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.