Improving oil production is one of the most challenging subjects in carbonate reservoirs, especially in the case of thin formations when reservoir pressure is close to saturation pressure with undesired well locations. In this study water injection was used to mitigate gas production in a thin reservoir with high gas oil ratio for the purpose of optimizing oil production.

The studied field is a cretaceous oil bearing reservoir composed of tightly packed limestone characterized by high porosity but poor permeability with a thickness of 55-65 meters throughout the reservoir. The matrix permeabilities and porosity are in the range of 0.01-150md and 5-35 percent respectively. The oil gravity is 21.5 degree API and reservoir pressure of 1700psia which is close to bubble point pressure of 1492psia. The produced wells were drilled in top layers of the reservoir.

A full field model was constructed to determine the optimal production strategy and applied reservoir management with available produced well locations. Two possible scenarios; namely, natural depletion and water injection were compared. Results indicated that water injection yields better recoveries than natural depletion. Different scenarios of injection well location, well orientation and mechanism of injection were considered.

Horizontal injection and production wells located at same layer were found to maintain reservoir pressure, prevent gas production, and increase oil recovery. Depleted regions near the producers were found to play a major rule on the success of the project. The enhancement of oil recovery was improved to 37 percent in the case of water injection with the implementation of proper reservoir management.

You can access this article if you purchase or spend a download.