CO₂ flooding in low-permeability and tight oil reservoirs is frequently compromised by severe gas channeling, which significantly reduces oil recovery and sweep efficiency. While foam flooding can effectively mitigate CO₂ channeling by trapping CO₂ within lamellae, its stability deteriorates under harsh high-temperature, high-salinity reservoir conditions, compromising its effectiveness. Furthermore, foam flow in porous media involves constant foam generation, collapse and propagation, making its flow behaviors difficult to predict. To address these challenges, a new foaming agent with satisfactory regenerative capability is developed to maintain gas mobility control under harsh reservoir conditions. The multiphase flow behaviors during CO₂ foam flooding are predicted using pore network modeling to obtain the corresponding relative permeability curves, which are further incorporated into a reservoir simulator to evaluate field-scale foam flooding performances, as well as optimize injection strategies. This multi-scale modeling approach establishes a quantitative link between pore-scale foam behaviors and field-scale oil recovery performances, offering new insights into carbon capture and utilization with enhanced oil recovery in low-permeability and tight reservoirs. Document Type: Original article Cited as: Peng, M., Zhou, Y., Yang, J., Wang, J., Lin, Z., Zhao, J. Experimental investigation and multi-scale simulations of CO₂ foam flooding for enhanced oil recovery. Capillarity, 2025, 16(2): 39-50. https://doi.org/10.46690/capi.2025.08.02

Fractional flow analysis is an efficient tool to evaluate the gas-trapping performance of foam in porous media. The pore-scale simulation study and the core-scale experimental work have been bridged via the fractional flow analysis to distinguish the characteristics of foam displacement inside the tight porous media with varying absolute permeability, injection rate, and foam quality. In this work, the combined investigation suggests that conventional foam-enhancing strategies, pursuing higher foam quality and stronger foam regime, are inefficient and restricted in tight reservoirs that the critical S_w corresponding to the limiting capillary pressure has increased around 37~43%, which indicates severely weakened gas-trapping capacity as permeability reduces one order of magnitude. The moderate mobility adjustment and corresponding optimized fluid injectivity exerting from the “weak foam” flow presents a staged decline feature of decreasing water fractional flow, which implies the existence of the delayed gas-trapping phenomenon when water saturation reduces to 0.5~0.6. The finding has supported the engineering ideal of promoting low-tension gas (LTG) drive processes as a potential solution to assist field gas injection applications suffering from gas channeling. Also, the validation with core-flooding experimental results has revealed several defects of the current pore network model of foam displacement in tight porous media, including exaggerated gas trapping and overestimated confining water saturation. This study has innovatively demonstrated the feasibility and potential of optimizing the foam performance of gas trapping and mobility control in tight reservoirs, which provides a clue that may eventually boost the efficiency of the gas injection process in enhanced oil recovery or CO₂ sequestration projects.