Temperature Effects on Injectivity Decline Due to Rock Dry-Out, Salt Precipitation and Fines Migration During CO2 Storage: Laboratory and Mathematical Modelling

Abstract Evaporation of connate water in the near-wellbore region during CO2 injection leads to salt precipitation, fines migration, and associated formation damage. These mechanisms contribute to injectivity decline—one of the major operational challenges in CCUS projects. Previous studies investigated overall rock drying at various temperatures; however, none of them separated the effect of salt precipitation and fines migration at high temperatures (reservoir conditions). Therefore, this study investigates injectivity impairment caused by rock dry-out, salt deposition, and fines migration under reservoir-temperature conditions. Permeability decline by each mechanism was separated though systematic injection of CO2 and brine, and the results were analyzed by mathematical formulations of Darcy's law considering damage. Two sandstone cores—a low-clay and a high-clay content sample—were selected to examine the influence of mineralogy. CO2 core-flooding experiments were conducted at 22°C and 80°C to evaluate the impact of temperature. Additional tests at 80°C assessed the effects of clay content and brine salinity on permeability. Permeability reduction was further interpreted using mathematical formulations to separate the contributions of salt effect and fines migration. Results demonstrate that higher clay content leads to significantly greater fines detachment. Rock dry-out accelerates with increasing temperature due to the higher water-carrying capacity of CO2 and the consequently enhanced evaporation rate. No fines-related permeability impairment was observed in the clay-free core. Lower-salinity brine resulted in faster drying and increased fines migration, whereas higher-salinity brine caused more severe permeability decline due to extensive salt precipitation.