Caprock characteristics and uncertainties in geological carbon sequestration in the Illinois basin

Geological carbon sequestration in deep saline aquifers has emerged as a promising mitigation strategy for reducing greenhouse gas emissions to the atmosphere. Success of commercial-scale GCS requires containment of injected CO2 and the sealing ability of the overlying caprock has been identified as an important factor related to the long-term storage of CO2. Caprock research is recent and the behavior of caprocks as seals in GCS is not well understood. Geological uncertainty assessment in GCS research is often limited to reservoir properties. This research presents a current review of the dominant physical characteristics of caprocks and their relation to CO2 containment. This work is limited to argillaceous sediments, such as shales and mudrocks, as caprocks in GCS. The ability to retard vertical fluid flow is a complex issue as the CO2 plume will be in contact with the caprock due to buoyancy and involve hydrodynamic, geomechanical, and geochemical processes. Physical processes which govern leakage through a caprock are often coupled, yet the effective geologic parameters are uncertain. To address caprock geologic parameter uncertainty in GCS modeling, a simplified caprock-reservoir simulation model based on the Eau Claire Formation and the Mt. Simon Formation at the Illinois Basin – Decatur Project (IBDP), a large-scale carbon capture and storage project, is developed. The extended Morris OAT method (Morris, 1991; Campolongo et al., 2007) is used to assess the sensitivity of the pressure response due to brine injection at locations in the caprock and reservoir with respect to four caprock parameters: horizontal permeability, anisotropic permeability ratio, porosity, and rock compressibility. All caprock parameters exhibited nonlinear and non-negligible effects. Horizontal permeability caprock is the dominating factor which aids in the dissipation of pressure in the caprock and reservoir at all times after injection. Caprock compressibility has a positive effect on pressure perturbation in the system at 10 years after injection ends. A higher caprock compressibility allows for greater pressure absorption in the caprock pore space; therefore decreasing the pressure in the underlying reservoir. These results indicate the parameters tested are all deserving of additional research; however, caprock compressibility and permeability are the dominant factors which influence pressure perturbation in the caprock and reservoir