CO2-brine relative permeability and capillary pressure of Tuscaloosa sandstone: Effect of anisotropy

Relative permeability and capillary pressure are known as essential properties that have substantial impacts on the accuracy of reservoir simulations. The effect of small-scale heterogeneity and lamination in the rock structure is often ignored during the measurement of capillary pressure and relative permeability curves in core samples. This study highlights the remarkable impact of anisotropy on the multiphase flow properties of stratified formations. A series of steady-state CO2-brine drainage and imbibition tests are conducted at reservoir conditions in horizontal and vertical core samples of the Tuscaloosa sandstone from the Cranfield CO2 injection site in Mississippi. The relative permeability curves represent an anisotropic behavior influenced by the heterogeneous and laminated structure of realistic rock samples. The CO2 saturation profiles during drainage and imbibition cycles indicate that the phase distribution in the pore space is controlled by core-scale heterogeneity in the porosity distribution among the laminations that causes capillary pressure inhomogeneity. Using the saturation profile during the imbibition cycle, the trapping characteristic of the horizontal and vertical rock samples are compared and we found that the capillary trapping is less likely in the vertical direction. Furthermore, the centrifuge-measured capillary pressure demonstrates distinctive characteristics for horizontal and vertical core samples. Since the flooding experiments are performed under capillary controlled flow, the capillary pressure contrast in the laminated structure of the rock strongly affects the relative permeability. The presented results can potentially improve the accuracy of the large-scale simulations for the CO2 post-injection period, in which the vertical displacement has an important role in the plume migration.