Introduction to

Offshore Pipelines and Risers

2007

Jaeyoung Lee, P.E.

-

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. 2007 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 ............................................................................................................ 57

9 PIPE WALL THICKNESS DESIGN................................................................................. 67

10 THERMAL EXPANSION DESIGN .................................................................................. 77

11 PIPELINE ON-BOTTOM STABILITY DESIGN ............................................................... 83

12 PIPELINE FREE SPAN ANALYSIS ................................................................................ 87

13 CATHODIC PROTECTION DESIGN .............................................................................. 90

14 PIPELINE INSTALLATION.............................................................................................. 95

15 SUBSEA TIE-IN METHODS ......................................................................................... 107

16 UNDERWATER WORKS.............................................................................................. 121

17 OFFSHORE PIPELINE WELDING ............................................................................... 123

18 PIPELINE PROTECTION – TRENCHING AND BURIAL ............................................. 129

19 PIPELINE SHORE APPROACH AND HDD.................................................................. 137

20 RISER TYPES............................................................................................................... 141

21 RISER DESIGNS .......................................................................................................... 145

22 COMMISSIONING AND PIGGING ............................................................................... 149

23 INSPECTION ................................................................................................................ 155

24 PIPELINE REPAIR........................................................................................................ 159

DEFINITIONS........................................................................................................................ 167

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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 America25%

Latin America20%Australasia

2%Asia10%

Africa40%

North Sea3%

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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.

µWTF

LRs

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 µ = 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 (α) at J-lay tower as10 degrees Top tension, T = Ws x WD / (1- sin α) = 22.6 x 3,000 / (1- sin 10) = 82,047 lb ∼ 82 kips Bottom tension, TH = T x sin α = 82 x sin 10 = 14.2 kips

ft 3,000 minimum Useft2,5130.522.61,00014.22.0

µWTF

LRs

Hss ∴=

×××

===

If the curvature angle (α) 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-(1RIE

µWTF

LR 2s

Hss α

+==

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

α

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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

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 Steel 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

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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

- 32 -

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

- 33 -

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

- 34 -

- 35 -

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

- 36 -

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

- 37 -

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

- 38 -

- 39 -

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]

- 40 -

Figure 6.2 Oceaneering Umbilical Plant [2]

- 41 -

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

- 42 -

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]

- 43 -

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

- 44 -

- 45 -

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, as expressed below.

0.43%15

CuNi5

VMoCr6

MnCCE(IIW) ≤+

+++

++=

(note: IIW = International Institute of Welding)

- 46 -

Pipes are graded per their tensile properties. Grade X-65 means that SMYS (specified minimum yield strength) of the pipe is 65 ksi. The yield strength is defined as the tensile stress when 0.5% elongation occurs on the pipe, per API-5L [1]. 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 %

- 47 -

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.

- 48 -

Figure 7.1.2 Pipe Types by Manufacturing Process

U-forming Expansion O-forming

(b) UOE pipe

(a) Seamless pipe

(c) Continuous ERW pipe

- 49 -

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)

- 50 -

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.

- 51 -

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

200

400

600

800

1000

1200

1400

0 0 2 4 6 8 10 12 14 16 18 20

Current Industry Limit

- 52 -

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]

- 53 -

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

- 54 -

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])

- 55 -

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.

- 56 -

Figure 7.7.1 Coiled Tubing Operation [9]

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

CT String

Injector Head

- 57 -

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

- 58 -

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.

- 59 -

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 h1

rr

rrln

Kr

rrln

Kr

rrln

Kr

h1

1U+⎟⎟

⎠

⎞⎜⎜⎝

⎛++⎟⎟

⎠

⎞⎜⎜⎝

⎛+⎟⎟

⎠

⎞⎜⎜⎝

⎛+

=

−−

L

Where,

h1 = internal surface convective heat transfer coefficient hm = external surface convective heat transfer coefficient r = radius to each component surface K = thermal conductivity of each component

For example, the U value for a 6.625” OD x 0.684” WT pipe with a 1” GSPU coating is: Pipe r1 = 2.6285” r2 = 3.3125” K1 = 30 Btu/hr-ft-oF GSPU r2 = 3.3125” r3 = 4.3125” K2 = 0.096 Btu/hr-ft-oF Neglect FBE corrosion coating and HDPE outer jacket and assume h1 & h3 = 1,000 Btu/hr-ft2-oF.

F)ftBtu/(hr1.65

1,0001

4.31252.6285

3.31254.3125ln

0.0962.6285/12

2.62853.3125ln

302.6285/12

1,0001

1U

o2 ⋅⋅=

+⎟⎠⎞

⎜⎝⎛+⎟

⎠⎞

⎜⎝⎛+

=

r1 rm

- 60 -

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.

- 61 -

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

- 62 -

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]

- 63 -

Outer Pipe Inner Pipe

InsulationNet 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

- 64 -

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 [3]

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”

- 65 -

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 [4]

- 66 -

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

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

[5] 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

- 67 -

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)

- 68 -

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;

DFS2DPt

×××

≥

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].

- 69 -

( ) formulapipewallThickab

r/PPbabPaPσ 22

2oi

222o

2i

h −−+−

=

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

b = outer pipe wall radius = Do / 2 r = arbitrary pipe radius (at which the hoop stress to be estimated)

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

Figure 9.1.1 Pipe Hoop Stress Comparison

c

σh_thin wall σh_thick wall σh_thick wall

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

D)P(Pσ

2RDRPAPIPt2

D)P(Pσ

:belowlistedarecodesanotherinformulasstresshoopthereference,aAs

wallinner@formulapipewallThickt)(D2t)P(P)P(P0.5

t2D)P(Pσ

oioi

h

ioi

h

oioi

oih

−−−

=

−−

=

−−

++−−

=

ab

D

Di t t

Po

Pi

- 70 -

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

Dt

E2eP

DtS2yP

2eP2

yP

ePyP

cP

cPofiPoPmax

−

⎟⎠⎞

⎜⎝⎛

=

⎟⎠⎞

⎜⎝⎛=

+=

≤−

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)

- 71 -

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

psi1,333.3PPoperationduringpsi2,666.74,0001,333.3PP

pipe)(emptyoninstallatiduringpsi1,333.301,333.3PP

psi2,6073,7240.7Pf

psi3,7244,9805,558

4,9805,558P

psi4,980)0.3(1

160.684

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

DtS24P

pmaxio

p

≥−

⎥⎦⎤

⎢⎣⎡=

- 72 -

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

160.68465,00024P

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

- 73 -

9.3 Bending Buckling Check Pipe WT should be checked for bending buckling during installation and operation per API RP-1111.

( ) ( )

( )

ovalityDDDD

δ

δ)20(1δg

D2tε

operationfor0.003on,installatifor0.005strainbendingε

δgP

PPεε

minmax

minmax

1-

b

c

io

b

=+−

=

+=

=

==

≤−

+

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

( ) ( )

( )

( )

( ) ( ) okayδgP

PPεε

operationduring0.7023,7242,666.7

0.2140.003

PPP

εε

oninstallatiduring0.3813,724

1,333.30.2140.005

PPP

εε

0.8330.01201δ)20(1δg

0.0214162

0.684D2tε

c

io

b

c

io

b

c

io

b

11-

b

∴≤−

+∴

−=−

+=−

+

=+=−

+

=×+=+=

=×

==

−

- 74 -

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:

RD1.25

t2

=

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

161.25t2

=×

×=

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 32

LhL2

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.

- 75 -

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]

σL

σh

(Tresca Stress) Von Mises Stress

σL

σh

B (unsafe) A (safe)

- 76 -

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

- 77 -

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 (α), differential temperature (δT) 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 (α = 6.5 x 10-6 /oF) is operated at 100oF differential temperature, the pipeline end elongation (δL) 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

- 78 -

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

- 79 -

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

- 80 -

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

- 81 -

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

- 82 -

- 83 -

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.

( ) ( )

ForceInertiaACρ4DπF

ForceDragVVCDρ21F

ForceLiftVCDρ21F

Where,

FFFWµ

Mw

2

I

DwD

2LwL

IDLs

=

=

=

+≥−

Hydrodynamic Force

Soil Resistance

Eq. 11.1

- 84 -

µ is the soil friction coefficient as mentioned in the previous paragraph; WS is the pipe submerged weight (lb/ft); ρw 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.

- 85 -

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

- 86 -

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

- 87 -

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

- 88 -

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

- 89 -

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

- 90 -

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 (+)

- 91 -

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.

- 92 -

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)

- 93 -

Table 13.2 Tapered Bracelet Anode Dimensions [5]

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

- 94 -

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

- 95 -

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

- 96 -

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

- 97 -

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

- 98 -

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

- 99 -

Figure 14.1.5 Pipe Moment-Curvature Changes during Reel-Lay

Figure 14.1.6 Spooling Base

curvature

moment

5

51

1

2

2

3

3

4

4

- 100 -

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)

- 101 -

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.

- 102 -

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

- 103 -

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

- 104 -

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

- 105 -

Figure 14.3.2 Davit Lift

Davit cables

Pipeline

Davits

- 106 -

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

- 107 -

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.

- 108 -

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

- 109 -

Figure 15.2 Collet Connector Assembly Sequence

- 110 -

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

- 111 -

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 15.2 summarizes the advantages and disadvantages of each tie-in system.

- 112 -

Figure 15.3 Pull-in Connection Method

(by Aker Kvaener)

- 113 -

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

- 114 -

Figure 15.5 Horizontal Jumper Connection Method

(by FMC)

(JSS (Jumper Stroking System) by ABB)

- 115 -

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.

- 116 -

Table 15.2 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

- 117 -

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

- 118 -

Figure 15.7 Pull-in Connection Systems

FMC ROVCON Aker Kvaerner RTS

ABB Icarus Subsea DMaC

Sonsub DFCS Technip Flexconnect II

- 119 -

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)

- 120 -

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

- 121 -

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)

- 122 -

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

- 123 -

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

- 124 -

• 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.

- 125 -

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)

- 126 -

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

- 127 -

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)

- 128 -

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

- 129 -

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, γsub

(kN/m3)

Angle of Friction, ϕ

(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

SD49W

z

zW

K

=

=

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

∴==

=××

=

- 131 -

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

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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

- 136 -

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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.

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Figure 19.3 HDD Sequence [3]

- 140 -

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

- 144 -

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, CL 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

3,000CL

ft205in2,46022.6/12

96729,000,000W

IE C1/31/3

s

∴⟩==

==⎟⎠⎞

⎜⎝⎛ ×

=⎟⎟⎠

⎞⎜⎜⎝

⎛=

The catenary formula is as below:

weightpipesubmergedisW(residual)tensionbottomhorizontalisT

Where,

WTa

ax cosh aY

s

H

s

H=

⎟⎠⎞

⎜⎝⎛=

- 146 -

The horizontal pipe tension is constant along the water depths, and can be estimated by top tension multiplied by sin α, where α is the hang-off angle at surface. Converting the above formula to obtain a free hanging catenary riser configuration gives;

⎟⎠⎞

⎜⎝⎛=

+=

=

=

−=+=+=

−

aSsinhaXtouchdown,todistanceHorizontal

Ya21YStouchdown,tolengthspanfreeRiser

WTaconstant,Catenary

sinαTTtension,Bottom

sinα1YW

YWsinαTYWTTtension,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;

ft1,536630.413,575sinh*630.41

aSsinh*aXtouchdown,todistanceHorizontal

ft3,5753,000630.41213,000

Ya21YStouchdown,tolengthspanfreeRiser

630.4122.6

1,00014.2WTaconstant,Catenary

kips14.210sin82sinαTTtension,Bottom

kips82.010sin1

3,00022.6sinα1

YWTtension,Top

11

s

H

oH

os

=⎟⎠⎞

⎜⎝⎛=⎟

⎠⎞

⎜⎝⎛=

=+=+=

=×

==

=×==

=−

×=

−=

−−

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

- 157 -

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

- 158 -

- 159 -

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]

- 161 -

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

- 163 -

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%0.00815.9016.1715.90-16.17(API)Ovality

1.7%0.01715.9016.1715.90-16.172(DNV)Ovality

,15.90"D,16.17"D,16"DIf

DDD-D(API)Ovality

DDD-D2

/2DDD-D

DD-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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