1. INTRODUCTION: Carbon dioxide (abbreviated to CO2) sequestration in appropriate geologic formations (e.g., deep saline aquifers, deep unmineable coal seams, and depleted oil and gas reservoirs) is expected to be a promising technique to reduce CO2 emission its great storage potential. In geological sequestration projects, CO2 is supposed to be injected in the form of supercritical fluid which is denser than vapor state and less viscous than liquid state. Revealing d process of formation water by CO2 phase porous rock system is of importance to estimate storage capacity and ensure safe CO2 injection predict migration of CO2 in reservoirs, reservoir rocks need to be characterized in terms of the capillary pressure response and the relative permeabilities for formation water and CO2. In laboratories, the relative permeability curves are usually core tests in which a fluid phase is injected into core sample to displace another fluid phase paper has been published to discuss the curves such as relative permeability curves pressure curves, for multiphase processe sequestration and H2S disposal [1, 2, 3]. Typical quantities obtained in the core tests are pressures, flow rates, and fluid compositions measured at the inlet and outlet of the core samples. This paper presents a one-dimensional immiscible twophase fluid flow model in a porous rock system. The model parameter values are estimated by carrying out forward analysis to match the computed behavior with experimentally observed one. The experimental data used was obtained from high pressure core flooding test in which supercritical CO2 injection into geological CO2 reservoir is simulated. To investigate applicability of inverse analysis to the multiphase fluid problem, the relative permeability and capillary pressure curves were characterized through inverse analysis. Polynomial functions and Brooks-Corey capillary pressure model are assumed for the relative permeability and capillary pressure curves, respectively.