Foam films stabilized with alpha olefin sulfonate (AOS)

Farajzadeh, R.; Krastev, Rumen; Zitha, Pacelli L.J.

doi:10.1016/j.colsurfa.2008.03.024

Cited by 106 publications

(92 citation statements)

References 16 publications

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“…Critical micelle concentration (CMC) refers to the concentration of surfactant solutions to form a large amount of micelles as one of the main parameters of each surfactant [9]. Critical micelle concentration can be determined from plot of interfacial tension (IFT) and surfactant concentration [3].…”

Section: B Recommendationmentioning

confidence: 99%

“…Moreover, AOS surfactants provide outstanding detergency, high compatibility with hard water, and good wetting and foaming properties with CO 2 even when the porous medium is partially saturated with oil. These properties make AOS surfactants an excellent candidate for EOR project that aim to produce more oil from underground reservoirs [9]. Beside of that, AOS surfactants have good stability at high temperature [10].…”

Section: Introductionmentioning

confidence: 99%

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Laboratory study of salinity and surfactant concentration effects on oil recovery

et al. 2017

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Abstract. This paper perfoms a discussion of the result from two laboratory tests of surfactant injection. The first test is focused on the influence of salinity that varies between 5000 ppm-9000 ppm with a concentration of 1% surfactant to the value of density, viscosity, interfacial tension, and Recovery Factor. The second test is performing the influence of surfactant concentration that varies between 0.1% -1% with a value of 5000 ppm salinity to the value of residual oil saturation, density, viscosity, and interfacial tension. The result of the first test shows that along with the increase of salinity levels, the increase in viscosity and density will occured as well. However, variations in salinity does not affect to the value of interfacial tension. Meanwhile, on Recovery Factor testing, the Recovery Factor optimal value of 61.53% was obtained when the salinity levels 6,000 ppm. The result of the second test showed that the addition of surfactant concentration lead to a decrease in the residual oil saturation and interfacial tension, but it may cause an increase in density and viscosity.

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Section: B Recommendationmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Laboratory study of salinity and surfactant concentration effects on oil recovery

et al. 2017

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“…The lamellae are stabilized by using surfactants, (e.g. [10]) or, to a lesser extent, polymers and nano-particles. The focus of this study is on foams stabilized by surfactants.…”

Section: Introductionmentioning

confidence: 99%

Immiscible Foam for Enhancing Oil Recovery: Bulk and Porous Media Experiments

et al. 2011

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This paper reports a laboratory study of foam for improving immiscible gas flooding. The study is relevant for both continuous and Water Alternating Gas (WAG) injection schemes. The effect of oil on the longevity of nitrogen and air foams was studied in bulk for a selected set of surfactants. Foam heights were measured in a glass column as a function of time, in the absence and presence of mineral and crude oils. From the column experiments it was found that foam longevity increases as the carbon chain length in the oil molecule increases, i.e. foam is more stable for higher viscosity oils. A surfactant formulation that gave the most stable foam in the presence of oil was used in the core-floods. Oil recovery with CO 2 and with N 2 foams from natural sandstone cores was studied with the aid of X-ray Computed Tomography, varying the injection rates, foam quality and surfactant concentration. The core-floods revealed that foam increases the oil recovery by as much as 20% of the oil initially in place (OIIP) over water flooding while injection of gas increased oil recovery by 10% only. Thus, foam adds up to 10% additional recovery on top of gas injection. This confirms that foam is potentially an efficient Enhanced Oil Recovery (EOR) method.

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“…The P c * concept in porous media is analogous to the concept of the critical disjoining pressure in bulk foam, above which a single foam lamella breaks (Aronson et al, 1992;Exerowa and Kruglyakov, 1998;Farajzadeh et al, 2008). Similarly, in foamdisplacement experiments in a porous medium, as gas saturation rises the local capillary pressure increases; at a certain point the capillary pressure is so great that foam films do not survive and the foam becomes coarser in texture (Khatib et al, 1988).…”

Section: Introductionmentioning

confidence: 99%

Effect of Permeability on Foam-model Parameters and the Limiting Capillary Pressure

Farajzadeh¹,

Lotfollahi²,

Eftekhari³

et al. 2015

Proceedings

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SUMMARYAccurate modelling of foam rheology on the field scale requires detailed understanding of the correlation between the fundamental properties of foam and the scalable parameters of the porous medium. It has been experimentally observed that foam experiences an abrupt coalescence when the capillary pressure in the porous medium approaches a certain value referred to as the "limiting capillary pressure", Pc*. Current foam models that treat foam texture implicitly mimic this fundamental behaviour with a so-called dry-out function, which contains adjustable parameters like fmdry and epdry (in the STARS foam simulator). Parameter fmdry (called Sw* in other models) represents the water saturation corresponding to the limiting capillary pressure Pc* and epdry determines the abruptness of foam coalescence as a function of water saturation. In this paper, using experimental data, we examine the permeability-dependence of these parameters. We find that the value of fmdry decreases with increasing permeability. We also find that, for the data examined in this paper, the transition from high-quality regime to low-quality regime is more abrupt in lower-permeability rocks. This implies that in high-permeability rocks foam might not collapse abruptly at a single water saturation; instead there is range of water saturation over which foam weakens. In addition, we address the question of whether Pc* is dependent on formation permeability. We estimate Pc* from data for foam mobility in vs. foam quality, and find, as did Khatib et al. (1988), who introduced the limiting capillary pressure concept, that Pc* can vary with permeability. It increases as permeability decreases, but not enough to reverse the trend of increasing foam apparent viscosity as permeability increases.

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Foam films stabilized with alpha olefin sulfonate (AOS)

Cited by 106 publications

References 16 publications

Laboratory study of salinity and surfactant concentration effects on oil recovery

Laboratory study of salinity and surfactant concentration effects on oil recovery

Immiscible Foam for Enhancing Oil Recovery: Bulk and Porous Media Experiments

Effect of Permeability on Foam-model Parameters and the Limiting Capillary Pressure

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