Wettability alteration toward a more water-wet state was found to be a promising approach for oil recovery improvement in oil-wet and naturally fractured carbonate reservoirs. This approach has been extensively studied in the literature using low-salinity/smart water and surfactant injection separately. However, application of surfactants in enhanced oil recovery is limited by their compatibility with the conditions of the reservoirs. In this study, polyethoxylated non-ionic surfactants with different ethylene oxide units were combined with low-salinity brine for a more efficient and cost-effective process. The compatibility of the surfactant solutions highly improved by reducing the salinity in the range of 200–2 g/L. Interfacial tension (IFT) measurements revealed that IFT decreased with increasing salinity. Contact angle measurements of calcite surfaces showed that wettability can be altered from a strong oil-wet state to a water-wet state after treatment with solutions of non-ionic surfactants over a wide range of salinities (∼2–110 g/L). ζ potential, Fourier transform infrared spectroscopy, and thermogravimetric analysis revealed that the non-ionic surfactant could partially displace carboxylate compounds from the surface and adsorb by forming a hydrogen bond with the hydroxyl group on the calcite surface. The formation of hydrogen bonds between ethoxy groups of the surfactant and hydroxyl or carboxylic groups on the solid surface can result in the replacement of organic compounds on the calcite surface. The organic compounds could form a new layer on the layer of adsorbed surfactant molecules via hydrophobic interactions. In addition, adsorption of the hydrophobic part of the non-ionic surfactant on the hydrophobic calcite surface and the formation of a surfactant double layer could partially contribute to the wettability alteration process.

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The lipopeptide biosurfactant produced by Bacillus subtilis strain W19 was investigated for the potential to maintain additional oil recovery at different dilutions and concentrations and in combination with synthetic chemical surfactant or alkali. The effect of salinity on the biosurfactant performance and the effect of biosurfactant on permeability reduction were also studied, at reservoir conditions. Core-flooding experiments were conducted to quantify the biosurfactant dosage for optimized enhanced oil recovery. Berea sandstone cores with respective average gas permeability and porosity of 223 mD and 21.5%, crude oil of American Petroleum Institute (API) gravity of 32°, and formation brine with salinities ranging from 7 to 9% were used. Biosurfactant reduced the interfacial tension (IFT) between the aqueous phase and crude oil from 20.9 to 1.8 mN/m. In core flood tests with cell-free biosurfactant broth at different dilutions (undiluted, 2.5×, 5×, 10×, and 20× diluted) and using crude biosurfactant powder (1 and 0.4 g/L), we observed additional 15 and 13% oil recovery over residual water-flood oil saturation, respectively. These results confirmed that a minimal biosurfactant concentration required for effective oil recovery was 0.4−0.5 g/L. Because biosurfactant broth is more economical then extracting biosurfactant, we have used it for further experiments. Salinity effect studies on oil recovery showed that this biosurfactant can maintain an additional recovery of 20% even at up to 20% (w/v) salinity. A mixture of 10× diluted biosurfactant with chemical surfactant to the ratio of "75:25", respectively, resulted in 28% additional recovery, which was better than using either alone. Mixing of biosurfactant with alkaline (Na 2 CO 3 at 0.5 and 1.0% concentrations) resulted in further reduction of IFT by a factor of 10, but no further improvement of oil recovery was observed. Diluted biosurfactant also showed very minimal reduction in permeability of sandstone cores. This study showed that the biosurfactant would produce an appreciable amount of additional oil after water-flooded residual oil at a low concentration, without much formation damage, and its performance can be improved even further by mixing it with chemical surfactants.

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This study investigates the ability of lipopeptide biosurfactant produced from Bacillus subtillis W19 isolated from oil contaminated Omani oil field soil samples to recover the residual oil at reduced concentration. The biosurfactant reduced the interfacial tension to 1.8 mN/m and also altered the wettability to more neutral wettability. The biosurfactant is stable over wide range of pH and temperatures. The minimum biosurfactant concentration required to make the process economically feasible was determined by performing core-flood experiments at various critical micelle dilutions using 200-300 mD Berea sandstone cores with porosity of 22%. The fluids used in the work are 32 o API crude oil, and brine with 7-9% salinity collected from the field of interest. All core-flood experiments were conducted at the reservoir temperature, 60 o C. It was found that even after 20 times dilution biosurfactant can maintain an extra recovery of 14% of residual oil after water flooding. These results revealed that the biosurfactant is still effective even at concentration as low as the CMC value (0.1 g/L). Furthermore, the performance of 20 times diluted biosurfactant was improved by mixing it with commercial chemical surfactant to the ratios of 50% biosurfactant: 50% chemical surfactant and 25% biosurfactant: 75% chemical surfactant, and, resulted in extra recovery of 28% and 27% of residual oil after water flooding respectively. Salinity studies show that this biosurfactant has high turbidity point, and maintained a relatively low interfacial tension values over wide range of salinities. When the salinity was increased to 20%, the biosurfactant was still successful in reducing the water flooding residual oil saturation by 12% even when diluted by 10 times. Economical evaluation showed that using this biosurfactant at low concentration would produce appreciable amount of trapped oil with minimum cost.