In-situ foaming the injection gas for Enhanced Oil Recovery (EOR) can improve the volumetric sweep efficiency of the gas phase and reduce gas channeling and viscous fingering in the oil reservoirs with permeability contrast. However, the success of foam displacement in porous media is predominantly dictated by its stability, which is adversely affected by the presence of oil and non-water-wet surfaces. The objective of this dissertation is to distinguish the effect of residual oil and surface wettability on foam generation and propagation in porous media. This includes a multiscale study that combines the knowledge of surface chemistry, rock-fluid interactions, and the transport phenomena in porous media. Foam in porous media is a train of gas bubbles separated by foam films or lamellae and stabilized by surfactant solution. Understanding the surfactant interaction with the rock surface and the oil phase, i.e., surfactant adsorption and emulsification, is essential to explore foam rheology in the presence of oil. In this study, the effect of rock surface wettability and redox potential on surfactant adsorption was investigated. This was achieved by testing a commercial anionic surfactant and sandstone cores. Surfactant adsorption levels were determined by analyzing the effluent history data with a dynamic adsorption model. It was found that the surfactant adsorption in neutral-wet cores was increased because of the hydrophobic interactions between the surfactant lipophile and the deposited crude oil components. However, as the surfactant adsorption was satisfied, the surfactant micelles solubilized the adsorbed crude oil component and revered the wettability to water-wet conditions. The surfactant ability to alter wettability toward water-wet conditions can potentially facilitate foam generation and stability under non-water-wet conditions. This idea was explored by the microvisual observations of gas snap-off and lamella movement in glass capillary tubes that were made neutral-wet by absorbing a film of oil on the glass surface. The neutral-wet glass was shown to be water-wet by contact with the surfactant solution. The surfactant solution made the neutral-wet glass surface water-wet by either removing the oil or by adsorbing surfactant on the surface with the hydrophilic head group making the exposed surface water-wet. Formation of a wetting film on the surface assisted gas snap-off and stable lamella movement in the capillary tubes. The observations were similar for the different wettability modification techniques, i.e., silanization and aging with crude oil, as well as different surfactant concentrations. In line with the capillary tube experiments, strong foam was generated in the oil-free neutral-wet sandstone cores with the tested anionic surfactant. However, adding some residual crude oil to the neutral-wet cores significantly impeded the foam generation. Strong foam was not generated until injecting many pore volumes of the foam/surfactant solution to remove the residual oil and the adsorbed components from the surface. With the test conditions, the combined effects of neutral wettability and residual oil were recognized as the unfavorable conditions for generating strong foam. In a separate study, the oil type and saturation effects on foam rheology was explored by combining the coreflooding with the NMR imaging. The analysis of the fluid distribution enabled us to quantify the relative significance of the oil displacement mechanisms, namely micellar solubilization versus capillary number. Additionally, the foam strength was correlated with the oil saturation from the foam-oil co-injection tests. In particular, the apparent viscosity first decreased with increasing oil saturation because of the detrimental effect of oil on foam stability; and then apparent viscosity increased with oil saturation due to the oil emulsification. It was demonstrated that in studying the foam-oil interactions in porous media, the emulsification effect should be carefully distinguished from that of foam destabilization. Finally, a texture-implicit local-equilibrium foam model was described to upscale the coreflooding experiments to numerical reservoir simulation. Water and oil saturation dependent parameters were extracted from the results of foam quality scans and their effects on steady state foam apparent viscosity was probed. Furthermore, two simulation cases, coupled with the foam model, were investigated. These included a sensitivity analysis on the foam model parameters and the application of CO2-foam for the diversion of a miscible solvent in a fractured reservoir.