CO₂ huff-n-puff is a promising enhanced oil recovery technique for shale oil reservoirs, but its efficiency in relation to pore structure across classified oil reservoirs remains unclear. This study investigates three reservoir classes (Types Ⅰ–Ⅲ) in the Jimusar Sag using high pressure mercury intrusion, nitrogen adsorption, and NMR to characterize pore architectures. Results show that the shale cores from the Jimusar shale oil reservoir are overall dominated by medium pores, with generally small pore radii. Among them, the Type Ⅰ oil reservoir class has a higher proportion of large pores (> 300 nm), whereas the Type Ⅲ oil reservoir class has a higher proportion of small pores (< 50 nm) than the other two classes. Online NMR monitored CO₂ huff-n-puff experiments under reservoir conditions (363.15 K, injection pressure > 24 MPa) reveal significant cumulative oil recovery differences: 56.36% (Type Ⅰ), 46.81% (Type Ⅱ), and 28.30% (Type Ⅲ) after four cycles. Recovery correlates with pore size: The Type Ⅰ oil reservoir class, with a higher proportion of large pores, exhibits stronger CO₂ flow capacity, whereas the Type Ⅲ oil reservoir class, with a larger proportion of small pores, significantly restricts oil mobilization. A second derivative analysis of the recovery–pore radius curve quantifies mobilization thresholds, indicating a lower limit effective pore radius of 20–35 nm. Sensitivity analysis shows that increasing injection pressure more effectively improves recovery and lowers the mobilization threshold than extending soaking time.

CO₂ injection into oil reservoirs is expected to achieve enhanced oil recovery along with the benefit of carbon storage, while the application potential of this strategy for shale reservoirs is unclear. In this work, a numerical model for multiphase flow in shale oil reservoirs is developed to investigate the impacts of nano-confinement and oil composition on shale oil recovery and CO₂ storage efficiency. Two shale oils with different maturity levels are selected, with the higher-maturity shale oil containing lighter components. The results indicate that the saturation pressure of the lower-maturity shale oil continues to increase with increasing CO₂ injection, while that of the higher-maturity shale oil continues to decrease. The recovery factor and CO₂ storage rate for higher-maturity shale oil after CO₂ huff-n-puff are 12.02% and 44.76%, respectively, while for lower-maturity shale oil, these are 4.41% and 69.33%, respectively. These data confirm the potential of enhanced oil recovery in conjunction with carbon storage in shale oil reservoirs. Under the nano-confinement impact, a decrease in the oil saturation in the matrix during production is reduced, which leads to a significant increase in oil production and a significant decrease in gas production. The oil production of the two kinds of shale oil is comparable, but the gas production of higher-maturity shale oil is significantly higher. Nano-confinement shows a greater impact on the bubble point pressure of higher-maturity shale oil and a more pronounced impact on the production of lower-maturity shale oil.

Tight conglomerate reservoirs are featured with extremely low permeability, strong heterogeneity and poor water injectivity. CO₂ huff-n-puff has been considered a promising candidate to enhance oil recovery in tight reservoirs, owing to its advantages in reducing oil viscosity, improving mobility ratio, quickly replenishing formation pressure, and potentially achieving a miscible state. However, reliable in-house laboratory evaluation of CO₂ huff-n-puff in natural conglomerate cores is challenging due to the inherent high formation pressure. In this study, we put forward an equivalent method based on the similarity of the miscibility index and Grashof number to acquire a lab-controllable pressure that features the flow characteristics of CO₂ injection in a tight conglomerate reservoir. The impacts of depletion degree, pore volume injection of CO₂ and soaking time on ultimate oil recovery in tight cores from the Mahu conglomerate reservoir were successfully tested at an equivalent pressure. Our results showed that oil recovery decreased with increased depletion degree while exhibiting a non-monotonic tendency (first increased and then decreased) with increased CO₂ injection volume and soaking time. The lower oil recoveries under excess CO₂ injection and soaking time were attributed to limited CO₂ dissolution and asphaltene precipitation. This work guides secure and reliable laboratory design of CO₂ huff-n-puff in tight reservoirs with high formation pressure.