Evaluation of CO2 Sequestration Potential in Ugnu Heavy Oil Formation on Alaska North Slope During the Enhanced Oil Recovery Process

Abstract The Ugnu formation is estimated to contain between 12-18 billion barrels of heavy oil, whose viscosity varies from 200 cp to as high as a million cp. The development pace of these vast resources has been slow and limited due to multiple factors. One of the most challenging factors is the proximity of the heavy oils to continuous permafrost, thus making thermal methods impractical. Given some successful applications of CO2 in heavy oil development, this study evaluates the performance of CO2 injection in Ugnu heavy oil reservoirs, where the CO2 is captured from post-combustion facilities on Alaska North Slope (ANS) and simultaneously quantifies the CO2 sequestration potential in Ugnu formation during the EOR process. A reservoir simulation technique is applied to evaluate the CO2 EOR performance and the CO2 sequestration potential during the process. The reservoir simulation model has been built based on available geological data and reservoir rock properties, and the Ugnu oil EOS model has been calibrated with available PVT data. Three injection strategies have been simulated and evaluated, including continuous CO2 injection, CO2-alternating-water injection, and CO2- alternating-polymer injection. For each injection strategy, sensitivity analysis on the well positions, CO2 injection time in each cycle, CO2 injection temperature, and gas injector shut-in time has been conducted to reveal their influence on the oil recovery performance and CO2 sequestration potential, respectively. Eventually, all results have been analyzed and compared to recommend the optimal injection strategy to maximize EOR performance and the optimal injection strategy to maximize CO2 sequestration potential. According to the simulation results from base scenarios, the CO2 EOR project in the Ugnu reservoir can store 5.47 TCF CO2 while recovering 31.1% of Ugnu oil by using the PAG_1YG_2YP (1-year-CO2-alternating-2-year-polymer injection) injection strategy. Sensitivity analysis on well positions, CO2 injection time in each cycle, CO2 injection temperature, and CO2 injector shut-in time revealed the influence of these parameters on oil recovery and CO2 sequestration potential. Changing the well positions to the bottom layer improves EOR performance and increases CO2 sequestration potential. Reducing the CO2 injection time in each cycle could improve the oil recovery but not enhance CO2 sequestration potential. Increasing the CO2 injection time in each cycle would hurt the EOR performance but increase the total amount of CO2 sequestrated in the reservoir. Increasing the CO2 injection bottomhole temperature to 90 degrees F to inject CO2 at supercritical conditions doesn't affect the CO2- EOR performance and CO2 sequestration potential since the supercritical CO2 temperature is not high enough to heat the heavy oil. Delaying the gas injector shut-in time can significantly increase the total amount of CO2 that can be stored in the reservoir before the average reservoir pressure reaches its maximum safety limit.