The Pressure of oil reservoirs decrease by production in natural depletion period, this leads to reduction in reservoir energy for further production. The reservoirs are flooded with water based fluids that are caused by two reasons: reservoir pressure maintenance and oil displacement by the viscosity force. Various laboratory studies have already established the sensitivity of rock surface wettability to brine total salinity. Manipulating injected water, especially total salinity, causes wettability alternation from oil wet to more water wet. It is noteworthy that the water flooding results of sandstone and carbonate rocks are completely different. Therefore, the effect of brine salinity and concentration of injected fluid ions on oil recovery and rock surface wettability were investigated in this study. Some investigations have shown the increasing oil recovery by lowering the injected fluid salinity. Moreover, pressure drop across the core has been observed, which indicates rock permeability alternation. Regarding the recent observations, various mechanisms have been suggested, but contradictory observations have been reported and thus researchers have not agreed on a main mechanism in this regard. Hence, this study dealt with the effect of calcium, magnesium, sodium, chlorine, sulfate and nitrate ions on the enhanced oil recovery process with contact angle measurement, water flooding, pH measurement tests and analysis of effluent. In order to do a primary investigation, contact angle measurement tests were performed for 30 solutions with TDS of 5,000 ppm, assuming that wettability alternation affected the oil recovery process. It should be noted that the study did not address the effect of total salinity on wettability alternation and oil recovery amount but it focused on the ions concentration. The contact angle measurement tests were designed to consider the best results of each step in the next step, and the effect of ions concentration on each step was investigated. According to the results of the contact angle tests, the best responses were selected as an injected fluid to the core. The cores A, B and C for flooding and slabs for contact angle tests in this study were dolomite and the solutions used had a neutral pH of about 7. Furthermore, the temperature conditions of the contact angle test was 75 ° C and the core flooding test was applied at room temperature condition (25 ° C). It is notable that the flow rate was injected at 0.1 ml/min in all core flooding stages. The results of the contact angle tests showed that the wettability alternation to more water wet state leads to the increased concentration of sulfate ion. In addition to sulfate ion, nitrate shows a suitable response. Moreover, the solution with a sulfate-nitrate ratio of 0.5 and calcium and magnesium equal to the 10 times diluted seawater shows the greatest response in core flooding test, and the amount of oil recovery due to this solution is equal to 0.86 original oil in place (%OOIP) that is a significant result in comparison with the same solution with removal of sulfate ion (the amount of oil recovery was about 74 %OOIP). Keywords: Smart Water Flooding, Smart Water, LowSal Water, Water Based EOR, Carbonated Reservoir EOR, Wettability Alternation, Relative Permeability, Capillary Pressure.