Compared to conventional reservoirs, the abundant nanopores developed in unconventional oil and gas reservoirs influence fluid properties, with nano-confinement effects. The phase behavior, flow characteristics, and solid–liquid interactions of fluids are different from those in conventional reservoirs. This review investigates the physical experiments, numerical simulations, and theoretical calculation methods used in the study of nano-confinement effects in unconventional oil and gas energy. The impact of different methods used in the analysis of fluid phase behavior and movement in nanopores is analyzed. Nanofluidic, Monte Carlo method, and modified equation of state are commonly used to study changes in fluid phase behavior. Nano-confinement effects become significant when pore sizes are below 10 nm, generally leading to a reduction in the fluid’s critical parameters. The molecular dynamic simulation, Monte Carlo, and lattice Boltzmann methods are commonly used to study fluid movement. The diffusion rate of fluids decreases as nanopore confinement increases, and the permeability of nanoscale pores is not only an inherent property of the rock but is also influenced by pressure and fluid–solid interactions. In the future, it will be essential to combine various research methods, achieve progress in small-scale experimental analysis and multiscale simulation.

Current methods for measuring three-phase relative permeability and its influencing factors

The transport behavior of multiphase flow in porous media is governed by the cross-scale coupling between fluid properties and pore structure, and serves as the theoretical foundation for core processes in fields such as energy development, underground carbon storage, and environmental remediation. Accurately characterizing the intrinsic relationship between physical properties and seepage responses is crucial for enhancing engineering prediction capabilities and optimizing operational strategies. However, the inherent heterogeneity and multiscale nature of natural reservoirs, coupled with the limitations of traditional experimental methods in terms of optical opacity and spatiotemporal resolution, severely hinder a deep understanding of the mechanisms of multiphase flow at the pore-scale. This paper systematically reviews the methodological framework for characterizing physical properties and seepage mechanisms in multiphase flow systems, with a focus on cutting-edge breakthroughs in experimental measurement and visualization technologies over the past decade. Starting with classical and emerging testing methods for key physical properties such as saturation, relative permeability, capillary pressure, and interfacial tension, the paper evaluates the applicability, accuracy advantages, and inherent limitations of different techniques. The paper focuses on the latest advancements in pore-scale visualization technologies, covering microfluidic models, high-resolution X-ray CT, synchrotron rapid dynamic imaging, and multimodal, multiscale imaging fusion strategies; it also explores AI-enabled image processing and data analysis methods, as well as the application potential of cross-scale numerical coupling models in revealing transient seepage mechanisms and correlating them with macroscopic responses. Based on this, an integrated analytical framework of “physical property measurement—visualization characterization—theoretical modeling—engineering application” is established, and the core challenges and future pathways for advancing multiphase flow and seepage research toward “quantification of mechanisms, cross-scale correlation, and adaptation to in situ real-world conditions” are identified.

Tight sandstone reservoirs are characterized by complex pore structures and ultra-low permeability, resulting in low recovery efficiency when relying solely on formation elastic energy. Consequently, water flooding is commonly employed for reservoir development. To investigate the two-phase flow behavior and pressure response during water flooding in tight sandstone reservoirs, long-core displacement experiments were conducted using outcrop tight sandstone cores. Thirteen pressure monitoring points were distributed along the core to continuously record the pressure response during water flooding, while cumulative oil and water production were measured to characterize the displacement performance. The temporal evolution of pressure and productivity index was systematically analyzed, and numerical simulation was further performed to interpret the relationship between pressure variations and water-front propagation. The results show that the cumulative oil production reached 50.95 mL, corresponding to a final oil recovery of 31.26%. No water production was observed during the initial stage of displacement, and water production began at approximately 8000 min, after which both water production and oil production gradually approached stable levels. The pressures at different monitoring locations exhibited a characteristic increase–decrease–increase pattern during the displacement process, whereas the productivity index decreased progressively before approaching a relatively stable value. Based on the experimental observations and numerical simulation results, the pressure response characteristics were closely associated with the propagation of the water front, with distinct pressure inflection points observed at different locations along the core. The mechanisms underlying pressure fluctuations and the decline in productivity index were analyzed from two perspectives: the extensive formation of dispersed phases and the dynamic evolution of interfacial flow resistance. These results provide experimental and numerical evidence for understanding pressure propagation and productivity evolution during water flooding in tight sandstone reservoirs.