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

Due to their high viscoelasticity and excellent plugging ability, surfactant foam systems can mitigate the effects of heterogeneity and have emerged as a key technology in tertiary oil recovery in recent years. Moreover, achieving ultra-low oil/water interfacial tension (IFT) is critical for enhanced oil recovery (EOR), as it facilitates the deformation and mobilization of oil droplets from pores. However, conventional surfactant systems often struggle to simultaneously achieve ultra-low oil/water IFT and high foam performance. To overcome this limitation, this study developed a composite surfactant system by combining small-molecule anionic and cationic surfactants with a nonionic surfactant, enabling both ultra-low oil/water IFT and high foam performance. The compound surfactants were evaluated for IFT, emulsification performance, and foam performance within a concentration range of 1–10 mM. Based on the comprehensive evaluation results, a concentration of 4 mM was selected for further investigation in a heterogeneous micro-model oil displacement experiment to analyze its displacement behavior. The results demonstrated that at a concentration of 2 mM, the foaming agent achieved the lowest oil/water IFT of 9.834 × 10^− 4 mN/m, while at 4 mM, the foam composite index reached its peak value of 12,960 mL·min. The ability to reduce IFT was found to be approximately proportional to foam performance and inversely proportional to emulsification performance. The heterogeneous micro-model oil displacement experiment demonstrated that chemical flooding increased the recovery ratio by 24% compared to water flooding, with the foam action zone exhibiting significantly enhanced displacement efficiency. The novelty of this study lies in the use of surfactants with different properties to construct a foam system with ultra-low oil/water IFT and excellent foam performance, as well as the execution of heterogeneous micro-model displacement experiments. This work provides valuable insights for the design of fracture carbonate foaming agents and future studies on EOR.

Foam flooding is an efficient and promising technology of enhanced oil recovery that significantly improves sweep efficiency of immiscible displacement processes by providing favorable mobility control on displacing fluids. Although the advantages in flexibility and efficiency are apparent, accurate prediction and effective control of foam flooding in field applications are still difficult to achieve due to the complexity in multiphase interactions. Also, conventional field-scale or mesoscale foam models are inadequate to simulate recent experimental findings in feasibility of foam injection in tight reservoirs. Microscale modeling of foam behavior has been applied to further connect those pore-scale interactions and mesoscale multiphase properties such as foam texture and the relative permeability of foam banks. Modification on a microscale foam model based on a pore-filling event network method is proposed to simulate its propagation in grain-based pore networks with varying degrees of heterogeneity. The impacts of foam injection strategy and oil-weakening phenomena are successfully incorporated. Corresponding microfluidic experiments are performed to validate the simulation results in dynamic displacement pattern as well as interfacial configuration. The proposed modeling method of foam propagation in grain-based networks successfully captures the effects of lamellae configurations corresponding to various foaming processes. The results of the simulation suggest that the wettability of rock has an impact on the relevance between reservoir heterogeneity and the formation of immobile foam banks, which supports the core idea of the recently proposed foam injection strategy in tight oil reservoirs with severe heterogeneity, that of focusing more on the IFT adjustment ability of foam, instead of arbitrarily pursuing high-quality strong foam restricted by permeability constraints.