Development and simulation of the gas-downhole water sink-assisted gravity drainage (GDWS-AGD) process to reduce carbon footprint and improve clean oil production by injecting CO2 and petroleum-associated gas

Abstract

Implementing continuous gas injection into oil reservoirs, surrounded by strong water drives, enhances oil production. Nevertheless, water coning/cresting in these reservoirs leads to high water cuts, substantial oil production reductions, and major water-handling issues for surface facilities. The Gas-Downhole Water-Sink-Assisted Gravity Drainage (GDWS-AGD) process can enhance oil recovery (EOR) in such reservoirs and mitigate the influx of aquifer water into the oil zone. This study compares the performance of GDWS-AGD and GAGD processes based on reservoir-simulation results for two heterogeneous reservoirs: the PUNQ-S3 reservoir and the giant South Rumaila (SR) oil field (Iraq).The PUNQ-S3 simulation exclusively employs carbon dioxide (CO2) as the injected gas. In contrast, the SR simulation evaluates the CO2 injection in comparison to petroleum-associated gas (PAG). The GDWS-AGD process performance was assessed based on oil recovery factor, water cut, gas-to-oil ratio (GOR) in oil producers, cumulative volumes of gas injected, and oil/gas saturations. The PUNQ-S3 simulation employs six wells: two vertical CO2 injectors with perforations at the top of the reservoir to form a gas-cap zone. Additionally, there are two horizontal oil-production wells and two horizontal water-production wells positioned below the oil-water contact (OWC). The GDWS-AGD process was assessed in the SR simulation, using CO2 and PAG, in several configurations to compare it with the basic GAGD. In the SR design, twenty-two vertical gas-injection wells, ten horizontal oil-production wells, and six horizontal water-production wells were placed in the gas-, oil-, and water-bearing zones, respectively. A vertical well was dual-completed with two lateral sections originating from separate kick-off points above and underneath the OWC with 2–3/8-inch tubing for oil and water production, respectively. Hydraulic packers in the vertical wellbore separate oil and water production tubing in the dual-completion configuration, and electric-submersible pumps are then employed for water production.The downhole-water-sink configuration effectively reduces oil-reservoir pressure and minimizes water cut/cresting tendencies. CO2 remains immiscible due to reduced gas-injection pressure and decreased solubility. The CO2-based simulation of the SR field yielded oil-recovery factors of 71.67%, 75.25%, and 76.162% for the GAGD, basic, and advanced GDWS-AGD setups, respectively. The oil-recovery factor of GDWS-AGD was further increased to 82.64% by implementing PAG injection, resulting in a decrease in water cut to 5% in all oil producers. Although PAG gas injection outperforms CO2 in oil recovery, water cut, and gas injectivity in the SR field simulation, the GDWS-AGD approach with CO2 remains a feasible option. This technology has the capability to effectively capture and store significant amounts of CO2 in the flooded reservoir for many years, thereby mitigating carbon emissions associated with fossil fuel usage.