Evaluation of CO2-Brine-Reservoir Rock Interaction with Laboratory Flow Tests and Reactive Transport Modeling

Abstract

Abstract Sequestration of carbon dioxide (CO2) in geological formations is one proposed method for isolating anthropogenic CO2 from the atmosphere. Determining the viability, risks, and optimal locations of sequestering CO2 in the subsurface requires detailed knowledge of the complex interactions among CO2, rock matrix, and pore fluids under appropriate in situ pressure and temperature conditions. Many physical and chemical processes are known to occur both during and after geologic CO2 injection, including diagenetic chemical reactions and associated permeability changes. Although it is commonly assumed that CO2 sequestered in this way will ultimately become mineralized, the rates of these changes, including CO2 hydration in brines, are known to be relatively slow. Together with hydrated CO2, cations from produced brines may form solid-state carbonate minerals, ostensibly providing permanent sequestration. We used results of earlier laboratory CO2-brine flow experiments performed in rock core to calibrate a reactive transport simulator. We are using the calibrated model to estimate in situ effects of a range of possible sequestration options in depleted oil/gas reservoirs. The code applied in this study is a combination of the well known TOUGH2 simulator, for coupled groundwater/brine and heat flow, with the chemistry code TRANS for chemically reactive transport. Variability in response among rock types suggests that CO2 injection will induce ranges of transient and spatially dependent changes in intrinsic rock permeability and porosity. Determining the effect of matrix changes on CO2 mobility is crucial in evaluating the efficacy and potential environmental implications of storing CO2 in the subsurface.