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July 27, 2017 | Author: sarahbst | Category: Pipeline Transport, Subsea (Technology), Offshore Drilling, Pipe (Fluid Conveyance), Steel
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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]
REGULATIONS AND PIPELINE PERMITS ................................................................ 15
DESIGN PROCEDURES AND DESIGN CODES ........................................................ 19
PIPELINE ROUTE SELECTION ................................................................................. 31
FLOW ASSURANCE .................................................................................................. 39
UMBILICALS .............................................................................................................. 43
PIPE MATERIAL SELECTION .................................................................................... 49
PIPE COATINGS ........................................................................................................ 65
PIPE WALL THICKNESS DESIGN ............................................................................. 75
THERMAL EXPANSION DESIGN............................................................................... 89
PIPELINE ON-BOTTOM STABILITY DESIGN ............................................................ 97
PIPELINE FREE SPAN ANALYSIS ........................................................................... 101
CATHODIC PROTECTION DESIGN ......................................................................... 109
PIPELINE INSTALLATION ........................................................................................ 119
SUBSEA TIE-IN METHODS ...................................................................................... 131
UNDERWATER WORKS ........................................................................................... 145
PIPELINE WELDING ................................................................................................. 147
PIPELINE PROTECTION – TRENCHING AND BURIAL ............................................ 153
PIPELINE SHORE APPROACH AND HDD ............................................................... 161
RISER TYPES ........................................................................................................... 165
RISER DESIGNS ...................................................................................................... 169
COMMISSIONING, PIGGING, AND INSPECTION .................................................... 175
PIPELINE REPAIR .................................................................................................... 185
APPENDIX A..................................................................................................................... 193 APPENDIX B..................................................................................................................... 199
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]
-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. •
Flowline/Pipeline/Riser System Fixed/Floating Structures Topside Processing System
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
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
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]
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: • • • • • • •
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: • • • • • • • • • • • • •
- 20 Table 3.1 Preliminary Design (FEED) Flowchart
Table 3.2 Detail Engineering Flowchart
- 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
Welding Connections to Pipe, 1996
Installation, Maintenance and Repair of Surface Safety Valves and Underwater Safety Valves - Offshore
Design and Hazards Analysis of Offshore Production Facilities
API RP 17D
Specification for Subsea Wellhead and Christmas Tree Equipment, 1996
Design and Operation of Completion/Workover Riser Systems
Installation of Subsea Umbilicals
API RP 17J
Specification for Unbonded Flexible Pipe, 1999
Steel Plates, Quenched and Tempered, for Offshore Structures
End Closures, Connectors and Swivels
Subsea Production Control Umbilicals
Specification for Deformed Billet-Steel Bars for Concrete Reinforcement
Standard Test Methods for Vickers Hardness of Metallic Materials
Test Methods for Controlling Quality of Radiographic Testing Using Wire Penetrometers
Standard Terminology Relating to Fatigue and Fracture Testing, 1996
Code of Practice for Fatigue Design and Assessment of Steel Structures, 1993
Global Buckling of Submarine Pipelines Structural Design due to High Temperature/High Pressure, 2007
- 28 DNV-RP-F204
International Organization for Standardization (ISO) ISO-9001
IOS-13628
Petroleum and Natural Gas Industries Design and Operation of Subsea Production Systems
IOS-13628-1
IOS-13628-2
Subsea Flexible Pipe Systems
IOS-13628-4
Subsea Wellhead & Christmas Trees
IOS-13628-6
IOS-13628-8
IOS-13628-9
Remotely Operated Tool (ROT) Intervention Systems
IOS-14000
ISO-15589-2
ISO-15590
National Association of Corrosion Engineers (NACE) NACE MR-01-75
NACE RP-01-76-94
NACE RP-0387
Metallurgical and Inspection Requirement for Cast Sacrificial Anodes for Offshore Applications
Application, Performance and Quality Control of Plant-Applied, Fusion-Bonded Epoxy External Pipe Coating
NACE RP-0492
NORSOK UCR-006
- 30 Miscellaneous TPA IBS-98
Recommended Standards for Induction Bending of Pipe and Tube, 1998, Tube & Pipe Association (TPA)
Personnel Qualification and Certification in Non-Destructive Testing, American Society of Nondestructive Testing
PIPELINE ROUTE SELECTION When layout the field architecture, several considerations should be accounted for: • • • • • •
- 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
F TH 2.0 × 14.2 × 1,000 = = 2,513 ft ∴Use minimum 3,000 ft Ws µ 22.6 × 0.5 Initiation point
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 )
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
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]
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]
- 36 Figure 4.6 Torvane Shear Test Kit [5]
- 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.
150 8” ID 100 150
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
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.
- 44 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.
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 +
- 50 Table 7.1.1 Tensile Requirements for API-5L PSL 2 Pipe
0.5 % Strain 0.3% 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)
1.093 1.250
1.031 1.218 1.437
1.156 1.375 1.562
1.031 1.280 1.500 1.750
1.218 1.531 1.812 2.062
- 53 Table 7.1.4 API-5L Standard Pipe Wall Thickness Pipe Wall Thickness
- 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.
- 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.
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.
(69,000 Mpa)
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
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
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 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)
1000 0 800 600
- 60 7.6
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
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.
- 62 7.7
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.
CT String Injector Head Stripper
- 64 References [1] API 5L, Specification for Line Pipe, Section 6.2.1, American Petroleum Institute, 2004 [2]
[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
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: – – – –
- 66 8.2
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)
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
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
- 68 8.3
Best K value 0.0139 W/m-oK at 50oC.
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.
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).
Poorest K-value (0.037 – 0.045 W/m-oK at 50oC) of all insulation materials but used extensively in the North Sea.
- 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 •
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.
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
Figure 8.4.1 Concrete Weight Coating [4]
Figure 8.5.1 Field Joint Coating [5]
- 74 References [1] Dunlaw Engineering Ltd. website, http://www.dunlaw.com/bend_limiters.html [2]
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.
- 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;
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