Summary
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 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.
© 2009. Society of Petroleum Engineers
View full textPDF
(
2,414 KB
)
History
- Original manuscript received:
12 December 2007
- Meeting paper published:
4 December 2007
- Revised manuscript received:
9 May 2008
- Manuscript approved:
19 May 2008
- Published online:
2 March 2009
- Version of record:
26 February 2009
View Cart
