A viable CO₂ storage resource must have sufficient storage capacity, reliable containment efficiency and adequate well injectivity. Deep saline formations stand out in terms of storage capacity and containment efficiency. However, formation brine dry-out and salt precipitation in the near well region could impair CO₂ injectivity in deep saline reservoirs, thus reducing their potential for CO₂ storage. Core-flood experiments and analytical modelling were used to investigate various mechanisms of external and internal salt precipitation. Particularly, the impact of the extension of the dry-out region on CO₂ injectivity was investigated. It was found that, for high permeability rocks, injection of CO₂ at relatively low injection rates could result in salt cake deposition at the injection inlet especially under high salinity conditions. It was also found that extension of the dry-out region does not have significant impact on CO₂ injectivity. Although the magnitude of CO₂ injectivity impairment increased more than two-fold when initial brine salinity was doubled, real-time changes in CO₂ injectivity during the drying process was found to be independent of initial brine salinity. We have shown that the bundle-of-tubes model could provide useful insight into the process of brine vaporization and salt deposition in the dry-out region during CO₂ injection. This work provides vital understanding of the effect of salt precipitation on CO₂ injectivity.

Reduction of the salinity of injection water has been found to improve the oil recovery in some sandstone reservoir rocks, but for other sandstone rocks disappointing results have been obtained. No mechanism has been widely accepted as the reason for the improved oil recovery in low salinity water flooding (LSWF). Since alteration of wettability to more water-wet conditions has been reported in promising cases, desorption of crude oil components from the minerals surfaces should occur during LSWF. Retention of oil components onto sandstone reservoir rock saturated with brines of different compositions has been studied by injecting crude oils of different compositions. Results from experiments and simulation of rock-brine interactions have been compared. In the study it has been shown that the compositions of both low salinity water and the crude oil are important for the retention of polar oil components. For the original crude oil with the lowest base/acid ratio, the retention of oil components was found to vary with the brine composition even though the total salinity was the same. For this crude oil the measured decrease in the retention of oil components was found to be in accordance with simulated decrease in the total concentration of divalent cations on clay surfaces. This indicated that the retention of oil components were dominated by bonding of carboxylic groups to clay surfaces by cation-bridging. For treated crude oil with reduced amount of acidic components (highest base/acid ratio), the retention of polar oil components was not sensitive to the brine salinity/composition and was higher than for the original oil (with lowest base/acid ratio). The retention was for this oil probably due to direct adsorption of basic components. The retention was therefore found to be sensitive to the concentration of acids in the crude oil, and was increasing with increasing base/acid ratio. It has been shown the ionic composition of the low salinity brine and the composition of the crude oil are important for the retention of polar oil components and thereby the wettability. The optimum low salinity water composition will depend on the formation water composition, mineral composition/distribution of reservoir rock and oil composition, and for tertiary LSWF also the composition of earlier injection brine.