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.

The existing productivity models of staged fractured horizontal wells in tight oil reservoir are mainly linear flow models based on the idealized dual-medium fracture network structure, which have a certain limitation when applied to the production prediction. Aiming at the difficulty in describing the shape of the complex fractal fracture network, a two-dimensional heterogeneous structure model of the fracture network is proposed in this paper. Considering the deformation characteristics of porous media and the characteristic of non-Darcy fluid flow, a three-zone steady-state productivity model with the combination of radial and linear flow is established. To eliminate strong nonlinear characteristics of the mathematical model, a fractional step method is employed to deduce the production formulas of staged fractured horizontal wells under infinite and finite conductivity fractures. The established productivity model is verified with the actual data of three horizontal wells in different blocks of S oilfield, and the error between the model calculation results and the actual production data is less than 4%. The analysis results of productivity sensitive factors show that production of horizontal wells is primarily influenced by the reservoir physical properties and fracturing parameters. The steady-state productivity model established in this study can be applied to effectively predict the average production of a horizontal well in stable stage of production, and it has theoretical and practical application value for improving the development effect of tight oil reservoir.

In low permeability reservoirs, water injection is the main means to supplement formation energy, and water quality is a key factor influencing the effect of waterflooding. However, the water quality is defined corresponding to large ranges of permeability under the current standard, which restricts the effective implementation of fine water injection into low permeability reservoirs. In this paper, throat distribution and contribution of mainstream throat to the permeability of low permeability reservoirs were analyzed, and the range of throats that influences water injection effect in such reservoirs was illustrated. Laboratory waterflooding physical simulation experiments on cores were conducted to quantitatively analyze the impacts of clay particle migration and hydration expansion on the seepage ability, and depending on the characteristics of throat distribution, quantify the damages to reservoirs caused by particle size and concentration of suspended solids in injected water. The particle size and concentration limits of suspended solids in injected water were proposed for low permeability reservoirs.

At present, the existing deliverability evaluation models mainly consider the impact of specific factors on production, and the description of the complex fracture network structure primarily remains at the stage of an ideal dual-pore medium with uniform distribution. However, this cannot reflect the actual fracture network structure and fluid flow law of fractured horizontal wells. Thus, in this paper, a non-uniform fracture network structure is proposed considering the influence of the threshold pressure gradient and stress sensitivity characteristics on the production performance of horizontal wells. The stress sensitivity and the fractal theory are combined to characterize the permeability of the complex fracture network, and a three-zone compound unsteady deliverability model for staged fractured horizontal wells in tight oil reservoirs is successfully developed. Laplace transformation, perturbation theory, and numerical inversion are applied to obtain the semi-analytical solution of the proposed deliverability model. The reliability and accuracy of the analytical solution are verified by the classical tri-linear flow model and an oil field example. The effects of related influential parameters on the production of horizontal wells are analyzed. The deliverability evaluation method proposed in this paper can provide a theoretical basis for formulating rational development technology policies for tight oil reservoirs.

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.