Optimized EOR Design for the Eileen West End Area, Greater Prudhoe Bay
Authors: Panda M. N. , Ambrose J. G. , Beuhler G. , McGuire P. L. 
Published: March 2009

The Prudhoe Bay field, on the north coast of Alaska, is the largest oil field in North America. Discovered in 1968, the Prudhoe Bay field is a massive sandstone reservoir complex covering more than 200 square miles.

Eileen West End (EWE) is a western extension of the Prudhoe Bay field, connected only through the aquifer. It consists of two tilted fault blocks, each with a gas cap and an oil leg with a combined oil originally in place (OOIP) of more than 750 million STB. Production began at EWE in June 1988, approximately 11 years after Prudhoe field startup.

Designing an optimal development strategy for a large oil reservoir like EWE is a challenging objective, both technically and commercially. It is especially true when the reservoir is structurally complex with numerous crossing faults. EWE is also complex stratigraphically, with both continuous and discontinuous shale bodies and tightly cemented sandstone intervals. In such cases, the logical starting point is to use the analog of a successful project, such as mainfield Prudhoe Bay. EWE initially was developed in the same style as Prudhoe Bay. To accomplish this, excess produced gas from Prudhoe Bay was injected into the EWE gas caps with a hope that the reservoir would produce with effective gravity drainage in a manner similar to that of Prudhoe Bay. Conductive faults and shale barriers, however, led to unexpected early gas breakthrough.

High gas/oil ratios reduced the oil production rate, leading to a reduced recovery factor from the field. A review of surveillance data, material balance studies, fluid mapping, simulation, and other analog data changed the perception that gravity drainage was an efficient recovery process at EWE. The work also showed that the aquifer influx was stronger than anticipated. As a result, gas injection was stopped in 2001, and water injection into the gas caps was started for pressure maintenance and to prevent oil from resaturating the gas cap.

To mitigate the prospect of low recovery from EWE, a modified comprehensive recovery plan was developed. A pattern water-alternating-(miscible)-gas (WAG) flood was initiated in 2003. The initial WAG patterns targeted areas with large gas cap expansion and gas underruns to capture oil trapped in these gas-invaded intervals. The WAG flooding is being expanded to areas of low gas cap expansion and peripheral regions. The main features of the modified comprehensive recovery plan are:

stop injection of lean gas into the gas cap; inject water into the gas cap to maintain the reservoir pressure and prevent the strong bottom aquifer from pushing oil into the gas cap; develop pattern floods to maximize volumetric sweep; and initiate a WAG flood to optimize ultimate recovery.

The flood patterns are developed by converting existing producers into injectors and also by drilling infill injection wells.

This paper describes the technical process used to select the major design parameters of the pattern WAG flood to optimize EWE recovery. The key parameters evaluated were slug size, injection rate, WAG ratio, and WAG sequencing. A fine-grid, fully compositional numerical simulator was used to determine the optimal design parameters. The modeling indicated that multiple WAG cycles with high voidage replacement ratio (VRR) during the gas cycle with an overall WAG ratio of 1 provided the largest cumulative oil recovery. Timing of the first gas slug within the first year after start of waterflood in addition to realignment of the injection and production wells also optimizes recovery. Surveillance of the secondary and tertiary recovery through well performance monitoring and surface and downhole data acquisition combined with classical reservoir engineering is ongoing to ensure that the EWE enhanced-oil-recovery (EOR) project remains optimized.