Alpha Olefin Sulfonate Research Articles

Exploring Low-IFT Foam EOR in Fractured Carbonates: Success and Particular Challenges of Sub-10-md Limestone

SummaryThe high formation heterogeneity in naturally fractured limestone reservoirs requires mobility control agents to improve sweep efficiency and boost oil recovery. However, typical mobility control agents, such as polymers and gels, are impractical in tight sub-10-md formations due to potential plugging issues. The objective of this study is to demonstrate the feasibility of a low-interfacial-tension (low-IFT) foam process in fractured low-permeability limestone reservoirs and to investigate relevant geochemical interactions.The low-IFT foam process was investigated through coreflood experiments in homogeneous and fractured oil-wet cores with sub-10-md matrix permeability. The performance of a low-IFT foaming formulation and a well-known standard foamer [alpha olefin sulfonate (AOS) C14-16] were compared in terms of the efficiency of oil recovery. The effluent ionic concentrations were measured to understand how the geochemical properties of limestone influenced the low-IFT foam process. Aqueous stability and phase behavior tests with crushed core materials and brines containing various divalent ion concentrations were conducted to interpret the observations in the coreflood experiments.Low-IFT foam process can achieve significant incremental oil recovery in fractured oil-wet limestone reservoirs with sub-10-md matrix permeability. Low-IFT foam flooding in a fractured oil-wet limestone core with 5-md matrix permeability achieved 64% incremental oil recovery compared to waterflooding. In this process, because of the significantly lower capillary entry pressure for surfactant solution compared to gas, the foam primarily diverted surfactant solution from the fracture into the matrix. This selective diversion effect resulted in surfactant or weak foam flooding in the tight matrix and hence improved the invading fluid flow in the matrix. Meanwhile, the low-IFT property of the foaming formulation mobilized the remaining oil in the matrix. This oil mobilization effect of the low-IFT formulation achieved lower remaining oil saturation in the swept zones compared with the formulation lacking low-IFT property with oil. The limestone geochemical instability caused additional challenges for the low-IFT foam process in limestone reservoirs compared to dolomite reservoirs. The reactions of calcite with injected fluids—such as mineral dissolution and the exchange of calcium and magnesium—were found to increase the Ca2+ concentration in the produced fluids. Because the low-IFT foam process is sensitive to brine salinity, the additional Ca2+ may cause potential surfactant precipitation and unfavorable over-optimum conditions. It, therefore, may cause injectivity and phase-trapping issues especially in the homogeneous limestone.Results in this work demonstrated that despite the challenges associated with limestone dissolution, the low-IFT foam process can remarkably extend chemical enhanced oil recovery (EOR) in fractured oil-wet tight reservoirs with matrix permeability as low as 5 md.

Influence of lauryl betaine on aqueous solution stability, foamability and foam stability

In gas flooding, one of the major problems in implementing foam as a gas mobility control method is the stability of foam. Foam booster when blended with surfactant could improve the foam stability. However, the influence of foam booster on the conventional foam stability and foamability at elevated temperature and presence of inorganic electrolytes is not yet explicit due to limited studies in this area. The objective of the present work was to evaluate the influence of a foam booster on aqueous solution stability, foamability and foam stability when blended with surfactant at different ratios at an elevated temperature in the presence of brine composed of monovalent and divalent ions. Three different surfactants AOS C14–16 (alpha-olefin sulfonate), SDS (sodium dodecyl sulfate) and a locally manufactured surfactant ‘Surf X’ were chosen as base surfactants. An amphoteric surfactant lauryl betaine was chosen as a foam booster in this study. The aqueous solution stability was visually evaluated, whereas the bulk foam experiments were conducted in a commercial foam analyzer apparatus. It was found that not all solutions were stable when lauryl betaine was blended. Lauryl betaine did not improve the foam generation time. The foam stability was improved; however, not all solutions were able to generate stable foam. ‘Surf X’ was able to generate more stable foam as compared to AOS and when blended with lauryl betaine it also required less amount of lauryl betaine to generate stable foam.

Modeling and Experimental Validation of Rheological Transition During Foam Flow in Porous Media

Flow of nitrogen foam stabilized by alpha olefin sulfonate (C14-16 AOS) was studied in a natural sandstone porous media using X-ray Computed Tomography. Foam was generated by a simultaneous injection of gas and surfactant solution into a porous medium initially saturated with the surfactant solution. It was found that the foam undergoes a transition from a weak to a strong state at a characteristic gas saturation of Sgc = 0.75 ± 0.02. This transition coincided with a substantial reduction in foam mobility by a two-order of magnitude and also with a large reduction in overall water saturation to as low as 0.10 ± 0.02. Foam mobility transition was interpreted by the surge of yield stress as gas saturation exceeded the Sgc. We proposed a simple power-law functional relationship between yield stress and gas saturation. The proposed rheological model captured successfully the mobility transition of foams stabilized by different surfactant concentrations and for different core lengths.

Sunflower Acid Oil‐Based Production of Rhamnolipid Using Pseudomonas aeruginosa and Its Application in Liquid Detergents

AbstractUtilization of industrial waste as substrates for the rhamnolipid synthesis by Pseudomonas aeruginosa is a worthy alternative for conventionally used vegetable oils and fatty acids to reduce the production cost of rhamnolipid. Sunflower acid oil (SAO), a by‐product of the oil industry, contains 70% 18:0 fatty acid, with oleic acid as a major component. In this scope, production and analysis of rhamnolipid was successfully demonstrated using SAO as a new substrate. Pseudomonas aeruginosa produced rhamnolipid (a glycolipid biosurfactant) at a maximum concentration of 4.9 g L−1 with 60 g L−1 of SAO in the medium. Structural properties of rhamnolipid biosurfactant are confirmed using thin layer chromatography (TLC), high performance liquid chromatography (HPLC), and fourier transformed infrared spectroscopy (FTIR) analysis. Further surface‐active properties of the crude rhamnolipid were evaluated by measuring surface tension and emulsification properties. The synthesized rhamnolipid reduced the surface tension of water to 30.12 mN m−1 and interfacial tension (against heptane) to 0.52 mN m−1. Moreover, rhamnolipid shows the highest emulsification index (above 80%) for vegetable oils. This study confirms the use of SAO as a potential substrate for rhamnolipid production. The synthesized rhamnolipid was incorporated in liquid detergent formulation along with alpha olefin sulfonate (AOS) and sodium lauryl ether sulfate (SLES). The performance properties including foaming and cleaning efficiency of liquid detergent were compared.

Effect of Amino Acids on Micellization and Micellar Parameters of Anionic Surfactant Alpha Olefin Sulfonate C14–C16 in Aqueous Solutions: Surface Tension, Conductometric, Volumetric, and Fluorescence Studies

The effect of l-glycine, l-alanine, and l-leucine on micellization, surface activity, and colloidal parameters of an anionic surfactant sodium alpha olefin sulfonate C14–C16 in aqueous solutions at different temperatures was studied. It was shown that the hydrophobicity of the studied amino acids had great influence on behavior of physicochemical parameters. In studied systems, the electrostatic interactions between zwitterionic groups of amino acids and ions of sodium alpha olefin sulfonate C14–C16 were also important.

CO2 foam for enhanced oil recovery (EOR) applications using low adsorption surfactant structure

The ability of surfactants to interact with CO2 is essential if the CO2 foam is intended to augment a water flooding process as a method to displace oil from a reservoir. Apart from improved sweep efficiency of foam, CO2 reduces the oil viscosity, causes the oil to swell, lowers the high interfacial tension between oil and rock, dislodges the immobile oil, and hence increases the volumetric sweep efficiency. The surfactant must possess suitable structure to successfully play these roles. In this context, a new surfactant with different functionalities has been synthesized to examine its CO2-philicity. The surfactant was evaluated for the enhanced oil recovery (EOR) suitability by firstly examining the fluid–fluid compatibility in various temperatures, salinity, and hardness conditions. The foaming properties were also assessed. The interfacial tension (IFT) between the surfactant and CO2 gas at 90 °C and up to 2700 psi pressure revealed some interesting findings. The IFT of CO2–brine without surfactant dropped from a value of 70 to 30 mN/m when CO2 critical pressure approached 1070 psi, and it remained at 30 mN/m at higher pressures. The incorporation of surfactant achieved the lowest IFT of 1.76 mN/m at critical pressure conditions at 90 °C. The foam stability of the surfactants was also evaluated. In the core flooding test, the mobility reduction factor (MRF) values reflected the same trend as that of IFT lowering and foam stability. The three-tailed surfactant showed the MRF of 3.4 while alpha olefin sulfonate (AOS) (commercial surfactant) had the MRF value of 1.3. The three-tailed surfactant provided the highest recovery of 96% of residual oil in place (ROOIP). The adsorption of the surfactant was low at less than 0.5 mg/g.

Effect of Alkyl Tail Length of Alpha Olefin Sulfonates on Foam Properties

AbstractThe effect of alkyl tail length on the foam properties of alpha olefin sulfonates (AOS) in aqueous solutions at various concentrations was investigated by measurements of the foamability, foam stability and bubble size and numbers, obtained from conductivity and image analyses techniques based on FoamScan foam analyzer. It was found that foamability and foam stability of Cn AOS (n = 14–16, 16–18, 20–24) first increase and then decrease with increase in the carbon chain length, showing an optimum for a length of n = 16–18. The foamability and foam stability of AOS increase with increasing of surfactant concentration. This is due to the fact that the adsorbed quantity of surfactant molecules increases at the air/water interface with the increase of concentration. In addition, it was found that the bubble size produced by C16–18 AOS is smaller than that of C14–16 AOS.

Aqueous foams stabilized with silica nanoparticle and alpha olefin sulfonates surfactant

Carbon dioxide (CO2) foams have been introduced to improve mobility of CO2 in CO2 flooding. However, using surfactant alone to stabilize CO2 foam has potential weaknesses such as high surfactant retention in porous media and the foam is thermodynamically unstable for a long-term. Nanoparticle has been an alternative in stabilizing CO2 foam longer. This study aims to analyze CO2 foam stability at varying concentrations of surfactant, silica nanoparticle (SNP) and brine. The additions of SNP in anionic surfactant of alpha olefin sulfonates (AOS)-water and in AOS-brine towards foam stability were demonstrated in this study. CO2 foam stability was measured through the foam height observation and bubble size analysis. The performance of SNP and AOS suspensions in stabilizing foam were observed at different concentrations of AOS (0.1, 0.3 and 0.5 wt%), SNP (0.1, 0.3 and 0.5 wt%) and brine (0.1, 1 and 5 wt%). The results revealed that the CO2foams were most stable at 0.3 wt% SNP suspension in 0.5 wt% AOS-water. It was found that the most stable foams formed at concentration of 1 wt% of brine. Smaller and uniform bubble size has been produced at 0.3 wt% SNP in 0.5 wt% AOS solution. Thus, concentrations of surfactant, SNP and brine have significant effects on CO2 foam stability.

Foam propagation and oil recovery potential at large distances from an injection well

While foam propagation, foam–oil interaction and foam oil recovery performance have been investigated by numerous research studies, most of previous works were performed on short porous media with the maximum length of 30cm. Therefore, their results mostly represent foam behavior in the vicinity of the injection well and may not represent the foam propagation, quality and oil recovery potential at large distances from the injection well. In this study, by using a high-pressure and high-temperature rig equipped with a 12-m long porous medium and microscopic visualization facilities, foam stability in the presence and absence of a reservoir crude oil, foam propagation, foam–oil interaction, and finally foam oil recovery potential at large distances from the injection well were investigated. The oil recovery behavior of four tertiary scenarios, including Sodium Dodecyl Sulfate (SDS) foam, Alpha-Olefin Sulfonate (AOS) foam, gas, and simultaneous water alternating gas (SWAG) injection, were investigated.According to results, pressure presented a positive impact on the foam stability. The extent of this impact was a function of the surfactant type. Compared to gas and SWAG injection, in the 12-m long porous medium, foam flooding scenarios presented much stronger oil recovery potentials. This reveals the strong potential of foam flooding in producing the oil trapped in areas deep into the reservoir and far from the injection well. Based on this study, by using a suitable surfactant solution and optimum gas fractional flow, even in the presence of oil, foam can propagate to large distances from the injection well and leads to extra oil recovery.

Numerical simulation of foam flooding in porous media in the absence and presence of oleic phase

This paper presents a novel integrated approach for numerical simulation of foam core-flood experiments in the absence and presence of oil. The experiments consisted of the co-injection of gas and Alpha-Olefin Sulfonate (AOS) surfactant solution into Bentheimer sandstone samples initially saturated with the surfactant solution [see Simjoo & Zitha (2013)]. The foam model implemented is based on a local equilibrium and describes dependency of foam mobility reduction factor using several independent functions, such as liquid saturation, foam velocity, oil saturation and capillary number.First, a series of numerical simulation was conducted to investigate the effect of surfactant concentration on pressure drop across the core for the foam flooding in the absence of oil. To this end, the dry-out and gas velocity functions in the foam model were determined from the experimental data obtained at low and high-quality regimes of foam flow at a constant injection velocity. Next, pressure drop profiles of foam flooding at two different surfactant concentrations were modelled to determine the parameters of the surfactant-dependent function in the foam model. The simulation results fit the experimental data of pressure drops very well. Then, the numerical simulations investigated the oil displacement, by foam where the main goal was to determine the foam model parameters dedicated to the oil saturation-dependent function. The pressure drop across the core, oil-cut, and oil recovery factor were modelled, and an excellent match was obtained between the pressure profile and the oil recovery obtained numerically compared with those obtained from the corresponding core-flood experiments.

New Force Field Parameters for the Sodium Dodecyl Sulfate and Alpha Olefin Sulfonate Anionic Surfactants.

Molecular dynamics simulations were carried out to obtain new force field parameters of two most commonly used anionic surfactants: sodium dodecyl sulfate and alpha olefin sulfonate. The present united atom models, of those surfactants, fail to reproduce one of the most important thermodynamic properties, the surface tension. Therefore, by scaling the Lennard-Jones parameters, the potential well (ϵ) and the length (σ), we were able to fit the experimental data. The correct micelle structure of the surfactants was also captured with the new set of parameters. The new proposed united atom models of both surfactants were tested with two different water models, TIP4P/ϵ and SPC/E, and good agreement with actual experiments was found.

Oil-degrading properties of a psychrotolerant bacterial strain, Rhodococcus sp. Y2-2, in liquid and soil media.

The aim of this study was to investigate oil-degrading ability of newly isolated strain Rhodococcus Y2-2at low temperature. Rhodococcus sp. Y2-2 was isolated from oil-contaminated soil sampled at the end of winter using a newly developed transwell plate method. In the liquid phase, the oil-degradation efficiency of strain Rhodococcus sp. Y2-2 was about 84% with an initial concentration of 1500ppm TPH (500ppm each of kerosene, gasoline, and diesel) when incubated for 2 weeks under optimal conditions: 10°C, pH 7, and 0.5g L- 1 inoculum. In the soil phase, the isolate showed 80% oil degradation efficiency using glucose as a carbon source, with an initial concentration of 4000ppm TPH and the addition of water during 14 days of incubation at 10°C. Additionally, the degradation efficiency of the isolate was increased by the addition of mixture of surfactant alpha olefin sulfonate and gelatin, although strain Y2-2 also produced many biosurfactant components. This study shows Rhodococcus sp. Y2-2 can degrade oil components both in liquid and soil media by consuming kerosene, gasoline, and diesel as a carbon and energy source. Therefore, the crude oil-degrading ability of Rhodococcus sp. Y2-2at low temperature provides proper bioremediation tool to clean up oil-contaminated sites especially in cold area or during winter season.

Micellar interaction of binary mixtures of alpha olefin sulfonate and nonylphenol polyethylene glycol ethers: Length effects of ethylene oxide

The micellization behavior of binary surfactant mixtures constituted by an anionic surfactant, alpha olefin sulfonate (AOS), and a nonionic surfactant nonylphenol polyethylene glycol ether (NPE) with different numbers of ethylene oxide (EO), namely, NP10EO, NP20EO, NP30EO, and NP40EO was comprehensively investigated by surface tensiometer, conductometer, cloud point measurement, and dynamic light scattering. Theoretical treatments were carried out to explain molecular interaction in the mixed micelles based on regular solution theory of Rubingh, micellization thermodynamics of Molyneux et al. and Maeda, and molecular thermodynamic theory of Pavvada and Blankschtein. Results indicate non-ideal mixing behavior in all AOS-NPE mixtures, where nonionic surfactant EO chain length was found to play critical roles. In the absence of additional electrolytes, NPEs exhibited substantially higher activity in micelles than bulk solution; with growth of EO groups, shrinkage on the scale of synergistic interaction was evidenced. In contrary, with swamping amount of electrolytes, synergistic interactions enlarged with the rise of EO groups, and AOS activity in mixed micelles was found depending on both EO length and bulk mole fraction (αA). These findings are of great significance in mixed surfactant formulation design/optimization to maximize the synergistic efficiency of the system thus to minimize the chemical consumption and cost.

Potential of Polymeric Surfactant in Stabilizing Carbon Dioxide Foam for Enhanced Oil Recovery

This study investigates the stability of carbon dioxide (CO2) foam generated from water, gas and formulation of Alpha-Olefin Sulfonate (AOS), Betaines and different types of polymeric surfactant. The effects of different types of crude oil on foam stability were also analyzed. It was found that a higher concentration of surfactant provided more stable foam while a finer texture of foam bubbles were observed with addition of Betaines. The addition of Poly(ethylene glycol) dimethyl ether showed the best result as the foam did not degenerate as rapidly as the other polymeric surfactants. The presence of crude oil also affected the foam stability as it went into a steep decline.

Experimental and mathematical modeling investigation on the dynamic viscoelasticity behavior of free liquid films prepared by alpha olefin sulfonate

The viscoelasticity behavior and corresponding mathematical models for free liquid films under dynamic conditions were investigated respectively. Systematic analysis of the effects of sinusoidal exciting frequency, surfactant concentration, inorganic salt, temperature and polymer additives on the viscoelasticity modulus of AOS (alpha olefin sulfonate) liquid films were performed in detail. Higher viscoelasticity modulus could be achieved for AOS liquid films at about the critical micelle concentration of AOS solution. Meanwhile, increasing the NaCl concentration increased both the values of the overall modulus (E) and elastic modulus (E′) of AOS liquid films, while the values of viscous modulus (E″) decreased in the presence of NaCl. The values of E, E′ and E″ of AOS liquid films decreased along with the increase of temperature. The viscoelasticity modulus of AOS liquid films improved significantly after the addition of polymer. Additionally, the experimental results indicated that the dynamic extensional viscoelasticity behavior of free liquid films could be simulated by A type standard linear and B type standard linear type model in the experiments.

Viscosity Models for Polymer Free CO2 Foam Fracturing Fluid with the Effect of Surfactant Concentration, Salinity and Shear Rate

High quality polymer free CO2 foam possesses unique properties that make it an ideal fluid for fracturing unconventional shales. In this paper, the viscosity of polymer free fracturing foam and its empirical correlations at high pressure high temperature (HPHT) as a function of surfactant concentration, salinity, and shear rate are presented. Foams were generated using a widely-used surfactant, i.e., alpha olefin sulfonate (AOS) in the presence of brine and a stabilizer at HPHT. Pressurize foam rheometer was used to find out the viscosity of CO2 foams at different surfactant concentration (0.25–1 wt %) and salinity (0.5–8 wt %) over a wide range of shear rate (10–500 s−1) at 1500 psi and 80 °C. Experimental results concluded that foam apparent viscosity increases noticeably until the surfactant concentration of 0.5 wt %, whereas, the increment in salinity provided a continuous increase in foam apparent viscosity. Nonlinear regression was performed on experimental data and empirical correlations were developed. Power law model for foam viscosity was modified to accommodate for the effect of shear rate, surfactant concentration, and salinity. Power law indices (K and n) were found to be a strong function of surfactant concentration and salinity. The new correlations accurately predict the foam apparent viscosity under various stimulation scenarios and these can be used for fracture simulation modeling.

Adsorption, wetting, foaming, and emulsification properties of mixtures of nonylphenol dodecyl sulfonate based on linear alpha-olefin and heavy alkyl benzene sulfonate

ABSTRACTNonylphenol dodecyl sulfonate (C12NPAS) has been synthesized, and mixed with heavy alkyl benzene sulfonates (HABS) in different proportions. The effects of different mixing ratios on properties such as adsorption, wetting, foaming, and emulsification, of the C12NPAS/HABS surfactant mixtures have been systematically investigated. Experimental results have shown that, after mixing, the wetting and foaming properties of C12NPAS/HABS are improved remarkably. Compared with C12NPAS and HABS alone, the adsorption and emulsifying properties of C12NPAS/HABS are far superior, which we attribute to a synergistic effect between these surfactants.

Characterization of ternary compound viscosity reducer system on viscosity of viscous crude oil

ABSTRACTBased on the theory that viscous crude oil can form stable two-phase oil-water interfacial molecular membrane with surfactant, the oil-water interfacial activity and viscosity reduction of oil-water interface of viscous crude oil were studied for the ternary compound system, including anionic surfactant alpha olefin sulfonate (AOS), weak alkali Na2CO3 and four different kinds of nonionic surfactant emulsifying silicon oil (LKR-1023), lauryl diethanolamide (LDEA), isomeric alcohol ethoxylates (E-1306), and polyoxyethylene sorbitan monooleate (T-80). Results showed when lipophilic or hydrophilic nonionic surfactants were used separately in the same compound system. The viscosity of viscous crude oil could be reduced, but the viscosity reduction efficacy was not desirable. However, using LKR-1023, E-1306, and T-80 as nonionic surfactant with mass fraction 1.0%, the viscosity reduction rate of viscous crude oil reaches 98.92%, 98.29%, and 96.87%, respectively. With 1.4% of LDEA, the viscosity reduction rate of viscous crude oil can reach 98.89%. Through all different kinds of the nonionic surfactant tested, oil-in-water (O/W) emulsion under LDEA ternary compound system has been proved to be the most stable with no phase inversion. Therefore, it is promising to improve the viscosity reduction of the super viscous crude oil by selecting the proper surfactant and dosage.

WETTABILITY STUDIES OF SANDSTONE AFTER THE INJECTION PROCESS OF SURFACTANT BY OBSERVING SALINITY EFFECT, SURFACTANT CONCENTRATION AND TEMPERATURE

The background of this research was based on residual of oil or residual saturation experienced by irrigated rocks or oil recovery in the secondary oil recovery phase, so an Enhanced Oil Recovery (EOR) method is necessary. However, at that phase also still found the remaining oil that remains attached to rocks. Thus, the study of residual oil is required by wettability using variations of surfactant chemical solutions at room temperature conditions and reservoir temperature variations. Therefor the objectives of this research, the processing injection surfactant, interfacial tension of oil-water would be reduced. But, the oil cannot be swept at all in the reservoir by surfactant injection (tendency fluid to adhere rocks). This research will particularly discuss about study of wettability in sandstones to examine the maximum sweeping point of area by combination of surfactant and brine. Data analysis used in this research was brine and anionic surfactant Alpha Olefin Sulfonate (AOS) and core. The specific concentrations of brine and surfactant such as 2000 ppm, 4000 ppm, 6000 ppm, 8000 ppm, 10000 ppm, and 15000 ppm and 1.0%, 1,2%, 1,4%,1,6% 1,8% and 2,0%. Both of them will examine in temperature 300C, 700C, 800C, and 900C.The result shows of three cores (M1, M2, and M3) of this research get the porosity of each other such as 21,5%, 17,8%, and 20,3% with the permeability such as 232 mD, 74 mD, and 185 mD. The category owned by porosity and permeability of each cores is very good. The wettability that very dominant category of each surfactant owned by mixed surfactant 2% with salinity 2000 ppm that have chosen by 36 mixed of surfactant in temperature 300C, 700C, 800C, and 900C. But, for mix surfactant in salinity 15.000 ppm would cause the wettability down from water-wet to intermediate-wet. Therefore, the wettability can be concluded that the wettability would get influence by passed of certain salinity of fluid or surfactant and the wettability would rise by temperature

Experimental investigation of associative polymer performance for CO2 foam enhanced oil recovery

Polymer addition amplifies the foam flood performance by providing a substantial mobility control during the enhanced oil recovery (EOR). A conventional anionic polymer i.e. hydrolyzed polyacrylamide (HPAM) is widely used for polymer enhanced foam (PEF) flooding. In this study, the foam stability and viscosity performance of the conventional HPAM polymer were compared with a relatively new associative polymer. An associative polymer (i.e. Superpusher B 192) and the conventional polymer of same molecular weight were considered and the foam generation was performed using a widely used foamer i.e. alpha olefin sulfonate (AOS) and a foam stabilizer (betaine). FoamScan was used to measure the foam stability whereas, for foam viscometric measurements, a high-pressure high-temperature foam rheometer was utilized. An associative polymer showed an interesting combination and both the apparent viscosity and foam stability were found to be significantly high. The conventional polymer failed to provide a high foam strength in rheometric analysis whereas, an associative polymer showed an interesting viscosity profile and a two-fold increase in the foam apparent viscosity was observed. This study shows that the associative Superpusher B192 holds a bright potential in increasing the foam flood performance during EOR.