Introduction to
Offshore Pipelines and Risers
2008
Introduction to Offshore Pipelines and Risers
PREFACE
This lecture note is prepared to introduce how to design and install offshore petroleum pipelines and risers including 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]
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
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 America 25% Latin America 20% Australasia 2% Asia 10% Africa 40% North Sea 3%
Offshore field development normally requires four elements as below and as shown in Figure 1.2. Each element (system) is briefly described in the following sub-sections.
• Subsea System
• Flowline/Pipeline/Riser System • Fixed/Floating Structures • Topside Processing System
Figure 1.2 Offshore Field Development Components
If the wellhead is located on the seafloor, it is called a wet tree; if the wellhead is located on the surface structure, it is called a dry tree. Wet trees are commonly used for subsea tiebacks using long flowlines to save cycle time (sanction to first production). Dry trees are useful for top tension risers (TTRs) or fixed platform risers and provide reliable well control system, low workover cost, and better maintenance.
FL/PL/Riser Subsea
Processing
Fixed/Floating Structures
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.
1.2 Flowline/Pipeline/Riser System
Oil was transported by wooden barrels until 1870s. As the volume was increased, the product was transported by tank cars or trains and eventually by pipelines. Although oil is sometimes shipped in 55 (US) gallon drums, the measurement of oil in barrels is based on 42 (US) gallon wooden barrels of the 1870s.
Flowlines transport unprocessed fluid – crude oil or gas. The conveyed fluid can be a multi-phase fluid possibly with paraffin, asphaltene, and other solids like sand, etc. The flowline is sometimes called a “production line” or “import line”. Most deepwater
flowlines carry very high pressure and high temperature (HP/HT) fluid.
Pipelines transport processed oil or gas. The conveyed fluid is a single phase fluid after separation from oil, gas, water, and other solids. The pipeline is also called an “export line”. The pipeline has moderately low (ambient) temperature and low pressure just enough to export the fluid to the destination. Generally, the size of the pipeline is greater than the flowline.
It is important to distinguish between flowlines and pipelines since the required design code is different. In America, the flowline is called a “DOI line” since flowlines are regulated by the Department of Interior (DOI 30 CFR Part 250: Code of Federal
Regulations). And the pipeline is called a “DOT line” since pipelines are regulated by the Department of Transportation (DOT 49 CFR Part 195 for oil and Part 192 for gas).
Figure 1.2.1 Flowline/Pipeline/Riser System
Flowline Pipeline
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.
Table 1.3.1 Number of Surface Structures Worldwide [2]
Structure Types No. of
Structures Water Depths (ft) Fixed Platforms (WD>1,000’) ~6,000 40 - 1,353 Compliant Towers 4 1,000 – 1,754 TLPs 23 482 - 4,674 Spars 16 1,950 - 5,610 Semi-FPSs (Semi-submersibles) 43 262 – 7,920 FPSOs 148 66 – 4,796 Subsea Tiebacks 3,622 49 – 7,600
Figure 1.3.1 Fixed & Floating Structures [3]
Fixed Platform Compliant Tower
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.
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
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].
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 8-5/8 inches installed in water depths less than 200 ft are to be buried to a depth of at least 3 ft below the mudline. If the MMS determines that the pipeline may constitute a hazard to other uses, all pipelines (regardless of pipe size) installed in water depths less than 200 ft must be buried. The purpose of these requirements is to reduce the movement of pipelines by high currents and storms, to protect the pipeline from the external damage that could result from anchors and fishing gear, to reduce the risk of fishing gear becoming snagged, and to minimize interference with the operations of other users of the OCS. For pipe sizes less than 8-5/8 inches, the burial requirement may be waived if the line is to be laid on a soft soil which will allow the pipeline to sink into the sediments (self-burial). Any pipeline crossing a fairway or anchorage in federal waters must be buried to a minimum depth of 10 ft below mudline across a fairway and a minimum depth of 16 ft below mudline across an anchorage area.
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
3 DESIGN PROCEDURES AND DESIGN CODES
There are typically three phases in offshore pipeline designs: conceptual study (or Pre-FEED: front end engineering & design), preliminary design (or FEED), and detail engineering.
• Conceptual study (Pre-FEED) – defines technical feasibility, system constraints, required information for design and construction, rough schedule and cost estimate • Preliminary design (FEED) – defines pipe size and grade to order pipes and
prepares permit applications.
• Detail engineering – defines detail technical input to prepare procurement and construction tendering.
The pipeline design procedures may vary depending on the design phases above. Tables 3.1 and 3.2 show a flowchart for preliminary design phase and detail engineering phase, respectively.
Design basis is an on-going document to be updated as needed as the project proceeds, especially in conceptual and preliminary design phases. The design basis should
contain:
• Pipe Size
• Design Pressure (@ wellhead or platform deck) • Design Temperature
• Pressure and Temperature Profile • Max/Min Water Depth
• Corrosion Allowance
• Required overall heat transfer coefficient (OHTC) Value • Design Code (ASME, API, or DNV)
• Installation Method (S, J, Reel, or Tow) • Metocean Data
• Soil Data • Design Life, etc.
Table 3.1 Preliminary Design (FEED) Flowchart Scope of Work Design Basis Hazard Survey Flow Assurance Permit Application Route Selection Pipe Material Selection Pipe WT Determination Pipe Coating Selection Thermal Expansion On-bottom Stability Free Span Cathodic Protection Installation Check Tie-ins and Shore
Approach Preliminary Cost Estimate Preliminary Design Drawings Procurement Long Lead Items
Table 3.2 Detail Engineering Flowchart Scope of Work Design Basis Route Survey Flow Assurance Route Selection Metallurgy & Welding Study Pipe WT and Grade Check Pipe Coating Selection Thermal Expansion On-bottom Stability Free Span Cathodic Protection Installation Check Tie-ins and Shore
Approach Material/Construction Specifications Construction Drawings Procurement & Construction Support
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
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
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
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)
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-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-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
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
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
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.
µ W T F L R s H s s = = Where,
Rs = Min. non-slippage pipeline route curve radius Ls = Min. non-slippage straight pipeline length F = Safety factor (~2.0)
TH = Horizontal bottom tension (residual tension) Ws = Pipe submerged weight
If a 16” OD x 0.684” WT pipe is installed in 3,000 ft of water depth using a J-lay method (assuming a catenary shape), the bottom tension and the Rs and Ls can be estimated as follows:
The submerged pipe weight, Ws = 22.6 lb/ft
Assuming the pipe departure angle (α) at J-lay tower as10 degrees
Top tension, T = Ws x WD / (1- sin α) = 22.6 x 3,000 / (1- sin 10) = 82,047 lb ∼ 82 kips Bottom tension, TH = T x sin α = 82 x sin 10 = 14.2 kips
ft 3,000 minimum Use ft 2,513 0.5 22.6 1,000 14.2 2.0 µ W T F L R s H s s = ∴ × × × = = =
If the curvature angle (α) and the pipe rigidity (elastic stiffness = elastic modulus (E) x pipe moment of inertia (I)) are considered to do a big role on the Rs and Ls estimates, the above formula can be modified as follows:
) cos -(1 R I E µ W T F L R 2 s s H s s α + = =
Once the field layout and pipeline route is determined by desktop study using an existing field map, the pipeline route survey is contracted to obtain site-specific information including bathymetry, seabed characteristics, soil properties, stratigraphy, geohazards, and environmental data.
Rs Ls Lay direction Initiation point α
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
Side scan sonar is the industry standard method of providing high resolution mapping of the seabed. It uses narrow beams of acoustic energy (sound) which is transmitted out to the seabed topography (or objects within the water column) and reflected back to the towfish. It is used to identify obstructions, outcrops, faults, debris, pockmarks, gas anchor scars, pipelines, etc. Typically objects larger than 1m are accurately located and measured (see Figure 4.2).
Figure 4.2
Side Scan Sonar Interpretation [2]
2D View
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.
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]
Weights (400-800 lbs) Wireline to surface Release mechanism Core catcher Weight triggering release mechanism on hitting seafloor Barrel (10-20 ft)
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.
References
[1] Pipeline Manual, Chevron, 1994
[2] EGS Survey Website, http://egssurvey.com/enter_ser.htm
[3] Geometrics Website, http://geometrics.com/magnetometers/Marine/G-882/g-882.html
[4] Submarine Pipeline On-bottom Stability Analysis and Design Guidelines, AGA, 1993
[5] Earth Manual, U.S. Department of the Interior, 1998, or http://www.usbr.gov/pmts/writing/earth/earth.pdf
[6] Simon A. Bonnel, et. al., Pipeline Routing and Engineering for Ultra-Deepwater Developments, OTC (Offshore Technology Conference) Paper No. 10708, 1999
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
Figure 5.2 illustrates one example of how to select pipe size from flow assurance results. The blue solid line represents inlet pressure at wellhead and the red dotted line
represents outlet fluid temperature. The 8” ID pipe may require a heavy (thick) wall and the 12” ID pipe may require a thick insulation coating depending on hydrate (wax or asphaltene) formation temperature.
Figure 5.2 Inlet Pressure & Outlet Temperature vs. Flowline ID
100 150 200 250 300 350 400 450 150 170 190 210 230 250 270 290 310 Flowline ID (mm) 0 10 20 30 40 50 60 70 Pressure (bar) Temperature(oC) 8” ID 10” ID 12” ID
Standard Temperature and Pressure (STP)
Science: 0oC (273.15oK) and 1 bar (100 kPa)
Oil & Gas Industry: 60oF (15.6oC) and 14.73 psia (30” Ag or 1.0156 bar) 1 bar = 14.504 psi
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
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]
Figure 6.2 Oceaneering Umbilical Plant [2]
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]
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
7 PIPE MATERIAL SELECTION
Pipe material type, i.e. rigid, flexible, or composite, should be determined considering:
• Conveyed fluid properties (sweet or sour) and temperature • Pipe material cost
• Installation cost
• Operational cost (chemical treatment)
There are several different pipes used in offshore oil & gas transportation as follows:
• Low carbon steel pipe
• Corrosion resistant alloy (CRA) pipe • Clad pipe
• Composite pipe • Flexible pipe • Flexible hose • Coiled tubing
7.1 Low Carbon Steel Pipe
Low carbon (carbon content less than 0.29%) steel is mild and has a relatively low tensile strength so it is used to make pipes. Medium or high carbon (carbon content greater than 0.3%) steel is strong and has a good wear resistance so they are used to make forging, automotive parts, springs, wires, etc. Carbon equivalent (CE) refers to the method of measuring the maximum hardness and weldability of the steel based on chemical composition of the steel. Higher C (carbon) and other alloy elements such as Mn (manganese), Cr (chrome), Mo (molybdenum), V (vanadium), Ni (nickel), Cu (copper), etc. tend to increase the hardness (harder and stronger) but decrease the weldability (less ductile and difficult to weld). The CE shall not exceed 0.43% of total components, per API-5L [1], as expressed below.
0.43% 15 Cu Ni 5 V Mo Cr 6 Mn C CE(IIW)= + + + + + + ≤
(note: IIW = International Institute of Welding)
Pipes are graded per their tensile properties. Grade X-65 means that SMYS (specified minimum yield strength) of the pipe is 65 ksi (see Table 7.1.1). The API-5L line pipe specification defines two different product specification levels, PSL 1 and PSL 2. PSL 2 is commonly used for weld joint connections (see Table 7.1.2).
Table 7.1.1 Tensile Requirements for API-5L PSL 2 Pipe
The yield strength is defined as the tensile stress when 0.5% elongation occurs on the pipe, per API-5L. The DNV code [2] defines the yield stress as the stress at which the total strain is 0.5%, corresponding to an elastic strain of approximately 0.2% and a plastic (or residual) strain of 0.3%, as shown in Figure 7.1.1.
Figure 7.1.1 Yield Stress
In elastic region, when the load is removed, the pipe tends to go back to its origin. If the load exceeds the elastic limit, the pipe does not go back to its origin when the load is removed. Instead, the stress reduces the same rate (slope) as the elastic modulus and reaches a certain strain at zero stress, called a residual strain.
Strain Stress SMYS 0.3% Residual strain 0.2% Elastic strain 0.5 %
Line pipe is usually specified by Nominal Pipe Size (NPS) and schedule (SCH). The most commonly used schedules are 40 (STD), 80 (XS), and 160 (XXS) (see Tables 7.1.3 and 7.1.4).
Table 7.1.3 Pipe Schedules
NPS OD (inches)
Wall Thickness (inches) SCH 10s SCH 10 SCH 20 SCH 30 SCH 40s SCH 40 SCH 60 SCH 80s SCH 80 SCH 100 SCH 120 SCH 140 SCH 160 10 10.75 .165 .165 .250 .307 .365 .365 .500 .500 .593 .718 .843 1.000 1.125 12 12.75 .180 .180 .250 .330 .375 .406 .500 .500 .687 .843 1.000 1.125 1.312 14 14.00 .188 .250 .312 .375 .375 .437 .593 .500 .750 .937 1.093 1.250 1.406 16 16.00 .188 .250 .312 .375 .375 .500 .656 .500 .843 1.031 1.218 1.437 1.593 18 18.00 .188 .250 .312 .437 .375 .562 .750 .500 .937 1.156 1.375 1.562 1.781 20 20.00 .218 .250 .375 .500 .375 .593 .812 .500 1.031 1.280 1.500 1.750 1.968 24 24.00 .250 .250 .375 .562 .375 .687 .968 .500 1.218 1.531 1.812 2.062 2.343
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
Pipe Wall Thickness (inch)
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.
Figure 7.1.2 Pipe Types by Manufacturing Process Expansion O-forming (b) UOE pipe U-forming
(a) Seamless pipe
7.2 CRA (Corrosion resistant alloy) Pipe
Depending on alloy contents, CRA pipe can be broken into follows:
• Stainless steel: 316L, 625 (Inconel), 825, 904L, etc.
• Chrome based alloy: 13 Cr, Duplex (22 Cr), Super Duplex (25 Cr), etc. • Nickel based alloy : 36 Ni (Invar) for cryogenic application such as LNG
(liquefied natural gas) transportation (-160oC)
• Titanium: Light weight (56% of steel), high strength (up to 200 ksi tensile), high corrosion resistance, low elastic modulus, and low thermal expansion, but high cost (~10 times of steel). Good for high fatigue areas such as riser touchdown region, stress joint, etc.
• Aluminum: Light weight (1/3 of steel), low elastic modulus (1/3 of steel), high corrosion resistance, but low strength (only up to 90 ksi tensile). Applications can include casing, air can, and risers.
Some key properties of each material are introduced in Table 7.2.1.
Table 7.2.1 Material Properties
Properties Carbon Steel Stainless Steel Titanium Aluminum
Specific Gravity (Density) 7.85 (490 lb/ft3) 8.03 (500 lb/ft3) 4.50 (281 lb/ft3) 2.70 (168 lb/ft3) Elastic Modulus (@ 200oF) 29,000 ksi (200,000 Mpa) 28,000 ksi (193,000 Mpa) 15,000 ksi (104,000 Mpa) 10,000 ksi (69,000 Mpa) Thermal Conductivity (@ 125oC) 30 Btu/hr-ft-oF (51 W/m-oC) 10 Btu/hr-ft-oF (17 W/m-oC) 12 Btu/hr-ft-oF (20 W/m-oC) 147 Btu/hr-ft-oF (255 W/m-oC) Thermal Expansion Coefficient 6.5 x 10-6 /oF (11.7 x 10-6 /oC) 8.9 x 10-6 /oF (16.0 x 10-6 /oC) 4.8 x 10-6 /oF (8.6 x 10-6 /oC) 12.8 x 10-6 /oF (23.1 x 10-6 /oC) 1 ksi = 6.8948 Mpa 1 Btu/(hr-ft-oF) = 1.731 W/(m-oC)
Depending on sour contents in the fluid, different chrome based alloy pipe should be selected per Table 7.2.2.
Table 7.2.2 Chrome Based Alloy Pipe Selection for Sour Service
Conveyed Fluid 13% Cr 22% Cr 25% Cr
CO2 > 1% > 1% > 1%
H2S < 0.04 bar < 0.2 bar < 0.4 bar
Cl No < 3% < 5%
7.3 Clad Pipe
Clad pipe is a combination of low carbon steel (outer pipe) and CRA (inner pipe). This pipe reduces material cost by using a thin wall CRA pipe at inner pipe wall surface to resist internal corrosion. And the carbon steel outer pipe wall provides structural integrity. Special caution should be addressed during clad pipe welding to the low carbon steel pipe, since hydrogen induced cracking (HIC) can occur by dissimilar material welding process.
7.4 Composite Pipe
A carbon-fiber or graphite material for small size pipe in low pressure application has been developed for mostly topside piping and onshore pipeline. However, its application is going to expand to subsea use due to its excellent corrosion resistant and low thermal expansion.
7.5 Flexible Pipe
Flexible pipe consists of steel layers and plastic layers. Each layer is un-bonded and moves freely from each other. It is known for excellent dynamic behavior due to its flexibility. However, the flexible pipe size is limited by burst and collapse resistance capacities. The maximum design temperature is 130oC due to the plastic 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.
Figure 7.5.1 Flexible Pipe Manufacturing Limit
Each steel and plastic layer has a different function as shown in Figure 7.5.2. For a sour service, a stainless steel carcass is required. For a water injection line, a smooth plastic bore can be used. The smooth bore is not normally used for gas applications due to gas permeation problem. The pressure build-up in the annulus of the pipe can occur due to diffusion of gas through the plastic sheaths. When no carcass is present, the inner plastic layer will collapse if the annulus pressure exceeds the bore pressure, such as shut-off case. To avoid this problem, gas vent valves are installed at end fitting to relieve the annulus pressure. Rough bore (with carcass) can cause noise and vibrations at high flow velocity.
The high density polyethylene (HDPE) is good for the content temperature of up to 65oC, Rilsan/nylon for up to 90oC, and polyvinylidene fluoride (PVDF) for up to 130oC. PVDF is better for higher temperatures but it is stiffer than nylon (3% vs. 7% in allowable strain). Another key component of the flexible pipe is the end fitting (Figure 7.5.3) which is designed to hold all layers of flexible pipe at each end.
The flexible pipe manufacturers include: Technip (formerly Coflexip), Wellstream, NKT, and DeepFlex. To reduce the flexible pipe weight (especially for dynamic riser use) and improve corrosion resistance, a composite material, such as for tensile wires, has been developed. DeepFlex uses a composite material (carbon fibre-reinforced polymer (CFRP)) for all layers (Figure 7.5.4.)
Pipe ID (inch) Design Pressure (psi)
API 17J Design Limit
200 400 600 800 1000 0 1200 1400 0 0 2 4 6 8 10 12 14 16 18 20
Figure 7.5.2 Flexible Pipe Structure [3]
Armour Wires - Resists tensile load
Pressure Layer
- Resists internal and external pressures
Carcass – Resists external collapse pressure Pressure Sheath (HDPE/Nylon/PVDF) - Contains internal fluid and transfers
internal pressure to pressure layer External Sheath (HDPE)
- Protects abrasion, seawater
penetration, and steel layer corrosion Intermediate Sheath (HDPE)
- Protects abrasion between steel layers
Figure 7.5.3 Flexible Pipe End Fitting [4]
7.6 Flexible Hose
Flexible hose is a single body rubber bonded (vulcanized, oven baked) structure, unlike the flexible pipe which consists of unbonded multiple plastic and steel layers. The flexible hose is commonly used for topside jumpers, single point mooring (SPM) risers, and surface floating risers to offload the product from the buoy to FPSO or shuttle tanker (see Figure 7.6.1).
Figure 7.6.1 Flexible Hose Applications .
The built in one-piece end couplings with integral built in bend limiters and a composite fire resistant layer provide a low minimum bend radius, a light compact construction with excellent flexibility and fatigue resistance. However, there are some manufacturing limits on hose size and length; the maximum hose size is 30” and the maximum length is 35 ft.
Flexible hose manufacturers include: Dunlop Oil & Marine, Bridgestone, GoodYear, Phoenix Rubber Industrial (formerly Taurus), etc.
Figure 7.6.2 shows some pictures of flexible hose applications and factory flexibility test.
Pipeline PLEM
Risers
SPM Buoy (mooring lines
not shown)
Offloading Hose FPSO or
Shuttle Tanker
Figure 7.6.2 Pictures of Flexible Hose Applications and Factory Flexibility Test
(Source: www.dunlop-oil-marine.co.uk [6])
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 Coiled Tubing Operation [9]
CT String Injector
Head Stripper
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
8 PIPE COATINGS
8.1 Corrosion Coating
Inner surface of the pipe is not typically coated, but if erosion or corrosion protection is required, fusion bonded epoxy (FBE) coating or plastic liner is applied. Outer surface of the carbon steel line pipes are typically coated with corrosion resistant FBE or neoprene coating. The three layer polypropylene (3LPP), three layer polyethylene (3LPE, see Figure 8.1.1), or multi-layer PP or PE is used for reeled pipes to provide abrasion resistance during reeling and unreeling process. Thermally sprayed aluminum (TSA) coating can be used for risers especially when there is a concern on CP shielding due to strakes or fairings. Abrasion resistant overlay (ARO) is commonly applied for the
horizontal directional drilling (HDD) pipes or bottom towed pipes.
The coating materials’ normal thickness and temperature limit are as follows:
– Fusion Bounded Epoxy, 0.4-0.5 mm, 200oF – Polyethylene, 3-4 mm, 150oF
– Polypropylene, 3-4 mm, 220oF – Neoprene, 3-5 mm, 220oF
Figure 8.1.1 3LPE Coating
Steel
Adhesive Layer FBE Layer
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.
The OHTC or U value can be obtained using the formula below: m m 1 1 m m 1 m 1 2 3 2 1 1 2 1 1 1 h 1 r r r r ln K r r r ln K r r r ln K r h 1 1 U + + + + + = − − L Where,
h1 = internal surface convective heat transfer coefficient hm = external surface convective heat transfer coefficient r = radius to each component surface
K = thermal conductivity of each component
For example, the U value for a 6.625” OD x 0.684” WT pipe with a 1” GSPU coating is:
Pipe r1 = 2.6285” r2 = 3.3125” K1 = 30 Btu/hr-ft-oF GSPU r2 = 3.3125” r3 = 4.3125” K2 = 0.096 Btu/hr-ft-oF Neglect FBE corrosion coating and HDPE outer jacket and assume h1 & h3 = 1,000 Btu/hr-ft2-oF. F) ft Btu/(hr 1.65 1,000 1 4.3125 2.6285 3.3125 4.3125 ln 0.096 2.6285/12 2.6285 3.3125 ln 30 2.6285/12 1,000 1 1 U o 2⋅ ⋅ = + + + = r1 rm
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.
Wacker/Porextherm
• Fumed microporous silica with a pore size of 10-6m. Wacker is purchased by Porextherm.
• Most expensive thermal insulation product. • Good K-value (0.0195 W/m-oK at 50oC). • Standard density is 0.19 SG.
• Developed for the reeling process and many track records exist. • Requires centralizers with a spacing of every 2m or so.
Mineral Wool
• Cheapest form of insulation.
• Poorest K-value (0.037 – 0.045 W/m-o
K at 50oC) of all insulation materials but used extensively in the North Sea.
• Densities are in the range of 0.1 - 0.12 SG.
• Not good for low U value unless combined with other method such as heat tracing.
PIP system requires bulkheads, water stops, and centralizers, depending on fabrication methods. The end bulkhead is designed to connect the inner pipe to the outer pipe, at each pipeline termination (see Figure 8.3.2). Intermediate bulkheads may require for reeled PIP to allow top tension to be transferred between the outer pipe and the inner pipe, at intervals of approximately 1 km. During installation, the tensioner holds the outer pipe only, so the inner pipe tends to fall down by its dead weight and may result in buckling at sag bend area near seabed, if no intermediate bulkheads exist.
Figure 8.3.2 End Bulkhead
Bulkhead Flange
Outer pipe Inner pipe
