Integrated Production and Reservoir Modeling To Optimize Deepwater Development
- Karen Bybee (JPT Assistant Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- May 2011
- Document Type
- Journal Paper
- 70 - 73
- 2011. Society of Petroleum Engineers
- 1 in the last 30 days
- 106 since 2007
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This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 131621, "Application of Integrated Production and Reservoir Modeling To Optimize Deepwater De velopment," by R.F. Stoisits, SPE, and H.M. Bashagour, ExxonMobil, and C.G. Su, SPT Group, originally prepared for the 2010 CPS/SPE Oil and Gas Conference and Exhibition in China, Beijing, 8-10 June. The paper has not been peer reviewed.
A deepwater satellite-field project encompasses two fields that are in the general vicinity of two existing floating production, storage, and offloading (FPSO) vessels. A number of development architectures that include various subsea tiebacks to two existing FPSOs were potential candidates for development. To establish an optimal subsea umbilical, riser, and flowline (SURF) architecture, a method to forecast production behavior of the various architectures is required. To achieve this objective, an integrated-production-modeling (IPM) tool was developed.
A deepwater development in West Africa consists of five fields that send production to two FPSOs. Two more fields currently are under development. The basis for the satellite project is a blockwide study (BWS). The objective of the BWS was to assess how best to develop the two discovered, but so far undeveloped, assets in the vicinity of the two existing FPSOs. The BWS concluded that these assets could be commercialized most economically in a common development as subsea tie-backs to the two FPSOs, filling processing ullage.
The BWS identified a high level of uncertainty involved in developing the satellite fields. In particular, both the resource base of the assets and the ullage expected to be available on the FPSOs are difficult to assess, with estimates varying considerably. The two target fields comprise complex, compartmentalized reservoirs with lower resource density and poorer-quality crude than the other existing developments. The BWS along with a parallel study, the execution breakthrough task force (EBTF), examined numerous development architectures. Analysis of these architectures concluded that an all-subsea-tieback development provided more-favorable economics and greater flexibility in responding to changing resource assessments than did concepts that included another FPSO. It also pointed to the concept developed by the EBTF which consisted of a loop flowline system connected to both existing FPSOs, as providing the greatest resource, ullage, and operational flexibility. Fig. 1 shows the final selected development concept that forms the basis for the satellites project.
The satellite loop consists of a single 27-mile production-flowline loop connecting the two FPSOs and includes the development of the two fields with 17 subsea wells drilled from four drill centers. The 10-in.-inner-diameter pipe-in-pipe (PIP) flowlines are connected to each FPSO by a newly installed 12-in.-diameter gas lifted PIP single hybrid riser (SHR). Two 12-in.-diameter water-injection flowlines (a 9-mile line from FPSO 1 to satellite Field C and a 7-mile line from FPSO 2 to satellite Field M) are connected to the FPSOs by existing water-injection risers. All gas is injected down existing FPSO gas-injection wells. All processing occurs on the FPSOs with additional I-tubes installed as required and various modifications made to their topsides to accommodate the increased infrastructure.
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