The main objective of this study was to determine the optimum polymer-injection strategy for the Polymer-Flood Expansion area in the Sarah Maria South Area of the Tambaredjo Field through reservoir simulation. The performance of the performance of the polymer-flood pilot was used as a sanity check for the obtained optimum polymer-injection strategy.

The performance of the existing polymer-flood pilot area was examined. Polymer related properties were obtained using the polymer-flood pilot data.

The key points (well-pattern design and combination of oil strata) of polymer-flood designs for the polymer-flood expansion area of the Tambaredjo Field were discussed. A large number (> 400) of polymer-injection scenarios in terms of different polymer-injection concentrations, downhole injection pressures, numbers of new wells, and injection sequences (tapered, flared, and uniform injection) were performed using the previously obtained history-matched dynamic model. The simulation runs of these scenarios were elucidated in detail.

The review of the polymer-flood-pilot performance reveals that polymer injection increased the developed reserve by 17%. In the Tambaredjo field, the permeability, the temperature, the salinity, and the reservoir type (sandstone) are favorable for polymer injection. However, the oil viscosity and reservoir heterogeneity are not favorable for polymer injection.

It turned out that the ratio of sweep to injectivity plays a key role in determining the optimum polymer-injection strategy. The optimum well pattern turned out to be driven by the remaining oil, existing wells, and connectivity. For all the polymer-injection scenarios, there is no value (no incremental oil) to go above downhole pressure 850 psi to inject polymer. Flared scenarios for a given cumulative polymer injection, are better than the tapered and constant-injection-concentration scenarios in terms of incremental oil and displacement efficiency. From a technical point of view, the flared scenarios with low average polymer-injection concentrations and shorter time intervals are optimum.

No further activity forecasts an oil recovery of 18% until year 2034. For full-field implementation (i.e., 102 injection wells), water injection as a base line to the performance of polymer injection can lead to a recovery factor of 21.5% until year 2034. Finally, full-field polymer injection (102 injection wells, flared injection sequence with polymer-injection ranges from 0 to 3,000 ppm and one-year time interval and injection pressures of about 800 psi) can lead to a recovery factor of 25%. Therefore, the optimum polymer-injection strategy can potentially increase the developed reserve by 39%.


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