Due to the increasing greenhouse effect as well as acute global climate and environmental problems, countries worldwide have reached a consensus to actively respond to climate change and reduce greenhouse gas emissions ^[1][2][1,2]. Since industrialization has continued since the industrial revolution, the use of fossil fuels has increased, and large amounts of CO₂ gas have been directly discharged into the air, which is one of the main reasons for the intensification of the greenhouse effect [3]. CO₂ emissions have led to a series of environmental problems, such as drought, glacier melt, and sea level rise, which have caused incalculable harm to the environment on which human beings depend [4]. At present, many technologies are available to control CO₂ emissions, such as improving the efficiency of fossil energy combustion, the efficient development and utilization of green and clean energy, and carbon capture and storage (CCS) [5]. CCS refers to the use of separation and purification technology to collect a large amount of CO₂ from industrial waste gas and inject it into appropriate underground reservoirs for permanent storage [6], which is recognized as one of the effective methods to manage CO₂ [7]. At present, the membranes used for the selective transport of CO₂ in the mixture of gases based on hollow alumina fiber-supported silica have been developed [8]. The application of this advanced technology greatly improves the efficiency of CO₂ capture. The main geological layers used for storage include abandoned mines, unrecoverable coal seams, depleted oil and gas fields, deep saline aquifers, and the ocean [9]. The storage depth is generally below 800 m. CO₂ geological storage is the most important part of CCS, and the storage capacity and safety of geological storage bodies determine the effectiveness of CO₂ emission control [10]. Compared to other gases, CO₂ is affected by temperature and pressure in the reservoir, and will produce phase transitions (gaseous, liquid, and supercritical). The microscopic flow of different phase states of CO₂ in porous media is different. In addition, when CO₂ flows in a reservoir, it can undergo physical and chemical reactions with reservoir water and matrix, causing damage to the reservoir. Meanwhile, the complexity, heterogeneity, and wettability [11] of the pores directly affect the flow behavior of CO₂ in reservoirs. Therefore, investigating the CO₂ flow law and revealing the CO₂ microscopic flow mechanism are key for evaluating the storage capacity and safety of geological storage bodies.

Numerous studies have been conducted on the flow of CO₂ in geological storage bodies. Lassen et al. [12] injected gaseous CO₂ into heterogeneous porous media at different rates, and the flow of CO₂ was monitored by sensors. The results showed that large-scale heterogeneity controlled the overall migration of gaseous CO₂ in porous media, whereas a smaller scale was important for gas saturation. The higher the injection rate, the larger the transverse diffusion of the gas phase. Zhang et al. [13] proposed that Darcy’s law could be used to describe a two-phase fluid flow in porous media at the macroscopic scale. Saleem et al. [14] compared and verified the constructed two-phase flow model using field observation data, such as the CO₂ eruption time, changes in the sediment pH, gas leakage rate, flow process, fluid interaction, and CO₂ dissolution in the CO₂ plume. The results showed that the CO₂ plume was formed and developed at a stable rate during the flow process, and the dissolution rate increased with an increase in the injection rate. These studies elucidated the flow of CO₂ from a macroscopic perspective. However, the flow behavior of CO₂ in a storage body is easily affected by its complex pore structures. In macroscale research, the complex pore structures of the storage body have not been accurately characterized. The research results were also based on macroscale flow and often ignored the effect of the pore structure complexity. Therefore, an accurate description of the microscopic flow of CO₂ is crucial for determining storage capacity and long-term safety [15].

2. Traditional Characterization of Pore Structures during CO₂ Microscopic Flow

Mercury intrusion porosimetry (MIP) ^[16][29], scanning electron microscopy (SEM) ^[17][30], and gas adsorption ^[18][31] have been used to characterize the pore structures of the storage body and further explore the flow of CO₂. Du et al. ^[19][32] used high-pressure mercury intrusion and permeation experiments to investigate the effect of CO₂ injected into coal. The results showed that the reaction between CO₂–water and coal led to an increase in the pore space and greatly increased the permeability, which increased the permeability area of CO₂ and improved the CO₂ storage capacity. Using SEM, Khather et al. ^[20][33] observed that a decrease in the pH during CO₂ injection caused the dissolution and migration of minerals, which resulted in an increase in the rock permeability and flow capacity of CO₂. Pearce et al. ^[21][34] studied the physical properties of the reservoir after CO₂ injection using SEM and found that the movement of fine particles could result in opening or blocking the pores during CO₂ injection, increasing or decreasing the permeability and affecting the CO₂ injection capacity. Brattekas and Haugen ^[22][35] used high-resolution micro-positron emission tomography (micro-PET) and radiotracers to achieve CO₂ tracing during the flow and capillary capture. The results showed that CO₂ mainly flowed into the outer part of the core with a high permeability. However, these techniques had numerous limitations for accurately characterizing the pore structure complexity in rocks. For example, MIP only obtained the total porosity of the sample and did not characterize the complexity of the pore distribution within the sample. SEM was an effective technique for generating 2D images of the microstructures. However, it did not provide 3D images, which were important for evaluating the pore structure complexity [5]. The measurement results obtained using gaseous adsorption methods were often constrained by the limited pore-scale range, and accurately characterizing the complexity of pore structures became challenging due to the size and interactions of the gas molecules ^[23][36]. More importantly, the traditional characterization methods did not visualize and quantitatively describe the microscopic flow of CO₂. In addition, Tang et al. ^[24][37] conducted a comprehensive comparison of the rock pore structure characterization techniques, including experimental analyses, image analyses, and digital core techniques, and emphasized the importance of digital core techniques for solving complex pore structure characterization. Therefore, to accurately reconstruct the 3D complex pore structures and visually and quantitatively study the microscopic flow mechanism of CO₂ in the geological storage body, it was necessary to use advanced techniques, such as CT scanning and NMR, to conduct an in-depth analysis using multidisciplinary intersection research ideas. It is worth noting that with the continuous improvement of artificial intelligence (AI), some research applied it in the field for studying the microscopic flow of CO₂ and achieved some remarkable results. A hybrid artificial intelligence model integrating a back propagation neural network (BPNN), genetic algorithm (GA), and adaptive boosting algorithm (AdaBoost) was proposed by Yan et al. ^[25][38], which was used to evaluate the change in the coal strength caused by the interaction between CO₂ and coal in the flow process. Zhang et al. ^[26][39] proposed four advanced machine learning schemes, including RBFNN-MVO, RBFNN-GWO, RBFNN-PSO, and MLPLM, to evaluate the contact angle of various shale systems. Overall, AI plays a key role in predicting the parameters of complex pore structures as well as evaluating safety. In addition, the method of using AI to predict fluid flow is a hot topic for future research.

3. Effects of the Porosity and Permeability Characteristics on the Microscopic Flow Mechanism of CO₂

The influence of the key parameters, including the porosity and permeability, on CO₂ flow in geological storage bodies is very important. By simulating 2D fluid flow experiments, Kitamura et al. ^[27][40] found that the flow behavior of CO₂ was strongly influenced by the small-scale heterogeneity of the pore structures. However, the simulation results had some errors since the model was 2D and could not fully describe the pore structure complexity. To investigate the effect of the reservoir laminar structures on the flow behavior of CO₂, Krishnamuthy et al. ^[28][41] used the CT scanning technique to observe the flow path of CO₂ by measuring the CO₂ saturation variation in the rock. The results showed that CO₂ preferentially flowed through the region with a larger porosity and passed unevenly along the axial direction. However, seepage under in situ conditions was not considered. Thus, the pore distribution in reservoir cores under in situ conditions could not be obtained. To accurately study the CO₂ microcosmic flow, Wang et al. ^[29][42] injected liquid CO₂ into a brine-saturated core. Multiscale CT scanning of sandstone was conducted and the distribution of the porosity at different locations in the core under in situ flow conditions was obtained. The phenomenon of CO₂ preferentially passing through the locations with a higher porosity was observed from the images. Al-Bayati et al. ^[30][43] conducted a displacement experiment on the stratified core samples using the CT scanning technique.  A clay interlayer, one of the typical representatives of a low-permeability layer, had an important influence on the CO₂ flow. Using CT scanning, Xu et al. ^[31][44] studied the flow characteristics of CO₂ in a special sandstone containing multiple thin clay interlayers. The experiment demonstrated that the flow channel of CO₂ was mainly established in the sandstone, and the clay interlayer hindered the CO₂ flow. However, the description of how the CO₂ flow was hindered by the clay interlayer was too vague. Therefore, Xu et al. ^[32][45] further monitored the flow process of CO₂ in the interior of the clay interlayer sample. When the injection direction was parallel to that of the clay interlayer, the clay interlayer separated the CO₂ flow. When the injection direction was perpendicular to that of the clay interlayer, the clay interlayer hindered the forward CO₂ flow.

4. Two-Phase Flow Law in CO₂ Microscopic Flow

When CO₂ was injected into the deep brine layer, it entered the reservoir pore structures to displace the original fluid from the pore space, and the flow process was an immiscible two-phase flow ^[33][16]. However, it was difficult to observe the space–time variation of the two-phase interface between the immiscible two-phase fluids in the porous media. Therefore, the immiscible two-phase flow needed to be understood from a pore-scale perspective, which was very important and extremely complex ^[34][46]. Using the CT scanning technique, Kogure et al. ^[35][47] injected CO₂ into the Berea sandstone at different times in opposite directions, and the flow behavior of CO₂ in the Berea sandstone was observed. The images showed several narrow pore throats that allowed for the CO₂ flow. Despite injections from opposite directions, the distribution of CO₂ was essentially the same in the final stage of injection. Liu et al. ^[36][48] injected CO₂ into a glass bead bed in both the upward and downward directions, and a displacement-saturated water experiment was conducted to investigate the distribution of CO₂ in the core. The displacement effect of CO₂ injected downward was substantially better than that of CO₂ injected upwards. This was attributed to the “gas channeling” phenomenon when CO₂ was injected upward, but the cause of the “gas channeling” phenomenon was not discussed in depth. Lv et al. ^[37][49] combined the CT scanning technique and a micromodel to study the flow process of CO₂–brine in the pore structures at different injection rates under static and transient conditions. The results showed that a higher injection rate caused a higher displacement efficiency but a lower sweep efficiency. Further, using the NMR technique, Teng et al. ^[38][50] found that the different viscosities and densities of CO₂ and water caused the “gas channeling” phenomenon of CO₂, which led to the premature breakthrough of CO₂ and reduced the displacement efficiency. In addition, Zhang et al. [13] obtained the local porosity and saturation of the Berea sandstone. The results showed that the forward movement of CO₂ on the capillary pressure was the main reason for the formation of the pathway of the CO₂ flow. CO₂ preferentially passed through the large-sized pores, and the seepage zone gradually expanded whereas the CO₂ saturation increased. The Influence of pore geometry on the microscopic flow mechanism of CO₂ was not ignored. Zhang et al. ^[39][51] used CT scanning to scan the displacement process of CO₂ and found that CO₂ was unevenly distributed in the sandstone samples. A larger flow patch was formed during the flow process. Herring et al. ^[40][52] adopted the Bentheimer sandstone core and used the CT scanning technique to observe the displacement process of CO₂ at the pore scale. The images showed that CO₂ invaded the pore space in a capillary fingering regime. Liu et al. ^[41][53] visualized and quantitatively analyzed the dynamic diffusion process of CO₂ in n-decane-saturated porous media. The results showed that the channels of the porous media hindered the diffusion of CO₂. The local diffusion coefficient of CO₂ gradually decreased with time along the diffusion path until it reached a steady state.

5. Microscopic Flow of CO₂ in Different Phase States

In geological storage, appropriate CO₂ phase states, including gaseous, liquid, and supercritical, should be selected according to the specific conditions and requirements of the storage body. CT scanning technology has been used to conduct extensive research on the microscopic flow of CO₂ in different phase states. CO₂ bubbles, a typical representative of the gaseous state, have a stable state in porous media with a high resistance factor (i.e., good plugging capacity), which plays an essential role in the safety of long-term storage of CO₂ ^[42][54]. Xue et al. ^[43][55] found that microbubble CO₂ injection minimized the content of free CO₂ in the reservoir compared to that of conventional CO₂ injection and also efficiently utilized the pore space of the reservoir, which was conducive to the long-term safety of large-scale CO₂ storage. Patmonoaji et al. ^[44][56] and Zhai et al. ^[45][57] conducted displacement experiments in sandstone and found that the microbubble flow had a stronger sweeping efficiency than that of the conventional flow, which improved the displacement efficiency and storage capacity of CO₂. The experimental results proved that CO₂ foam not only improved oil and gas recovery compared to conventional CO₂, but also improved the pore space utilization and increased CO₂ storage in the reservoir. Accordingly, Du et al. ^[46][58] further investigated the seepage characteristics of CO₂ bubbles in porous media. However, the experimental object was self-made homogeneous porous media, whereas most of the actual reservoir was composed of heterogeneous rocks. Thus, the experimental results had some limitations. For this reason, McLendon et al. ^[47][59] injected CO₂ with and without a surfactant into real Berea sandstone under high-pressure conditions to observe the in situ bubble generation. The results showed that CO₂ tended to pass through the high-permeability reservoir without the addition of a surfactant but resulted in a decrease in the sweep efficiency of CO₂. Du et al. ^[48][60] studied the dynamic bubble flow behavior in the entrance region of porous media and obtained dynamic three-phase saturation distributions along the sample core. The results showed that the CO₂ bubble pushed most of the liquid phase into the latter part of the porous media, but the forepart was difficult to push, showing an obvious entrance effect. The above studies investigated the microscopic flow of single-phase CO₂. However, it was unusual that CO₂ not only existed in the actual storage body, but two or multiphase may be present. Therefore, it was essential to further study the microscopic flow of CO₂ under the condition of polyphase coexistence (including miscible, near-miscible, and immiscible phases). Alhosani et al. ^[49][61] conducted an in situ study on immiscible-phase CO₂ displacement in oil-wet reservoirs. The images showed that in strongly oil-wet rocks, the largest pore space was occupied by water, the smallest pore space was occupied by oil, and the medium-sized pore space was occupied by CO₂. CO₂ was distributed in a connected layer under near-miscible-phase conditions and existed as separated “ganglia” in medium-sized pores under immiscible-phase conditions. Qin et al. ^[50][62] conducted a study on the wettability and spatial distribution of near-miscible-phase CO₂ in oil-wet carbonate rocks under a high temperature and pressure. The results showed that at the initial stage of injection, CO₂ had good connectivity with the oil phase and poor connectivity with the brine phase. With the continuous injection of CO₂, the wettability reversal process was triggered, resulting in a decrease in the oil wettability and an improvement in the CO₂ connectivity with brine. Hao et al. ^[51][63] conducted multi-phase and multiple injection experiments. It was found that under the immiscible-phase condition, the porous media showed remarkable gas coverage and flow stratification owing to gas buoyancy. The miscible-phase CO₂ injection eliminated the effect of buoyancy, thus expanding the storage area and flow range of CO₂. The reliability of CO₂ geologic storage depends on the flow mechanism of CO₂ in reservoirs. Due to advanced imaging techniques such as CT scanning and NMR in experimental studies, it was beneficial to study the microscopic flow mechanism of CO₂ in complex pore structures. However, few studies used CT scanning and NMR technology to conduct real-time visualization and quantification research on the microscopic flow process of CO₂. In addition, microscopic flow studies of different phases of CO₂ in complex pore structures were not sufficiently comprehensive, which will be the focus of future research.