No abstract

Foam generation is one of the most promising techniques to overcome gas mobility challenges and improve the sweep efficiency of reservoir fluids. The synergistic effect of surfactant and nanoparticles can help produce a stronger and more stable foam in reservoir porous media. The objective of this work is to assess the ability of anionic surfactant and a mixture of the surfactant and nanoparticles to produce foam for gas mobility control and the enhancement of oil recovery. Static, dynamic, and core flood tests were conducted to evaluate foam strength. Static foam tests in the presence of crude oil showed a clear trend on foam behavior when solid nanoparticles were added to surfactant. As the concentration of nanoparticles increases, the foam half-life increases, too. Foamability tests in Bentheimer sandstone showed better foam generation and stabilization when nanoparticles were used. The addition of nanoaprticles to surfactant solutions resulted in higher pressure drop and, therefore, higher reduction of gas mobility compared to surfactant. The rise in temperature from 25 to 50 °C reduces the measured pressure drop across the core samples in the absence and presence of nanoparticles, which can be attributed to the reduction in foam stability and strength. Both surfactant and a mixture of surfactant and nanoparticles were able to enhance oil recovery. The surfactant was able to bring the oil recovery to 41.45% of the original oil in place (OOIP). In contrast, the presence of nanoparticles resulted in higher oil recovery, 49.05%, of the OOIP.

Injecting carbon dioxide into oil reservoirs has the potential to serve as an enhanced oil recovery (EOR) technique, mitigating climate change by storing CO 2 underground. Despite the successful achievements reported of CO 2 to enhance oil recovery, mobility control is one of the major challenges faced by CO 2 injection projects. The objective of this work is to investigate the potential of using surfactant and a mixture of surfactant and nanoparticles to generate foam to reduce gas mobility and enhance oil recovery. A newly developed anionic surfactant and a mixture of the surfactant and surface-modified silica nanoparticles were used to assess the ability of generating a stable foam at harsh reservoir conditions: sc-CO 2 and high temperature. Dynamic foam tests and coreflood experiments were conducted to evaluate foam stability and strength. To measure the mobility of injected fluids in sandstone rocks, the foam was generated by co-injection of sc-CO 2 and surfactant, as well as a mixture of surfactant and nanoparticles at 90% quality. The coreflood experiments were conducted using non-fractured and fractured sandstone cores at 1550 psi and 50 °C. The use of surfactant and mixture was able to generate foam in porous media and reduce the CO 2 mobility. The mobility reduction factor (MRF) for both cases was about 3.5 times higher than that of injecting CO 2 and brine at the same conditions. The coreflood experiments in non-fractured sandstone rocks showed that both surfactant and a mixture of surfactant and nanoparticles were able to enhance oil recovery. The baseline experiment in the absence of surfactant resulted in a total recovery of 71.50% of the original oil in place. However, the use of surfactant was able to bring oil recovery to 76% of the OOIP. The addition of nanoparticles to surfactant, though, resulted in higher oil recovery, 80% of the OOIP. In fractured rocks, oil recoveries during secondary production mechanisms for the mixture, the surfactant alone, and sc-CO 2 alone were 12.62, 8.41, and 7.21% of the OOIP, respectively. Huge amount of oil remains underground following the primary and secondary oil production schemes. CO 2 has been widely used to enhance oil recovery. However, its high mobility might result in unfavorable and unsuccessful projects. The use of specially designed surfactants and the synergistic effect of surfactant and nanoparticles may provide a solution to stabilize CO 2 /brine foam at harsh reservoir conditions and, therefore, reduce the gas mobility and, consequently, enhance oil recovery.

This work investigated experimentally the potential of the mixture of two anionic surfactants to reduce the mobility and enhance the oil recovery by generating stronger foam than that of the individual surfactants. Foams of the Alcohol Alkoxy Sulfate (AAS), Internal Olefin Sulfonate (IOS) surfactants and their mixtures were compared in bulk and in porous media. In bulk, after the foam has been generated by shaking, the foam columns decay was monitored to measure the foamability and foam stability. Furthermore, interfacial tension was measured for all surfactants solutions for explanation purposes and foam stability interpretations. Dynamically, Boise sandstone was used for surfactant-nitrogen co-injection for mobility reduction evaluation and foam viscosity measurements. Finally, the enhanced oil recovery was investigated by conducting core-flooding experiments for foam application after water flooding. AAS surfactant showed impressive foamability in NaCl brines, but medium to poor foam stability especially with crude oil. On the other hand, IOS was the best in Deionized Water (DW) especially with crude oil, but poor foamability in brine. The synergism was more obvious in brine than in DW. For instance, the mixture provided five times and four times longer foam half-lives than AAS in absence and presence of crude oil, respectively. Dynamically, the foam generation was observed by the pressure drop jump during the surfactant-gas co-injection. The mixture reduced the mobility 13 and 5 times in comparison with that of AAS. Finally, the application of foam flooding as a tertiary recovery process resulted in 7.5% additional oil recovery by the mixture compared with 2.5% for AAS.

Carbon dioxide (CO 2) flooding is one of the most globally used EOR processes to enhance oil recovery. However, the low gas viscosity and density result in gas channeling and gravity override which lead to poor sweep efficiency. Foam application for mobility control is a promising technology to increase the gas viscosity, lower the mobility and improve the sweep efficiency in the reservoir. Foam is generated in the reservoir by co-injection of surfactant solutions and gas. Although there are many surfactants that can be used for such purpose, their performance with supercritical CO 2 (ScCO 2) is weak causing poor or loss of mobility control. This experimental study evaluates a newly developed surfactant (CNF) that was introduced for ScCO 2 mobility control in comparison with a common foaming agent, anionic alpha olefin sulfonate (AOS) surfactant. Experimental work was divided into three stages: foam static tests, interfacial tension measurements, and foam dynamic tests. Both surfactants were investigated at different conditions. In general, results show that both surfactants are good foaming agents to reduce the mobility of ScCO 2 with better performance of CNF surfactant. Shaking tests in the presence of crude oil show that the foam life for CNF extends to more than 24 h but less than that for AOS. Moreover, CNF features lower critical micelle concentration (CMC), higher adsorption, and smaller area/molecule at the liquid-air interface. Furthermore, entering, spreading, and bridging coefficients indicate that CNF surfactant produces very stable foam with light crude oil in both deionized and saline water, whereas AOS was stable only in deionized water. At all conditions for mobility reduction evaluation, CNF exhibits stronger flow resistance, higher foam viscosity, and higher mobility reduction factor than that of AOS surfactant. In addition, CNF and ScCO 2 simultaneous injection produced 8.83% higher oil recovery than that of the baseline experiment and 7.87% higher than that of AOS. Pressure drop profiles for foam flooding using CNF was slightly higher than that of AOS indicating that CNF is better in terms of foam-oil tolerance which resulted in higher oil recovery.