A comparison of water chemistry from a CO 2 ‐enhanced oil recovery project with reactive transport modeling of CO 2 injection into a carbonate reservoir

A long‐term geochemical monitoring program was conducted at a CO 2 ‐enhanced oil recovery site in central Alberta (Canada) to examine geological storage of CO 2 . The program included geochemical monitoring of reservoir brines, a mineralogical study, and using TOUGHREACT to compare model and field observations. CO 2 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 ∼915 m from the injection well at a depth of ∼936 m. Downhole water compositions were calculated using SOLMINEQ88 and compared to predictions from TOUGHREACT. Following CO 2 breakthrough after ∼23 months, downhole pH decreased, HCO 3 -super-−; 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 CO 2 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 CO 2 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. © 2013 Society of Chemical Industry and John Wiley & Sons, Ltd