Introduction to
Offshore Pipelines and Risers
2008
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 key considerations, general requirements, and terminologies, etc. The author’s nearly twenty years of experience on offshore pipelines along with the enthusiasm to share his knowledge have aided the preparation of this note. Readers are encouraged to refer to the references listed at the end of each section for more information. Unlike other text books, many pictures and illustrations are enclosed in this note to assist the readers’ understanding. It should be noted that some pictures and contents are borrowed from other companies’ websites and brochures, without written permit. Even though the exact sources are quoted and listed in the references, please use this note for engineering education purposes only.
2008 Jaeyoung Lee, P.E. Houston, Texas
[email protected]
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TABLE OF CONTENTS 1
INTRODUCTION .......................................................................................................... 7
2
REGULATIONS AND PIPELINE PERMITS ................................................................ 15
3
DESIGN PROCEDURES AND DESIGN CODES ........................................................ 19
4
PIPELINE ROUTE SELECTION ................................................................................. 31
5
FLOW ASSURANCE .................................................................................................. 39
6
UMBILICALS .............................................................................................................. 43
7
PIPE MATERIAL SELECTION .................................................................................... 49
8
PIPE COATINGS ........................................................................................................ 65
9
PIPE WALL THICKNESS DESIGN ............................................................................. 75
10
THERMAL EXPANSION DESIGN............................................................................... 89
11
PIPELINE ON-BOTTOM STABILITY DESIGN ............................................................ 97
12
PIPELINE FREE SPAN ANALYSIS ........................................................................... 101
13
CATHODIC PROTECTION DESIGN ......................................................................... 109
14
PIPELINE INSTALLATION ........................................................................................ 119
15
SUBSEA TIE-IN METHODS ...................................................................................... 131
16
UNDERWATER WORKS ........................................................................................... 145
17
PIPELINE WELDING ................................................................................................. 147
18
PIPELINE PROTECTION – TRENCHING AND BURIAL ............................................ 153
19
PIPELINE SHORE APPROACH AND HDD ............................................................... 161
20
RISER TYPES ........................................................................................................... 165
21
RISER DESIGNS ...................................................................................................... 169
22
COMMISSIONING, PIGGING, AND INSPECTION .................................................... 175
23
PIPELINE REPAIR .................................................................................................... 185
APPENDIX A..................................................................................................................... 193 APPENDIX B..................................................................................................................... 199
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1
INTRODUCTION Deepwater means water depths greater than 1,000 ft or 305 m by US MMS (Minerals Management Service) definition. Deepwater developments outrun the onshore and shallow water field developments. The reasons are: •
Limited onshore gas/oil sources (reservoirs)
• • •
Relatively larger (~20 times (oil) and 8 times (gas)) offshore reservoirs than onshore More investment cost (>~20 times) but more returns Improved geology survey and E&P technologies
A total of 175,000 km (108,740 mi.) or 4.4 times of the 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 13,212 psi (911 bar) and 333oF (167oC), in 1,066 ft of water. The deepwater exploration and production (E&P) is currently very active in West Africa which occupies approximately 40% of the world E&P (see Figure 1.1). Figure 1.1 Worldwide Deepwater Exploration and Production [1]
North Sea 3%
North America 25%
Africa 40%
Asia 10%
Australasia 2%
Latin America 20%
-8Offshore 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 structure (Christmas tree) and manifold as needed Control system – subsea control module (SCM), umbilical, umbilical termination assembly (UTA), flying leads, sensors Connection system – jumper, pipeline end termination (PLET) Figure 1.1.1 Subsea System
Wellhead (typically 28-in. diameter) is a topside structure of the drilling casing (typically 36-in. diameter) above the mudline, which is used to mount a control panel with valves. The shape of the wellhead structure with valves looks like a pine tree so the wellhead is also called as “Christmas tree”. The manifold is placed to gather productions from multiple wellheads and send the productions using a smaller number of flowlines. The control system includes SCM, umbilical, UTA, flying leads, and sensors. SCM is a retrievable component used to control chokes, valves, and monitor pressure, temperature, position sensing devices, etc. that is mounted on the tree and/or manifold. UTA allows the use of flying leads to control equipment. Flying leads connect UTAs to subsea trees. Sensors include sand detectors, erosion detectors, pig detectors, etc. For details on connection system, please see Subsea Tie-in Methods in Section 15.
- 10 1.2
Flowline/Pipeline/Riser System Oil was transported by wooden barrels until 1870s. As the volume was increased, the product was transported by tank cars or trains and eventually by pipelines. Although oil is sometimes shipped in 55 (US) gallon drums, the measurement of oil in barrels is based on 42 (US) gallon wooden barrels of the 1870s. Flowlines transport unprocessed fluid – crude oil or gas. The conveyed fluid can be a multi-phase fluid possibly with paraffin, asphaltene, and other solids like sand, etc. The flowline is sometimes called a “production line” or “import line”. Most deepwater flowlines carry very high pressure and high temperature (HP/HT) fluid. Pipelines transport processed oil or gas. The conveyed fluid is a single phase fluid after separation from oil, gas, water, and other solids. The pipeline is also called an “export line”. The pipeline has moderately low (ambient) temperature and low pressure just enough to export the fluid to the destination. Generally, the size of the pipeline is greater than the flowline. It is important to distinguish between flowlines and pipelines since the required design code is different. In America, the flowline is called a “DOI line” since flowlines are regulated by the Department of Interior (DOI 30 CFR Part 250: Code of Federal Regulations). And the pipeline is called a “DOT line” since pipelines are regulated by the Department of Transportation (DOT 49 CFR Part 195 for oil and Part 192 for gas). Figure 1.2.1 Flowline/Pipeline/Riser System
Riser
Pipeline
Flowline
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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 a new surface structure.
- 12 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-submersible
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.
- 14 References [1]
SUT (Society for Underwater Technology) Subsea Tieback (SSTB) Workshop, Galveston, Texas, 2007
[2]
2006 Deepwater Solutions & Records for Concept Selection, Offshore Magazine Poster
[3]
www.mms.gov, Minerals Management Service website, U.S. Department of the Interior
[4]
Offshore Engineering - An Introduction, Angus Mather, Witherby & Company Limited, 1995
[5]
Offshore Pipeline Design, Analysis and Methods, Mouselli, A.H., Penn Well Books, 1981
[6]
Offshore Pipelines, Guo, Boyun, et. al, Elsevier, 2005
[7]
Pipelines and Risers, Bai, Y., Elsevier, 2001
[8]
Deepwater Petroleum Exploration and Production, Leffler, W.L., et. al., Penn Well Books, 2003
[9]
Petroleum Production Systems, Economides, Michael, et. al., Prentice Hall Petroleum Engineering Series
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2
REGULATIONS AND PIPELINE PERMITS Prior to conducting drilling operations, the operator is required to submit an Application for Permit to Drill (APD) and obtain approval from the authorities. The APD requires detailed information about the drilling program for evaluation with respect to operational safety and pollution prevention measures. Other information including project layout, design criteria for well control and casing, specifications for blowout preventers, and a mud program is required. The developer must design, fabricate, install, use, inspect, and maintain all platforms and structures to assure their structural integrity for the safe conduct of operations at specific locations. Factors such as waves, wind, currents, tides, temperature, and the potential for marine growth on the structure are to be considered. All surface production facilities including separators, treaters, compressors, and headers must be designed, installed, and maintained to assure the safety and protection of the human, marine, and coastal environments. In the USA, the regulatory processes and jurisdictional authority concerning pipelines on the Outer Continental Shelf (OCS) and in coastal areas are shared by several federal agencies, including the Department of Interior (DOI), the Department of Transportation (DOT), U.S. Army Corps of Engineers (COE), the Federal Energy Regulatory Commission (FERC), and U.S. Coast Guard (USCG) [1]. The DOT is responsible for regulating the safety of interstate commerce of natural gas, liquefied natural gas (LNG), and hazardous liquids by pipeline. The regulations are contained in 49 CFR Part 192 (for gas pipeline) and part 195 (for oil pipeline) (References [2] & [3]). The DOT is responsible for all transportation pipelines beginning downstream of the point at which operating responsibility transfers from a producing operator to a transporting operator. The 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].
- 16 Pipeline permit applications to regulatory authorities include the pipeline location profile drawing, safety schematic drawing, pipe design data to scale, a shallow hazard survey report, and an archaeological report (if required). The proposed pipeline 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.
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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
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 3.1 and 3.2 show a flowchart for preliminary design phase and detail engineering phase, respectively. Design basis is an on-going document to be updated as needed as the project proceeds, especially in conceptual and preliminary design phases. The design basis should contain: • • • • • • • • • • • • •
Pipe Size Design Pressure (@ wellhead or platform deck) Design Temperature Pressure and Temperature Profile Max/Min Water Depth Corrosion Allowance Required overall heat transfer coefficient (OHTC) Value Design Code (ASME, API, or DNV) Installation Method (S, J, Reel, or Tow) Metocean Data Soil Data Design Life, etc. Fluid property (sweet or sour)
- 20 Table 3.1 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
Permit Application
Thermal Expansion
Procurement Long Lead Items
On-bottom Stability
Free Span
Cathodic Protection
Tie-ins and Shore Approach
Installation Check
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Table 3.2 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
- 22 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 Q1
Specification for Quality Programs for the Petroleum, Petrochemical and Natural Gas Industry
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 5C6
Welding Connections to Pipe, 1996
API RP 5L1
Recommended Practice for Railroad Transportation of Line Pipe
API RP 5L5
Recommended Practice for Marine Transportation of Line Pipe
API RP 5LW
Recommended Practice for Transportation of Line Pipe on Barges and Marine Vessels
- 23 -
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 14H
Installation, Maintenance and Repair of Surface Safety Valves and Underwater Safety Valves - Offshore
API RP 14J
Design and Hazards Analysis of Offshore Production Facilities
API RP 17A
Recommended Practice for Design and Operation of Subsea Production Systems – Pipelines and End Connections
API RP 17B
Recommended Practice for Flexible Pipe, 1998
API RP 17D
Specification for Subsea Wellhead and Christmas Tree Equipment, 1996
API RP 17G
Design and Operation of Completion/Workover Riser Systems
API RP 17I
Installation of Subsea Umbilicals
API RP 17J
Specification for Unbonded Flexible Pipe, 1999
API RP 500C
Classification of Locations for Electrical Installation at 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
Steel Plates, Quenched and Tempered, for Offshore Structures
API Spec 5L
Line Pipe
API Spec 6A
Wellhead and Christmas Tree Equipment
API Spec 6D
Pipeline Valves (Gate, Plug, Ball, and Check Valves)
API Spec 6H
End Closures, Connectors and Swivels
API Spec 14A
Subsurface Safety Valve Equipment
API Spec 17E
Subsea Production Control Umbilicals
API Std 1104
Standard for Welding of Pipelines and Related Facilities
- 24 -
American Society of Mechanical Engineers (ASME) ASME B16.5
Pipe Flanges and Flanged Fittings
ASME B16.9
Factory Made Wrought Steel Butt Welding Fittings
ASME B16.10
Face-to-Face and End-to-Ends Dimensions of Valves
ASME B16.11
Forged Steel Fittings, Socket Welding and Threaded
ASME B16.20
Ring Joints, Gaskets and Grooves for Steel Pipe Flanges
ASME B16.25
Butt Welded Ends for Pipes, Valves, Flanges and Fittings
ASME B16.34
Valves - Flanged, Threaded, and Welding End
ASME B16.47
Large Diameter Steel Flanges - NPS 26 through NPS 60
ASME B31.3
Chemical Plant and Petroleum Refinery Piping
ASME B31.4
Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia and Alcohols, 1999
ASME B31.8
Gas Transmission and Distribution Piping Systems, 1999
ASME II
Materials
ASME V
Non-Destructive Examination
ASME VIII, Div 1&2
Rules for Construction of Pressure Vessels
ASME IX
Welding and Brazing Qualifications
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
- 25 -
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 A370
Standard Test Methods and Definitions for Mechanical Testing of Steel Products
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 Bars for Concrete Reinforcement
ASTM A694
Standard Specification for Carbon and Alloy Steel Forgings for Pipe Flanges, Fittings, Valves and Parts for High Pressure Transmission Service
ASTM B418
Cast and Wrought Galvanized Zinc Anodes (Type II)
ASTM E23
Standard Test Methods for Notched Bar Impact Testing of Metallic Materials
ASTM E92
Standard Test Methods for Vickers Hardness of Metallic Materials
ASTM E94
Radiographic Testing
ASTM E747
Test Methods for Controlling Quality of Radiographic Testing Using Wire Penetrometers
ASTM E1290
Standard Test Method for Crack-Tip Opening Displacement (CTOD) Fracture Toughness Measurement
ASTM E1444
Standard Practice for Magnetic Particle Examination
ASTM E1823
Standard Terminology Relating to Fatigue and Fracture Testing, 1996
American Welding Society (AWS) AWS D1.1
Structural Welding Code – Steel
- 26 -
British Standard (BS) BS 4515
Appendix J. Process of Welding of Steel Pipelines on Land and Offshore– Recommendations for Hyperbaric Welding
BS 6899
Insulation Material Tests
BS 7608
Code of Practice for Fatigue Design and Assessment of Steel Structures, 1993
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
- 27 -
DNV-OS-E301
Position Mooring
DNV-OS-E402
Offshore Standard for Diving Systems
DNV-OS-E403
Offshore Loading Buoys
DNV-OS-F101
Submarine Pipeline Systems, 2003
DNV-OS-F107
Pipeline Protection
DNV-OS-F201
Dynamic Risers, 2001
DNV-OSS-301
Certification and Verification of Pipelines
DNV-OSS-302
Offshore Riser Systems
DNV-OSS-306
Verification of Subsea Facilities
DNV-RP-B401
Cathodic Protection Design, 1993
DNV-RP-C201
Buckling Strength of Plated Structure
DNV-RP-C202
Buckling Strength of Shells
DNV-RP-C203
Fatigue Strength Analysis of Offshore Steel Structures
DNV-RP-C204
Design against Accidental Loads
DNV-RP-E301
Design and Installation of Fluke Anchors in Clay
DNV-RP-E302
Design and Installation of Plate Anchors in Clay
DNV-RP-E303
Geotechnical Design and Installation of Suction Anchors in Clay
DNV-RP-E304
Damage Assessment of Fibre Ropes for Offshore 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-F110
Global Buckling of Submarine Pipelines Structural Design due to High Temperature/High Pressure, 2007
DNV-RP-F111
Interference between Trawl Gear and Pipe-lines
DNV-RP-F202
Composite Risers
- 28 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
DNV-RP-H102
Marine Operations during Removal of Offshore Installations
DNV-RP-O401
Safety and Reliability of Subsea Systems
DNV-RP-O501
Erosive Wear in Piping Systems
International Organization for Standardization (ISO) ISO-9001
Quality Assurance Standard
IOS-13628
Petroleum and Natural Gas Industries Design and Operation of Subsea Production Systems
IOS-13628-1
Subsea Production Systems
IOS-13628-2
Subsea Flexible Pipe Systems
IOS-13628-4
Subsea Wellhead & Christmas Trees
IOS-13628-6
Subsea Production Control Systems
IOS-13628-8
Remotely Operated Vehicle (ROV) Interfaces on Subsea Production Systems
IOS-13628-9
Remotely Operated Tool (ROT) Intervention Systems
IOS-14000
Environmental Management System
ISO-15589-2
Cathodic Protection of Pipeline Transportation Systems - Part 2: Offshore Pipelines, 2004, International Organization for Standardization
ISO-15590
Induction Bends
- 29 -
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 MR-01-75
Sulfide Stress Corrosion Cracking
NACE RP-01-76-94
Corrosion Control of Steel Fixed Offshore Platforms Associated with Petroleum Production, 1994
NACE RP-0387
Metallurgical and Inspection Requirement for Cast Sacrificial Anodes for Offshore Applications
NACE RP-0394
Application, Performance and Quality Control of Plant-Applied, Fusion-Bonded Epoxy External Pipe Coating
NACE RP-0492
Metallurgical and Inspection Requirements for Offshore Pipeline Bracelet Anodes
Nobel Denton Industries (NDI) NDI-0013
General Guidelines for Marine Loadouts
NDI-0027
Guidelines for Lifting Operations by Floating Crane Vessels
NDI-0030
General Guidelines for Marine Transportations
NORSOK Standards NORSOK G-001
Marine Soil Investigations
NORSOK L-005
Compact Flanged Connections
NORSOK M-501
Surface Preparation and Protective Coating
NORSOK M-506
Corrosion Rate Calculation Model
NORSOK N-001
Structural Design
NORSOK N-004
Design of Steel Structures
NORSOK U-001
Subsea Production Systems
NORSOK UCR-001
Subsea Structures and Piping Systems
NORSOK UCR-006
Subsea Production Control Umbilicals
- 30 Miscellaneous TPA IBS-98
Recommended Standards for Induction Bending of Pipe and Tube, 1998, Tube & Pipe Association (TPA)
ASNT-TC-1A
Personnel Qualification and Certification in Non-Destructive Testing, American Society of Nondestructive Testing
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4
PIPELINE ROUTE SELECTION When layout the field architecture, several considerations should be accounted for: • • • • • •
Compliance with regulation authorities and design codes Future field development plan Environment, marine activities, and installation method (vessel availability) Overall project cost Seafloor topography Interface with existing subsea structures
The pipeline route should be selected considering: • • • • • • • • • •
Low cost (select the most direct and shortest P/L route) Seabed topography (faults, outcrops, slopes, etc.) Obstructions, debris, existing pipelines or structures Environmentally sensitive areas (beach, oyster field, etc.) Marine activity in the area such as fishing or shipping Installability (1st end initiation and 2nd end termination) Required pipeline route curvature radius Riser hang-off location at surface structure Riser corridor/clashing issues with existing risers Tie-in methods
The required minimum pipeline route curve radius (Rs) should be determined to prevent slippage of the curved pipeline on the sea floor while making a curve, in accordance with the following formula [1]. If the pipeline-soil friction resistance is too small, the pipeline will spring-back to straight line. The formula also can be used to estimate the required minimum straight pipeline length (Ls), before making a curve, to prevent slippage at initiation. If 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)
- 32 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 s (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.
- 33 -
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 4.1). Figure 4.1 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 anchor scars, pipelines, etc. Typically objects larger than 1m are accurately located and measured (see Figure 4.2).
Figure 4.2 Side Scan Sonar Interpretation [2]
- 34 An acoustic sub-bottom profiler is a tool to measure geological characteristics i.e. subsurface strata (stratigraphy), faults, sediment thickness, etc. Figure 4.3 shows one example of sub-bottom profile and its interpretation.
Figure 4.3 Sub-bottom Profile [2]
Magnetometer (Figure 4.4) 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 4.4 Geometrics G-882 Magnetometer [3]
- 35 -
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 4.5 and 3.6 show drop corer and Torvane shear test kit.
Figure 4.5 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
- 36 Figure 4.6 Torvane Shear Test Kit [5]
Environmental (metocean) data including wind, waves, and current along the water depth for 1, 5 (2 or 10), and 100 year return periods are required.
- 37 -
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
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5
FLOW ASSURANCE Flow assurance is required to determine the optimum flowline pipe size based on reservoir well fluid test results for the required flowrate and pressure. As the pipe size increases, the arrival pressure and temperature decrease. Then, the fluid may not reach the destination and hydrate, wax, and asphaltene may be formed in the flowline. If the pipe size is too small, the arrival pressure and temperature may be too high and resultantly a thick wall pipe may be required and a large thermal expansion is expected. It is important to determine the optimum pipe size to avoid erosional velocity and hydrate/ wax/asphaltene deposition. Based on the hydrate/wax/asphaltene appearance temperature, the required OHTC is determined to choose a desired insulation system (type, material, and thickness.) If the flowline is to transport a sour fluid containing H2S, CO2, etc., the line should be chemically treated or a special corrosion resistant alloy (CRA) pipe material should be used. Alternatively, a corrosion allowance can be added to the required pipe wall thickness. Capital expense (Capex) and operational expense (opex) using CRA, chemical injection, corrosion allowance, or combination of the above should be exercised to determine the pipe material and wall thickness. Figure 5.1 shows various plugged flowlines due to asphaltene, wax, and hydrate deposition.
Figure 5.1 Plugged Flowlines
(a) Asphaltene
(b) Wax
(c) Hydrate
- 40 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)
300 250
40 30
Pressure (bar)
200
20
150 8” ID 100 150
50
12” ID
10” ID
10 0
170
190
210
230
250
270
290
Flowline ID (mm)
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
310
- 41 -
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 [9] Steven Cochran, “Details of Hydrate Management in Deepwater Subsea Gas Developments,” Deep Offshore Technology (DOT) International Conference and Exhibition, 2006 [10] Roald Sirevaag, “Experience with HPHT Subsea HIPPS on Kristin,” DOT 2006
- 42 -
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6
UMBILICALS Umbilicals (Figure 6.1) are used to supply electric/hydraulic power to subsea valves/ actuators, receive communication signal from subsea control system, and send chemicals to treat subsea wells. The functions of umbilicals can be: • • • • • •
Chemical Injection Electric Hydraulic Electric Power Hydraulic Communications Scale Squeeze
From flow assurance analysis, the type, quantity, and size of each umbilical tube are determined. Most commonly used chemicals are: scale inhibitor, hydrate inhibitor, paraffin inhibitor, asphaltene inhibitor, corrosion inhibitor, etc. The umbilical terminates at subsea umbilical termination assembly (SUTA) and each function hose or cable connects to manifold or tree by flexible flying leads. Umbilical manufacturers include: DUCO (formerly Dunlop Coflexip, now a Technip company), Oceaneering Multiplex, Aker Kvaener, Nexans (formerly Alcatel), JDR, etc. Figure 6.2 shows Oceaneering’s Panama City plant and Figure 6.3 shows UTA installation.
Figure 6.1 Umbilical Lines [1]
- 44 Figure 6.2 Oceaneering Umbilical Plant [2]
- 45 -
Figure 6.3 UTA (Umbilical Termination Assembly) Installation [3]
- 46 -
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]
- 47 -
References [1]
Offshore-Technology.com website, www.offshore-technology.com
[2]
Oceaneering International, Inc. website, www.oceaneering.com
[3]
Nexen Aspen Project, presented at Houston Marine Technology Society luncheon meeting, 2007, www.mtshouston.org
[4]
Dunlaw Engineering Ltd. website, http://www.dunlaw.com/bend_limiters.html
[5]
Trelleborg CRP website, http://www.crpgroup.com/engineered_products.htm
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7
PIPE MATERIAL SELECTION Pipe material type, i.e. rigid, flexible, or composite, should be determined considering: •
Conveyed fluid properties (sweet or sour) and temperature
•
Pipe material cost
•
Installation cost
•
Operational cost (chemical treatment)
There are several different pipes used in offshore oil & gas transportation as follows:
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 the method of measuring the maximum hardness and weldability of the steel based on chemical composition of the steel. Higher C (carbon) and other alloy elements such as Mn (manganese), Cr (chrome), Mo (molybdenum), V (vanadium), Ni (nickel), Cu (copper), etc. tend to increase the hardness (harder and stronger) but decrease the weldability (less ductile and difficult to weld). The CE shall not exceed 0.43% of total components, per API-5L [1], as expressed below.
CE(IIW) = C +
Mn Cr + Mo + V Ni + Cu + + ≤ 0.43% 6 5 15
(note: IIW = International Institute of Welding) Pipes are graded per their tensile properties. Grade X-65 means that SMYS (specified minimum yield strength) of the pipe is 65 ksi (see Table 7.1.1). The API-5L line pipe specification defines two different product specification levels, PSL 1 and PSL 2. PSL 2 is commonly used for weld joint connections (see Table 7.1.2).
- 50 Table 7.1.1 Tensile Requirements for API-5L PSL 2 Pipe
Table 7.1.2 API-5L PSL 1 vs. PSL 2
- 51 -
The yield strength is defined as the tensile stress when 0.5% elongation occurs on the pipe, per API-5L. The DNV code [2] defines the yield stress as the stress at which the total strain is 0.5%, corresponding to an elastic strain of approximately 0.2% and a plastic (or residual) strain of 0.3%, as shown in Figure 7.1.1. Figure 7.1.1 Yield Stress Stress
SMYS
0.5 % 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.
- 52 Line pipe is usually specified by Nominal Pipe Size (NPS) and schedule (SCH). The most commonly used schedules are 40 (STD), 80 (XS), and 160 (XXS) (see Tables 7.1.3 and 7.1.4). Table 7.1.3 Pipe Schedules OD NPS (inches)
Wall Thickness (inches) SCH 10s
SCH 10
SCH 20
SCH 30
SCH 40s
SCH 40
SCH 60
SCH 80s
SCH 80
SCH 100
SCH 120
SCH 140
SCH 160
10
10.75
.165
.165
.250
.307
.365
.365
.500
.500
.593
.718
.843
1.000
1.125
12
12.75
.180
.180
.250
.330
.375
.406
.500
.500
.687
.843
1.000 1.125
1.312
14
14.00
.188
.250
.312
.375
.375
.437
.593
.500
.750
.937
1.093 1.250
1.406
16
16.00
.188
.250
.312
.375
.375
.500
.656
.500
.843
1.031 1.218 1.437
1.593
18
18.00
.188
.250
.312
.437
.375
.562
.750
.500
.937
1.156 1.375 1.562
1.781
20
20.00
.218
.250
.375
.500
.375
.593
.812
.500
1.031 1.280 1.500 1.750
1.968
24
24.00
.250
.250
.375
.562
.375
.687
.968
.500
1.218 1.531 1.812 2.062
2.343
SCH 80s = 80 ksi SMYS stainless steel
- 53 Table 7.1.4 API-5L Standard Pipe Wall Thickness Pipe Wall Thickness
NPS
OD
(inch)
(inch)
4
4
0.250
0.281
0.318
4.5
4.5
0.337
0.438
0.531
0.674
5
5.563
0.375
0.500
0.625
0.750
6
6.625
0.375
0.432
0.500
0.562
0.625
0.719
0.750
0.864
0.875
8
8.625
0.375
0.438
0.438
0.500
0.562
0.625
0.719
0.750
0.812
0.875
1.000
10
10.75
0.365
0.438
0.438
0.500
0.562
0.625
0.719
0.812
0.875
0.938
1.000
1.250
12
12.75
0.375
0.406
0.438
0.500
0.562
0.625
0.688
0.750
0.812
0.875
0.938
1.000
1.062
1.125
1.250
14
14
0.375
0.406
0.438
0.469
0.500
0.562
0.625
0.688
0.750
0.812
0.875
0.938
1.000
1.062
1.125
1.250
16
16
0.375
0.406
0.438
0.469
0.500
0.562
0.625
0.688
0.750
0.812
0.875
0.938
1.000
1.062
1.125
1.188
1.250
18
18
0.375
0.406
0.438
0.469
0.500
0.562
0.625
0.688
0.750
0.812
0.875
0.938
1.000
1.062
1.125
1.188
1.250
20
20
0.438
0.469
0.500
0.562
0.625
0.688
0.750
0.812
0.875
0.938
1.000
1.062
1.125
1.188
1.250
1.312
1.375
22
22
0.500
0.562
0.625
0.688
0.750
0.812
0.875
0.938
1.000
1.062
1.125
1.188
1.250
1.312
1.375
1.438
1.500
24
24
0.562
0.625
0.688
0.750
0.812
0.875
0.938
1.000
1.062
1.125
1.188
1.250
1.312
1.375
1.438
1.500
1.562
26
26
0.562
0.625
0.688
0.750
0.812
0.875
0.938
1.000
28
28
0.562
0.625
0.688
0.750
0.812
0.875
0.938
1.000
30
30
0.562
0.625
0.688
0.750
0.812
0.875
0.938
1.000
1.062
1.125
1.188
1.250
32
32
0.562
0.625
0.688
0.750
0.812
0.875
0.938
1.000
1.062
1.125
1.188
1.250
34
34
0.562
0.625
0.688
0.750
0.812
0.875
0.938
1.000
1.062
1.125
1.188
1.250
36
36
0.562
0.625
0.688
0.750
0.812
0.875
0.938
1.000
1.062
1.125
1.188
1.250
38
38
0.562
0.625
0.688
0.750
0.812
0.875
0.938
1.000
1.062
1.125
1.188
1.250
40
40
0.562
0.625
0.688
0.750
0.812
0.875
0.938
1.000
1.062
1.125
1.188
1.250
42
42
0.562
0.625
0.688
0.750
0.812
0.875
0.938
1.000
1.062
1.125
1.188
1.250
44
44
0.562
0.625
0.688
0.750
0.812
0.875
0.938
1.000
1.062
1.125
1.188
1.250
46
46
0.562
0.625
0.688
0.750
0.812
0.875
0.938
1.000
1.062
1.125
1.188
1.250
(inch)
- 54 Depending on pipe manufacturing process, there are several pipe types as: • • •
Seamless pipe UOE pipe or DSAW (double submerged arc welding) pipe ERW (electric resistant welding) pipe
Seamless pipe is made by piercing the hot steel rod, without longitudinal welds. It is most expensive but ideal for small diameter, deepwater, or dynamic applications. Currently up to 24” OD pipe can be fabricated by manufacturers. UOE pipe is made by folding a steel panel with “U” press, “O” press, and expansion (to obtain its final OD dimension). The longitudinal seam is welded by double (inside and outside) submerged arc welding. UOE pipe is produced in sizes from 18" through 80" OD and wall thicknesses from 0.25" through 1.50". (UOE pipe is made by DSAW Technique but spiral formed pipe can be welded by DSAW technique, so DSAW pipe is not necessarily UOE pipe.) ERW pipe (produced in sizes from 16” OD to 26” OD) is cheaper than seamless or DSAW pipe but it has not been widely adopted by offshore industry, especially for sour or high pressure gas service, due to its variable electrical contact and inadequate forging upset. However, development of high frequency induction (HFI) welding enables to produce better quality ERW pipes. Figure 7.1.2 shows pipe types by manufacturing process.
- 55 -
Figure 7.1.2 Pipe Types by Manufacturing Process
(a) Seamless pipe
(b) UOE pipe
U-forming
(c) Continuous ERW pipe
O-forming
Expansion
- 56 7.2
CRA (Corrosion resistant alloy) Pipe
Depending on alloy contents, CRA pipe can be broken into follows: • Stainless steel: • Chrome based alloy:
316L, 625 (Inconel), 825, 904L, etc. 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) 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.
• Titanium:
• 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 Mpa)
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)
- 57 -
Depending on sour contents in the fluid, different chrome based alloy pipe should be selected per Table 7.2.2. Table 7.2.2 Chrome Based Alloy Pipe Selection for Sour Service
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.
- 58 Figure 7.5.1 Flexible Pipe Manufacturing Limit Design Pressure (psi)
1400 1200
API 17J Design Limit
1000 0 800 600
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.)
- 59 -
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]
- 60 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 & Marine, Bridgestone, GoodYear, Phoenix Rubber Industrial (formerly Taurus), etc. Figure 7.6.2 shows some pictures of flexible hose applications and factory flexibility test.
- 61 -
Figure 7.6.2 Pictures of Flexible Hose Applications and Factory Flexibility Test
(Source: www.dunlop-oil-marine.co.uk [6])
(Source: www.bridgestone.co.jp [7])
- 62 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 at just above the blowout preventer
Some benefits of CT applications are: safe and efficient live well intervention, rapid mobilization and rig-up resulting in less production downtime, and reduced crew/personnel requirements, etc. CT technology can be used for: • Well Unloading • Cleanouts • Acidizing/Stimulation • Velocity Strings • Fishing • • •
• • • •
Tool Conveyance Well Logging (real-time & memory) Setting/Retrieving Plugs CT Drilling Fracturing Deeper Wells Pipeline/Flowline, etc.
The coiled tubing manufacturers include Quality Tubing, Inc. (QTI) and Tenaris (formerly Precision Tube Technology and Maverick Tube), etc. Figure 7.7.1 shows a CT operation at onshore wellhead.
- 63 -
Figure 7.7.1 Coiled Tubing Operation [9]
CT String Injector Head Stripper
- 64 References [1] API 5L, Specification for Line Pipe, Section 6.2.1, American Petroleum Institute, 2004 [2]
DNV-OS-F101, Submarine Pipeline Systems, 2003, Sec. 5, C405
[3]
Technip USA Flexible Pipe Presentation
[4]
NKT Flexibles Website, www.NKTflexibles.com
[5]
DeepFlex Website, www.DeepFlex.com
[6]
Dunlop Oil Marine Website, www.dunlop-oil-marine.co.uk
[7]
Bridgestone Website, www.bridgestone.co.jp
[8]
“An Introduction to Coiled Tubing – History, Applications, and Benefits”, International Coiled Tubing Association (ICTA), 2005
[9]
http://commservices.ssss.com/Literature/documents/ STEWARTANDSTEVENSONCTU.pdf
[10] Farouk A. Kenawy and Wael F. Ellaithy, Case History in Coiled Tubing Pipeline, OTC (Offshore Technology Conference) Paper No. 10714, 1999 [11] Tim Crome, et. al., “Smoothbore Flexible Risers for Gas Export,” OTC Paper #18703, 2007 [12] Mikhail Gelfgat, “New Prospects in Development of Aluminum Alloy Marine Risers,” Deep Offshore Technology (DOT) International Conference and Exhibition, 2006 [13] Freddy Paulsen, “Use of Composite Materials for the Protection of Subsea Structures and Pipelines in Deepwater,” DOT 2006
- 65 -
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
- 66 8.2
Insulation Coating
To keep the conveyed fluid warm, the pipeline should be heated by active or passive methods. The active heating methods include, electric heat tracing wires wrapped around the pipeline, circulating hot water through the annulus of pipe-in-pipe, etc. The passive heating method is insulation coating, burial, covering, etc. Glass syntactic polyurethane (GSPU), PU foam, and syntactic foam are the commonly used subsea insulation materials (see Figure 8.2.1). Although these insulation materials are covered (jacketed) with HDPE, they are compressed due to hydrostatic head and migrated by water as time passes, so it is called a “wet insulation”. Figure 8.2.1 GSPU (left) and Syntactic Foam Insulation (right)
OHTC or U value is used to represent the 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.
- 67 -
The OHTC or U value can be obtained using the formula below:
U=
1 r r 1 1 r1 r2 r1 r3 r + ln + ln + L + 1 ln m + 1 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” 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. 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)
- 68 8.3
Pipe-in-Pipe Another pipe insulation method is pipe-in-pipe (PIP) which an inner pipe is covered by a larger outer pipe (Figure 8.3.1). The annuls between inner pipe and outer pipe are filled with insulation materials including: micro-porous silica (Aerogel), polyurethane foam (PUF), Wacker/Porextherm, Mineral wool, etc.
Figure 8.3.1 PIP
Aerogel •
Microporous silica with a pore size of 10-9m.
•
Best K value 0.0139 W/m-oK at 50oC.
•
The density is 0.11 SG.
•
Developed for the reeling process and many track records exist.
•
Requires centralizers with a spacing of every 2m or so.
•
Cheaper than Wacker/Porextherm product.
PUF •
2nd cheapest form of insulation.
•
2nd poorest K-value (0.029 W/m-oK at 50oC) of all insulation materials but used extensively for S/J-lay projects, normally without centralizers.
•
Densities are in the range of 0.07 - 0.12 SG.
•
Use with reel-lay has been limited due to potential damage (compression and crack) during reeling.
- 69 -
Wacker/Porextherm • •
Fumed microporous silica with a pore size of 10-6m. Porextherm. Most expensive thermal insulation product.
•
Good K-value (0.0195 W/m-oK at 50oC).
•
Standard density is 0.19 SG.
•
Developed for the reeling process and many track records exist.
•
Requires centralizers with a spacing of every 2m or so.
Wacker is purchased by
Mineral Wool •
Cheapest form of insulation.
•
Poorest K-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
- 70 Water stops (see Figure 8.3.3) are installed to limit the pipeline length damaged in the event that the annulus is flooded due to pipeline failure or puncture. Considering low fabrication cost and low heat loss, it is recommended to install one or two water 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]
- 71 -
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
The PIP can be used for cold products such as LPG (liquefied petroleum gas) and LNG (liquefied natural gas) to keep the product as cold as possible. For example, LNG flows at -256°F (-160°C), and the LNG pipelines need to be kept below a certain temperature and above a certain pressure to prevent vapor generation. The LNG is commonly transported from ship carrier (LNG tanker) to onshore facility via thick insulated pipelines installed on a jetty. Dredging may be required along the ship channel to facilitate vessel access to the jetty. To control the pipeline contraction due to cold product temperature, frequent expansion loops are also required. Recently, many subsea LNG pipelines are under development. The advantages of subsea LNG pipelines include: increase security due to pipeline buried under the low cost of jetty construction and dredging, no expansion loops, no insulation coating damage, and sound control of thermal cyclic fatigue, etc. Some challenges of subsea cryogenic LNG pipelines are: effective insulation system (vaccum, Nanogel, Aerogel, IzoFlex, etc.) and special cryogenic materials for pipe, forgings, and welding consumables. Either 36% nickel alloy (Invar) or 9% nickel alloy is typically used for the inner pipe of the cryogenic LNG pipelines [3]. A triple PIP (pipe-in-pipe-in-pipe) system is introduced by ITP (InTerPipe) to transport LNG through subsea [7].
- 72 8.4
Concrete Weight Coating Concrete weight coating (Figure 8.4.1) is applied to make the pipe stable under the water. One inch is the minimum concrete coating thickness that fabricator can put on. It should be evaluated if concrete coating is the most cost effective option to increase pipe weight. Increasing the pipe wall thickness may be more efficient considering pipe transportation and project management cost for the concrete weight coating.
Figure 8.4.1 Concrete Weight Coating [4]
The polyethylene outer wrap in the above picture is removed after the concrete coating is cured. Each pipe end is left without concrete coating for welding and welding inspection. No coating is applied near the pipe end for automatic welding and automatic ultrasonic test (AUT), as indicated in Figure 8.4.2. The concrete coating stop distance from the pipe end is also called concrete cut-back length.
Figure 8.4.2 Coating Cut-Back Length (Lengths shown below are for reference use only and can vary by contractor and project.) Bare Steel
FBE
6”
15”
Concrete
- 73 -
8.5
Field Joint Coating After the field weld is made, each pipe joint should be coated with a corrosion resistant coating. The field joint coating (FJC) can be done by FBE, heat shrink sleeve, or PU foam (for concrete coated pipe). Figure 8.5.1 presents one example of field joint coating for insulation coated pipes.
Figure 8.5.1 Field Joint Coating [5]
- 74 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]
Tom Phalen, C. Neal Prescott, Jeff Zhang, and Tony Findlay, “Update on Subsea LNG Pipeline Technology,” OTC (Offshore Technology Conference) paper No. 18542, 2007
[4]
Bayou Companies website, http://www.bayoucompanies.com
[5]
Pipeline Induction Heat website, http://www.pih.co.uk
[6]
M. Delafkaran and D.H. Demetriou, “Design and Analysis of High Temperature, Thermally Insulated, Pipe-in-Pipe Risers,” OTC (Offshore Technology Conference) paper No. 8543, 1997
[7]
ITP website, http://www.itp-interpipe.com/
- 75 -
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)
- 76 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
