High salinity and high oil content present major challenges to the effectiveness of foam in enhanced oil recovery (EOR). This study introduces RCS, a novel oil-resistant foam system designed for reservoirs with salinity levels reaching 2.1 × 10⁵ mg/L. RCS forms stable foams at oil–water ratios up to 60% and is effective across a wide crude oil viscosity range (10.8–7890 mPa·s). We investigated the film properties of oil-containing foam and the co-permeation behavior of the crude oil–N₂–foam system to elucidate the mechanisms underlying foam stability and steady-state flow. RCS emulsified high-viscosity crude oil into stable, large droplets that accumulated within the plateau borders, reducing drainage. Even at concentrations as low as 0.01 wt%, RCS formed stable pseudoemulsion films that prevented intrusion into the gas–water interface, allowing the foam half-life to be mainly controlled by the dilatational viscoelasticity of the interface. With increasing oil–water ratios, both drainage resistance and dilatational modulus increased, extending the drainage and foam half-lives. Coreflood experiments showed that co-injection of RCS with N₂ and crude oil produced stable foams and in-situ emulsions. At 5% oil fractional flow, the critical foam quality (f_g^*) remained unchanged compared to oil-free conditions, although the maximum apparent viscosity decreased by 29.8%. At 10% oil fractional flow, f_g^* shifted to a lower value, while the apparent viscosity in the low-quality regime increased markedly—exceeding that of the oil-free condition. These findings highlight that while crude oil more strongly impairs foam stability in porous media than in bulk, the formation of in-situ emulsions can partially offset or even enhance mobility control through a synergistic Jamin effect. Therefore, in-situ emulsification should be emphasized in foam applications within oil-containing environments.

Cocamidopropyl hydroxyl sulfobetaine (CHSB) is one of the most promising foaming agents for high-salinity reservoirs because the salt in place facilitates its foam stability, even with salinity as high as 2 × 10⁵ mg/L. However, the synergistic effects between CHSB and salt have not been fully understood. This study utilized bulk foam tests and thin-film interferometry to comprehensively investigate the macroscopic and microscopic decay processes of CHSB foams with NaCl concentrations ranging from 2.3 × 10⁴ to 2.1 × 10⁵ mg/L. We focused on the dilatational viscoelasticity and dynamic thin-film thickness to elucidate the high-salinity-enhanced foam stability. The increase in dilatational viscoelasticity and supramolecular oscillating structural force (Π_OS) with salinity dominated the superior stability of CHSB foam. With increasing salinity, more CHSB molecules accumulated on the surface with a lower diffusion rate, leading to high dilatational moduli and surface elasticity, thus decelerating coarsening and coalescence. Meanwhile, the number density of micelles in the thin film increased with salinity, resulting in increased Π_OS. Consequently, the energy barrier for stepwise thinning intensified, and the thin-film drainage slowed. This work conduces to understand the mechanisms behind the pronounced stability of betaine foam and can promote the widespread application of foam in harsh reservoirs.