CO2 geological storage is a promising method to cut CO2 atmospheric emissions. Determining the extent of the injected CO2 plume within a target storage formation has direct implications for the safety of the CO2 storage project as it determines the area of CO2 exposure. In this study, a pressure interference test is introduced to characterize the CO2 plume in the reservoir. For a given CO2 plume, water is injected at the injection well and pressure interference signal (and its arrival time) is obtained at several observation wells inside/outside of the plume. We utilize an analytical expression to determine multi-phase diffusivity coefficient from numerical simulation results. The relationship between travel time and diffusivity coefficient is expressed as a line integral to obtain the pressure arrival time. We introduce a method to invert the arrival time in the synthetic pressure interference data in order to estimate the average gas saturation. It is shown that when inverting the arrival time from the numerical simulation to find the average CO2-rich (gaseous) phase saturation, the percent error was high, but the actual change in gaseous saturation was small, showing strong potential to be applied to the field. Complexities were added to the system such as anisotropy and heterogeneity in two- and three-dimensional systems. Observation wells were located co-linear to the injection well, so anisotropy had minimal effect on the permeability used for calculations.