Simulation analysis of salt precipitation in large-scale CO2 storage using periodic injection via a horizontal well

Abstract

This simulation study investigates the novel aspects of salt precipitation and formation damage near a horizontal injector during CO2 storage in an offshore depleted oil reservoir with high water saturation and non-negligible residual oil. Building upon prior experimental findings, our study delves into the intricate interplay between displacement, evaporation, and capillary backflow during periodic CO2 injection, necessitating fine gridding (e.g., down to 2 cm) near the wellbore and an equivalent representation of the wellbore area to capture salt precipitation dynamics accurately. A key contribution of this work is the identification and detailed quantitative characterization of three distinct drying regimes—evaporative, capillary, and viscous—based on gas flux at the perforation, which poses unique challenges in reservoir simulation. Notably, our study is the first to demonstrate these drying regimes specifically along a single CO2 injector well, providing critical insights for reservoir management. The results highlight the significant impact of the capillary regime on injectivity loss and underscore the necessity of refined wellbore grid resolution to mitigate potential total plugging risks. Furthermore, this work evaluates the effects of injection temperature and trapped oil, revealing their suppressive effects on salt precipitation. Importantly, employing a 3D sector model, we explore extreme scenarios such as complete perforation plugging within the capillary regime, showcasing redirection of gas flux to preserve injectivity. Overall, this study advances the field by offering detailed quantitative assessments of drying regimes and underscores the critical importance of tailored simulation approaches for effective reservoir management in complex offshore environments with residual oil.