Abstract

The current technique for producing shale oil reservoirs involves primary depletion using horizontal wells with multiple transverse fractures, resulting in an oil recovery factor typically ranging from 5% to 10%. Therefore, there is a significant opportunity for enhanced oil recovery (EOR) through a gas injection scheme. The pursuit of decarbonization is creating new possibilities for CO2 utilization, with EOR being a notable example with an exit option of leaving the maximum amount of CO2 in the reservoir. In this study, we present a novel approach to evaluate gas injection in oil shale reservoirs, examining various gases, identifying optimal Huff-n-Puff operational parameters, and investigating the contributions of diffusive forces to incremental oil recovery and long terms storage. A representative segment of the Bakken field for the objective was employed. Initially, history matching of the reservoir simulation model was performed using the historical production data. A base case for primary production was established to serve as a benchmark for evaluating primary recovery. Various gas solvents were assessed based on their Minimum Miscibility Pressure (MMP) and simulation results. A sensitivity analysis of Huff-n-Puff operational parameters was conducted, encompassing the optimum injection rate, time, number of cycles, soaking time, and the diffusion of the gas solvent in the in-situ oil. Additionally, an economic model was developed to assess the revenue generated from incremental oil production and the potential amount of stored CO2 added to the total value stream.

The history matching process showed an agreement between the historical and simulated production rates. The sensitivity analysis of the best injectant found that pure CO2 or produced gases mixed with CO2 had the most significant impact on oil recovery. The optimum parameters for the Huff-n-Puff method showed that the extended soak times compatible with the production time scales had minimal effect, and injection rate of 10 MMSCF/D, and three cycles yielded the optimum recovery factor. Higher solvent diffusion coefficients led to increased oil recovery during optimal soaking times. Comparing injected to produced CO2 demonstrated significant storage. Economic analysis showed a positive Net Present Value (NPV) from incremental oil production and tax returns from stored CO2.

This study improves shale oil recovery by introducing an innovative gas injection strategy to address primary depletion inefficiencies. It establishes a correlation between optimal soaking time, injectant diffusion coefficient, and in-situ oil composition changes. Through evaluating various gases and optimizing Huff-n-Puff parameters, the study not only identifies optimal operational parameters but also underscores the significance of injectant diffusion in in-situ oil as a crucial factor for EOR success. The novelty lies in the comprehensive analysis of gas injection impact, using a representative simulation model for the Bakken Field, providing practical insights for future EOR applications with CO2 sequestration options.

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