Saline aquifers deeper than 800 m are suitable as geo-sequestration reservoirs. To ensure sequestration safety, confirming the injectivity and stability of the reservoir rock formation is of critical importance, requiring studies of the rock porosity and permeability to uncover the fluid migration scenarios within the porous reservoir rock. Two-phase (CO2-brine) flow behavior following the post super-critical CO2 injection is believed to be a dominating factor; its flooding behavior within the porous reservoir rock media needs to be further clarified prior to confirming the feasibility of domestic CO2 geo-sequestration. This study aims to determine the relative permeability of rock cores obtained from field outcropping. A test facility was established to determine the relative permeability during drainage and imbibition processes using a core-flooding test implemented with the displacement method. The test facility was assembled by the authors locally and is regarded as a pioneering attempt. By data interpretation using the Pseudo-Darcy Method and Modified JBN Method, the parameters of relative permeability for predicting the movement of super-critical CO2 after injection can be modeled. To enhance test data availability, more reliable parameters can be obtained using history matching processes wherein time-elapsed data calibration is used in conjunction with a computer code, TOUGH2. The test results, including the time-elapsed pressure change and outflow data acquiredwere iteratively calibrated using numerical simulation by conducting a history matching process. The K-S curves derived from best-fit parameters are believed to be the most relevant relative permeability for the reservoir rock. Through this preliminary study, a better understanding of some of the problems and limitations associated with the determination of the relative permeability using core scale two-phase flow test with the displacement method is achieved, but more advanced research is required.