be less than 1.0. Also, the

TF should not be too big because when the platform moves up, an excessive tension will

occur on the riser.

Vortex induced motion (VIM) or interface with other risers or mooring lines should be

checked during riser designs. Also, the riser constructability needs to be evaluated in

early stage.

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References:

[1] Pipeline Riser System Design and Application Guide, PR-178-622, PRCI

(Pipeline Research Council International, Inc.), 1987

[2] Ruxin Song and Paul Stanton, “Deepwater Tie-back SCR: Unique Design

Challenges and Solutions,” OTC 18524, 2007

[3] API RP-2RD, Design of Risers for Floating Production Systems (FPSs) and

Tension-Leg Platforms (TLPs), 1998

[4] DNV OS-F201, Dynamic Risers, 2001

[5] Brian McShane and Chris Keevill, “Getting the Risers Right for Deepwater Field

Developments,” Deepwater Pipeline and Riser Technology Conference, 2000

[6] K.Z. Huang, “Composite TTR Design for an Ultradeepwater TLP,” OTC Paper

#17159, 2005

[7] A.C. Walker and P. Davies, “A Design Basis for the J-Tube Method of Riser

Installation,” Journal of Energy Resources Technology, Sept. 1983

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22 COMMISSIONING AND PIGGING

22.1 Commissioning and Pre-commissioning

By definition, commission is a request to someone to perform a task (duty or mission).

The pipeline mission is to transport products safely, without failure or leak during the

design life. Commissioning (or startup) is to introducing the first product in the pipeline

system after the new system is installed. Prior to commissioning, the pipeline system

needs to be checked for cleanness, structure strength, leak proof, etc. These actions

are called pre-commissioning which include;

Debris removing, cleaning, gauging, and flooding (watering)

Hydrotesting and leak testing

Dewatering and drying

After installation, pipeline should be checked for internally cleanness and free from

debris such as welding rods, tools, etc. After debris-removal pig runs, a wire-brush

cleaning pig should run to remove more stubborn debris such as mill scale, weld bead

slag, etc. After cleaning the line, the pipeline should be checked for the pipe ID

reduction due to dent or flattening (increased ovality), by using a guage pig. The guage

pigs are fitted with aluminum plate of which diameter is typically 95% of the minimum

pipe ID. Now the pipeline is ready for hydrotesting and should be filled with filtered

water with biocide or corrosion inhibitor (for a long flood time). Prior to water pumping, a

pig is placed in front of the water to ensure removal of all the air in the line. To save

offshore operation cost, the above steps could be performed simultaneously using a

series of pigs (pig train) while flooding the line.

Each pipeline system, such as pipe segments, jumpers and PLETs, are hydrotested at

factory or confirmed by structural integrity test (SIT) or factory acceptance test (FAT).

However, the overall pipeline system, after completion of transportation and

connections, should be checked for its structural integrity (hydrotest) and leak proof (leak

test). The hydrotest pressure is set to be no less than 1.25 times of the maximum

allowable operating pressure (MAOP) or no more than 90% of the pipe SMYS, for at

least 8-hour holding time. The gas riser needs to be hydrotested for at least 1.5 times of

the MAOP. The leak test can be done with 1.1 times of the MAOP, for at least 1-hour

holding time.

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After successful hydrotesting or leak testing, pipeline needs to be dewatered before

introducing the oil or gas. Dewatering pigs (or pig train) is used to displace water

efficiently. Air drying or vacuum drying is required for dry gas pipelines, but not required

for wet gas or oil pipelines. If pipeline is dewatered using a nitrogen gas, there is no

need to dry the pipeline.

During commissioning, pigs (pig train) are located in front of the first produced gas or oil,

to remove remaining air in the line and ensure that the line is fully filled with the product.

22.2 Pigging

Pig is a device used for cleaning a pipeline or separating fluids being moved down the

pipeline. It is inserted in the pipeline and carried along by pressurized flow of water, oil,

or gas. An intelligent pig is fitted with magnetic or ultrasonic sensors to detect corrosion

or defects in the pipeline. Pigging is performed during installation and operation for such

purposes as:

During Installation

Debris removing, cleaning, and gauging

Watering, dewatering, and drying

Commissioning

During Operation

Cleaning – wax/scale/condensate buildups removal

Inventory management – sweeping out batching products

Corrosion and scale control

Inspection – geometry (physical damage), corrosion, crack, leak detection

Miscellaneous

Decommissioning

Isolation

Recommissioning

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During operation, pipelines should be pigged on a regular basis. Timing and frequency

for pigging is dependent on corrosion risk assessment and the production rate

fluctuation. Common pig types are as follows:

Utility pig – foam, elastomer, mandrel (central metal body with various

components: discs, wires brushes, scraper blades, gauging

plates, etc.) to perform debris removing, cleaning, gauging,

watering, dewatering, drying, and batch separation of products

Gel pig - made with highly viscous product for batching/separating, debris

removal, and dehydrating. Can be used alone (in liquid lines), in

place of batching pigs, or in conjunction with various types of

conventional pigs to improve overall performance by eliminating

the risk of a pig stuck.

Sphere pig - foam or elastomer skin inflated with glycol and/or water normally

used to sweep liquids from gas lines

Inspection pig - intelligent or smart pig using gauging plates and calipers to detect

geometry variations (dent, wrinkle, etc.), wall thickness variations,

cracks, corrosion, etc.

There are dual diameter pigs available to negotiate two distinct diameters, for example

8” and 10”. Typical pig speeds are in the range of 2 to 10 mph (1 to 5 m/s or 3 to 15 fps)

for oil line and 5 to 15 mph (2 to 7 m/s or 7 to 22 fps) for gas line [1]. Inspection pigs

may require slower speed, i.e. 0.5 m/s (1.5 fps).

Pipe bend for pigging should be at least 3D radius (bend radius equivalent to three pipe

nominal outside diameters) to allow intelligent pigs.

Flexible pipe‟s corrugated carcass may allow bypass of fluid past the pig cups so a

double cup arrangement is recommended to reduce fluid by-pass. Appropriate pig

should be selected to avoid jam and stuck to the corrugated carcass gap.

Pigs could get stuck somewhere in the line during pigging. The main cause is that the

pig cups flip forward and the flow bypass the cups, so the pig is no longer pushed.

When this happens, another pig should run to push the stuck pig. When bidirectional pig

is stuck, it may be recovered by reversed flow. If the stuck pigs can not be recovered,

the pipeline section around the stuck pigs should be cut and replaced [1].

Pig launcher and receiver are used to send and receive pigs (Figure 22.2.1). Figure

22.2.2 shows debris and buildups removals. Variety Pig types are shown in Figure

22.2.3.

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Figure 22.2.1 Pig Launcher and Receiver

(Source: www.ppsa-online.com [2])

Figure 22.2.2 Debris and Buildups Removal Pigging

Pig Launcher

(source: www.pipelineengineering.com [3])

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Figure 22.2.3 Pig Types

(a) Utility pigs (Foam - Wire brush – disc)

(c) Intelligent pig (SmartScan by GE, www.geoilandgas.com [4])

(b) Sphere pig

(d) Dual diameter pig

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There are also isolation (plug) pigs available to plug the line temporarily during pipeline

installation or valve/damaged pipe replacement without interrupting the production or

minimizing the downtime. Figure 22.2.4 shows one application of plugs when risers are

being replaced while transporting the production from the other platforms.

Figure 22.2.4 Isolation Plug Application

(Source: www.tdwilliamson.com/media/video.html [5])

(Send plugs to riser bottom Remove risers Install new risers Retrieve plugs)

References

[1] Offshore Pipelines, Boyun Guo, et. al., 2005

[2] An Introduction to Pipeline Pigging, PPSA (Pigging Products & Services

Association), 1995

[3] www.pipelineengineering.com

[4] GE Oil & Gas Website, WWW.GEOILANDGAS.COM

[5] TDW Offshore Services, Remotely Operated Plugging Pig Service Catalogue,

www.tdwilliamson.com/media/video.html

[6] Ralph Parrott and Edd Tveit, “The Use of Intelligent Plugs to isolate Operating

Pipelines for Construction and Maintenance Activity,” The Oil & Gas Review,

2005

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23 INSPECTION

Subsea systems should be monitored or inspected regularly, internally and externally.

The inspection can provide such information as: geometry variation (dent, wrinkle,

buckle, etc.), wall thickness variation (metal loss), corrosion, crack, leak, etc.

The advantages and disadvantages of internal and external inspections are as follows:

Internal inspection: Applicable for inaccessible (buried or concrete/insulation

coated) pipes. May have to shut-down the system to send

pigs. Pigs may be stopped or lost due to pipe buckle or

pressure loss due to large hole on the pipe.

External inspection: Applicable for un-piggable line. No need to shut-down the

system. Good for partial suspicious area inspection, such as

manifold, jumper connection, riser, etc.

Self-crawling intelligent pigs have been developed to perform the In-line inspection (ILI)

without interrupting the production. The external inspections or integrity monitoring

systems are performed by ROV or tools mounted on the pipeline (Figure 23.1).

Magnetic and ultrasonic tools are commonly used to detect corrosion, crack, geometry

and wall thickness variations. Detecting a leak as early as possible will reduce the

environmental damage. The current leak detection systems available for subsea

pipelines are;

Ultrasonic - transmit ultrasonic waves and receive/record reflected waves

Acoustics - monitor/detect noise or pressure change being created by a

rupture or sudden leak

Dye detectors - detect optical fluorescent leak visually by a laser beam

Fiber optics - detect leaks by hydrophones, accelerometers, temperature

monitoring sensors installed on a distributed fiber optic cable

along the pipeline

Flow balance - detect leak by monitoring volumetric flow rate, pressure, and

temperature

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Figure 23.1 Internal and External Inspection Systems [1]

(The bristle-actuated pipeline tractor is powered through riser and operated by brush modules that when actuated against each other provide a high pull-capability along the riser or pipeline.)

(a) Internal Inspection

(Guided ultrasonic waves are used to screen long length of pipeline (several tens of meters) for corrosion or cracks from a single transducer location.)

(b) External Inspection

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The effective integrity monitoring and management planning allows the operator to

reduce uncertainties and risks associated with riser fatigue, corrosion build-up, hydrate

plug or wax formation conditions, etc.

The subsea integrity monitoring service providers include:

Genesis SIG (Subsea Integrity Group)

Come Monday, Inc.

IICORR (Integrity Inspection Corrosion)

Fugro Structural Monitoring (FSM)

2H Offshore

MCS

DeepSea Monitoring Solutions (DMS), etc.

References

[1] Genesis SIG Website, www.genesis-sig.com

[2] TDW Williamson Company Brochure

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

Page 164: Pipeline 2008

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Page 165: Pipeline 2008

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24 PIPELINE REPAIR

Pipeline repairs may be required during pipeline installation or during operation. If a

pipeline is flooded (water penetrated due to buckling or damage) during pipe laying, the

best repair method is to reverse the lay operation and recover the defect point on the

vessel for replacement.

Shell‟s Mensa project performed a 12-inch repair job at 5,000 ft water depth when the

pipe failed at a welding point due to excessive bending stress. Seven miles of pipe from

depths between 5,300 ft and 4,700 ft were recovered up the stinger by “reversed lay”

and later reinstalled [1]. The use of a repair clamp is another option for repair during

installation, if the defect point is small and precisely located.

Abandonment and recovery (A&R) procedures can be used to retrieve the damaged

pipeline section during pipelay. The process involves:

1) Identifying the damage by ROV or diver

2) Cutting off the damaged pipe (by cutting saw or shaped charge explosive)

3) Installing a pipeline recovery tool (PRT)

4) Dewatering the pipe, if needed

5) Retrieving the pipe end to the water surface by “reversed lay”

The recovery tool may incorporate a dewatering mechanism with a subsea pig launching

apparatus (see Figure 24.1). During operation, there are generally two repair methods

available;

Clamp repair (see Figure 24.2)

Spool piece repair – on-bottom or surface lift

If the defect is isolated with no significant reduction in pipe diameter, such as a leak or

crack due to welding defect or pitting corrosion, a repair clamp method can be used. If

the pipe diameter is severely reduced or the damaged section is long, such as a

buckling rupture, a spool piece repair method must be used.

The basic tasks and procedures to complete a diverless clamp repair are as follows:

1) Locate the damage

2) Prepare the work site (lifting the pipe by H-frame or jetting around the pipe)

3) Remove external coatings, if required

4) Lower, position, and install the clamp

5) Pressure test the clamp

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Figure 24.1 Pipeline Recovery Tool (PRT)

(Picture taken from TD Williamson factory in Houston)

Figure 24.2 Diverless Repair Clamp [2]

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The on-bottom spool repair method conducts all operations, cuts and connections at sea

bottom, without lifting the pipe to the water surface. An expandable horizontal spool or a

Z-shaped spool can be used like a horizontal jumper connection method.

The on-bottom spool repair procedures are as the following:

1) Locate the damage section

2) Prepare the work site (lifting the pipe by H-frame or jetting around the pipe)

3) Cut the pipe in two places on either side of the damaged section

4) Put aside the cut section on the sea floor or retrieve to the surface

5) Remove coatings and clean each pipe end

6) Install connectors on each pipe end (test seal integrity)

7) Measure spool piece distance and fabricate spool with connectors

8) Lower, position, and connect the spool piece

9) Pressure test pipeline

The surface lift repair method has been used in shallow water repairs and is expandable

to deepwater repairs. This method requires pipe lifting to the surface, so a large vessel

to handle the pipe is required. The repair procedures are given below:

1) Locate the damage section

2) Prepare the work site (lifting the pipe by H-frame or jetting around the pipe)

3) Cut the pipe in two places on either side of the damaged section

4) Place a recovery tool (head) at the cut end of the damaged pipeline, dewater if

required

5) Lift the damaged pipeline to surface using a single point lifting method

6) Remove (cut off) damaged pipe section at the surface

7) Remove coatings and clean pipe end

8) Install a connector on a sled with a yoke

9) Lower the pipeline back to the sea bottom

10) Repeat for the second end of the pipeline

11) Measure spool piece distance and fabricate spool with connectors

12) Lower, position, and connect the spool

13) Pressure test pipeline

Figures 24.3 through 24.5 show clamp repair, on-bottom spool repair, and surface lift

repair sequence, respectively. Figure 24.6 shows shallow water pipeline repair

sequence, using a diver, forged stab end connectors, and a misalignment ball flanged

spool piece.

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Figure 24.3 Clamp Repair Sequence [3]

Raise pipe and lower repair clamp

ROV opens clamp

ROV closes clamp and tests seals

Recover lift frames

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Figure 24.4 On-Bottom Spool Repair Sequence [3]

Raise the pipe and cut the damaged pipe section. Prepare pipe end for grip & seal coupling installation.

Lower repair sled with a horizontal coupling and a vertical connector hub. ROV installs the coupling to the pipe. Repeat for the other end.

Lower spool piece. ROV connects both connectors and tests seals.

Recover rigging.

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Figure 24.5 Surface Lift Repair Sequence [3]

Raise the pipe and cut the damaged pipe section. Install pipeline recovery tool and lift the pipe to the surface.

Install repair sled with a horizontal coupling and a vertical connector hub at surface and lower to the seabed. Repeat for the other end.

Lower spool piece. ROV connects both connectors and tests seals.

Recover rigging.

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Figure 24.6 Pipeline Repair in Shallow Water

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References:

[1] OTC paper #8628, “Mensa Project: Flowlines,” 1998

[2] QCS (Quality Connector Systems) Website, www.qualityconnectorsystems.com

[3] Oil States Industries Inc. Website, http://oilstates.com

[4] Harvey Mohr, “Deepwater Pipeline Connection and Repair Equipment,” The

Deepwater Pipeline Technology Conference, 1998

[5] Alex Alvarado, “Gulf of Mexico Pipeline Failure and Regulatory Issues,”

Deepwater Pipeline and Riser Technology Conference, 2000

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DEFINITIONS (Not in alphabetical order. To be updated periodically.)

Hydrogen Induced Cracking (HIC): The mechanism begins with hydrogen atoms

diffusing through the metal. When these hydrogen atoms re-combine in minuscule voids

of the metal matrix to hydrogen molecules, they create pressure from inside the cavity

they are in. This pressure can increase to levels where the metal has reduced ductility

and tensile strength, up to where it can crack open so it is called hydrogen induced

cracking (HIC). High-strength and low-alloy steels, aluminium, and titanium alloys are

most susceptible.

Hydrogen embrittlement (or hydrogen grooving) is the process by which various metals,

most importantly high-strength steel, become brittle and crack following exposure to

hydrogen. Hydrogen cracking can pose an engineering problem especially in the context

of a hydrogen economy.

Hydrogen embrittlement can happen during various manufacturing operations or

operational use, anywhere where the metal comes in contact with atomic or molecular

hydrogen. Processes which can lead to this include cathodic protection, phosphating,

pickling, and electroplating. A special case is arc welding, in which the hydrogen is

released from moisture (for example in the coating of the welding electrodes; to minimize

this, special low-hydrogen electrodes are used for welding high-strength steels). Other

mechanisms of introduction of hydrogen into metal are galvanic corrosion, chemical

reactions of metal with acids, or with other chemicals (notably hydrogen sulfide in

sulphide stress cracking, or SSC, a process of importance for the oil and gas industries).

(Source: http://en.wikipedia.org)

Sweet or Sour Crude: The corrosivity of an oil and gas well is increased by the

presence of Cl (chloride) in water solutions, CO2 (carbon dioxide), and H2S (hydrogen

sulphide). The crude is considered sweet as long as H2S is not present. However, CO2

alone can cause high corrosion, since it is acidifying the solution and the corrosion is

further accelerated if Cl is present.

Sour Crude is defined when the partial pressure of H2S is above 0.05 psi. At higher

partial pressures, the corrosion rate on carbon steel is substantially increased by means

of making the water phase more acidic and by forming iron sulphide scale. Sulphide

stress cracking (SSC) is common in high strength steels.

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The impurities (H2S, CO2, Cl, etc.) will need to be removed before the low quality sour

crude is refined into gasoline, thereby increasing the cost of processing. This results in a

higher-priced gasoline than one made from sweet crude oil. Thus sour crude is usually

processed into heavy oil such as diesel rather than gasoline to reduce processing cost.

HIPPS: High Integrity Pressure Protection System is an instrument based over pressure

protective system (OPPS) which is attractive for high pressure/high temperature (HP/HT)

developments where it is not possible to design the pipeline and risers to the full

wellhead shut-in pressure. The instrument can include series of fast acting (high

sensitivity) pressure relief valve, ESD (emergency shutdown valve), etc. There are less

than 6 subsea HIPPS worldwide (mostly in North Sea) and no HIPPS exists in the GOM.

PLEM and PLET: Pipeline end manifold (PLEM) is a sled equipped with multiple

connector hubs. If only one connector hub exists, it is called a pipeline end termination

(PLET). Midline sled is commonly called an in-line sled (ILS).

API Degree (gravity): The API (American Petroleum Institute) degree (or gravity), is a

measure of how heavy or light a petroleum liquid compared to water. If its API degree is

greater than 10, it is lighter and floats on water. API degree 10 equals to 1.0 specific

gravity (SG) of fresh water.

Although mathematically API gravity has no units (see the formula below), it is referred

to as being in “degrees”. API degree formula is derived using a hydrometer instrument

and designed so that most values would fall between 10 and 70 API gravity degrees.

(Source: http://en.wikipedia.org)

131.5F60atSG

141.5degreeAPI

o

Fresh water: 10 oAPI

Heavy oil: <22 oAPI

Medium oil: 22 oAPI – 31 oAPI

Light oil: 31 oAPI – 45 oAPI

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Workover: Maintenance is performed during the service life of the well to ensure the

well produces at optimum levels. In addition to periodic maintenance, producing wells

occasionally require major repairs or modification, called "workover." Problems that can

result in a workover operation are: equipment failure, wellbore problems, and saltwater

disposal.

For problem wells, the remedial workover is performed to increase productivity, to open

new producing zones, or to eliminate excessive water or gas production. Examples of

these remedial workover operations are deepening, plugging back, pulling and resetting

liners, squeeze cementing, etc.

Ovality: Pipe out-of-roundness is the difference between largest diameter and smallest

diameter of a pipe (Dmax – Dmin). Ovality is the ratio between out-of-roundness and

average diameter (DNV definition). The ovality defined by API is half of the DNV ovality.

0.8%0.00815.9016.17

15.90-16.17(API)Ovality

1.7%0.01715.9016.17

15.90-16.172(DNV)Ovality

,15.90"D,16.17"D,16"DIf

DD

D-D(API)Ovality

DD

D-D2

/2DD

D-D

D

D-D(DNV)Ovality

nommaxnom

minmax

minmax

minmax

minmax

minmax

minmax

av

minmax

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RAO: Response amplitude operator (RAO) is used to represent the vessel or floating

structure‟s six degree movements due to waves and wind, as below.

Surge

Heave

Sway

Roll

Yaw

Pitch

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