An integrated dynamic modeling workflow for acid gas and CO2 geologic storage screening in saline aquifers with faults: A case study in Western Canada

This study investigates the feasibility of storing the acid gas produced from the oil and gas facilities in Southern Saskatchewan into the Basal Sand aquifer using a coupled wellbore-aquifer-compositional reservoir model. The simulations investigate the pressure change around the fault in proximity of the primary storage location incorporating the influence of reservoir permeability, fault transmissibility, and wellbore configuration, on the factors critical to safe and efficient storage, such as plume migration, pressure changes, and CO₂ storage capacity. A compositional fluid model created using an equation of state was integrated into the reservoir model. Simultaneous incorporation of fault transmissibility, phase solubility, water salinity, temporal in-situ hysteresis and structural trapping, and in-situ compositional tracking of individual gas components is considered as the main novelty of this work. The main challenge of the study was the lack of available data to characterize the aquifer. To this end, a comprehensive workflow of reservoir studies and modeling was applied to reduce the uncertainties and evaluate the site selection. The Basal sand scoping models reveal that the aquifer is expected to handle the required disposal volume given its extent. The injected acid gas plume migrates laterally and preferentially towards the northwest, away from the fault, owing to the aquifer's geological structure. CO₂ remains entirely in the supercritical state, offering storage advantages due to its lower volume. The reservoir permeability significantly impacts the pressure patterns with lower permeability formations triggering higher wellhead injection pressures. Substantial pressure increases around the sealing fault can be observed. Pressure changes of 110 kPa (16 psi) to over 400 kPa (58 psi) were observed at the fault segment after 20 years of continuous gas injection for the expected range of reservoir properties. Mitigation strategies to minimize the increase in fault pressure entail relocating the injection site away from the fault or utilizing a horizontal well trajectory and using an observation well near the fault for monitoring any pressure buildup and slippage.