CO2 flood is one of the most successful and promising enhanced oil recovery technologies. However, the displacement is limited by viscous fingering, gravity segregation and reservoir heterogeneity. Foaming the CO2 and brine with a tailored surfactant can simultaneously address these three problems and improve the recovery efficiency. Commonly chosen surfactants as foaming agents are either anionic or cationic in class. These charged surfactants are insoluble in either CO2 gas phase or supercritical phase and can only be injected with water. However, some novel nonionic or switchable surfactants are CO2 soluble, thus making it possible to be injected with the CO2 phase. Since surfactant could be present in both CO2 and aqueous phases, it is important to understand how the surfactant partition coefficient influences foam transport in porous media. Thus, a 1-D foam simulator embedded with STARS foam model is developed. All test results, from different cases studied, have demonstrated that when surfactant partitions approximately equally between gaseous phase and aqueous phase, foam favors oil displacement in regard to apparent viscosity and foam propagation speed. The test results from the 1-D simulation are compared with the fractional flow theory analysis reported in the literature.