Abstract: To investigate the evolution of reservoir pressure during CO₂ storage and to prevent wellbore leakage during the well drilling and completion within the storage site, this study established a numerical model of the CO₂ reservoir-caprock system based on the theory of multiphase flow through porous media to clarify the characteristics of the pressure difference evolution during the storage process and to analyze the influence patterns of key engineering geological factors.The study shows that: the injection of CO₂ leads to an increase in pressure within both the reservoir and caprock.After injection ceases,the reservoir pressure gradually dissipates,with the pressure change range significantly exceeding the radius of CO₂ diffusion.The caprock pressure response is delayed,causing dynamic evolution of interbed pressure differences,and there is a peak in pressure difference during the early stages of injection,which can easily lead to wellbore leakage.The peak pressure difference is negatively correlated with the distance from the injection well,reservoir temperature and pressure, reservoir pore permeability,and reservoir thickness,and positively correlated with the injection rate in a linear relationship.For large-scale CO₂ geological storage,controlling the distance between CO₂ injection wells and completion wells,and selecting injection points in deep-buried,thick,high-permeability,and high-porosity beds can help reduce the risk of wellbore leakage.The results of this study can provide a reference for CO₂ geological storage.

Key words: CO₂ storage, formation pressure, wellbore integrity, numerical simulation, multiphase flow