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Sandstone reservoir with polymer injection

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This page provides a reservoir management case study for a sandstone field in which polymer injection techniques have been implemented.

Background and geological information

Production is from three sandstone zones of a Cretaceous-age formation. Productive area of the polymer project was 3,560 acres. Gross thickness was 230 ft, and net-to-gross thickness averaged 0.3. Porosity averages 27%; permeability varies by zone and is less than 100 md in two of them and 170 md in the third, most extensive one. Oil gravity was 20° American Petroleum Institute (API), and viscosity varied from 18 to 24 cp. TR was 150°F.

Program used

The primary depletion mechanism was solution-gas drive. The field was developed competitively on 40-acre spacing. A unit was formed, and waterflooding began with a staggered line drive. Injection water with a salinity of only 3,500 ppm total dissolved solids (formation water 150,000 ppm) was used without any apparent damage caused by clay swelling or sloughing.

The adverse mobility ratio was recognized early in the waterflood and polymer injection begun in 1976. Polymer concentrations were targeted to improve the mobility ratio by a factor of 16 (reduced to 0.5). The injection of polymer was targeted to reduce the cycling of water through previously water-swept oil sands and to divert injected-brine polymer into noncontacted zones to displace additional oil.

Recovery performance

Waterflooding increased oil rates from 300 to 2,000 barrels of oil per day (BOPD). The rate had declined to 1,600 BOPD when polymer injection began. The rate of oil production decline subsequently was reduced in several wells. Primary plus waterflooding recovery factor was 23% of original oil in place (OOIP). Subtle changes in production decline rates and WOR (acronym) make it difficult to determine the incremental recovery from polymer injection. An incremental increase of 1 to 3% of OOIP has been estimated. Lower injectivity resulted when polymer was added.

Field surveillance and management

Surveillance activities focused on maintaining injectivity and pattern balancing. Well stimulations and cleanout were needed. 2D cross-section simulation was used to manage the injection volumes and distribution of polymer and to design the optimum concentrations of the final polymer injection. Rates were adjusted to inject an average of 20% PV of 600 ppm polyacrylamide polymer solution.

Noteworthy papers in OnePetro

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External links

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See also

Reservoir management

Polymer waterflooding