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Primary oil recovery remains less than 10% in tight oil reservoirs, even after expensive multistage horizontal well hydraulic fracturing stimulation. Substantial experiments and pilot tests have been performed to investigate CO2-EOR potential in tight reservoirs; however, some results conflict with each other. The objective of this paper is to diagnose how these conflicting results occurred and to identify a way to narrow the gap between experimental results and field performance through a comprehensive literature review and data analysis. Peer-reviewed journal papers, technical reports, and SPE publications were collected, and three key steps were taken to reach our goal. First, rock and fluid properties of tight reservoirs in North America and China were compared, and their potential effect on tight oil production was analyzed. Afterward, based on published experimental studies and simulation works, the CO2-EOR mechanisms were discussed, including molecular diffusion, CO2-oil interaction considering nanopore confinement, and CO2-fluid-rock minerals interaction. Subsequently, pilot projects were examined to understand the gap between laboratory works and field tests, and the challenges faced in China's tight oil exploitation were rigorously analyzed. Compared with Bakken and Eagle Ford formation, China's tight oil reservoirs feature higher mud content and oil viscosity while they have a lower brittleness index and formation pressure, leading to confined stimulated reservoir volume and further limited CO2-oil contact. The effect of CO2 molecular diffusion was relatively exaggerated in experimental results, which could be attributed to the dual restrictions of exposure time and oil-CO2 area in field scale. Numerical modeling showed that the improved phase properties in nanopores led to enhanced oil recovery. The development of nano-scale chips withholding high pressure/temperature may advance the experimental study on nano-confinement's effect. Oil recovery can be further enhanced through wettability alteration due to CO2 adsorption on nanopores and reaction with rock minerals. CO2 huff-n-puff operations were more commonly applied in North America than China, and the huff time is in the order of 10 days, but the soaking time is less. Conformance control was essential during CO2 flooding in order to delay gas breakthrough and promote CO2-oil interaction. There is less than 5% of tight oil reserve surrounded by CO2 reservoirs in China, limiting the application of CO2-EOR technologies. An economic incentive from the government is necessary to consider the application of CO2 from power plants, refineries, etc. This work provides an explanation of conflicting results from different research methods and pilot tests, and helps researchers and oil operators understand where and when the CO2-EOR can be best applied in unconventional reservoirs. New directions for future work on CO2-EOR in tight formations are also recommended.

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Phase behavior of shale gas or oil in nanopores is not yet well understood. One complexity comes from the fact that fluid adsorption can be significant in densely developed nanopores. A prediction process for the behavior of a ternary mixture (CH 4 , n-C 4 H 10 , and n-C 8 H 18 ) and an actual Bakken oil in nanopore formation are performed by applying an adsorption-dependent Peng− Robinson equation of state, and the effect of adsorption and its induced critical properties shifts is discussed. Results indicate that the presence of adsorption could decrease the vapor−liquid equilibrium coefficient (K-value) and the vapor phase molar fraction for the confined ternary mixture, especially in the nanopores with a few nanometers. The shift in the saturation pressures of the ternary mixture and Bakken oil shows that the bubble point pressure and upper dew point pressure are depressed and the lower dew point pressure is increased with the synthetic effect of adsorption and critical shifts. The suppressed bubble point pressure well explains the production performance of a long-term flat producing gas/oil ratio in the Bakken reservoir. It should be noted that adsorption is relatively more dominant on bubble point pressure and critical shifts exhibit a greater influence on dew point pressure. For Bakken oil, the presence of adsorption increases the oil density and viscosity; however, critical shifts present conflicting impacts on oil density and viscosity, and the critical shifts are more dominant compared with fluid adsorption. This emphasizes the importance of considering both adsorption and critical shifts when describing phase behavior in shale nanopores.

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The confinement effects including capillarity and adsorption play a significant role in phase behavior and transport of shale fluids. The effect of capillary pressure has been widely studied and is fully understood. However, the investigation of the adsorption effect on reservoir fluid properties and production performance is still lacking. In this work, an efficient model is proposed to fill this gap and investigate the phase behavior and well performance in the Bakken shale oil reservoir. First, an improved phase equilibrium model is developed based on an adsorption-dependent Peng−Robinson equation of state and a modified Young−Laplace equation. The effect of adsorption and adsorption induced critical property shifts in nature is considered. Second, the phase equilibrium model is used to calculate and compare the black-oil properties of the Bakken oil under different pressures and confinement conditions. Finally, the fluid properties results are combined with the reservoir simulator to assess the confinement effects on the well performance of the Bakken shale reservoir. The result indicates that fluid adsorption makes a more significant contribution to the suppressed bubble point pressure than capillarity. The change in the black-oil properties shows that the confinement effect exhibits a great impact on the physical properties of the oil phase including solution gas−oil ratio, oil formation volume factor, and oil viscosity, but presents a small impact on the physical properties of the gas phase including gas formation volume factor and gas viscosity. In terms of production performance, the presence of confinement increases the cumulative oil production, first increasing, and then decreasing cumulative gas production, which leads to a flatter producing gas−oil ratio. Overall, the effect of adsorption is more significant under high-pressure conditions, and the effect of capillary pressure is more significant under low-pressure conditions.