448616 CO2/Brine/Rock Interactions in Lower Tuscaloosa Formation

Wednesday, November 16, 2016
Grand Ballroom B (Hilton San Francisco Union Square)
Yee Soong1, Bret H. Howard2, Dustin Crandall3, Bob McLendon4, Robert Dilmore5, Liwei Zhang3, Ronghong Lin6 and Igor Haljasmaa7, (1)National Energy Technology Laboratory (NETL), Office of Research and Development, Department of Energy, Pittsburgh, PA, Pittsburgh, PA, (2)U.S. Department of Energy, National Energy Technology Laboratory, Pittsburgh, PA, (3)DOE/NETL, (4)NETL, Pittsburgh, PA, (5)National Energy Technology Laboratory, U.S. Department of Energy, Pittsburgh, PA, (6)Department of Biomedical and Chemical Engineering, Syracuse University, Syracuse, NY, (7)US DOE/NETL, Pittsburgh, PA

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.


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