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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.

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Two major applications of injecting dense carbon dioxide (CO2) into the petroleum reservoirs are enhanced oil recovery and sequester CO2 underground. For enhanced oil recovery applications, CO2 has low miscibility pressure causing the swelling of crude oil and reducing its viscosity therefore improving the macroscopic sweep process. However, the low viscosity of injected CO2 compared with the reservoir fluids causes the fingering of CO2, which may lead to bypassing huge amount of oil, early breakthrough of CO2, and increasing the gas to oil ratio (GOR). The use of direct thickeners, such as polymers, is one of the techniques used to increase the CO2 viscosity. Nevertheless, the solubility of polymers in CO2 and the high cost of soluble polymers are the main challenges facing this technique. In this study, a novel, soluble, and cost-effective thickener is proposed to directly increase the CO2 viscosity. In this study, a PVT high pressure and high temperature (HPHT) apparatus was used to evaluate the compatibility and the solubility of the thickener in dense CO2. Also, a custom designed apparatus was used to measure the viscosity of dense CO2 in the presence of the thickener at different conditions. The assessment was conducted at different experimental pressures, temperatures, and thickener concentrations. The effect of pressure on the solubility of the thickener in CO2 and on the measured viscosity of CO2 was evaluated at 1500, 2000, 2500, and 3000 psi. Also, the influence of temperature was evaluated at 25 and 50°C. Moreover, the concentrations used to study the effect of thickener concentration on the measured viscosity of CO2 ranged between 0.10-2 %. The results from laboratory experiments clearly demonstrated that the addition of the thickener at certain conditions can significantly impact the dense CO2 viscosity. The results revealed that there must be a minimum pressure at which the thickener dissolves in the dense CO2. The solubility of the thickener can occur when the CO2 is either in the liquid or supercritical phase. The results also pointed out that the CO2 viscosity increased as the pressure increased. The increase of CO2 pressure can significantly impact the solubility of the thickener in the dense CO2 and consequently the CO2 viscosity. The increase of the thickener concentration also had a significant impact on the measured CO2 viscosity. The results showed that the CO2 viscosity increased with the thickener concentration. The CO2 viscosity increased 100 to 1200 -fold as a result of adding the thickener depending on the experimental conditions

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.

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CO2 foam helps to increase the viscosity of CO2 flood fluid and thus improve the process efficiency of the anthropogenic greenhouse gas’s subsurface utilization and sequestration. Successful CO2 foam formation mandates the development of high-performance chemicals at close to reservoir conditions, which in turn requires extensive laboratory tests and evaluations. This work demonstrates the utilization of a microfluidic reservoir analogue for rapid evaluation and screening of commercial surfactants (i.e., Cocamidopropyl Hydroxysultaine, Lauramidopropyl Betaine, Tallow Amine Ethoxylate, N,N,N′ Trimethyl-N′-Tallow-1,3-diaminopropane, and Sodium Alpha Olefin Sulfonate) based on their performance to produce supercritical CO2 foam at high salinity, temperature, and pressure conditions. The microfluidic analogue was designed to represent the pore sizes of the geologic reservoir rock and to operate at 100 °C and 13.8 MPa. Values of the pressure drop across the microfluidic analogue during flow of the CO2 foam through its pore network was used to evaluate the strength of the generated foam and utilized only milliliters of liquid. The transparent microfluidic pore network allows in-situ quantitative visualization of CO2 foam to calculate its half-life under static conditions while observing if there is any damage to the pore network due to precipitation and blockage. The microfluidic mobility reduction results agree with those of foam loop rheometer measurements, however, the microfluidic approach provided more accurate foam stability data to differentiate the foaming agent as compared with conventional balk testing. The results obtained here supports the utility of microfluidic systems for rapid screening of chemicals for carbon sequestration or enhanced oil recovery operations.

Gas injection is amongst the oldest and most used enhanced oil recovery (EOR) methods in the petroleum industry. Nevertheless, gas EOR is subject to poor macroscopic sweep efficiency due to the higher mobility and lower density of gas compared to reservoir fluids. Foamed-gas injection can regulate the mobility of gas by trapping a large fraction of the gas inside the porous medium, thereby increasing its apparent viscosity and reducing its relative permeability. However, the poor stability of foam at harsh reservoir temperature and salinity conditions is a major limitation that hinders the effectiveness of the foam flood. A combination of surfactant and nanoparticles (NPs) provides a novel solution to foam stability challenges. This study evaluates the role of NPs on enhancing foam stability. Static and dynamic laboratory tests were conducted along with particle size and zeta potential measurements to capture the foam stability and strength in porous media for a cationic surfactant combined with surface modified silica NPs. The static bulk foam stability was determined by measuring the foam half-life over time. The dynamic foam stability was determined through the mobility reduction factor (MRF) using a micromodel apparatus. The tests were carried out on a variety of NPs concentrations and fixed surfactant concentration. The results from the experiments show that the use of surfactant combined with NPs enhances the stability and strength of the generated foam when compared to the use of surfactant alone. The foam static tests show that the mixture of NPs and surfactants produces foams with smaller bubbles and longer half-life when compared to those in the absence of NPs. The results also demonstrate that the concentration of surfactant and NPs is a crucial parameter for foam stability and that there is an optimal concentration of NPs for strong foam generation. In porous media, the addition of NPs to surfactant solutions results in larger pressure differences across the micromodel chip and, accordingly, greater reduction of gas mobility when compared to those using surfactant solution alone. The results also reveal that the generation of NPs flocs is the main mechanism of foam stabilization enhancement. This work shows that using NPs at carefully selected concentrations in combination with surfactant can improve the foam static and dynamic stability in porous media, effectively lowering the mobility of the injected fluids and, eventually, improving the sweep efficiency of gas compared to the typical application of using surfactant alone.