Simulation of the Triple Completion-Gas Downhole Water Sink-Assisted Gravity Drainage Process through the Re-Injection of Petroleum Associated Gas (PAG)

Abstract The ongoing production of oil results in a gradual depletion of reservoir pressure over time. This decline in pressure persists until it reaches a threshold at which the reservoir can no longer yield hydrocarbons through primary recovery methods. Therefore, the implementation of secondary recovery techniques is necessary to streamline pressure maintenance operations. This intervention mitigates the pressure decline for a limited period, repeating the process until the reservoir no longer generates hydrocarbons through secondary recovery techniques. Therefore, we employ tertiary recovery strategies as the last resort to enhance oil recovery from the reservoir. In this paper, we reconstructed a compositional reservoir simulation model to simulate the use of Petroleum Associated Gas (PAG) for re-injection in clastic reservoirs, surrounded by strong water aquifers, with the aim of maximizing oil production and minimizing water cut to the greatest extent possible. We specifically employed the Triple Completion Gas Downhole Water Sink Assisted Gravity Drainage (TC-GDWS-AGD) process on the Upper Sandstone member to improve cumulative oil production and reduce water cut. The TC-GDWS-AGD process places a 7-inch casing diameter and two horizontal completions, one for water production beneath the water-oil contact and the other for oil production within the high oil saturation oil zone. A packer isolates both completions from each other. Additionally, a packer perforates the top vertical annulus for gas injection at the reservoir's top, forming a gas cap and mitigating pressure depletion. The results showed that the DC-GAGD had a significant increase in the cumulative oil (24.5 MMbbl), while the TC-GDWS-AGD achieved similar results by an amount of 23.4 MMbbl, which is nearly 5 MMbbl more than the primary scenario of 18 MMbbl. As for the water cut, DC-GAGD showed a decrease in the first days, reaching 70%, but after a short period, the water cut would rise again as a result of the continued gas injection, while TC-GDWS-AGD showed better results and for a relatively longer period of time compared to DC-GAGD, although the water cut decrease in it was 80%. It was evident that the reservoir could not sustain production for 10 years at a rate of 10,000 barrels per day. Therefore, we investigated if the TC-GDWS-AGD process could significantly mitigate the tendency of water cresting and reduce the water cut in oil production wells to low levels, especially when we reduced the strength of the maximum oil production to the appropriate levels of the current reservoir capacity, which is 2000 STB/day However, oil recovery is lower than in other cases with higher constraint values. Therefore, we should conduct an optimization to determine the optimal levels of constraints that yield the maximum oil production and the minimum water cut.