CO2 injectivity in saline aquifers: The impact of non-Darcy flow, phase miscibility, and gas compressibility

A key aspect of CO2 storage is the injection rate into the subsurface, which is limited by the pressure at which formation starts to fracture. Hence, it is vital to assess all of the relevant processes that may contribute to the pressure increase in the aquifer during CO2 injection. Building on an existing analytical solution for immiscible and spatially varying non-Darcy flow, this paper presents a mathematical model that accounts for combined effects of non-Darcy flow, phase miscibility, and gas compressibility in radial two-phase displacements. Results show that in low-permeability formations when CO2 is injected at high rates, non-Darcy simulations forecast better displacement efficiency compared to flow under Darcy conditions. This will have a positive effect on the formation CO2 storage capacity. This, however, comes at the cost of increased well pressures. More favorable estimations of the pressure buildup are obtained when CO2 compressibility is taken into account because reservoir pressures are reduced due to the change in the gas phase properties. Also, non-Darcy flow results in a significant reduction in halite precipitation in the near-well region, with a positive effect on CO2 injectivity. In the examples shown, non-Darcy flow conditions may lead to significantly different pressure and saturation distributions in the near-well region, with potentially important implications for CO2 injectivity.