Subsurface CO2 storage estimation in Bakken tight oil and Eagle Ford shale gas condensate reservoirs by retention mechanism

Abstract

This paper describes the CO2 geological sequestration process in unconventional reservoirs in northern and southern United States such as Bakken tight oil and Eagle Ford shale gas condensate reservoirs. The hysteresis modelling and retention mechanism was performed in this research and this is one of the efficient and proven method to store CO2 in the subsurface. This can be achieved through CO2 EOR process while injecting CO2, the fluid will be trapped in the pore spaces between the impermeable rocks and oil can be recovered simultaneously. A total of four cases was taken for the analysis, such as the Bakken and Eagle Ford reservoirs with CO2 huff-n-puff process and another two cases with CO2 Flooding. Injection pressure, injection rate, injection time, number of cycles, carbon dioxide soaking time, fracture half-length, fracture conductivity, fracture spacing, porosity, permeability, and initial reservoir pressure as is taken as inputs and cumulative oil production, and oil recovery factor was taken as outputs. The reservoirs were modelled for 30 years of oil production and the factor year was taken as Decision Making Unit (DMU) and the models was calculated at each year. The retention was successfully calculated in all four models and percentage of retention above 90% was observed in all four cases and the injection pressure has the most dominating effect on the CO2 geological sequestration. It was also revealed that the CO2 huff-n-puff performance in Bakken reservoir is not that much more effective since the retention rate decreases during soaking period and flooding was found to be a suitable method in this formation. Even in Eagle Ford formation, the average performance of CO2 flooding process is better than the huff-n-puff, but the latter process was quite effective in this shale gas condensate reservoir.