Perdido is located in the Western Gulf of Mexico in 7,817 feet of water. It is being developed with cutting-edge subsea technologies to mitigate the project's key development challenges, which include extreme water depth, rugged seafloor terrain, low-pressure reservoirs, and aggressive hydrate formation tendency. This paper provides an overview of the Perdido Development subsea and flowline system and its associated flow assurance strategy. This paper also includes reviews of the design, fabrication, and installation of key subsea equipment such as twophase separators, subsea trees, manifolds, top-tensioned production risers, umbilicals, and flowlines. In particular, the two enabling subsea technologies, subsea boosting system and surface Blow-Out Preventer (BOP) for drilling and completing of subsea wells, are discussed. Unique features of the Perdido subsea system include:All wells are subsea (wet trees operated by umbilicals) and consist of 22 local Direct Vertical Access (DVA) wells and 12 offset wells.The subsea DVA wells are drilled, completed, and intervened through a single high-pressure drilling/completion riser and a surface BOP with the host rig.All production will flow from manifolds into five subsea boosting systems where gas will flow naturally to the topside facility, while liquids will be pumped using electrical submersible pumps (ESPs). Introduction The Perdido Development, jointly developed by Shell, BP, and CVX, includes the Great White, Silvertip, and Tobago fields and is located in the Perdido Basin and Foldbelt, in the Alaminos Canyon Protraction Area. This area is located in the western Gulf of Mexico, 200 miles south of Freeport, only eight miles north of the Mexico maritime border. All three fields are developed with subsea wells tied back to the host, which is a Spar with full offshore processing capabilities and pipelines for export.
Typically, offset flowlines (both ends located subsea without a surface piercing riser) are installed and tested with the mainline back to the host facility. However, expansion of existing infrastructure in deepwater has created a need for the ability to test flowlines without a surface piercing element. To accommodate subsea expansions of brownfield developments, there exists a need for definition of criteria and design of hardware to provide for the flowline precommissioning function. This paper describes the processes implemented for garnering industry consensus and regulatory approval, as well as the criteria applied to system selection and design. Introduction The first subsea pressure testing of a production flowpath was the Macaroni Manifold testing in June, 1999. The manifold was tested to 10,000 psi in 3700 feet of water. The technology was based on ROV based injection systems, which have been used for pressure testing of subsea connections, such as jumper connectors; and high pressure packages, such as the jetting skid developed for pipeline burial on the Angus project. Einset was the first subsea Gulf of Mexico flowline to perform a regulatory hydrostatic test using an ROV based system. Typically, offset flowlines (both ends located subsea without a surface piercing riser) are installed and tested with the mainline back to the host facility. However, expansion of existing infrastructure in deepwater has created a need for the ability to test flowlines without a surface element. Einset. The SE Tahoe flowlines and wellhead were installed and became operational in 1996. The system included a spare hub on the SE Tahoe sled for future expansion. The Einset prospect is located 5 miles from the SE Tahoe sled, and was tied back to SE Tahoe with a 6-inch flowline in December 2001, as illustrated in Figures 1 and 2. Advantages of a Subsea Hydrotest System. For subsea-bysubsea flowlines, a means of hydrotesting subsea is desirable. The alternative to subsea testing is cleaning the mainline and testing both the existing mainline and new subsea line together. This may require existing production to be deferred while the flowline is displaced with multiple linefills of water to remove all hydrocarbon and residue. The contaminated water must be processed or disposed of appropriately. Alternatively, using a subsea hydrotesting system, the new segment of flowline can be tested without impacting the mainline and then a final pre-tested connection installed without loss of any production. High pressure testing in the congested confines of a production platform creates an undesirable, although manageable, hazard to personnel. However, subsea testing eliminates the exposure by relocating the pressure source to the seabed. As deepwater prospects trend toward higher shutin tubing pressures, the risk is increased. The number of deepwater 15K systems is growing quickly, requiring test pressures exceeding 18,000 psi. In addition to the higher pressures, longer offset lengths (host to well) are being enabled. The longer lengths result in greater flow assurance requirements and better insulation. Traditional hydrotesting typically utilizes surface seawater (70 degrees F).
This p a w war m W a d tw premtallon by !ha OTC pmOrm CommMee folkwing rev'w of information c m t a h d inM abalrd submillad by the uthods). Contsntr of the POW. as prewntad, have nor bm revwwed by th. M h o r e Technology C a r h n n u , and are rubjea to c~a l o n by the wlhor(s). The mnni#l, u pramtad, a s no1 nacasurily r.nba any poritw of ma Onahom T.chnol-y Confwmm or its o(Aan. E W m i c reprodudion. dislribulion, or stong. of m y pul d mom paper for c u n m~a l plcpoms without th. wrillen conmom d tho Onahom T.chnolopy Contmcl, is pmhbitad. Pamilaion to nprodua intmnt is resviclad to an abaind d nor m a r Uun 300 wrdr; ilkutntlQlr may nor bo copiad. The abar.cl must contain conmpiarars acknowl.dgmsnt d w h w and by whom the paper wes prassnlad AbstractThe subsea development scheme for the Tahoe field utilizes an innovative approach to tie-ins of multiple flowlines using hard pipe fabricated jumpers and vertical collet connections. Umbilical connections take advantage of recent advances in ROV "flying lead" technology to connect bundles of control system and chemical injection lines. The Tahoe field will see between six and ten subsea satellite wells completed with flowlines routed back to a host platform. This approach to tieins mimics simple, diver installed spool piece connections and umbilical stab plate connections which were the industry standard methods for several decades.
The Perdido Development project, in the Gulf of Mexico, has set several record firsts; including, in 4500 feet of water, the first diverless deep-water tie-in to an existing export line and the deepest tie-in to an in-service pipeline system. It is also the first to employ a unitized foundation and prefabricated jumper spool. Identifying options for transmission of oil and gas production from the deepwater spar facility to shore required innovative thinking and input from many technical disciplines. The options were limited; Perdido is located in an area with little export infrastructure, and the route to shore covers some of the gulf's most challenging terrain. The closest shallow-water platform is over 140 miles from Perdido. Analysis revealed that the lowest cost option with the most manageable risk was a tie-in to the existing HOOPS export pipeline, approximately 70 miles north of Perdido. However, connecting to an 18-inch, operating pipeline in deep water provided major engineering challenges. The project required subsea installation of a piggable wye in the HOOPS pipeline to provide a connection point for Perdido. In a clear break with conventional tie-in projects, an innovative new methodology was developed that enabled the Perdido export connection system to be fabricated in its entirety onshore and reassembled on the pipeline using a reference system to ensure a perfect fit. The objective was to reduce HOOPS shut-in time and return the pipeline to service as safely and efficiently as possible. However, the connection system also had to meet several other criteria: zero release of hydrocarbons and re-configurable, which would provide the flexibility to serve future connection needs. Six months after the project's spar production platform was put into place, the Perdido subsea tie-in was installed on the seafloor. HOOPS production was interrupted for 17 days in March 2009 to accommodate the connection. Consistent with Shell's commitment to protecting people and the environment, the work was executed with no safety or environmental incidents. The ability to connect subsea without a pre-existing connection point is an enabling technology available to the industry as it continues to move into ultra-deep water while executing projects far from existing production transportation infrastructure. Introduction The Perdido spar is the world's deepest direct vertical-access spar. Moored in a water depth of 7817 feet with flowlines extending to 9790 feet, it will act as a hub for and enable development of three fields: Great White, Tobago and Silvertip. The Perdido Development is a joint venture between Shell (operator), Chevron and BP. Located in Alaminos Canyon blocks 857, 859 and 815 in the western Gulf of Mexico, it supports subsea wells connected to the spar host facility by a system of flowlines and subsea structures.
Novel methods were required to address the high operating temperatures of the Appomattox flowlines. Appomattox is predicted to operate as high as 365F, requiring thermal mitigation along the length of the flowline and anchoring at the base of the riser. Existing thermal mitigation methods were screened but were found unacceptable. Alternatively, a system of multiple buoyancy modules was found to be highly efficient and reliable to address the thermal expansion along the length of the flowline. Also, a unique rigid anchoring system was designed to restrain the riser base. Appomattox began production in Q2 of 2019. A flowline survey performed in Q3 2019 demonstrated good alignment with the analysis predictions for buckling locations, shapes and buckle magnitudes.
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