Foam-forming surfactants

The interfacial tension results reported in this paper are part of a study to examine the benefits of using commercial foam-forming surfactants with steam-based processes for obtaining additional oil recovery. Low interfacial tension at elevated temperatures is needed to reduce residual oil saturation and to allow foams to form, or enhance their performance. 

Although many factors, such as film thickness and adsorption behaviour, have to be taken into account, the ability of a surfactant to reduce surface tension and contribute to surface elasticity are among the most important features of foam stabilization (see Section 5.4.2). The relation between Marangoni surface elasticity and foam stability [201,204,305,443] partially explains why some surfactants will act to promote foaming while others reduce foam stability (foam breakers or defoamers), and still others prevent foam formation in the first place (foam preventatives, foam inhibitors). Continued research into the dynamic physical properties of thin-liquid films and bubble surfaces is necessary to more fully understand foaming behaviour. Schramm et al. [306] discuss some of the factors that must be considered in the selection of practical foam-forming surfactants for industrial processes. 

Mannhardt, K. Novosad, J.J. Adsorption of Foam-Forming Surfactants for Hydrocarbon-Miscible Flooding at High Salinities in Foams, Fundamentals and Applications in the Petroleum Industry, Schramm, L.L. (Ed.), American Chemical Society Washington, 1994, pp. 259-316. 

Novosad, J.J. On Minimizing Adsorption of Foam-Forming Surfactants in Porous Media in Chemicals in the Oil Industry Developments and Applications, Ogden, P.H. (Ed.), Royal Society of Chemistry Cambridge, 1991, pp. 159-173. 

Chad, J. Matsalla, P. Novosad, J.J. Foam Forming Surfactants in Pembina/Ostracod G Pool in Proc., CIM Annual Technical Meeting, Canadian Inst. Mining, Metallurgical and Petroleum Engineers Calgary, AB, 1988, paper CIM 88-39-40. 

Foam-forming surfactant may be absorbed or adsorbed by the oil, especially if there is emulsification, causing depletion in the aqueous phase and hence from the gas-liquid interface. 

Because the interfacial tension can change with time after an initial spreading of oil, 5 may be time-dependent, and it follows that, in some cases, oils may act as defoamers only for a limited amount of time. The dynamic interfacial tensions were studied (37, 40, 47) for various crude oil and foam-forming surfactant solution combinations. Some of these systems exhibited dynamic interfacial tensions, but typical variations over up... 

Figure 8. Foam phase-behavior diagrams for a series of foam-forming surfactants and four different oils. (Reproduced with permission from reference 47. Copyright 1992 Elsevier Science Publishers.)...

These results have been expressed in terms of the influence of the wetting condition of the porous medium as foam is flowing through it. A complication is that the foam-forming surfactant may adsorb onto the solid surfaces and may alter the wettability. In the microvisual experiments of Schramm and Mannhardt (60), some of the foaming systems investigated appeared to change the wettability back to water-wet, in which case the foam sensitivities to oil reverted back to those appropriate to the... 

Interfacial Tension Behavior. Reduction in the residual oil saturation over and above that obtained by steam injection is desirable and, in many heavy oil reservoirs, essential to ensure efficient foam formation during application of steam-foam processes (13). The extent of heavy oil desaturation is, however, dependent on the reduction in interfacial tension between oil and water. Thus, foam-forming surfactants can improve their own cause by reducing interfacial tensions at steam temperature. 

Adsorption of Foam-Forming Surfactants for Hydrocarbon-Miscible Flooding at High Salinities... 

No universally accepted practices exist for selecting foam-forming surfactants for specific rock—fluid systems. In addition, information dealing with foam performance at brine salinities as high as those found in the pools mentioned previously is not readily available in the literature. The selection process is based on the following common sense criteria (2) ... 

This section has demonstrated that some commercially available surfactants are soluble in brines of extreme salinity and hardness and also form effective mobility control foams under these conditions. The remainder of this chapter is devoted to the development of a better understanding of the adsorption properties of foam-forming surfactants, mainly those for high-salinity conditions. It is hoped that this discussion will contribute to the development of a systematic approach for selecting or formulating surfactants with minimal adsorption levels. 

Some anionic foam-forming surfactants do not adsorb appreciably on sandstone from low-salinity (0.5 mass %) brine (7). However, adsorption increases steeply when the salinity is increased to several mass percent. 

Figure 6 shows that adsorption levels of foam-forming surfactants can vary widely from near-zero (measurements numbered 1 and 2) to almost... 

Figure 6. Adsorption levels measured in 96 core-flood experiments with foam-forming surfactants.

Most foam-forming surfactants, particularly those suitable for high-salinity conditions, are very hydrophilic and do not partition into oil, eliminating the first of the listed mechanisms. The amount of surfactant adsorbed at the oil—water interface depends on the surface excess of surfactant at this interface and on the amount of interface present. Although the surface excess of surfactant at the oil—water interface can be estimated from interfacial tension data using the Gibbs adsorption equation, the amount of interface that is present is not easily accessible to measurement. 

The amount of surfactant that may be deactivated by asphaltenes possibly can be comparable to the amount adsorbed at the solid—liquid interface (22), and this mechanism may thus contribute significantly to surfactant loss in reservoirs containing oil of high asphaltene content. However, the experiments described in reference 22 were carried out with a surfactant that partitions into oil. Because many foam-forming surfactants do not partition significantly, surfactant loss by complexation to asphaltenes is not expected to contribute substantially to surfactant loss. 

This section discusses the adsorption behavior of a number of foamforming surfactants under a wide variety of conditions. Surfactant adsorption data that appear in the petroleum literature are often difficult to compare because they are measured by different methods (batch or coreflood experiments), and experimental conditions may vary widely and are frequently not completely specified. The data discussed in this section, which are taken from references 7—12, 34, and 82 and some unpublished results, constitute the most extensive set of adsorption data for commercial foam-forming surfactants that were measured in a consistent manner by performing core-floods. 

Dependence of Adsorption on Temperature. Figures 11 and 12 show the temperature dependence of adsorption for several foam-forming surfactants on sandstone or unconsolidated sand. Physical adsorption is an exothermic process and is expected to decrease with increasing temperature. This trend is observed for the anionic surfactants (Figures 11a and 12) Adsorption decreases up to an order of magnitude when the temperature is raised from 50 to 150 °C. In contrast, adsorption of the amphoteric surfactants is affected very little by temperature and may even show a slight increase with temperature in some cases (Figure lib). An increase in adsorption with temperature has sometimes been taken as an indication of chemisorption (36). 

Dependence of Adsorption, on Rock Type. Table I shows that gas injection EOR projects are being conducted in sandstone and carbonate pools. Hydrocarbon- and C02-misdble projects are run largely in carbonate reservoirs. With the exception of several studies that report adsorption levels of EOR surfactants on carbonates (4,11,12, 24, 33, 62—64, 86), the petroleum literature has dealt almost exclusively with anionic, and sometimes nonionic, surfactant adsorption on sandstones, because most studies have been carried out with surfactants used in low-tension flooding. These surfactants are not considered suitable for application in carbonate reservoirs because of their low salinity and hardness tolerance. Foam-forming surfactants suitable for high-salinity environments include amphoteric surfactants (2). The adsorption behavior of this surfactant type has also rarely been studied (10—12, 87, 88). 

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