Most fractured carbonate oil reservoirs have oil-wet rocks. Therefore, the process of imbibing water from the fractures into the matrix is usually poor or basically does not exist due to negative capillary pressure. To achieve appropriate ultimate oil recovery in these reservoirs, a water-based enhanced oil recovery method must be capable of altering the wettability of matrix blocks. Previous studies showed that carbonated water can alter wettability of carbonate oil-wet rocks toward less oil-wet or neutral wettability conditions, but the degree of modification is not high enough to allow water to imbibe spontaneously into the matrix blocks at an effective rate. In this study, we manipulated carbonated brine chemistry to enhance its wettability alteration features and hence to improve water imbibition rate and ultimate oil recovery upon spontaneous imbibition in dolomite rocks. First, the contact angle and interfacial tension (IFT) of brine/crude oil systems were measured for several synthetic brine samples with different compositions. Thereafter, two solutions with a significant difference in WAI (wettability alteration index) but approximately equal brine/oil IFT were chosen for spontaneous imbibition experiments. In the next step, spontaneous imbibition experiments at ambient and high pressures were conducted to evaluate the ability of carbonated smart water in enhancing the spontaneous imbibition rate and ultimate oil recovery in dolomite rocks. Experimental results showed that an appropriate adjustment of the imbibition brine (i.e., carbonated smart water) chemistry improves imbibition rate of carbonated water in oil-wet dolomite rocks as well as the ultimate oil recovery.

The in-depth knowledge of reservoir heterogeneity is imperative for identifying the location of production and injection wells. The present study aimed at experimentally investigating the process of water flooding in the viscous oil-saturated glass micromodels, which contain layers with different permeability where the fractures were placed in different locations. Computational Fluid Dynamics (CFD) simulations of flooding were also conducted to study the impact of different water flow rates and wettability states. The results showed that the fractures, which have a deviation with the trend of maximum pressure gradient line, would widen the water path and vice versa. The performance of injection wells would increase the recovery factor by 18% if these would be located in the zones with high permeability for low flow rates of water. With changes in wettability state from water to oil wet conditions, the oil production will increase by 11%. Computational Fluid Dynamics results also indicated that an increase in the capillary number from 0.8 × 10−6 to 1.6 × 10−5, would cause the recovery factor to decrease as much as 14.34% while further increase from 1.6 × 10−5 to 2.24 × 10−5, the oil production will increase by 9.5%. Comparison between the obtained oil recoveries indicates that the maximum oil recoveries will happen when the injector well is located in the zone where ascending permeability, capillary number greater than 4.81 × 10−6 and also fracture with the most deviation with pressure gradient line (i.e. angular pattern) are gathered in an area between the injection and production wells.