Spontaneous imbibition is the process in which the wetting phase displaces a non-wetting phase under the action of capillary forces. However, variations in interfacial properties, imbibition directions, and fractures result in different imbibition modes, posing challenges to a comprehensive understanding of the process. In this study, microfluidic chips representing matrix and fracture–matrix systems were designed. Imbibition agents with varied interfacial properties were selected to conduct experiments under counter-current and co-current conditions. A flow factor (γ), related to fracture geometry and imbibition direction, was defined and used together with the microscopic capillary number (Ca_micro) to characterize the imbibition process. Three distinct imbibition modes were observed for different Ca_micro and γ, clearly separated by γ–Ca_micro boundaries. During co-current imbibition, an unusual capillary-driven displacement process was observed, leading to fingering in the fracture–matrix model and leaving a large area of macroscale remaining oil. Smaller Ca_micro and fracture development will facilitate this process. In addition, various forms of microscale remaining oil, caused by bypass flow snap-off and Saffman–Taylor instability/Rayleigh–Taylor instability, were also observed across different imbibition processes. This study elucidates the imbibition mechanisms under the combined influence of capillary and viscous forces, providing deeper insights into the imbibition process in porous media.

Boosted by economic development and rising living standards, the world's carbon dioxide emissions remain high. Maintaining temperature rises below 1.5 ℃ by the end of the century requires rapid global carbon capture and storage implementation. The successful application of carbon capture, utilization, and storage (CCUS) technology in oilfields has become the key to getting rid of this predicament. Foam flooding, as an organic combination of gas and chemical flooding, became popular in the 1950s. Notwithstanding the irreplaceable advantages, as a thermodynamically unstable system, foam's stability has long restricted its development in enhanced oil and gas recovery. With special surface/interface effects and small-size effects, nanoparticles can be used as foam stabilizers to enhance foam stability, thereby improving foam seepage and oil displacement effects in porous media. In this paper, the decay kinetics and the stabilization mechanisms of nanoparticle-reinforced foams were systematically reviewed. The effects of nanoparticle characteristics, including particle concentration, surface wettability, particle size, and type, and reservoir environment factors, including oil, temperature, pressure, and salinity on the foam stabilization ability were analyzed in detail. The seepage and flooding mechanisms of nanoparticle-reinforced foams were summarized as: improving the plugging properties of foams, enhancing the interaction between foams and crude oil, and synergistically adjusting the wettability of reservoir rocks. Finally, the challenges in the practical application of nanoparticle-reinforced foams were highlighted, and the development direction was proposed. The development of nanoparticle-reinforced foam can open the way toward adaptive and evolutive EOR technology, taking one further step towards the high-efficiency production of the petroleum industry.

The polymeric surfactant can be used as an efficient agent for enhanced oil recovery (EOR) because of its large bulk viscosity and good interfacial activity. However, there is a sparse understanding of its matching relationship with reservoirs and emulsification occurrence conditions, which may affect its migration and EOR efficiency. One intermolecular association molecule polymeric surfactant (IAM) was synthesized by micellar polymerization and characterized with ¹H NMR, FTIR, and TGA. The matching relationship between IAM and reservoirs was evaluated by comparing the viscosity retention rate of effluent in the core flow experiments. Moreover, the effect of the matching relationship on EOR in the heterogeneous reservoir was clarified with parallel core displacement experiments by considering different flow abilities of IAM in the high-permeability layer. The occurrence conditions of in-situ emulsification of IAM were evaluated via oil-water co-injection experiments under the different injection rates and oil-water ratios. Microscopic visualization displacement was carried out to compare the micro EOR mechanisms of different chemical systems. The results show that IAM features thickening, shearing resistance, viscoelasticity, thermal stability, and interfacial activity. The matching relationship between cores and IAM could be divided as hardly injected, flow limited, and flow smoothly, corresponding to the viscosity retention ratio of < 20%, 20%–80%, and > 80%, respectively. IAM could gain better EOR efficiency (17.69%) when its matching relationship to the high permeability layer was “flow limited”. The defined mixture capillary number shows that only when it is greater than 1 × 10⁻³, the in-situ emulsions can be generated. Compared to HPAM, IAM could reduce IFT and form vortices to more effectively displace film and corner remaining oils by stripping and peeling off crude oil. The formed emulsion accumulated at the pore throat could further increase flow resistance, which benefits swept area enlargement. This work could provide theoretical and data support for the parameters design in the polymeric surfactant practical application.