The recoverable hydrocarbon reserves of conventional oil and gas resources are very limited in China. As important alternative resources, unconventional oil and gas have become a research hotspot. Though tight reservoirs have great potential to alleviate the increasing demand, issues during the development process, such as the rapid pressure depletion, fast decline in production, low productivity, and difficulties in water injection, are usually encountered due to poor physical properties like small pore throats and strong heterogeneity of the pore structure. The CO2 flooding technique could effectively replace crude oil from micro-nanopores, which is considered as a promising way to enhance the development performance of tight oil. However, precipitation and dissolution phenomena usually occur along with the CO2 injection process into reservoirs, affecting the pore structure evolution and oil displacement efficiency. In addition, artificial and natural fractures will even make this process more complicated. This paper presents the commonly used experimental approaches for CO2 injection into tight reservoirs and summarizes the main methods for investigating the influence of CO2 injection on the pore structure of reservoir rocks. Based on this, we highlighted that more attention should be paid to the influence of fractures and their dynamic changes on the evolution of pore structure during CO2 injection and the study of the solid–liquid interactions. To establish a method that could quantitatively evaluate the full-scale evolution of pore throats after CO2 injection is necessary. Meanwhile, the interaction strength of precipitation and dissolution and their effects on pore structure also remain open. Finally, a rigorous framework that could reveal the evolution mechanism and characterize the multiscale pore structure involving multiple influencing factors is urgently warranted.

The microscopic pore structure of tight sandstone reservoirs significantly impacts CO2 flooding characteristics. In this work, two types of realistic sandstone visualization models were selected based on petrophysical properties and the pore structure feature. CO2 flooding experiments under different injection pressures and volumes were carried out using the in-house high-temperature and -pressure visualization flooding system. Then, the characteristics of oil movement and residual oil distribution were quantitatively described and analyzed for two rock types. The results show that the type I model has better physical properties and a more favorable pore structure, thus a higher oil recovery than the type II model. The immiscible CO2 flooding efficiency of the type I model is up to 64.5%. On the other hand, the oil recovery of the type II model increases when the miscible pressure is reached, and the maximum oil recovery is 49.5%. In the high-pressure miscible flooding stage, two types of models have similar oil recovery increments, which are 10.7 and 10.6%, respectively. Additionally, the residual oil distribution varies with the pore structure. The type I model has a small residual oil region and thus a high oil recovery efficiency. In contrast, the residual oil saturation of the type II model is larger, and the final oil recovery decreases. Furthermore, as the injection pressure and volume increase, the residual oil saturation becomes smaller, and oil recovery of both models increases. The occurrence characteristics of residual oil are oil droplet, cluster-shaped residual oil, flake oil, and dead corner oil, and the main influencing factors are capillary force, injection pressure, and pore connectivity.

CO2 injection is an effective way to improve oil recovery for tight sandstone reservoirs. In this study, the tight sandstone cores collected from Chang 6 Member of Yanchang Formation in Ordos Basin underwent continuous CO2 flooding, and CO2 huff and puff oil displacement measurements were collected under five various CO2 injection pressures, 4, 8, 12, 16, and 20 MPa respectively; combined with the classification of pores in the tight sandstone cores, the differences in oil producing degree in varying scale of pores were discussed in detail. Under continuous CO2 flooding, the oil producing degree reaches up to 73.29%, while the CO2 huff and puff features a higher oil producing degree, and it reaches almost 82.03%. The oil producing degree for these two modes shows a triple-stage with increasing CO2 injection pressures. There are five types of pores in tight sandstone pores, including I-1, I-2, I-3, I-4, and II, and the I-3 and I-4 pores feature not only a significantly high oil producing degree but also the smallest differences in oil producing degree under the two different CO2 flooding modes. The pore size effect is more significant in the tight sandstone cores with the increase in CO2 injection pressures; in comparison with the continuous CO2 flooding, the difference of oil producing degree in the pores with smaller apertures is significantly higher for the CO2 huff and puff, while it is not obvious in the pores with larger pore apertures, especially when the CO2 injection pressure exceeds the minimum miscible pressure (MMP). In addition, the CO2 injection pressure decreases to obtain the optimal oil producing degree in pores with larger pore aperture. This study can help in selecting appropriate CO2 injection modes to achieve the oil enhanced recovery for various types of tight sandstone reservoirs.