TECHNOLOGY FOCUSSubsea Technology The 2008 Offshore Technology Conference (OTC) was a record-breaking event: Attendance (75,000+, the highest in 26 years), participating companies, and, as a friend noticed, iron on the ground (I do not believe there are statistics on this issue, but…). Technical-session attendees were treated with projects and technologies for regions that ranged from the Arctic offshore to the deep water of east Asia—a rather broad array of applications. The StatoilHydro subsea-to-shore gas development, Ormen Lange, received an OTC award for overcoming significant technical challenges to become Norway’s deepest offshore development (800–1100 m). Although a subsea-compression system is yet to be developed to solve the challenges completely, Ormen Lange offers pioneering innovative solutions that will enlarge the industry’s knowledge and improve confidence to face demanding tasks ahead that will test our ability to implement technological advances. As of the first week of June, we reached record oil prices and an overall cost escalation in the oil industry. The implications are diverse. However, I believe it underscores how the ever-growing costs of drilling/completion/intervention rigs will put a very high burden on the development of any field, mainly subsea, that is heavily dependent on mobile offshore drilling units. Overcoming such cost escalation is a major challenge. At the same time, it is also a major opportunity for improvement. To contemplate this quest for innovate solutions and the state-of-the-art technology in exploration and production, the highlighted papers vary from classical developments by Petrobras in its Roncador field offshore Brazil to Murphy Sabah’s Kikeh field in Malaysia. In the case of Roncador, you will get to know an innovative pendulum method for installing manifolds in ultradeep water; in Kikeh, you will get an idea of the innovations necessary that were implemented to overcome the challenges of Malaysia’s first deepwater development. In addition, a paper from BP outlines its successful track record of subsea developments, challenges facing the next generation, and the company’s approach to technology to ensure success. It is definitely an impressive collection of papers for their scope, content, and effect JPT on the industry. I feel especially pleased to invite you to read them. Subsea Technology additional reading available at the SPE eLibrary: www.spe.org SPE 108970 • “Ormen Lange Subsea-Condition and Leakage Monitoring” by Jens Abrahamsen, Bjørge A/S, et al. SPE 112723 • “Requirements for a Full-Drill-Through Subsea Wellhead and Tree System” by Sterling Lewis, SPE, ExxonMobil, et al. Additional reading available at OnePetro: www.onepetro.org OTC 19139 • “Managing Flow Assurance and Operation Risks in SubseaTieback System” by Shanhong Song, Chevron 68 JPT • AUGUST 2008 Jacques B. Saliés, SPE, is Drilling and Completion Manager of Petrobras America for the Gulf of Mexico. His 27-year career at Petrobras spans engineering and management positions in E&P, including coordination of the Petrobras Technological Program on Ultradeepwater Exploitation Systems— PROCAP 3000. Saliés holds a BS degree in mechanical engineering from the Military Institute of Engineering, Brazil, an MS degree in petroleum engineering from the Federal University of Ouro Petro, Brazil, and a PhD degree in petroleum engineering from the University of Tulsa. He has served on the SPE Board of Directors for Brazil and has authored and coauthored several papers. Saliés serves on the JPT Editorial Committee. SUBSEA TECHNOLOGY Kikeh Development: Malaysia’s First Deepwater Development The Kikeh development, the first deepwater project in Malaysia, is offshore eastern Malaysia in the South China Sea with a water depth of 1320 m. Kikeh is to be developed with 34 wells, and initial production was in August 2007. The full-length paper discuses the offshore-installation-vessel selection process including the effects on the decision process of using local equipment vs. mobilizing deepwater construction equipment from other deepwater basins around the world. With deepwater Sabah being a greenfield deepwater basin, a number of challenges arose in relation to equipment availability within the region and logistics to support deepwater construction operations. Introduction While these types of deepwater subsea developments have been brought on production in other deepwater basins for a number of years, particularly in West Africa and the Gulf of Mexico, the Kikeh development, as a first for Southeast Asia, brought about a number of challenges to and specific requirements for both operaThis article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19637, “Kikeh Development: Subsea-Equipment-Installation Challenges for Malaysia’s First Deepwater Development,” by G. Murray and D. Lowther, Technip Subsea 7 Asia Pacific, and A. Ledingham and T.J. Stensgaard, Murphy Sabah Oil Co. Ltd., originally prepared for the 2008 Offshore Technology Conference, Houston, 5–8 May. The paper has not been peer reviewed. Copyright 2008 Offshore Technology Conference. Reproduced by permission. Fig. 1—Deep Pioneer with PPS-01 lay system. tor and contractor that necessitated close cooperation in terms of sharing of installation assets across a number of contracts associated with the Kikeh development to meet the overall project schedule. Because of the nature of this type of deepwater subsea project, involving the supply and installation of flexible flowlines and risers, the engineering, procurement, construction, installation, and commissioning (EPCIC) contractor elected to use a joint-venture partnership to execute the project on its behalf. The project team was established in Perth, Western Australia, where all design engineering, procurement activities, and preparation of installation procedures were undertaken. Offshore-Vessel Selection The primary vessel-capacity requirements were crane-lift capabilities, flexible-pipe lay tensions, and overall deck-storage capacity to handle the products to be installed. To determine the installation-vessel requirements, some initial engineering was conducted to better understand maximum lift and deployment loads associated with the installation program. The installation program, as defined by the project-execution strategy, split the installation scope of work into two distinct phases. Installation of subsea structures, laying of flowlines, laying of static umbilical sections, and preinstallation and wet storing of the dynamic flexible risers and dynamic umbilical sections before floating production, storage, and offloading (FPSO) vesssel arrival and hookup formed the Phase I work scope. Recovery and pull in of the dynamic flexible risers and dynamic umbilical sections into the FPSO turret, along with installation of rigid The full-length paper is available for purchase at OnePetro: www.onepetro.org. JPT • AUGUST 2008 69 Fig. 2—Rockwater 2. jumpers and flying leads, was the scope of work to be performed in Phase II directly following hookup of the FPSO. Preinstallation of the flexible flowlines, risers, and umbilicals was specified by the client to facilitate a more-rapid hookup of the field following FPSO mooring at site and to disassociate the FPSO installation from the flexible-pipe- and umbilical-installation program to reduce schedule risk. Phase III, outside the scope of work of the EPCIC contract, is the period (still ongoing) during which the remaining 10 subsea wells are tied in to the previously installed subsea infrastructure. Phase I. For Phase I, the largest scope of work involved installation of the flexible flowlines, risers, and umbilicals. Initial analysis determined the installation loads for the 10-in. water-injection (WI) flowline and riser would be approximately 280 to 300 tons. Significant lay-tension requirements were driven primarily by the approximately 1400-m water depth, large pipe diameter, and laying of the pipe flooded to avoid flexiblepipe collapse. The magnitude of the calculated tensions confirmed the requirement for the newly designed flexible-pipe lay system, Portable Pipelay System (PPS-01), which had a 350-ton capacity and, at that time, was under construction in France. Given the overall dimensions and weight of the PPS-01 (17.5×11.8 m×37.4 m high and 960 tons) and the operational power requirements of 1.4 MW, it became apparent that there was no vessel available within the Southeast Asia/Australia area that would be able to accommodate the lay system. Identifying and securing an appropriate vessel from another deepwater operating area would be a priority for the project team. There were to be 22 flowline reels, 10 riser reels, and 3 umbilical reels. To accommodate this number of reels, a heavy-lift transportation vessel (HLV) was required to transport the reels from Europe and act as a storage vessel from which reels would be transferred to the installation vessel. In addition, to maintain an efficient installation program, the installation vessel would be required to accommodate a minimum of six reels on deck, along with the PPS-01, two work-class remotely operated vehicle (ROV) systems, and a precommissioning spread that would permit flushing/filling the flowlines with inhibited fluids following lay operations and allow umbilical testing following installation. Once the specific equipment criteria had been established, a review of vessels throughout the joint-venture fleets identified that the Deep Pioneer (Fig. 1) had the deck capacity to accommodate the required flowlineand riser-installation spread and also had sufficient additional available power to drive the PPS-01 and was allocated to the project. Mobilization of the vessel in Europe was driven by the availability of the newly built PPS-01, which was scheduled to be completed in July 2006. Following mobilization and final commissioning of the PPS-01 on the Deep Pioneer in Le Trait, France, the vessel sailed from Europe to Singapore for final project mobilization. On the basis of completion of the PPS-01 and the mobilization activities, a window to complete the Phase I flowline-, riser-, and umbilical-installation scope of work was agreed upon from October 2006 to the end of January 2007. For the subsea-structure scope of work, analysis determined that the largest dynamic load to be installed was the 10-in.-WI-riser holdback suction anchor with a maximum estimated loading of 154 tons. Riser holdback piles were used to reduce both the overall footprint of the subsea development and the flexible-pipe flowline lengths. Given the relatively close proximity of the Kikeh field to the offshore supply base of Labuan (approximately 8 hours transit time), multiple transits of the installation vessel between the field and supply base to reload equipment was considered not to be cost-prohibitive, provided that a medium-sized construction vessel was used. Evaluation of available vessels based within the Asia Pacific region determined that the Rockwater 2 (Fig. 2) would be the most appropriate selection, although the crane would have to be upgraded to 200-ton offshore lift capacity and the crane wire drum changed to accommodate 2200 m of wire to enable deployment of the heaviest structures to the seabed. Deck layouts confirmed that all 12 suction anchors, five manifolds, five subsea distribution units, and two temporary pipeline-end terminals (PLETs) could be installed with three vessel loadouts from Labuan and an overall installation program of approximately 25 days. Integrity verification of the flowlines and risers at the conclusion of Phase I operations was to be provided by means of a hydrostatic pressuretesting program. Because all lines were to be flooded with treated water from the Deep Pioneer before sec- 70 JPT • AUGUST 2008 Fig. 3—Normand Ivan. ond-end lay down, a means of pressurizing each of the flowline and riser systems from their respective manifolds needed to be developed. With the project preference to avoid hydrotesting the flow systems from the pipelay vessel because of the significant schedule and cost implications, alternative integrity-pressuretesting means were investigated. One system that appeared to have significant merit was the use of a subsea testing unit. However, the systems available consisted of a large seabedbased flooding and testing unit with a weight greater than 15 tons and requiring a vessel with crane capacity adequate to deploy and recover the unit. This large seabed unit also was deemed cost-prohibitive, and, therefore, the project team set out to develop a small pumping skid that could be ROV deployed and had the capability of pressurizing each of the lines up to the required leak-test pressure. The ability to use this small ROV-mounted pressurization skid meant that a small, locally based dynamically positioned (DP) vessel without a crane was all that would be required to support the Phase I flowline-integrity verification work scope. A Malaysian-companyowned vessel, the Allied Shield, was selected by the project team for this operation. Phase II. For Phase II, the critical installation activity was the recovery and transfer to the FPSO of the wetstored flexible risers and dynamic umbilical sections. Because the Deep Pioneer with the PPS-01 was not going to be available for Phase II operations, an alternative means of lifting the risers and transferring the load to the FPSO pull-in-winch wire had to be developed. Recovery and hang off of the riser above the water surface on the recovery vessel was not a viable option because of the significant loads involved (as much as 280 tons for the 10-in. WI riser); therefore, a means of completing the transfer of the riser to the FPSO pull-in rigging with the riser termination remaining subsea had to be engineered. It also was apparent that mobilizing a heavy DP construction vessel with large crane capacity from another region for a standalone 20-day riser-recovery program in Southeast Asia was not a realistic option in terms of cost or availability in a market that was already overheated. This led the project team to assess the viability of using a largecapacity DP anchor-handling vessel with winch capacity greater than 400 tons as an alternative solution. The Normand Ivan (Fig. 3) was a vessel that Murphy had placed on longterm charter to install deepwater preset moorings, carry out rig moves, and provide general-operations support to the Ocean Rover mobile offshore drilling unit (MODU) within the Kikeh field. Initial evaluation confirmed that with its 500-ton winch and stern roller capacity and twin aft Karm forks rated to 750 tons, a workable methodology could be developed for recovery and transfer of all five risers and two dynamic umbilicals using the Normand Ivan. Furthermore, because of the preset mooring work scope, the vessel was already fitted out with a work-class ROV. A “best for project” decision was made to make the vessel available for this Phase II work scope. Subsequent detailed engineering, however, was to identify a number of additional difficulties that had to be addressed and overcome, as is discussed in greater detail in the fulllength paper. Other Phase II activities involved the installation of the five rigid spools, six hydraulic flying leads, and six electrical flying leads, plus the recovery of the second end of a 6-in.-WI flowline vertical-connection module (VCM) from a temporary PLET and its connection to a subsea tree. With deployed loads at the seabed not exceeding 30 tons and nothing onerous in terms of deckspace requirements, the Rockwater 2 was considered to be the most appropriate vessel to undertake this installation work scope, with the heavecompensated crane considered to be of benefit in landing the rigid-spool VCMs onto the receiving manifold and subsea-tree hubs. Phase III. For Phase III activities, the plan was to install rigid jumpers and hydraulic flying leads, on the basis of lessons learned from Phase II, from a light intervention vessel, preferably from the newly built field-support vessel Armada Tuah 100 or, if this were unavailable, a vessel of similar size. The electrical flying leads were of a size and configuration that made installation possible by a work-class ROV on the MODU at opportune moments between well-completion JPT support activities. JPT • AUGUST 2008 71 SUBSEA TECHNOLOGY Developing Subsea Facilities for the Roncador Field The second phase, Module 1A, of the Roncador field, offshore Brazil, was developed with a large semisubmersible floating production unit (FPU). This paper explains the strategies adopted by Petrobras to overcome the challenge of starting oil and gas production at a water depth of 1800 m in a short period of time, which required starting the platform construction early, almost simultaneously with the design of the riser system. Introduction Campos basin is offshore Rio de Janeiro State, southeastern Brazil. It covers approximately 100 km2 ranging from 20 to 3400 m water depth (WD). Roncador field lies in 1500 to 1900 m of water in the basin and was discovered in 1996. Development of Roncador field was planned with four production modules. Module 1A comprises two phases of exploitation: Phase 1 began production in 2002 with floating-production-storageand-offloading (FPSO) vessel Brasil moored in approximately 1300 m WD, to operate some of the wells temporarily. By the end of 2007, the second phase of Module 1A (Phase 2) started to produce to the FPU P-52, which has a total displacement 80,000 t, moored This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 19274, “Development of Subsea Facilities in the Roncador Field (P-52),” by José Maurício T.G. Lima, Mariele Lima Kuppens, Paulo Ferreira da Silveira, and Pedro Felipe K. Stock, Petrobras, prepared for the 2008 Offshore Technology Conference, Houston, 5–8 May. The paper has not been peer reviewed. Copyright 2008 Offshore Technology Conference. Reproduced by permission. Fig. 1—Artist’s illustration of gathering system. in 1800 m WD. This FPU has the capacity to produce 2.86×104 m3/d of oil (3.18×104 m3/d of liquid) and to process 9.3×106 m3/d of natural gas, and it is intended to gather production from all wells of Module 1A, starting with new wells and gradually adding the wells producing to the FPSO Brasil. Thereafter, P-52 will be linked to at least 18 production and 11 water-injection wells. Riser System. Feasibility studies for the second phase of Module 1A began in late 2001. At that time, 1800 m WD was beyond riser-technology limits. To identify and manage the risks, three riser options were studied: semisubmersible, FPSO turret, and FPSO differential-compliance anchoring system. The ranking of these options was made through assessment of the stage of development and knowledge, operational issues, and available resources (e.g., installation vessels). The semisubmersible platform was selected to mitigate the risks of riser development. However, the desire to start Phase-2 production 4 years later required designing and contracting platform construction before the riser system was defined. Problems faced during qualification testing of flexible-pipe flowlines and risers for Phase 1 raised concerns about the capability of this traditional riser solution for applications in ultradeep water. Therefore, other riser concepts were assessed. The steel catenary riser (SCR) was determined as appropriate technology for the design WD. An in-house technical feasibility study confirmed the SCR as the primary gathering system, The full-length paper is available for purchase at OnePetro: www.onepetro.org. 72 JPT • AUGUST 2008 Installing Subsea Manifolds. Installation of the first manifold in Roncador field, at 1885 m WD, required three vessels: a semisubmersible rig and two anchor-handling tug/supply vessels. Deployment of the new manifolds uses a pendulous installation method, which ended lowering manifolds to the sea bottom with a drilling rig or special vessel. It also improved the operating window compared with the previous method. SCR-System Technical Feasibility The feasibility study (FS) of the SCR system was performed during the hull-design stage. The scope of work included SCR mechanical design, static interference analysis of typical neighboring risers, preliminary wavefatigue and vortex-induced-vibration assessment, maximum-stress analysis, and simulations of riser transference during pull-in and pullout operations. The main findings of the FS were as follows. • Critical risers, in terms of dynamic response, should be connected to the hull inside its ring pontoon and should use top angles of approximately 20°. • The feasibility of production SCRs for the selected hull was achieved by reducing the insulation thickness to half the initial value (improved fatigue life by 40%), changing the insulation from solid to syntactic polypropylene, and using clad sections in the critical fatigue regions. From the FS results, it was possible to generate a consistent riser-connection layout, to estimate appropriately the riser configurations and interface loads to allow the development of the platform design, and to identify the critical risers to be studied in the basic design of the SCR system. Pendulous Installation Method Deployment of heavy subsea hardware in ultradeep water with proven methods is difficult, expensive, and somewhat risky. The conventional method of using wire rope has the disadvantage that a substantial portion of the allowable cable tension is taken by its own weight. Resonance is another key aspect if heave-motioncompensation systems are not accessible. An alternative is the use of spe- Fig. 2—Pendulous installation method illustration. while the flexible riser remained an alternative requiring approval in a prequalification program. The SCR system and flexible risers, after prequalification of the latter with full-scale offshore tests, were both included in the subsea bid for the construction phase. Even though some changes were necessary in the FPU to allow the use of flexible risers, all the provisions for SCRs were kept operational for contingency purposes in the future. Gathering-System Architecture. The Phase-2 gathering system is shown in Fig. 1 and comprises subsea wellheads and manifolds in WDs ranging from 1550 to 1900 m. Production and injection flowlines connect the FPU directly to each well. Gas lift distribution for most production wells—as well as control, monitoring, and chemical injection— is provided through three subsea gas lift manifolds. P-52 is connected to the manifolds by way of a mainloop flowline for gas lift, called the gas lift ring (GLR) pipeline, and service flowlines. Currently, all flowlines and risers for the gathering system are flexible pipes. Subsea connections of flowlines to wellheads and manifolds are provided by flexible pipe and a verti- cal-connection module. At the FPU side, riser porches on the ring pontoon connect the gathering flexible risers in free-hanging catenary configuration, but they also are designed for SCRs. Gas Lift System. Gas lift will be used as the artificial-lift method in all production wells. To reduce the number of risers arriving at the FPU, three subsea gas lift manifolds were incorporated into the gathering system, tied to P-52 by the GLR pipeline. GLR. The GLR pipeline provides full inspection through the main gas lift SCRs and rigid flowlines, without interruption of the supply of gas to the manifolds. Also, it fits the room limitations in the platform hull for the connection of SCRs. The GLRpipeline design has a rigid main-loop flowline connected to SCRs on both ends, with in-line tees for connection with each manifold by way of flexible jumpers and in-line shutdown valves for both SCRs. When the flexible pipes took the place of the SCRs and rigid flowlines for the whole gathering system, the GLR pipeline kept the same operational philosophy, regardless of significant changes to make the equipment suitable for a flexibleloop flowline. 74 JPT • AUGUST 2008 cial construction vessels with heavyload-handling capabilities. However, the low availability and high costs of such vessels may have a large effect on installation costs and schedules. The use of synthetic-fiber rope is an alternative but requires cable-handling restrictions during deployment, such as bending and heating. Resonance is also a concern, in a way similar to that of the wire rope. The pendulous method overcomes these difficulties. A simple pendulous motion was developed for the installation, as shown in Fig. 2. The hardware is transported to the location on the deck of a workboat equipped with a crane (transportation vessel). At the installation site, the hardware is overboarded and submerged to a depth of 50 m. The installation cable (polyester rope) from the second workboat (installation vessel) is connected to the hardware rigging. The installation-cable length is slightly less than the WD, and the distance between the workboats is approximately 90% of the cable length. The transportation vessel releases the hardware, and the system pendulates until the installation cable held by the installation vessel reaches the vertical position at equilibrium. Installation-cable elongation is checked to assess clearance from the mudline. Because of drag load on the hardware and installation cable, the system is damped to eliminate a reverse pendulum motion (i.e., the system will not swing back and forth). At the end of the pendulous motion, the installation vessel controls vertical motions of the system. However, axial resonance will be prevented because the axial stiffness of the polyester rope length is such that the system behavior is compliant and the dynamic amplification factor is substantially reduced compared to a wire-rope system. The subsea equipment then will be at an appropriate distance from the mudline to be deployed further by paying out the segment of chain connected to the upper end of the polyester rope, and after heading adjustment, the equipment will be landed. Qualification. Despite numerical analysis and model tests, Petrobras decided to perform a full-scale test with a dummy manifold (DM), aiming to qualify the installation procedure. The test also offered an opportunity to train the vessel crew that would perform the installation. The DM was designed with the same dimensions, weights, center of gravity, center of buoyancy, and radii of gyration as the largest manifold for Roncador. Basically, it comprised a steel structure, without the piping system, and 10 boxes of variable weights to reproduce these parameters. A monitoring system was installed to record manifold motions, which were compared to model tests and numerical analyses for validation. The DM was installed in December 2005, in 1850 m WD. The comparison of some measured variables agreed with numerical analysis and model tests, such as the polyestercable force, which showed no peaks and a monotonically increase over time. The results of the DM monitoring system identified a 200° rotation around its longitudinal axis 40 seconds after its release in the beginning of the pendulous motion. The DM rotated in the opposite direction and returned to the normal position 60 seconds later. This rotation had been identified during the scale tests. To minimize or even avoid the excessive rotation of the manifolds during the initial pendulous motion, a counterweight mechanism with a mechanical fuse was tested and approved for use during Roncador-manifold installation. Conclusion Development of Roncador field has been distinguished as a permanent search for subsea technology in very challenging conditions. The P-52 project, particularly, imposed great challenges to the risers and subsea hardware in terms of design, installation activities, and operation in a safe and cost-effective way. The work detailed in the full-length paper was a large team effort. Despite difficulties that occurred, all objectives were reached through technicians’ creativity and engagement. The exhaustive studies performed in the design of riser alternatives for P-52 provided relevant background that will help ensure successful results in ultradeep water in the JPT near future. JPT • AUGUST 2008 SUBSEA TECHNOLOGY BP’s Subsea Developments The full-length paper presents an overview of BP’s many milestones in subsea projects over the years. The next wave of deepwater and subsea projects will require the development of reservoirs with compound issues. Some of these reservoirs are in remote regions with few offshore host facilities and ecologically sensitive environments. Introduction Currently, BP has approximately 180 subsea wells worldwide, producing approximately 127 190 m3 of oil and gas. This number of wells is expected to double over the next 5 years as the company continues to explore and develop difficult reservoirs in deeper and more-remote hydrocarbon basins. The first subsea wells in the mid1970s were in the Arabian Gulf. In the 1990s, harsh-environment field developments based on floating production, storage, and offloading (FPSO) vessels were completed in deepwater West of Shetland. Since then, BP has developed and operated subsea fields worldwide with ever-increasing water depths and distances to production hubs. These hubs range from fixed platforms to floating deepwater vessels, tension-leg platforms, FPSOs, semisubmersibles, and spars. Most notable is the series of very large and complex developments in the Gulf of Mexico (GOM), Angola, and Norway. This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 113652, “BP’s Subsea Developments: Past Successes and Future Challenges,” by Fikry Botros, Cornelia Noel, SPE, David Brookes, SPE, and Robert Perry, BP plc, originally prepared for the 2008 SPE Indian Oil and Gas Technical Conference and Exhibition, Mumbai, India, 4–6 March. The paper has not been peer reviewed. Fig. 1—Thunder Horse semisubmersible. The water depths for the GOM developments exceed 2500 m and in some cases have high-pressure/hightemperature (HP/HT) reservoir conditions of 1000 bar and 130°C, respectively. Off the coast of West Africa, the development of the Greater Plutonio field has been completed successfully by use of an FPSO host, with follow-on plans to develop four additional subsea developments, three of which will be in ultradeepwater Block 31 (2500-m water depth) using modular FPSOs. In Norway, the Skarv harsh-environment FPSO-based subsea development is under development currently. In addition, there are plans to develop a large number of subsea tieback projects to existing facilities, including the record-breaking 72-km Taurt gas development in Egypt and the Kingdevelopment subsea boosting project in the GOM. Early Developments (1970–1999) North Sea. The five-well Buchan subsea development, started in 1981, is tied back through tensioned-steel vertical risers to a pentagon-style floating rig. In 1988, the two-well Seillean subsea development was the first to produce by means of tensioned risers tied back to a dynamically positioned floating production, storage, and trans- For a limited time, the full-length paper is available free to SPE members at www,spe.org/jpt. 76 JPT • AUGUST 2008 port vessel (the forerunner of extended-test and early-production systems). The Magnus field, in 186 m of water, started in 1981, used multiplexed electrohydraulic control systems. The Don field, a 17-km host offset, and the Andrew field with the then-novel 6-km pipeline-bundle tieback concept, followed. The Machar field was completed in 1996 and included the longest black-oil single-leg tieback, approximately 35 km. It also boasted the first subsea pig launcher and subsea metering system. To date, the Foinaven and Scheihallion fields, the former started in 1997, in the harsh environment West of Shetland in depths of 400 to 500 m remain the largest subsea developments in the UK sector of the North Sea. They include 70 subsea wells tied back to two turret-moored FPSOs with flexible risers in a lazywave configuration equipped with extensive on-line condition monitoring. The field architecture was based on the compact-manifolds concept and an award-winning remotely operated vehicle connection system. These two projects had to overcome many challenges associated with the cold and rough waters of the West of Shetland, with seabed temperatures as low as –2°C, seabed currents of 1.5 m/s, and waves heights greater than 30 m. GOM. In the GOM, the 1994 Pompano development in 600-m water depth used compact through-flowline technology. This enabled remote replacement of tubing-deployed chokes from a fixed jacket approximately 10 km away. In 1997, the Troika four-well cluster development in 700-m water depth used a 25-km subsea bottom-towed dual pipe-in-pipe flowline system. South China Sea. The Liuhua development, completed in 1996, pioneered the large-scale modular subsea scheme (25 subsea wells) from a production and storage semisubmersible with a separate tanker storage and offloading vessel. It is still ranked as the largest field development in the South China Sea. Recent Deepwater and Subsea Developments Since 1999, BP has embarked on the execution of a number of recordbreaking deepwater subsea developments worldwide that include Thunder Horse, Atlantis, and Greater Plutonio, among others. Thunder Horse. One of the largest fields ever developed in the GOM, the Thunder Horse development includes 19 subsea wells, four manifolds, and 30 pipeline-end terminals (PLETs)/ sleds in 2000-m water depth. The system is designed to produce 31 800 m3/d oil and 5 700 m3/d of gas. The Thunder Horse development set a number of records as an HP/HT development (1040 bar and 130°C, respectively) and the largest production/drilling/quarters semisubmersible ever built at some 45 000 tonnes (Fig. 1). Atlantis. The Atlantis field, discovered in 1989, came on stream in 2007. It is the world’s deepest subsea development, in approximately 2100-m water depth, with a design capacity of 31 800 m3/d of oil and 5098 m3/d of gas. It has four manifolds, four pipeline-end manifolds, five PLETs, 16 producers, and four water-injection wells tied back by steel catenary risers to a production/quarters semisubmersible. The Atlantis field presents numerous challenges including geohazards as a result of the proximity of the steep Sigsbee escarpment, high bottom currents, a complex bathometry, and numerous flow-assurance issues. Greater Plutonio. The Greater Plutonio development represents a major achievement for subsea-development projects. It comprises 54 subsea wells, nine manifolds, and a riser tower in 1258 m of water (tallest in the world). The development includes more than 105 km of umbilicals and 160 km of flowlines, including a unique singleleg 22-km insulated flowline on the northern sector with an uninsulated water-injection service line to provide circulating capability to avoid the cost of a dual insulated line. The FPSO has a rated production capacity of 31 800 m3/d and has on-board storage capacity of 318 000 m3. Other features of this development include subsea multiphase metering and running the Christmas trees on wires. North Sea. The Farragon development, started in 2006, features a 6.5-km-long bundle for a two-well project. The HP/ HT Rhum gas field uses a high-integrity pressure-protection system (HIPPS) JPT • AUGUST 2008 Resources to protect a 25-km, 16-in. pipe-inpipe bundle. Future Challenges The last wave of subsea-technology development projects harnessed additional reserves in rather challenging circumstances—long offsets, deepwater, HP/HT, and small reservoir pockets. On the near horizon, the challenge is to improve reserves recovery from subsea developments to achieve and exceed those from dry-tree developments. Future challenges will need to address a number of issues, including extended well testing in ultradeep water and harsh environment and operating in remote and/or ecologically sensitive regions (e.g., the Arctic) with few local host facilities. In addition to all the technology challenges, the entire oil and gas industry will need access to highly skilled, but limited, human resources essential to development and implementation of these technologies. Deepwater Research and Development A long-term research and development program helps to deliver deepwater and subsea developments successfully. The ultimate “prize” sought through research is a reduction in project cycle time and cost without a loss in product quality while maintaining long-term integrity. The deepwater research and development program is administered according to four main themes: floating systems and moorings; riser, flowlines, and pipelines; flow assurance; and subsea reliability and integrity. From these many challenges, the following technology focus areas have been identified: subsea processing; HP/HT; inspection, maintenance, and repair (IMR) technologies; and cold flow and subsea reliability. In addition, technology associated with operating subsea developments in arctic conditions also is under investigation. Subsea Processing (Boosting and Separation). This focus area includes the development of technologies for boosting production from subsea fields to enhance recovery rates and overcome host ullage and weight constraints. Associated technologies also would assist with reduction of distance-related costs and flow-assurance difficulties on long tiebacks. Potential areas of application include ultradeep water in Angola, The World’s Fastest and Most Robust Full-Physics Reservoir Simulator No other model even comes close Get the Evidence at CoatsEngineering.com Generations ahead - Free download Who dominates SPE10 Model 2? 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[email protected] www.petrostudies.com T.T. & Associates Inc. T 78 JPT • AUGUST 2008 the deepwater GOM, and the longer tiebacks in basins with arctic conditions. Industry has developed synergistic technologies such as the all-electric subsea control system and standard electrical communication protocol. HP/HT. The HP/HT program kicked off in 2002 after a preliminary survey of the industry to gauge lead time for project deliverables. From the inception, the HP/HT program was staged to work in tandem with the exploration-drilling program. One key project enabler, with universal application, are the HIPPSs. Other aspects of the HP/HT research and development include codification of new design standards, novel material and welding technologies, a standardized subsea tree/wellhead system, seabed high-pressure chemical injection, and intervention tooling. IMR Technology. IMR technologies are focused on autonomous underwater vehicles (AUVs) and lightweight wellintervention methods. AUVs have no umbilicals and can operate from a minimal vessel, with the future goal to eliminate completely the need for any vessel. In 2001, BP successfully pioneered the use of the technology for seabed surveys in the GOM. The vision is to have a shore- or facility-based AUV system for pipeline, riser, and mooring inspection; light intervention; and general structural/ field inspection. To date, two advanced AUV field trials were funded in 2006 and 2007. Further work will be required in the areas of launch-and-recovery systems and sensor technology. For lightweight well intervention, the business driver is improved system availability at an economical cost. The components of the subsea-intervention lubricator system have been qualified fully, and a field trial is carded for 2008 in approximately 1070-m water depth. The trial will test a basic wireline-tosurface system with a subsea lubricator. If successful, this will set a precedent because water depth is almost twice the depth of any previous riserless intervention. Recently, a wireline subsea system was developed where the wireline winch and tools are deployed on the seabed. The system is encased in a single container to reduce risk, with no wires protruding from the pressure vessel. Cold Flow. Cold-flow technology deals with problems of hydrate and wax deposition in subsea pipelines. In a conventional subsea tieback, flowline fluids will, if unprotected, form hydrates and wax solids, particularly during shutdown and restart. Present solutions are expensive preventive or remedial measures that increase in cost with increasing water depths and offset distances. In a new coldflow process, a hot well stream is mixed rapidly with a cooled recycle well stream containing hydrate and wax particles that act as seed crystals. This produces a stable slurry of tiny suspended hydrate and wax particles that readily flows without forming a plug. The technology is particularly well suited for harsh environments where surface-piercing structures are undesirable and where long transport distances to existing facilities, hubs, or to shore are required. The system complexity is low, promising low maintenance costs. This technology has the potential to deliver significant cost savings and can be an enabler for development of smaller oil fields with marginal or unattractive economics. Subsea Reliability. BP collaborated with Cranfield University in the UK to develop a set of reliability processes that culminated in an industrywide subsea reliability standard. Through the implementation of this strategy, BP has achieved worldwide recognition as the industry leader in setting new standards to enable achieving long-term reliable performance of subsea equipment. This strategy is being implemented now across BP global subsea projects and Frame Agreement contracts. Conclusions The successes to date of BP, and the ability to meet future challenges, depend on a progressive in-house approach to novel-technology development. Keys to the program are developing and maintaining a world-class staff of engineering experts supported by state-of-the-art tools and processes. Technology breakthroughs required in the past included advances in the design, installation, and operation of floaters, risers, and flow assurance. Future breakthroughs will require that existing technologies be evolved to address challenges unique to HP/HT reservoirs, long-distance tiebacks, arctic conditions, and stranded deepwater JPT oil/gas reserves. JPT • AUGUST 2008