Introduction to Offshore Pipelines & Risers - Jaeyoung Lee

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 Sea 3%

North America 25%

Africa 40%

Asia 10%

Australasia 2%

Latin America 20%

-6Offshore 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

Processing Subsea

Fixed/Floating Structures

FL/PL/Riser

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.

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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

Controls Wellhead

Mudline

Drilling casing

Flowline Connection Wellhead

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.

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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

Fixed Platforms (WD>1,000’)

~6,000

Water Depths (ft) 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

3,622

49 – 7,600

Subsea Tiebacks

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.

- 12 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].

- 14 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 85/8 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.

- 15 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.

Rs = Ls =

F TH Ws µ

Where, Rs = Ls = F= TH = Ws =

Min. non-slippage pipeline route curve radius Min. non-slippage straight pipeline length Safety factor (~2.0) Horizontal bottom tension (residual tension) Pipe submerged weight

µ=

lateral pipeline-soil friction factor (~0.5)

- 18 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 Rs = Ls =

F TH 2.0 × 14.2 × 1,000 = = 2,513 ft ∴ Use minimum 3,000 ft Ws µ 22.6 × 0.5

Initiation point

Ls

Rs

α

Lay direction

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:

Rs = Ls =

F TH EI + 2 Ws µ R (1 - cos 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.

- 19 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

2D View

3-D View 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] B

- 20 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]

- 21 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]

Wireline to surface

Release mechanism

Weights (400-800 lbs)

Barrel (10-20 ft)

Core catcher

Weight triggering release mechanism on hitting seafloor

- 22 -

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.

- 23 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/g882.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

- 24 -

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4

DESIGN PROCEDURES AND DESIGN CODES There are typically three phases in offshore pipeline designs: conceptual study (or PreFEED: 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)

- 26 -

Table 4.1 Preliminary Design (FEED) Flowchart

Scope of Work Route Selection Design Basis

Pipe Material Selection

Hazard Survey

Pipe WT Determination

Preliminary Cost Estimate

Flow Assurance

Pipe Coating Selection

Preliminary Design Drawings

Thermal Expansion

Procurement Long Lead Items

Permit

On-bottom Stability

Free Span

Cathodic Protection

Tie-ins and Shore Approach

Installation Check

- 27 -

Table 4.2 Detail Engineering Flowchart

Scope of Work

Design Basis

Route Selection

Metallurgy & Welding Study

Pipe WT and Grade Check

Material/Construction Specifications

Pipe Coating Selection

Construction Drawings

Thermal Expansion

Procurement & Construction Support

Route Survey

Flow Assurance

On-bottom Stability

Free Span

Cathodic Protection

Tie-ins and Shore Approach

Installation Check

- 28 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

- 29 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

- 30 -

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

- 31 -

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 450

70

400

60

350

Temperature(oC)

40

300 250

30

Pressure (bar)

20

200 150 8” ID 100 150

50

170

190

12” ID

10” ID 210

230

Flowline ID (mm)

250

270

290

10

310

0

- 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:

7.1

•

Low carbon steel pipe

•

Corrosion resistant alloy (CRA) pipe

•

Clad pipe

•

Composite pipe

•

Flexible pipe

•

Flexible hose

•

Coiled tubing

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. CE(IIW) = C +

Mn Cr + Mo + V Ni + Cu + + ≤ 0.43% 6 5 15

(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 Stress

SMYS

0.5 % Strain

Strain 0.3% Residual strain

0.2% Elastic strain

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.

- 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

(a) Seamless pipe

(b) UOE pipe

U-forming

(c) Continuous ERW pipe

O-forming

Expansion

- 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

8.03

4.50

2.70

(490 lb/ft3)

(500 lb/ft3)

(281 lb/ft3)

(168 lb/ft3)

Elastic Modulus

29,000 ksi

28,000 ksi

15,000 ksi

10,000 ksi

(@ 200oF)

(200,000 Mpa)

(193,000 Mpa)

(104,000 Mpa)

(69,000)

Thermal Conductivity

30 Btu/hr-ft-oF

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)

8.9 x 10-6 /oF

4.8 x 10-6 /oF

12.8 x 10-6 /oF

(16.0 x 10-6 /oC)

(8.6 x 10-6 /oC)

(23.1 x 10-6 /oC)

(51 W/m-oC)

(@ 125oC) Thermal Expansion 6.5 x 10-6 /oF Coefficient (11.7 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

7.3

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%

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 Design Pressure (psi)

1400 1200

API 17J Design Limit

1000 800 600

Current Industry Limit

400 200 0 0

2

4

6

8

10

12

14

16

18

20

Pipe ID (inch)

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.)

- 52 -

Figure 7.5.2 Flexible Pipe Structure [3] External Sheath (HDPE) - Protects abrasion, seawater penetration, and steel layer corrosion

Intermediate Sheath (HDPE) - Protects abrasion between steel layers Pressure Layer - Resists internal and external pressures Pressure Sheath (HDPE/Nylon/PVDF) - Contains internal fluid and transfers internal pressure to pressure layer

Armour Wires - Resists tensile load

Carcass – Resists external collapse pressure

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 . FPSO or Shuttle Tanker

Offloading Hose SPM Buoy (mooring lines not shown)

Risers

Pipeline

PLEM

Seabed

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.

- 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]

CT String

Injector Head

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

- 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 FBE Layer Adhesive 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:

U=

1 ⎛ r ⎞ r 1 1 r1 ⎛ r2 ⎞ r1 ⎛ r3 ⎞ r ln⎜⎜ ⎟⎟ + L + 1 ln⎜⎜ m ⎟⎟ + 1 + ln⎜⎜ ⎟⎟ + h1 K 1 ⎝ r1 ⎠ K 2 ⎝ r2 ⎠ K m−1 ⎝ rm−1 ⎠ rm hm

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

rm

r1

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

U=

1 1 2.6285/12 ⎛ 3.3125 ⎞ 2.6285/12 ⎛ 4.3125 ⎞ 2.6285 1 ln⎜ ln⎜ + ⎟+ ⎟+ 1,000 30 0.096 ⎝ 2.6285 ⎠ ⎝ 3.3125 ⎠ 4.3125 1,000

= 1.65 Btu/(hr ⋅ ft 2 ⋅o F)

- 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. 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.

Wacker is purchased by

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 Inner pipe

Outer pipe

Bulkhead

Flange

- 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 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 Inner Pipe

Annulus Gap

Outer Pipe

Net Gap

Insulation

Centralizer

- 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

6”

15”

Concrete

- 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-keyreeled-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 Flowline

Design Factor 0.72

Code 30-CFR-250

0.60 (riser) Pipeline (Oil)

0.72 0.60 (riser)

Pipeline (Gas)

0.72 0.50 (riser)

49-CFR-195 (ASME B31.4) 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;

t≥

Where,

P= D= S= DF =

P×D 2 × S × DF

internal pressure (psi) pipe OD (inch) pipe SMYS (psi) 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.

t≥

4,000 × 16 = 0.684" 2 × 65,000 × 0.72

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. t≥

4,000 × 16 = 0.985" 2 × 65,000 × 0.5

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