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Seawater can improve the water wetness of chalk at high temperatures, which improves the oil displacement by spontaneous imbibition of water. It is experimentally verified that the interaction between Ca 2þ , Mg 2þ , and SO 4 2at the chalk surface will displace adsorbed carboxylic acids and increase the water wetness. In this work, the effect of salinity and ionic composition of smart water on oil recovery was studied at different temperatures, 100, 110, and 120 °C. The ultimate oil recovery was compared using seawater as the base fluid. When NaCl was removed from seawater, both the imbibition rate and oil recovery increased in comparison to seawater at the temperatures tested. At 110 and 120 °C, the oil recovery from seawater depleted in NaCl increased by about 10% of original oil in place (OOIP) compared to seawater. A decrease in oil recovery of about 5% of OOIP was observed when increasing the amount of NaCl in seawater 4 times. A systematic decrease in oil recovery was observed when using seawater diluted with distilled water as imbibing fluid. Imbibition tests at 110 °C showed that the water-wet fraction increased 29% for seawater depleted in NaCl compared to 11% for ordinary seawater. Diluted seawater to 10 000 ppm did not change wetting conditions at 110 °C. The results confirmed that not only is the concentration of the active ions Ca 2þ , Mg 2þ , and SO 4 2important for wettability alteration to take place but also the amount of nonactive salt, such as NaCl, has an impact on the wettability alteration process, which is discussed as a doublelayer effect at the chalk surface. No significant improvement in the ultimate oil recovery was observed during forced displacement by modified seawater.

Both laboratory and single well field tests have documented that enhanced oil recovery can be obtained from sandstone reservoirs by performing a tertiary low saline waterflood. Due to the complexity of the crude oil-brine-rock interactions, the mechanism behind the low saline EOR process has been debated in the literature for the last decade. Both physical and chemical mechanisms have been proposed, but it appears that none of the suggested processes has so far been generally accepted as the main contributor to the observed low salinity EOR effect. Based on published data and new experimental results on core flooding, effects of pH and salinity on adsorption of acidic and basic organic components onto different clay minerals, clay properties like ion exchange capacity and selectivity, and oil properties, a new chemical mechanism is suggested, which agrees with documented experimental facts. At reservoir conditions, the pH of formation water is about 5 due to dissolved acidic gases like CO 2 and H 2 S. At this pH, the clay minerals, which act as cation exchange material, are adsorbed by acidic and protonated basic components from the crude oil, and cations, especially divalent cations from the formation water, like Ca 2+ . Injection of a low saline fluid, which promotes desorption of Ca 2+ , will create a local increase in pH close to the brine-clay interface because Ca 2+ is substituted by H + from the water. A fast reaction between OHand the adsorbed acidic and protonated basic material will cause desorption of organic material from the clay. The water wetness of the rock is improved, and increased oil recovery is observed. To observe low salinity EOR effects in sandstones, a balanced initial adsorption of organic components and Ca 2+ onto the clay is needed. Both the adsorption capacity and the pH-window for adsorption/desorption of organic material is somewhat different for various types of clay minerals. A detailed knowledge of the chemical mechanism behind the low saline EOR process together with information on formation brine composition, oil properties and type of clay material present, will make it possible to evaluate the potential for increase in oil recovery by a low salinity waterflood.