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Abstract The Ompoyi and Orindi fields are located 5 km offshore Gabon in a water depth of 20 m. The high oil density (23ยฐ API) and high produced water salinity (150 kppm) combined with reservoir pressure depletion meant that primary production of the Ozouri reservoir required artificial lift. Initially, progressing cavity pumps (PCPs) were selected, however, following failures of the elastomers, electric submersible pumps (ESPs) were deployed to produce at higher rates with high gas/oil ratios (GORs). The production instability associated with the dual-porosity reservoir behaviour and high free-gas content in both the inflow and outflow of the wells presented the main challenge to ESP design and operation. Additionally, most of the wells were remote from the main production facility and were produced via multiphase subsea flowlines, which made well testing difficult due to the phase segregation in the flowlines. To achieve economically viable production utilizing ESPs, innovative use was made of a range of existing technology. Operationally, however, real-time monitoring was essential to setting wellhead pressures and pump speed to maximize drawdowns. Key technology elements were monopods to minimize the offshore structure cost, fit-for-purpose subsea power cable and helicoaxial downhole pumps for high gas void fraction operation. Key lessons were learned following the trial of several completion architectures to find the optimal combination of gas venting, reservoir access, and a dual barrier mechanism. The first well was put on production in 2002. Since then a further 10 wells have been drilled to reach a total liquid production of 8,000 B/D with a 60% water cut. Production has been economical and thus confirmed ESPs as being the right solution for this reservoir. The lessons learned prove that the application of ESPs is not limited to traditional waterfloods and that it is feasible to produce challenging reservoirs with ESPs.
- Europe (1.00)
- North America > United States > Texas (0.69)
- Asia (0.68)
- Geology > Structural Geology > Tectonics (0.46)
- Geology > Rock Type > Sedimentary Rock (0.46)
- Geology > Petroleum Play Type > Unconventional Play > Fractured Carbonate Reservoir Play (0.40)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- North America > United States > California > San Joaquin Basin > San Joaquin Valley > Monterey Field > Monterey Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Milne Point Field > Kuparuk Formation (0.99)
- North America > United States > Pennsylvania > Warren Field (0.93)
- Africa > Gabon > Gabon Basin > Ozouri Field (0.93)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (2 more...)
Abstract Traditionally it has been quite a daunting task to place high-performance cement in tophole sections of many subsea wells, where tight-formation pressure windows pose problems for operators. Cement jobs have reportedly been unsuccessful in numerous cases under such challenging conditions. Losing cement to the formation, plus the added problems of shallow gas and water influx, have been common elements in such cement-job failures. AGR has developed a cementing method that mitigates the risk of losses in tophole sections during circulation and early gas migration in the dormant and transient-gelation periods. This subsea Managed Pressure Cementing (MPC) method was implemented successfully first time in early 2010 on a subsea well in the Caspian Sea, isolating unconsolidated, overpressurized sand stratum with well-bonded cement. This meant drilling could continue to the next hole section with the desired integrity at the shoe. Proven Riserless Mud Recovery (RMR) equipment, which includes the Subsea Pump Module (SPM) as the key component of the system, is used for subsea MPC operation. A closed-loop circulation system is established facilitating an excellent level of control over the wellbore pressure gradient, so wellbore pressure falls inside the pressure window of the formation during all stages of the cement job. Any small amount of loss is detected immediately and cured by the subsea pump inlet pressure. Great potential was seen with this subsea MPC method. Indeed it has not shown any problems that would prevent its use in similar situations. This paper examines details of this method and its successful applications in one of the most challenging areas in offshore.