(619at) CO2/Brine/Rock Interactions in Lower Tuscaloosa Formation

Soong, Y., National Energy Technology Laboratory (NETL), Office of Research and Development, Department of Energy, Pittsburgh, PA
Howard, B. H., National Energy Technology Laboratory
Crandall, D., NETL
McLendon, B., NETL
Dilmore, R., U.S. Department of Energy
Zhang, L., DOE/NETL
Lin, R., Syracuse University
Haljasmaa, I., US DOE/NETL
Saline aquifers are the largest potential continental geologic CO2 sequestration resource.  Understanding of potential geochemically-induced changes to the porosity and permeability of host CO2 storage and sealing formation rock will improve our ability to predict CO2 plume dynamics, storage capacity, and long-term reservoir behavior.


Experiments exploring geochemical interactions of CO2/brine/rock on saline formations under CO2 sequestration conditions were conducted in a static system.  Chemical interactions in cores samples from the Lower Tuscaloosa formation from Jackson County, Mississippi with exposure CO2 saturated brine under sequestration conditions were studied through six months of batch exposure. The experimental conditions to which the core samples of Lower Tuscaloosa Massive Sand and Selma chalk were exposed to was a temperature of 85 °C, pressure of 23.8 MPa (3,500 psig), while immersed in a model brine representative of Tuscaloosa Basin that was mixed with CO2. Computed tomography (CT), X-Ray diffraction (XRD), Scanning Electron Microscopy (SEM), brine chemistry, and petrography analyses were performed before and after the exposure. Permeability measurements from the sandstone core sample before and after exposure showed a permeability reduction. No significant change of the permeability measurements was noticed for the core sample obtained from Selma chalk after it was exposed to CO2/brine for six months. These results have implications for performance of the storage interval, and the integrity of the seal in a CO2 storage setting.  


In addition, a numerical core scale model was also developed to simulate reactive transport with porosity and permeability change of the sandstone from the Lower Tuscaloosa formation and Selma Chalk rock from the sealing formation above the Lower Tuscaloosa formation. The model predicted a 5.2% permeability decrease in the sandstone after 180 days of exposure to CO2-saturated brine, which was close to laboratory-measured permeability results.  For the Selma Chalk sample, there was a very small porosity decrease in the interior of the sample after 180 days of exposure. The model predicted no significant change of permeability for the Selma Chalk sample after 180 days of exposure, which was consistent with laboratory-measured permeability results.