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Many experimental investigations on carbonated water injection (CWI) have shown an increase in oil recovery which CWI is defined as the process of injecting CO2-saturated water in oil reservoirs as a displacing fluid. In every enhanced oil recovery method, the potential formation damage of the injected fluid is considered. This is due to the fact that the injection of incompatible fluids often causes clay swelling and fines migration and thus impairs the formation permeability. Permeability reduction by clay particles mostly depends on its distribution which can be pore lining, pore bridging, dispersed or combination of these causing pore blocking or pore-throat diameter reduction. Besides, fine migration is considered as an important mechanism of recovery improvement during injection of low-salinity water in sandstone oil reservoirs. The present paper investigates the impact of injection of carbonated water and brines with the different salt concentrations on oil recovery and formation damage focusing on permeability variation. The investigation has been done on 12 relatively homogeneous clay-containing sandstone cores, while the compositions of the injection water were varied from 40,000 to 1000 ppm, at 176° F and 2000 psi. The amount of recovery improvement and permeability drop recorded in all tests and the fine effluent of two experiments were analysed using XRD, one for CWI and one for WF (water flooding). In all salinities, CWI has shown more oil recovery improvement than conventional water. CWI of 40,000 ppm showed the minimum permeability reduction of 6 percent, while the highest permeability was obtained by injection of water with 1000 ppm. Maximum ultimate oil recoveries of 61.2% and 42% were achieved by 1000 ppm both for CWI and WF, respectively. In comparison with brine injection, CWI resulted in more permeability drop in salinity above critical salt concentration (CSC), while below CSC, WF has caused more formation damage than CWI. Experimental results also showed that fine migration was the main reason behind formation damage. It was also revealed that permeability was significantly reduced due to fine production in the effluent.

Emulsions are extensively prevalent in the oil industry in both advantageous and disadvantageous ways. In the literature, conventional water flooding in high permeability oil reservoirs has confronted with water channeling and poor sweep efficiency. In this paper, the remedial application of O/W emulsions as an EOR method in improving water performance is discussed. To this purpose, a series of flooding experiments were carried out in one of the Iranian oil reservoirs in reservoir condition of 75 C and 2000 psi. Then, visual stability measurements were conducted to inspect the stability characterization of the emulsion. Sodium dodecyl sulfate was applied helping simple dispersion of the gasoil into the water phase, and emulsions with water percentage of 90, 80, 70 and 60 were developed to introduce into the porous media. It was found out from flooding experiments that emulsion injection after conventional water flooding can lead to additional oil recovery (up to 20%). Besides, the emulsion with 80% water cut was determined as the optimum emulsion for injection in this reservoir considering financial aspects. Moreover, results of the stability test revealed that the aqueous phase with one wt% surfactant or higher had formed emulsions which have been stable during a long period of 6 months.