The effective displacement of the shale oil from organic nanopores plays a significant role in development of the shale oil reservoirs. In order to deeply understand the microscopic displacement mechanism of alkane of shale oil by CO₂ in organic nanopores, microscopic pore model of organic matter and molecular model of CO₂ and n-dodecane were established to investigate the influences of key parameters on the displacement process by using the Monte Carlo and molecular dynamics simulation method. The instantaneous adsorption of molecules demonstrates that the displacement of n-dodecane and the adsorption of CO₂ are proportional to the increase of the injection pressure of CO₂ as well as the pore size. In addition, the results also show that the adsorption capacity of CO₂ first increases and then decreases with the increase of the temperature, which indicates that the optimum temperature exists for the adsorption of CO₂. This work can provide critical insights into understanding the microscopic displacement mechanism of shale oil by CO₂ in organic nanopores in shale oil reservoirs and lay a solid foundation for the CO₂ flooding in the shale oil reservoir and the CO₂ storage.

Due to the confinement effect of nanopores, the fluid-phase behavior of shale oil reservoirs is much different from that of conventional reservoirs. The accurate description of the phase change characteristics of fluid in nanopores is the basis to design development plan, production system, and EOR methods of shale oil reservoirs. In this study, molecular dynamics simulation was employed to analyze the phase behavior of single-component system and hydrocarbon–CO₂ mixture system in organic nanopores. The results show that the confinement effect on the phase change pressure of the single-component system is influenced by the distribution of the electron cloud. The phase change pressure of hydrocarbons with even distribution of the electron cloud would be increased, while that of CO₂ would be decreased due to the instantaneous dipole moment. In addition, as the length of carbon chains increases, the confinement effect on hydrocarbons becomes stronger. When the temperature increases, the confinement effect becomes weaker. In the hydrocarbon–CO₂ mixture system, when the occurrence condition changes from bulk to the nanopore of 5 nm, the bubble point pressure decreases by 39.21–68.85%, and the critical temperature and pressure decrease by 75.98% and 7.13%, respectively. On the whole, the P–T phase envelope is shrunken under the confinement effect. CO₂ is much easier to be miscible with shale oil in nanopores. Moreover, full mixing and keeping in single liquid phase of CO₂–hydrocarbons mixture system can reduce the adsorption of hydrocarbons on organic pore walls. Therefore, CO₂ injection could be a feasible method to enhance oil recovery in the matrix of shale oil reservoirs.

In order to investigate energy supply capacity and oil production contribution of near-fracture and fracture-free zone in fractured tight oil reservoirs, a series of CO₂ huff-and-puff tests were designed and carried out in different experimental conditions. A fracture-matrix long-core system was established to simulate the near-fracture zone and matrix zone of tight oil reservoirs. The NMR technique was utilized to identify the microscopic remaining oil of certain core samples. The effects of fracture length, soaking time, depressurization method, and asphaltene precipitation on the oil recovery performance of CO₂ huff-and-puff process were evaluated, respectively. The results indicated that the dissolution and diffusion range of the injected CO₂ can be apparently increased from both macro and micro aspects through increasing the length or density of the fractures and extending the soaking time; and, during puff period, the slow depressurization method has better recovery effect on near-fracture zone, while the step depressurization method has better recovery effect on distal fracture-free matrix. After CO₂ huff-and-puff process, the oil recovery of the medium pores near fracture could be close to oil recovery of the large pores, which is higher than 60. But, in the distal matrix, the oil recovery of the medium pores was only a little higher than depletion development. The remaining oil of medium pores in distal fracture-free matrix still has great potential to be developed after CO₂ huff-and-puff process.

Polymer flooding has been proved by many scholars for use in heavy oil reservoirs. However, due to mobility control effects and injectivity, selecting the appropriate solution viscosity is essential. It is difficult to form a deep understanding of the effect and mechanism of polymer flooding using conventional experimental methods with oil recovery as the reference standard, so it is necessary to conduct further study with the aid of simulation methods. In this study, a one-dimensional displacement mathematical model based on the Buckley–Leverett theory was established, and in the range of water–oil viscosity ratio from 0.1 to 0.6, the variation of water saturation along the flow caused by polymer solution was studied. The research results showed that under the action of a polymer solution, compared with water flooding, there was a decreasing region of water saturation along the flow due to oil phase accumulation. The larger the water–oil viscosity ratio, the larger the area of water saturation decline and the greater the degree of water saturation decline, resulting in a better the displacement effect. However, under the condition of oil–phase viscosity of 70 mPa·s, when the water–oil viscosity ratio reached 0.4, the range and degree of water saturation decline along the way no longer changed, all the crude oil that could be swept had been displaced, and the outlet end was close to producing only water, not oil; therefore, further increasing the water–oil viscosity ratio could not increase the oil recovery. At the same time, the increase in pressure had not changed, that is, the increase in pressure had not resulted in the same increase in oil recovery. When the viscosity of oil phase increased to 140 mPa·s, the same rule was displayed, the appropriate water–oil viscosity ratio was also 0.4. The paper analyzed the action mechanism of polymer solution through process description, and the results provided a clear selection method for selecting reasonable polymer solution concentration, as well as a reference for polymer solution range under different crude oil viscosity conditions.