Analytical Model for Assessing the Impact of High-Rate CO2 Injection on Dry-out and Salt Precipitation in the Near-Wellbore Region of Saline Aquifers

Dry-out and salt precipitation (DSP) around the wellbore are potential operational challenges during CO₂ sequestration in saline aquifers. We present an extended Forchheimer–Darcy model for evaluating the impact of high-rate CO₂ storage on the DSP effects close to wellbores in saline aquifers, considering the high-velocity non-Darcy (or Forchheimer) flow, the mutual solubilities of formation fluids, and water evaporation and salt precipitation. We explored the governing parameters─Péclet number, which determines the contributions of the evaporation regime and advection regime to flow-through drying and salt precipitation, as well as the criteria for transitioning to Forchheimer flow. Sensitivity analyses are also conducted on the critical parameters of the CO₂-brine displacement and salt saturation to better understand their impact. Results indicate that using Darcy’s law to model fluid dynamics and salt deposition for high-velocity gaseous flows leads to inaccuracies. Specifically, it yields imprecise estimations of gas saturation evolution, range, and degree of the DSP effects near the wellbore. The inertial effect is prominent at a high CO₂ injection rate, which leads to a more uniform displacement and results in a moderate decrease in salt saturation by slowing down gas flow. Formations with better petrophysical properties and fluid flow capacity have a larger range of dry-out region without considering the capillary backflow mechanism, where the salt plugging problem may not be severe. Additionally, higher injection rates and a thinner layer thickness moderately reduce salt saturation but significantly increases the extent of the DSP area, which is a more critical aspect of this physical phenomenon. We compared all computational results with Pruess’s benchmark Darcy flow model. Moreover, we verified the saturation profiles, especially under non-Darcy flow conditions, displaying excellent agreement between analytical and numerical solutions. Findings of this research provide new insights for future studies on the fluid behavior in formations with similar geological settings, as well as the impact of DSP effects on aquifer injectivity and injection safety.