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Enhanced oil recovery methods are the future of maximizing oil recoveries. Any incremental oil recovery can support the world economy by producing more oil at a minimum price. The surfactants are the major constituent of the injection fluids for EOR applications. Addition of foam-generated surfactants in water alternating gas injection is one of the potential solutions for reducing the gas mobility and improving sweep efficiency, but the major challenge of surfactants used with water alternating gas injection is its stability in presence of formation water and crude oil at reservoir conditions. The objective of this study is to investigate the stable surfactant as a foaming agent to improve the efficiency of residual oil and reduce the gas mobility. To achieve this main objective, individual and new surfactant blended formulations were evaluated with injection water and crude oil in the porous media at 96°C and 1400 psi. Experimental result showed that generated foam in presence of crude oil has reduced gas mobility which provides good indication of CO 2 mobility control and improves sweep efficiency. Oil recovery based on original oil-in-place by surfactant blend of 0.6 wt% AOS ? 0.6 wt% TX 100, 0.6 wt% AOS ? 0.6 wt% LMDO and individual surfactant of 0.6 wt% AOS were recorded as 91.9, 83.7 and 72.66%, respectively. Foam stability in presence of crude oil, reduction in gas mobility and increase in oil recovery indicated that these surfactant blends are good foaming agents as compared to individual surfactant in enhanced oil recovery applications.

Most of the available commercial surfactants precipitate due to the hardness of formation water. The study of surfactant generated foam and its stability is very complex due to its multifaceted pattern and common physicochemical properties. This research involved the study of foam generation by using the blended surfactants and their evaluation in terms of enhanced oil recovery (EOR). The objective of this study is to systematic screening of surfactants based on their capability to produce stable foam in the presence of two different categories of crude oil. Surfactant types such as non-ionic, anionic and amphoteric were selected for the experimental study. The foam was generated with crude oil, and the synthetic brine water of 34,107 ppm used as formation water. Surfactant concentration with the both types of crude oil, foam decay, liquid drainage and foam longevity was investigated by measuring the generated foam volume above the liquid level. The surfactant with concentration of 0.6wt%AOSC14-16, 1.2wt%AOSC14-16, 0.6wt%AOSC14-16 + 0.6wt%TX100 and 0.6wt%AOSC14-16 + 0.6wt%LMDO resulted in the maximum foam longevity with formation water and two categories of crude oil. The 50% liquid drainage and foam decay of surfactant solutions with concentration of 0.6wt%AOSC14-16 + 0.6wt%LMDO and 0.6wt%AOSC14-16 + 0.6wt%TX100 were noted with the maximum time. The findings of this research demonstrated that the generated foam and its longevity is dependent on the type of surfactant either individual or blended with their concentration. The blend of surfactant solution combines excellent foam properties.

The use of surfactant is one of the possible solutions to minimize the mobility of gases and improve the sweep efficiency, but the main problem with this process is its stability in the presence of injection water and crude oil under reservoir conditions. In this study, the three types of surfactant anionic, nonionic and amphoteric are examined in the presence of brine salinity at 96 °C and 1400 psia. To access the potential blended surfactant solutions as gas mobility control, laboratory test including aqueous stability, interfacial tension (IFT) and mobility reduction factor (MRF) were performed. The purpose of MRF is to evaluate the blocking effect of selected optimum surfactant solutions. Based on experimental results, no precipitation was observed by testing the surfactant solutions at reservoir temperature of 96 °C. The tested surfactant solutions reduced the IFT between crude oil and brine. The effectiveness and strength of surfactant solutions without crude oil under reservoir conditions were evaluated. A high value of differential pressure demonstrates that the strong foam was generated inside a core that resulted in delay in breakthrough time and reduction in the gas mobility. High mobility reduction factor result was measured by the solution of blended surfactant 0.6%AOS + 0.6%CA406H. Mobility reduction factor of other tested surfactant solutions was found low due to less generated foam by using CO2 under reservoir conditions. The result of these tested surfactant solutions can provide the better understanding of the mechanisms behind generated foam stability and guideline for their implementation as gas mobility control during the process of surfactant alternating gas injection.

Among 64 bacterial strains isolated in this study, the best two of biosurfactant-producing bacteria were selected and identified based on the phenotypic properties and molecular approach based on 16S rRNA having 100% similarity to the gram-negative Enterobacter aerogenes B19 strain bacteria and rode gram-positive strain Bacillus cereus ISU-02 in the Nucleotide database of the National Center for Biotechnology Information. The study showed that two selected isolates gave the highest positive results that were used to investigate the biosurfactant production including: interfacial reduction, foaming activity, hemolytic activity, CTAB agar plate, drop collapse assay, oil displacement test and emulsification index E24%. Both Bacillus cereus ISU-02 strain and Enterobacter aerogenes B19 strain have reduced the interfacial tension to 27.61 and 28.93, respectively. Biosurfactants produced from both isolates were tested for oil recovery using spontaneous imbibition process. Bacillus cereus ISU-02 strain gave the highest oil recovery of 66.9% for rock permeability of 843 mD, followed by Enterobacter aerogenes B19 strain with oil recovery of 34% for rock permeability 197 mD, while the lowest rate of oil recovery was 12.1% for FW with permeability of 770 mD. An additional oil rate reached to 7.9% has been recovered from the residual oil when the core plug that was treated with formation water alone was retreated with the cell free biosurfactant supernatant. Use of the new biosurfactants has improved oil recovery better than use of formation water alone or formation water with the commercial surfactant SDS.Publisher's Note Springer Nature remains neutral with regard to jurisdictional claims in published maps and institutional affiliations.