During the last decade, smart waterflooding has been developed into an emerging EOR technology both for carbonate and sandstone reservoirs that does not require toxic or expensive chemicals. Although it is widely accepted that different salinity brines may increase the oil recovery for carbonate reservoirs, understanding of the mechanism of this increase is still developing. To understand this smart waterflooding process, an extensive research has been carried out covering a broad range of disciplines within surface chemistry, thermodynamics of crude oil and brine, as well as their behavior in porous media. The main conclusion of most previous studies was that it is the rock wettability alteration towards more water wetting condition that helps improving the oil recovery. In the first step of this project, we focused on verifying this conclusion. Coreflooding experiments were carried out using Stevens Klint outcrop chalk core plugs with brines without sulfate, as well as brines containing sulfate in different concentrations. The effects of temperature, injection rate, crude oil composition and different sulfate concentrations on the total oil recovery and the recovery rate were investigated. Experimental results clearly indicate improvement of the oil recovery without wettability alteration. At the second step of this project, we studied crude oil/brine interactions under different temperatures, pressures and salinity conditions in order to understand mechanisms behind the high salinity waterflooding. Our results show, in particular that sulfate ions may help decreasing the crude oil viscosity or formation of, seemingly, an emulsion phase between sulfate-enriched brine and oil at high temperature and pressure. Experimental results indicate that crude oils interact differently with the same brine solutions regarding phase behavior and viscosity measurements. This difference is attributed to the difference in composition of the different crude oils. More experiments are carried out in order to understand mechanisms of the crude oil viscosity reduction and emulsion formation. We observed that a heavy oil (that with a large fraction of heavy components) exhibited viscosity reduction in contact with brine, while a light crude oil exhibited emulsion formation. Most of reported high salinity waterflooding studies were carried out with outcrop chalk core plugs, and by performing spontaneous imbibition rather than forced flooding. The objective of the third step of this project was to investigate the potential of high salinity waterflooding process by carrying out experiments with reservoir chalk samples. We carried out waterflooding instead of spontaneous imbibition using core plugs with and without aging. The total oil recovery, recovery rate and interaction mechanisms of ions with rock were studied for different injected fluids under different temperatures and wettability conditions. Experimental results demonstrate that the oil recovery mechanism under high salinity seawater flooding at high temperatures is different for the different chalk rocks (outcrop and reservoir), although they have similar surface area and reactivity of the potential determining ions. In the last decade, laboratory waterflooding experiments and field tests have proven increase in oil recovery from sandstone reservoirs by injecting brine of low salinity. However, this effect has not been thoroughly investigated for carbonates. At the final stage of this project, we have experimentally investigated the oil recovery potential of low salinity water flooding in the carbonate rocks. We used both reservoir carbonate and outcrop chalk core plugs. The flooding experiments were carried out initially with the seawater. Afterwards the contribution to oil recovery was evaluated by sequential injection of various diluted versions of the seawater. The significance of this work may be summarized in five main findings: * Injection of sulfate rich brine may lead to additional recovery from Stevens Klint chalk even under completely water wet conditions. Therefore, increment in oil recovery with sulfate ions cannot be explained just by the rock wettability alteration. * Experimental results show that sulfate ions may help decreasing the crude oil viscosity when brine is contacted with oil under high temperature and pressure. We have also observed formation of an emulsion-like phase between oil and brine with increased sulfate ion concentration under high temperature and pressure. The viscosity decrease and formation of an emulsion phase could be the possible reasons for the observed increase in oil recovery with sulfate ions at high temperature in chalk reservoirs, besides the mechanism of the rock wettability alteration. * Crude oil/brine interaction study suggests that viscosity reduction for crude oil in contact with brine is connected to the presence of heavy components in the crude oil, while formation of emulsions with brine is a phenomenon related to the presence of lighter components in the crude oil. * The reservoir chalk rocks showed relatively less effect of temperature and sulfate ions concentration on oil recovery as compared to Stevens Klint outcrop chalk. This indicates that the rock may also determine whether the effect of temperature and high salinity brine on the recovery is observed. * Migration of fines and dissolution of rock particles are possible mechanisms of oil recovery increment with low salinity brines from carbonate core plugs at 90 ?C.