A comparison of water chemistry from a CO2-enhanced oil recovery project with reactive transport modeling of CO2 injection into a carbonate reservoir

A long-term geochemical monitoring program was conducted at a CO2-enhanced oil recovery site in central Alberta (Canada) to examine geological storage of CO2. The program included geochemical monitoring of reservoir brines, a mineralogical study, and using TOUGHREACT to compare model and field observations. CO2 was injected into a highly permeable carbonate reservoir at 78 tonnes/day for 2.5 years. Fluid and gas samples were obtained for geochemical characterization before, during, and 1.4 years after injection from a production well approximate to 915 m from the injection well at a depth of approximate to 936 m. Downhole water compositions were calculated using SOLMINEQ88 and compared to predictions from TOUGHREACT. Following CO2 breakthrough after approximate to 23 months, downhole pH decreased, HCO3-; and calcium concentrations increased, while magnesium concentrations changed marginally, indicating solubility and ionic trapping were occurring simultaneously. Trends in analyzed and modeled species were similar, but concentration levels were different. Calibrating the model to achieve better correlation between results was attempted but proved unsuccessful. The variances were likely caused by differences between ideal and reservoir mineral's kinetic parameters, surface area, thermodynamic parameters and sampling technique. Five-hundred-year simulations showed the CO2 plume migrating vertically due to capillary forces with no significant change in gas saturation below the caprock over the post-injection period. The majority of CO2 remained trapped as a supercritical phase as the reservoir is composed of only carbonate minerals. The low reactivity of the reservoir is positive, in that the reservoir is not negatively impacted by dissolution and negative in that no mineral trapping occurs. (c) 2013 Society of Chemical Industry and John Wiley & Sons, Ltd