Deep saline aquifers are key targets for secure CO2 geological storage because of their petrophysical and geochemical characteristics. This study conducts two-dimensional radial numerical simulations of CO2–brine flow and dissolution to examine plume migration and dissolution in saline aquifers while allowing porosity and permeability to evolve with pressure. The model outputs include reservoir pressure, porosity, permeability, gas saturation, and dissolved CO2, with additional analyses of permeability anisotropy, initial reservoir pressure, and stratified sandstone–shale architecture. Simulations with evolving properties predict a smaller radial plume extent than simulations with fixed properties, together with a maximum pressure buildup of about 2 MPa near the injection well. In a homogeneous aquifer, porosity and permeability increase nonlinearly during injection and reach about 1.25 and 2.6 times their initial values near the injection well after 1200 days, whereas the increases are lower in the sandstone–shale case at about 1.16 and 2.0 times because shale interlayers confine the enhanced zone to the lower sandstone. Increasing permeability anisotropy shifts migration toward lateral spreading, and higher initial reservoir pressure reduces plume extent. Overall, the assumption of constant porosity and permeability tends to predict larger plume footprints and different pressure responses, with sensitivity controlled by anisotropy, initial pressure, and shale interlayers.
Wu et al. (Thu,) studied this question.