The Effect of Oil Brine Ratio on Surfactant Adsorption From Microemulsions

Abstract

Static adsorption measurements of petroleum sulfonates on crushed Bell Creek and Berea cores were made utilizing fluids with the same active surfactant concentration but varying brine-to-oil mass ratios. The salinity of the brine was chosen such that a significant three-phase region existed in the oil/brine/surfactant/alcohol system. The surfactant adsorption was found to be independent of the structural and compositional differences among the fluids. A series of oil recovery tests in which middlephase microemulsions were injected into waterflooded cores were also carried out. The cores utilized in these tests had been treated to remove divalent ions accessible to fluid flow. Microemulsion slugs (1.75 to 146 percent pore volume) of equal active surfactant concentration but differing brine-to-oil mass ratios were injected. The total surfactant retention for this system was also found to be independent of the brine-to-oil mass ratio. Introduction Control of sulfonate loss is one of the single most important factors in determining the success or failure of a surfactant flooding process. In a typical surfactant flood sulfonate costs are frequently half or more of the total project cost. As a result, this area has been frequently studied. Many authors have studied detailed adsorption mechanisms—mostly from aqueous solutions and at relatively low concentrations. A recent thesis from the University of Texas, and the references contained therein, provide an excellent description of this type of work. The petroleum industry literature deals more with evaluating the controlling factors in actual flood implementation. Surfactant loss has been broken down into adsorption, precipitation, and phase trapping. The effects of sacrificial agents, sulfonate fractionation, divalent ions, and salinity gradients have all been investigated. Since it is not the purpose of this paper to provide a review of the literature, we have attempted only to summarize some of this literature in the form of a table (see Table 1).

Static Adsorption of an Ethoxylated Nonionic Surfactant on Carbonate Minerals

“…A variety of surface forces plays a major role in surfactant adsorption onto the rock surface. These interactions can be attractive or repulsive depending on (i) surfactant charge, (ii) charges and wettability of the rock/brine interface, (iii) brine ionic strength, composition, and pH, and (iv) temperature. − Typically, anionic surfactants show high adsorption on calcite and low adsorption on silica, while cationic surfactants show the opposite results due to electrostatic interactions between the surfactant and minerals. Additionally, compared to an air environment, CO 2 was found to decrease adsorption of cationic surfactant cetylpyridinium chloride (CPC) on dolomite and limestone surfaces by increasing the ζ potential of the mineral surfaces. , Zwitterionic surfactants are sensitive to brine ionic strength.…”

“…They also found that temperature did alter the zwitterionic surfactant adsorption onto mineral surfaces. Rock wettability in the presence of residue oil also influences surfactant adsorption by preferentially partitioning to the brine/oil interface, resulting in phase trapping. − …”

A review on polymer, gas, surfactant and nanoparticle adsorption modeling in porous media

“…This has led to recovery increase but with a drawback of adsorption unto the rock surface which begs the question of its economic viability as an EOR option in the face of adsorption. Over the years, several surfactants have been tried on different reservoir systems with different mineralogy to quantify the degree of adsorption and suitability for enhanced oil recovery (Celik and Somasundaran, 1980;Cui et al, 2015;Meyers and Salter, 1980;Wang et al, 2015;Zhou et al, 2012). Debates have been ongoing for decades over the effect of surfactant/ CO 2 co-injection for enhancing the oil recovery process and the effect of gas fractional flow on recovery.…”

“…This unique quality of the surfactant led to a reduction in adsorption however, the presence of clay and silica presents a drawback. More so, the presence of divalent and trivalent cations reduces dissolution of calcite or dolomite at high pressure however presents a challenge of a rise in pH which increases adsorption (Meyers and Salter, 1980). Contrary to the conventional method of adsorbed surfactant measuring technique which involves measuring concentration changes, Zhou et al (2005) developed a novel technique called sandwashing technique which allows the determination of adsorbed surfactant on the sand face and at an oil-water interface in the presence of oil.…”