Impact of Dry-Out and Salt Precipitation on Injectivity: Case Study of Nagaoka CO2 Storage Project

Abstract This paper presents a comprehensive study of injectivity evolution in the Nagaoka CO2 storage project in Japan, where 10,400 ton of CO2 were injected into a deep saline aquifer between 2003 and 2005. While previous studies primarily attributed the observed injectivity increases to CO2 relative permeability enhancement from dry-out effects, this research investigates the competing influence of salt precipitation that may have been masked by these favorable permeability changes. A detailed layer-cake radial simulation model incorporating key physical mechanisms, such as CO2 dry-out, capillary-driven backflow, and salt precipitation-induced permeability reduction, was developed and history-matched to observed bottomhole pressure data. Extensive sensitivity analyses examined the influence of formation water salinity, injection strategies, and relative permeability characteristics on injectivity behavior. Results confirmed that the continuous injectivity improvement observed at Nagaoka was predominantly driven by CO2 relative permeability enhancement under dry-out conditions. Salt precipitation effects were minimal at the site's relatively low formation water salinity of 8,000 ppm. However, hypothetical scenarios with higher salinity up to 150,000 ppm demonstrated significant injectivity impairment, with bottomhole pressure increases of up to 2.7 MPa and injectivity reductions exceeding 50%. The study revealed that injection intermittency significantly influences salt precipitation patterns. While capillary-driven backflow occurs continuously during the injection process, natural pressure equilibration dominates water movement during injection interruptions, particularly affecting high-permeability layers. Continuous injection reduces the impact of this natural backflow, dispersing salt precipitation over larger volumes away from the wellbore. Conversely, intermittent injection enhances water return toward the wellbore, concentrating salt precipitation in high-permeability layers and creating more severe near-wellbore permeability damage. This research demonstrates that salt precipitation impacts on injectivity depend on complex interactions between formation characteristics, operational parameters, and fluid properties. Accurate prediction of injectivity behavior in CO2 storage projects requires comprehensive modeling that incorporates these coupled phenomena, particularly in formations with high salinity where precipitation effects may outweigh dry-out benefits despite generally favorable reservoir conditions.