Abstract

The utilization of CO2 as an injection agent to enhance shale oil recovery has garnered significant attention. Nonetheless, the introduction of CO2 results in complex phase behavior and flow mechanisms of formation fluids. Thus, a comprehensive framework consisting of theoretical models and algorithms has been developed to explore the impact of CO2 dissolution on fluid phase behavior and flow within shale oil-water systems. In this study, an improved multi-phase flash algorithm is introduced that utilizes a fugacity calculation model incorporating adsorption effects to compute the fluid properties of shale oil-water-CO2 mixtures in nanopores. The findings indicate that the system comprises two phases, namely an oil-rich phase and a water-rich phase, independent of the CO2 feed. Additionally, a representative pore network of shale is obtained by employing three-dimensional FIB-SEM imaging, encompassing 6,914 pores and 10,725 throats. Finally, pore network modeling is carried out to simulate steady-state oil-water flow, taking into adsorption, slip effects, and changes in fluid properties caused by nano-confinement and CO2 dissolution. With the increase in the mole fraction of CO2, the molecular weight of the oil phase decreases significantly, while that of the aqueous phase slightly increases. Changes in fluid composition leads to a slight increase in the density of both phases, a decrease in the viscosity of the oil phase and the interfacial tension between the phases. These physical property changes result in a significant increase in the flow rate of the oil phase and a minor decrease in the flow rate of the aqueous phase. The average flow rate of the oil phase increases by 3.26 times when the CO2 mole fraction rises from 1.96% to 51.96%. This study enhances our understanding of the phase equilibrium and flow mechanisms in shale oil reservoirs and offers guidance for the development of enhanced oil recovery methods for shale reservoirs.

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