(91a) CO2/Brine/Rock Interactions Under CO2 Sequestration Conditions

Saline aquifers are considered to be among one of the CO2 sequestration options. Knowledge of possible geochemically-induced changes to the porosity and permeability of host CO2 storage sandstone and seal rock will enhance our capability to predict CO2 storage capacity and long-term reservoir behavior.  The Lower Tuscaloosa Formation in the southeast region of the U.S is recognized as a promising candidate host reservoir for carbon sequestration. The Lower Tuscaloosa formation is a deep saline aquifer and is a primary reservoir target for large scale carbon dioxide injection tests due to its proximity to CO2 sources, favorable depth, thickness, permeability, porosity, and the presence of an overlying low permeability shale formation as a seal.  The Southeast Regional Carbon Sequestration Partnership has selected the lower Tuscaloosa Formation as one of its major demonstration projects. While the Lower Tuscaloosa Sandstone has ideal reservoir characteristics in some areas, there are significant variations in porosity, permeability, and mineralogy. Hence, the injection of CO2 into a deep saline aquifer will affect porosity since it can cause both mineral dissolution and precipitation in the formation.  To predict the most likely changes to the reservoir porosity and permeability during sequestration, it is critical to understand the behavior of the minerals that line pore spaces when they are in contact with the CO2 saturated brine.

An experimental study of the interaction of CO2/brine/rock on saline formations in a static system under CO2 sequestration conditions was conducted.  Chemical interactions in the cores samples from Lower Tuscaloosa Formation upon exposure to CO2 mixed with brine under sequestration conditions for six months were studied. The experimental parameters used were core samples of Lower Tuscaloosa Massive Sand and Selma Chalk from Jackson County, Mississippi; Tuscaloosa Basin model brine; temperature of 85 °C, pressure of 23.8 MPa (3,500 psig), and CO2. CT, XRD, SEM, petrography, and brine, porosity, and permeability analyses were performed before and after the exposure.  Preliminary permeability measurements observed from the Massive Sand core sample showed a change after it was exposed to CO2-saturated brine for six months. This observation suggests that mineral dissolution and mineral precipitation could occur in the host deposit altering its characteristics for CO2 storage over time.   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.