CCUS‐enhanced oil recovery (EOR) technology relies on the unique properties of CO₂ gas in the process of efficient oil displacement while achieving effective storage, which has become one of the most economical and effective measures for reducing greenhouse gas emissions in today's society and is important for helping to realize the global strategic goal of carbon neutrality. Based on previous research results, this review presents the oil displacement and geological storage mechanisms of CO₂ in micropores in the oil and gas fields, and summarizes their respective influencing factors. At the same time, it also summarizes the current research status of CO₂‐EOR and geological storage from the perspectives of laboratory experiments and numerical simulations. Moreover, it provides a detailed overview of four key technologies namely, miscibility improvement, swept volume expansion, storage potential assessment and storage safety monitoring, and their field applications. On this basis, this review compares the development status of field applications in Developed Countries and China, analyzes the problems of CCUS‐EOR technology in theoretical research, technology research and development and project industrialization, and points out the future development directions. Results are presented that research on CO₂‐EOR and geological storage in Developed Countries such as the United States started early and developed rapidly. A relatively complete industrial chain system has been formed, and the scale and number of CCUS‐EOR projects are far ahead those in China. In China, relevant research started relatively late and developed slowly at the early stage. In recent years, due to the notable attention given to climate change and carbon storage, development efforts in China have gradually intensified. At present, there are more than 20 large‐scale CCUS‐EOR demonstration projects in operation, which are preliminarily ready for industrial promotion. Notably, the world has continued to increase its attention to CCUS‐EOR projects based on national conditions, further improving policy guidance mechanisms, strengthening research and development efforts, promoting the construction of the full‐process industry chain, achieving large‐scale and refined development, and providing theoretical guidance and technical support for realizing the strategic goal of carbon neutrality.

The microscopic pore structure controls the fluid seepage characteristics, which in turn affect the final recovery of the reservoir. The pore structures of different reservoirs vary greatly; therefore, the scientific classification of microscopic pore structures is the prerequisite for enhancing the overall oil recovery. For the low permeability conglomerate reservoir in Mahu Sag, due to the differences in the sedimentary environment and late diagenesis, various reservoir types have developed in different regions, so it is very difficult to develop the reservoir using an integrated method. To effectively solve the problem of microscopic pore structure classification, the low permeability conglomerate of the Baikouquan Formation in Well Block Ma18, Well Block Ma131, and Well Block Aihu2 are selected as the research objects. The CTS, HPMI, CMI, NMR, and digital cores are used to systematically analyze the reservoir micro pore structure characteristics, identify the differences between different reservoir types, and optimize the corresponding micro pore structure characteristic parameters for reservoir classification. The results show that the pore types of the low permeability conglomerate reservoir in the Baikouquan Formation of the Mahu Sag are mainly intragranular dissolved pores and residual intergranular pores, accounting for 93.54%, microfractures and shrinkage pores that are locally developed, accounting for 5.63%, and other pore types that are less developed, accounting for only 0.83%. On the basis of clear pore types, the conglomerate reservoir of the Baikouquan Formation is divided into four types based on the physical properties and microscopic pore structure parameters. Different reservoir types have good matching relationships with lithologies. Sandy-grain-supported conglomerate, gravelly coarse sandstone, sandy-gravelly matrix-supported conglomerate, and argillaceous-supported conglomerate correspond to type I, II, III, and IV reservoirs, respectively. From type I to type IV, the corresponding microscopic pore structure parameters show regular change characteristics, among which, porosity and permeability gradually decrease, displacement pressure and median pressure increase, maximum pore throat radius, median radius, and average capillary radius decrease, and pore structure becomes worse overall. Apparently, determining the reservoir type, clarifying its fluid migration rule, and formulating a reasonable development plan can substantially enhance the oil recovery rate of low permeability conglomerate reservoirs.

The low-permeability conglomerate reservoir in the Mahu Sag has great resource potential, but its strong heterogeneity and complex microscopic pore structure lead to a high oil-gas decline ratio and low recovery ratio. Clarifying the migration rule of crude oil in microscopic pore throat of different scales is the premise of efficient reservoir development. The low-permeability conglomerate reservoir of the Baikouquan Formation in the Mahu Sag is selected as the research object, and two NMR experimental methods of centrifugal displacement and imbibition replacement are designed to reveal the differences in the migration rule of crude oil in different pore throats. According to the lithology and physical properties, the reservoirs in the study area can be divided into four categories: sandy grain-supported conglomerates, gravelly coarse sandstones, sandy-gravelly matrix-supported conglomerates and argillaceous-supported conglomerates. From type I to type IV, the shale content of the reservoir increases, and the physical property parameters worsen. Centrifugal displacement mainly produces crude oil in large pore throats, while imbibition replacement mainly produces crude oil in small pores. In the process of centrifugal displacement, for type I reservoirs, the crude oil in the pore throats with radii greater than 0.5 μm is mainly displaced, and for the other three types, it is greater than 0.1 μm. The crude oil in the pore throats with radii of 0.02–0.1 μm, which is the main storage space for the remaining oil, is difficult to effectively displace. The crude oil in the pore throats with radii less than 0.02 μm cannot be displaced. The two experimental methods of centrifugation and imbibition correspond to the two development methods of displacement and soaking in field development, respectively. The combination of displacement and soaking can effectively use crude oil in the full-scale pore throat space to greatly improve the recovery of low-permeability conglomerate reservoirs.

In this study, nuclear magnetic resonance and computed tomography scanning were used to analyze the production law and displacement mechanism of Jimusaer continental shale oil during CO₂ huff ‘n’ puff, and the optimal parameters were determined. The results indicated that CO₂ huff ‘n’ puff mainly produces crude oil in pore throats with 0.1–1 μm radii, while crude oil in pore throats with radii below 0.1 μm cannot be produced. Multiple CO₂ huff ‘n’ puff cycles can connect fluids in fractures with fluids in large–medium pore throats, eliminate fracture effects on the oil recovery factor, and achieve coefficient development of both fractured and unfractured shales. In the CO₂ huff ‘n’ puff process, core pressure change could be divided into three stages of injection–holding–depletion, and the oil displacement mode was the piston type. The study of huff ‘n’ puff parameters revealed that huff ‘n’ puff cycles and injection pressure have a great influence on the CO₂ huff ‘n’ puff efficiency, while the injection timing and soaking time imposed relatively small effects. For continental shale in the Jimusaer Sag, the optimal CO₂ huff ‘n’ puff parameters are five cycles, 4‐MPa injection timing, 25‐MPa injection pressure, and 12‐h soaking time.