Abstract: The development of CO₂ injection in shale reservoirs has the dual effects of enhancing crude oil recovery and greenhouse gas storage. Though indoor core experiments and field-scale simulations can confirm the feasibility of the technology in terms of oil production increase, the microscopic flow patterns and mechanisms of underground multiphase fluids are often neglected. This leads to the difficulty in capturing the microscopic migration and remaining characteristics as well as the development dynamics of CO₂ flooding. Using the Duvernay shale reservoir as an example, the microscopic flow simulations of CO₂ injection and oil production were carried out based on the geologi-cal setting and production characterization. Firstly, the pore/throat distribution characteristics of the Duvernay shale reservoir were revealed, and the microscopic pore and throat model was established after gray-scale and morphologi-cal processing of the scanned images of reservoir core. Based on this model, the seepage law of porous media during the CO₂ injection and displacement process in the Duvernay shale reservoir was simulated by using the phase field method to track the fluid interface. Then, the simulation results were applied to analyze the production and remaining oil characteristics, and to obtain the relative permeability curves of the wetting and the non-wetting phase of the model under different CO₂ injection volumes. Finally, the programs' simulation results of different injection rate rates, crude oil viscosities, and contact angles were compared to analyze their influence on development and sequestration effects. Results show that: (1) As the displacement front advances along the dominant channel, the CO₂ production rate increases at the model outlet end gradually and the oil phase production rate gradually decreases. When the CO₂ injection exceeds 3 PV, a breakthrough occurs, and then four types of residual oil are formed: membranous, columnar, clustered, and blind-end. (2) The swept coefficient of CO₂ flooding with the oil expansion and viscosity reduction effect reaches 37.08% to 41.30%, having the greatest impact on oil production and achieving a remarkable oil recovery effect. (3) CO₂ adsorption and fluid exchange effect, which changes the wetting contact angle, moves the model in the direction of stripping the wall crude oil and promoting storage, forming two modes: bondage and adsorption storage. (4) Increasing the injection rate has little effect on increasing the swept coefficient, but the driving effect can change the pressure distribution near the inlet end of the microscopic numerical model, and create better conditions for subsequent development. The research results, through visualization technology, revealed the multiphase flow process of CO₂ and crude oil, and will provide theoretical support for the microscopic mechanism of CO₂ injection for oil recovery in shale reservoirs.