There are limitations to the amount of free gas that can be handled by high volume downhole pump systems. A new pump design employing axial flow impellers coupled with high speed downhole turbine drive has been developed, and is the first true downhole multiphase pump. This paper describes the staged research and development program leading to the first field trial installation in the Captain Field, in the North Sea. Development and design requirements are reviewed, with the results from laboratory testing in water and nitrogen followed by full scale loop testing in multiphase fluid, including crude, methane and brine. Test configuration is described, and key performance results reviewed. Special testing defined the nature of fluids and rheology related to high rotational speed pumping of viscous crude and brine mixtures in pumps and pipelines. Following successful laboratory scale testing, design considerations are reviewed for its application in a field trial. Completion design includes provision for open loop flow and access below the pump assembly for coiled tubing intervention. New downhole monitoring systems employ pump and turbine monitors along with pump flow and reservoir evaluation monitoring. The design results in extended range of pump operability, improved reliability, and improved control and reservoir management. Introduction As technology improves in horizontal drilling, completion practices, and subsea equipment, the need for high volume downhole pumping systems has increased. Small accumulations or thin oil zones, previously considered marginal, can be exploited economically. But in some applications, pumping systems needed higher gas handling capability because maximizing recovery from individual wells requires larger pressure drawdown. Additionally, horizontal wells located at the top of the productive intervals can encounter free gas caps. Development of a downhole pumping system that could operate successfully in a gassy environment (higher than 30% gas void fraction), and deliver high reliability was key to exploiting new reserves. This technology could be applied within many major oil compani's existing asset portfolio, such as the Gulf of Mexico or West of Shetlands deepwater environments, and elsewhere in the North Sea. One of the assets that could benefit from this technology is the Captain Field. Although the main area of the field is being developed with Electrical Submersible Pumps (ESP), an isolated gas cap was identified in the eastern section of the field that would limit the reliability of ESP systems, and would limit the withdrawal rate. The field has 19 degree API crude oil, with 88 centipoise (CP) viscosity at reservoir pressure of 1300 psi and 87 deg F.
The Captain Field has been developed with high volume ESP systems, designed for maximum reliability. The process involved integration of new technologies and production practices to the development of high horsepower systems for viscous oil wells and aquifer lift. This paper describes the key aspects of the design and implementation of the artificial lift systems employed in the development of this offshore field using horizontal wells in unconsolidated sand Appraisal well testing results were used to develop key facility and well functionality, and development of a performance based incentive pump supply contract. Electrical testing demonstrated suitability of electrical penetrator systems for high amperage service. System selection and sizing integrated specially designed full scale multiphase loop performance testing with viscous crude. Completion equipment selection targeted systems to add flexibility for extending pump run times. New downhole monitoring systems were developed integrating ESP condition monitoring with downhole flow and reservoir performance evaluation. Surface control systems integrated downhole and surface parameters to optimize performance and protection of equipment. Special operating guidelines were developed and utilized during the early production phase for troubleshooting, optimization ofwell performance and reservoir evaluation. Introduction The Captain Field is approximately 90 miles north-east of Aberdeen, Scotland in the UK Continental Shelf Block 13/22a. The field was discovered in 1977 and it was clear that economical extraction of the low density (19 API), viscous (88 centipoise), low gas oil ratio crude oil, from a shallow field (3000 ft depth) with a large area extent (7.3 miles × 3.3 miles) would not be easy. The permeable, unconsolidated, thin sands (100 ft) were underlain by water in portions of the field Not until appraisal testing conducted in 1990 and 1993 using electrical submersible pumps and long horizontal wells with prepack screens, was it clear that these technical challenges could be overcome. During 1993, a ten well appraisal program, including an extended well test of a field development prototype well, water coning test, field delineation drilling, and topsides definition engineering was successfully completed. Conclusions from this program indicated that successful field development would require horizontal wells up to 6,000 ft long, artificial lift systems to deliver 15,000 BPD from each oil well producer. It would require sand control well completions, the capability of performing production logging and coiled tubing intervention of the horizontal completions. It would require high temperature and high retention time fluid separation equipment to treat 60,000 BOPD and 200,000 BWPD, and a single aquifer lift well to deliver 60,000 BWPD make up water for waterflooding at full voidage replacement. The field would be developed in two stages, with the main western section developed first with a Wellhead Protection Platform (WPP), producing via subsea pipelines to a Floating Production, Separation and Offloading (FPSO) vessel.
Texaco UK North Sea is operator and 100%
Funding and support: By JACEP Open policy, all authors are required to disclose any and all commercial, financial, and other relationships in any way related to the subject of this article as per ICMJE conflict of interest guidelines (see www.icmje.org). The authors have stated that no such relationships exist.
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