This extended abstract describes the use of infill drilling to improve solvent sweep efficiency and EOR recovery in a gravity dominated WAG flood.
Much of the incremental oil recovery in the Prudhoe Bay Miscible Gas Project (PBMGP) is displaced from a relatively small volume of swept reservoir surrounding each WAG injector. Solvent override occurs due to high vertical permeability and the large density difference between solvent and reservoir fluids. Solvent rises to the top of the reservoir or underneath shales, forming cone-shaped swept intervals around WAG injectors (Figure 1).
Vertical sweep by solvent in gravity dominated WAG floods can be improved by increasing the viscous-to-gravity ratio. A higher viscous-to-gravity ratio (HVGR) expands the solvent swept areas around the injection wells before gravity segregation occurs. However, little can be done in the PBMGP to reduce gravity forces, and water and solvent injection rates are currently near the maximum attainable.
Reduced well spacing remains the only viable method to increase viscous-to-gravity ratio. Most of the benefit from reduced well spacing is due to displacing oil from new WAG cones around the new injectors.
Early screening indicated the central portion of the Northwest Fault Block (NWFB) area of the Prudhoe Bay field should be favorable for increasing EOR reserves from reduced well spacing. Favorable characteristics include a thick oil column of up to 300 feet, relatively short shales with maximum lengths believed to be a few hundred feet, and higher permeability in the lower half of the pay interval.
Fine grid mechanistic simulations were used to investigate different infill pattern scenarios and the impact of reservoir description uncertainty. Simulation results indicate most of the incremental recovery is attributable to miscible sweep around the new WAG injectors. The infill project reduces well spacing from 80 to 60 acres and is projected to increase recovery by 4% OOIP, with less than 1% OOIP attributable to improved waterflooding.
Simulations indicate that long shales extending between wells (2000 feet) could significantly reduce EOR reserves. Long shales break the reservoir into a series of thinner intervals with individual WAG cones forming within each interval. Recovery decreases because complete gravity segregation occurs closer to the injector in the thinner intervals.
Infill patterns were evaluated to maximize additional recovery and oil rate, while minimizing investment.
Nine-spot, line-drive, and five-spot infill patterns yield similar incremental recoveries. However, the line-drive pattern requires fewer new wells and achieves higher initial oil rates per new infill due to more favorable infill locations.
The linedrive also takes advantage of historical flood anisotropy caused by a west-to-east pressure gradient in the NWFB. Watercuts and GOR's are higher in producers located north-west and south-east of existing injectors. The line-drive pattern allows the new injectors to be oriented north-west to south-east in more mature locations, while the new producers are located in relatively less mature areas.
The Prudhoe Bay Unit implemented the first phase of a line-drive infill project in 1992 based on this work. The central portion of the NWFB was converted from an 80 acre inverted nine-spot to a 60 acre line-drive by drilling seven producers and one injector, with three producer-to-injector conversions (Figure 2).
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