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.

Experimental study on production characteristics and enhanced oil recovery during imbibition and huff-n-puff injection in shale reservoir

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.

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.

Wettability, as a vital tool for analyzing and describing oil flow, plays a significant role in determining oil/water relative permeability, residual oil distribution, and on–site recovery efficiency. Although the contact angle method is widely used for measuring wetting behavior, it is susceptible to the effects of surface roughness, oil–water saturation, and the distribution of mixed wetting within the range of droplet sizes. Additionally, millimeter–scale droplets fail to accurately represent the wetting distribution and the influencing factors at the micro/nano–scale. Therefore, this study presents a comprehensive investigation of the microstructure and wettability of shale samples. The characterization of the samples was performed using scanning electron microscopy (SEM) and atomic force microscopy (AFM) techniques to gain insights into their microscopic features, surface properties, and wettability. Results demonstrate the following: (1) Quartz and clay minerals tended to exhibit rough surface topography, appearing as darker areas (DA) under scanning electron microscopy (SEM). It is worth noting that plagioclase minerals exhibited brighter areas (BA) under SEM. (2) An increase in the content of minerals such as quartz and clay minerals was observed to decrease the surface oil wetting behavior. In contrast, plagioclase feldspar exhibited an opposite trend. (3) Based on the adhesive forces of the samples towards oil or water, a wetting index, I, was established to evaluate the wettability of shale at a microscale. The dimensionless contact angle W, obtained by normalizing the contact angle measurement, also consistently indicated oil wetting behavior. (4) By comparing the differences between I and W, it was observed that surface roughness significantly affected the behavior of water droplets. The presence of roughness impeded the contact between the solid and liquid phases, thus influencing the accuracy of the wetting results. Organic matter also plays a significant role in influencing surface wettability, and its distribution within the shale samples can lead to localized variations in wettability.