Fluid flow in microporous and nanoporous media exhibits unique behaviors that deviate from classical continuum predictions due to dominant surface forces at small scales. Understanding these microscale flow mechanisms is critical for optimizing unconventional reservoir recovery and other energy applications. This review provides a comparative analysis of the existing literature, highlighting key advances in experimental techniques, theoretical models, and numerical simulations. We discuss how innovative micro/nanofluidic devices and high-resolution imaging methods now enable direct observation of confined flow phenomena, such as slip flow, phase transitions, and non-Darcy behavior. Recent theoretical models have clarified scale-dependent flow regimes by distinguishing microscale effects from macroscopic Darcy flow. Likewise, advanced numerical simulations—including molecular dynamics (MD), lattice Boltzmann methods (LBM), and hybrid multiscale frameworks—capture complex fluid–solid interactions and multiphase dynamics under realistic pressure and wettability conditions. Moreover, the integration of artificial intelligence (e.g., data-driven modeling and physics-informed neural networks) is accelerating data interpretation and multiscale modeling, offering improved predictive capabilities. Through this critical review, key phenomena, such as adsorption layers, fluid–solid interactions, and pore surface heterogeneity, are examined across studies, and persistent challenges are identified. Despite notable progress, challenges remain in replicating true reservoir conditions, bridging microscale and continuum models, and fully characterizing multiphase interface dynamics. By consolidating recent progress and perspectives, this review not only summarizes the state-of-the-art but underscores remaining knowledge gaps and future directions in micro/nanopore flow research.

Tight reservoirs are sensitive to stress changes during fracturing and oil and gas production. Facing different production modes, the variation characteristics of rock permeability and pore structure need to be further clarified. In this study, using a self-built high temperature and pressure physical simulation device and NMR equipment, the influence of the stress loading method, cyclic loading, and loading rate on rock permeability and pore characteristics were analyzed, and the relationship between them was clarified. The permeability sensitivity under variable confining pressure (63.3%) was greater than that of variable flow pressure (46.4%). The damage rate decreased with repeated loading (63.3%-35.8%) and increased loading rate (53.1%-42.3%). As for the pore features, when the net stress increased, the volume variation range of micropores was greater than that of mesopores. The damage rate of permeability (63.3%) was obviously larger than that of pore volume (10.4%). The slope of the fitted curve of permeability and pore volume decreased evidently with loading times. The structure deformation of rock skeleton and the migration of cement had a great influence on permeability in the first loading. Later, it was mainly the bulk deformation of rock particles, the particles’ contact surface increasing and the seepage space shrinking slowly. Eventually, the permeability remained stable due to the limited pore compression. This study can provide a reference for designing reasonable production parameters and reducing formation damage.

There are complex pore structures in shale reservoirs, and the nonlinear flow characteristics of shale reservoirs are complicated by stress sensitivity and boundary layer effects. In this research, a new flow mathematical model was established based on capillary model, stress sensitivity and boundary layer effect. The model was verified by the experimental results of Jilin shale oil reservoir, and the influencing factors of flow characteristics were analyzed. The results show that the new shale oil flow model has good fitting and high reliability with the experimental results. The boundary layer effect and stress sensitivity are the main factors affecting the seepage characteristics. With the increase in the pressure gradient, the influence of the boundary layer effect on the flow is gradually enhanced, and the influence of the stress sensitivity on the flow is gradually weakened. At the same time, this study developed a method for the evaluation of effective displacement distance of shale oil reservoir with CO₂ injection through the limited injection-production well spacing method, and obtained the nonlinear flow curve of displacement distance with reservoir permeability under different injection and production pressure difference. This research deeply studies the flow characteristics of shale oil reservoir and provides a theoretical basis for the enhanced oil recovery of shale oil with CO₂ injection.

Hydraulic fracturing technology has become a key technology for the development of low-permeability/tight oil and gas reservoirs. The evaluation on the postfracturing effect is imperative to the formulation and implementation of the fracturing and development plan. Based on the characteristics of the flow in fracture network after a large-scale hydraulic fracturing, a numerical method for evaluating the effect of fracturing in vertical well was established. This study conducts postfracturing effect evaluations to block C Oilfields wells that underwent conventional fracturing and volumetric fracturing, respectively, proposes the definition of fracture network conductivity and its relationship with cumulative production, and analyzes the fracturing construction parameters. The results suggest that the conventional fracturing can only form a single fracture instead of a stimulated reservoir volume (SRV) region. However, the volumetric fracturing transformation can form a complex fracture network system and SRV region and meanwhile bring obvious increase in the production. The effective time lasts for a longer period, and the increase of average daily oil is 2.2 times more than that of conventional fracturing. Additionally, with the progress of the production, the SRV area within the core region of the volume transformation gradually decreased from 6664.84m² to 4414.45m²; the SRV area of the outer region decreased from 7913.5m² to 5391.3m². As the progress develops, the equivalent permeability and the area of the fracture gradually decrease as the fracturing effect gradually weakens, and so does the conductivity of the network decreasing exponentially; a good correlation is observed between the conductivity of the fracture network, the cumulative production, and fracturing construction parameters, which can serve as the evaluation parameters for the fracturing effects and the basis for fracturing productivity prediction and provide a guidance for fracturing optimization design.

The confinement effect in micro- and nanopores gives rise to distinct flow characteristics in fluids. Clarifying the fluid migration pattern in confined space is crucial for understanding and explaining the abnormal flow phenomena in unconventional reservoirs. In this study, flow characteristics of water and oil in alumina nanochannels were investigated with diameters ranging from 21 nm to 120 nm, and a heterogeneous viscosity flow model considering boundary fluid was proposed. Compared with the prediction of the HP equation, both types of fluids exhibit significant flow suppression in nanochannels. As the channel size decreases, the deviation degree increases. The fluid viscosity of the boundary region displays an upward trend as the channel size decreases and the influence of the interaction between the liquid and solid walls intensifies. The thickness of the boundary region gradually decreases with increasing pressure and eventually reaches a stable value, which is primarily determined by the strength of the interaction between the liquid and solid surfaces. Both the pore size and wettability are essential factors that affect the fluid flow. When the space scale is extremely small, the impact of wettability becomes more pronounced. Finally, the application of the heterogeneous flow model for permeability evaluation has yielded favorable fitting results. The model is of great significance for studying the fluid flow behavior in unconventional reservoirs.