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.

The fracturing fluid residing in a reservoir undergoes spontaneous imbibition. Here, to explore the mechanism of fracturing fluid imbibition and oil displacement, experiments on the spontaneous imbibition of fracturing fluid under different influencing factors were conducted on a core sample from the Ordos Basin of the Chang 8 formation. Combined with nuclear magnetic resonance technology, we quantitatively evaluated the degree of oil production of different pores during the fracturing fluid displacement process. Experimental results show that fracturing fluid salinity, fracturing fluid interfacial tension, and crude oil viscosity are negatively correlated with oil recovery. The phenomenon of microscale imbibition oil displacement occurs in pores of various scales in the core. The imbibition scale was between 0.10 and 1608.23 ms. The degree of crude oil production in the pores at each scale increased with increasing imbibition time. Moreover, the crude oil viscosity, fracturing fluid salinity, and fracturing fluid interfacial tension are negatively correlated with the degree of oil production at various pore scales. Decreasing crude oil viscosity significantly improves the degree of small-pore (0.1–16.68 ms) crude oil production; the low interfacial tension possesses a higher degree of oil production in the large pores (>16.68 ms), and the increment in the degree of oil production under different salinities of the small pores (0.1–16.68 ms) is greater than that of the large pores (>16.68 ms).

Gel particle profile modification and flooding is one of the main technical methods for stabilizing oil, water control, and production cycle prolonging in the oil field. Quantitative evaluation of the plugging effect of the displacement agent on pores of different sizes under various conditions may provide useful guidance for field development. In this study, nuclear magnetic resonance technology and dynamic physical simulation experiments were used to quantitatively evaluate the plugging effect of pore spaces at different scales. The influence of permeability, temperature, injection pressure, injection volume, and formation water salinity on plugging effect was also investigated. The results show that the poly(ethylene glycol) (PEG)-1 gel particle system flooding agent can effectively plug pore spaces at different scales. For artificial cores, the plugging dimension was between 0.10 and 59.95 ms, and for natural cores, the plugging dimension was between 0.10 and 1144.64 ms. The plugging effect of gel particles was negatively correlated with permeability and salinity of formation water and positively correlated with temperature, injection pressure, and injection volume. Moreover, the plugging efficiency of gel particles for larger pores (>10.0 ms) was always better than that for smaller pores (0.10−10.0 ms).