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When supercritical CO2 is injected into a deep saline aquifer, the salinity of the brine can influence both the solubility of the injected CO2 in the brine and the subsequent aqueous geochemical reactions that occur. The objective of this study is to assess the effect of brine salinity on CO2 storage in deep saline carbonate formations. Specifically, the study aims to quantitatively assess the effect of brine salinity on (a) the amount of CO2 that can be sequestered in the aqueous phase, (b) the storage efficiency of the repository, (c) the change in pH of the residual brine after dissolution of CO2, and (d) changes in the mineralogy and porosity of the rock matrix that result from mineral dissolution and precipitation reactions induced by CO2 injection. Injection of CO2 into a model layered carbonate formation was simulated using the reactive‐transport code TOUGHREACT 3.3. The simulations consisted of 50 years of injection into a partially completed injection well, followed by 50 years of equilibration (no injection). Salinity of the brine was varied between 1% and 15% to determine the effects of salinity. Because the solubility of CO2 decreases as the salinity of the brine increases, an increase in brine salinity from 1% to 15% resulted in a 19% decrease in storage efficiency and a 25% decrease in the mass of CO2 dissolved in the aqueous phase. However, despite the strong effect of brine salinity on CO2 dissolution, there was almost no effect of salinity on the pH change in the residual brine: the chemical activity coefficient of the dissolved CO2 increases with brine salinity, counteracting the effects of decreased solubility. Consequently, brine salinity had little effect on mineral dissolution or precipitation, or on changes in formation porosity. The study therefore helps to choose sequestration sites depending upon the salinity of the brine: lower salinity results in more solubility trapping and better storage efficiency without noticeable differences in pH drop or mineral dissolution. © 2020 Society of Chemical Industry and John Wiley & Sons, Ltd.

Geological sequestration of carbon dioxide (CO2) in deep saline aquifers is one of the most promising technologies for large-scale CO2 mitigation. Temperature can play a significant role in the ensuing geochemistry, affecting equilibria in a multicomponent system and impacting reactive transport processes. The objectives of this study are to quantify the effect of temperature on storage efficiency, solubility trapping of CO2, pH of residual brine, and changes in the mineralogy and porosity. Using toughreact 3.3 (a reactive transport simulator), we have simulated the injection of CO2 into a heterogeneous layered carbonate formation for a period of 50 years, followed by a 50-year equilibration period with no injection. Mineralogy and physical properties of the simulated aquifer are based on a dolomitic limestone aquifer located within the South Florida Basin. Simulations were conducted for seven values of temperature. Density of supercritical CO2 decreases with an increase in temperature, which leads to higher buoyancy at elevated temperatures. Therefore, the storage efficiency of the aquifer decreases as temperature increases. Simulation results indicate that an increase in temperature from 35 °C to 95 °C results in a 35% decrease in storage efficiency. However, surprisingly, solubility trapping of CO2 increases with an increase in temperature because the interfacial area increases with temperature. Temperature effects on pH and on porosity change (due to mineral dissolution and precipitation) are small. The study can be helpful in screening a reservoir for geological carbon storage based on the formation temperature.

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