CO₂-enhanced oil recovery (CO₂-EOR) is a crucial method for CO₂ utilization and sequestration, representing an important zero-carbon or even negative-carbon emission reduction technology. However, the low viscosity of CO₂ and reservoir heterogeneity often result in early gas breakthrough, significantly reducing CO₂ utilization and sequestration efficiency. A water-alternating-gas (WAG) injection is a technique for mitigating gas breakthrough and viscous fingering in CO₂-EOR. However, it encounters challenges related to insufficient mobility control in highly heterogeneous and fractured reservoirs, resulting in gas channeling and low sweep efficiency. Despite the extensive application and research of a WAG injection in oil and gas reservoirs, the most recent comprehensive review dates back to 2018, which focuses on the mechanisms of EOR using conventional WAG. Herein, we give an updated and comprehensive review to incorporate the latest advancements in CO₂-WAG flooding techniques for enhanced sweep efficiency, which includes the theory, applications, fluid displacement mechanisms, and control strategies of a CO₂-WAG injection. It addresses common challenges, operational issues, and remedial measures in WAG projects by covering studies from experiments, simulations, and pore-scale modeling. This review aims to provide guidance and serve as a reference for the application and research advancement of CO₂-EOR techniques in heterogeneous and fractured reservoirs.

The mechanism by which oil recovery can be enhanced by different injection methods of CO₂ miscible flooding to alleviate the influence of heterogeneous reservoirs was studied to optimize the injection methods, further improving oil recovery. According to the reservoir heterogeneity characteristics of the TI oil formation group in Lunnan Oilfield, a 1 m double-layer long core was designed and prepared for four CO₂ miscible displacement experiments with different injection methods. By analyzing the variation in the injection-production parameters, the displacement effects of different injection methods were compared, and the mechanism of enhanced oil recovery (EOR) was summarized. The results indicate the following. ① The displacement efficiency of the different injection methods lies in the following order. Alternate CO₂-water injection, continuous CO₂ flooding, cyclic CO₂ flooding, and alternate CO₂-hydrocarbon gas injection. ② The recovery of crude oil via CO₂ miscible flooding in heterogeneous reservoirs relies on both convective diffusion and miscible mass transfer. Convective diffusion depends mainly on control of the displacement pressure differential and the plugging of preferential seepage channels in high-permeability areas, while miscible mass transfer depends mainly on the swept range of the convective diffusion and the degree of miscibility between CO₂ and crude oil. ③ To improve the recovery efficiency of CO₂ miscible flooding in heterogeneous reservoirs, it is necessary to choose an injection method that optimizes these two aspects.

Understanding the dynamic characterization of the CO₂ miscible flooding process in low permeability reservoirs and its mechanism for oil recovery enhancement is crucial for controlling CO₂ miscible flooding sweep efficiency and further enhancing oil recovery. This study was conducted in a low permeability reservoir in Jilin, China, using both online nuclear magnetic resonance CO₂ miscible flooding and long-core CO₂ miscible flooding experiments. A refined dynamic characterization of the CO₂ miscible flooding process from the macroscopic core scale to the microscopic pore scale was achieved through multiple spatial online nuclear magnetic resonance testing methods. Analysis of dynamic characteristics of physical parameters was based on long-core displacement experiments and gas chromatography. This study summarizes the influence mechanism of CO₂ miscible flooding on enhanced oil recovery in low permeability reservoirs and demonstrates the feasibility of CO₂ miscible flooding. The results indicated that (1) CO₂ miscible flooding enables simultaneous oil recovery from micro-, meso-, and macropores, significantly improving displacement efficiency. (2) The recovery process unfolds in two stages: the initial CO₂ miscible flooding stage before gas breakthrough and the subsequent CO₂ miscible transport stage after gas breakthrough. (3) Both stages are instrumental in expanding the macroscopic swept range of CO₂, thereby enhancing oil recovery. (4) The miscibility of CO₂ with crude oil can affect the oil's composition. (5) The combined effect of miscible flooding and transport underpins the high displacement efficiency of CO₂ miscible flooding. Emphasizing these critical aspects could enhance oil recovery from CO₂ miscible flooding in field production.

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.

It is very important to effectively describe the sweep characteristics of CO₂ miscible flooding based on physical models for actual reservoir development. In this study, based on the geological characteristics of the Jilin ultra-low permeability reservoir, which has significant vertical heterogeneity, a two-dimensional double-layer heterogeneous visualization model with a permeability contrast of 10 and thickness contrast of 2 was designed to perform experimental research on the sweep law of CO₂ miscible flooding with an injection-production mode of “united injection and single production”. With the goal of determining the obvious differences in the gas absorption capacity and displacement power of the two layers, the CO₂ dynamic miscible flooding characteristics were comprehensively analyzed, and the sweep law of CO₂ miscible flooding, including the oil and gas flow trend, migration direction of the oil–gas interface, and distribution characteristics of the miscible zone, was further studied in combination with the oil displacement effect. In this experiment, the gas absorption capacity was the key factor affecting the sweep efficiency of the CO₂ miscible flooding. Under the combined influence of the internal and external control factors of the reservoir thickness, permeability, and injection-production mode, the gas absorption capacity of the high-permeability layer was much greater than that of the low-permeability layer, resulting in the retention of a large amount of remaining oil in the low-permeability layer, which effectively displaced and swept the oil in the high-permeability layer. The gas absorption capacity of the reservoir, gravitational differentiation, and miscible mass transfer were key factors affecting the migration of the oil–gas interface and distribution of the miscible zone. The entire displacement process could be divided into three stages: ① The gas-free rapid oil production stage, which was dominated by the displacement; ② the low gas–oil ratio stable oil production stage, which was jointly affected by the displacement and miscible mass transfer; and ③ the high gas–oil ratio slow oil production stage, which was dominated by the effect of CO₂ carrying.

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.