CO sub(2)/brine/rock interactions in Lower Tuscaloosa formation

• Published in: Greenhouse gases: science and technology 2016-12, Vol.6 (6), p.824-837
• Main Authors: Soong, Yee, Howard, Bret H, Dilmore, Robert M, Haljasmaa, Igor, Crandall, Dustin M, Zhang, Liwei, Zhang, Wu, Lin, Ronghong, Irdi, Gino A, Romanov, Vyacheslav N, Mclendon, Thomas R
• Format: Article
• Language: English
• ISSN: 2152-3878; 2152-3878
• DOI: 10.1002/ghg.1611

Saline aquifers are the largest potential continental geologic CO sub(2) sequestration resource. Understanding of potential geochemically induced changes to the porosity and permeability of host CO sub(2) storage and sealing formation rock will improve our ability to predict CO sub(2) plume dynamics, storage capacity, and long-term reservoir behavior. Experiments exploring geochemical interactions of CO sub(2)/brine/rock on saline formations under CO sub(2) sequestration conditions were conducted in a static system. Chemical interactions in core samples from the Lower Tuscaloosa formation from Jackson County, Mississippi, with exposure to CO sub(2)-saturated brine under sequestration conditions were studied through six months of batch exposure. The experimental conditions to which the core samples of Lower Tuscaloosa sandstone and Selma chalk were exposed to a temperature of 85 degree C, CO sub(2) pressure of 23.8 MPa (3500 psig), while immersed in a model brine representative of Tuscaloosa Basin. 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 CO sub(2)/brine for six months. These results have implications for performance of the storage interval, and the integrity of the seal in a CO sub(2) storage setting.