Bulk foam, as found in the head of a glass of beer or as found in association with cleaning solutions, is a metastable dispersion of a relatively large volume gas in a continuous liquid phase that constitutes a relatively small volume of the foam. An alternate definition of bulk foam is an "agglomeration of gas bubbles separated from each other by thin liquid films."  In most classical foams, the gas content is quite high (often 60 to 97% volume). In bulk form, such as in oilfield surface facilities and piping, foams are formed when gas contacts a liquid in the presence of mechanical agitation. As used herein, bulk foams are foams that exist in a container (e.g., a bottle or pipe) for which the volume of the container is much larger than the size of the individual foam gas bubbles.
General nature of foams
Capillary processes control the formation and properties of foams in porous media. Foams for use in conformance improvement are dispersions of microgas bubbles usually with diameters/lengths ranging between 50 and 1000 μm. Foam in porous media exists as individual microgas bubbles in direct contact with the wetting fluid of the pore walls. These microgas bubbles are separated by liquid lamellae that bridge the pore walls and form a liquid partition on the pore scale between gas bubbles. Foam propagates in most matrix reservoir rock as a bubble train in which each gas bubble is separated from the next by a liquid lamellae film. In many instances, individual foam bubbles in reservoir matrix rock can be many pore bodies in length. Gauglitz et al. have defined foam structure in porous media as "a dispersion of gas in a continuous liquid phase with at least some gas flow paths made discontinuous by thin liquid films called lamellae." 
All foams discussed on this page and all foams that are used for conformance improvement have surfactants dissolved in the foam’s liquid phase to stabilize the gas dispersion in the liquid. The gas phase of a foam can include both a classical gas and a supercritical gas, such as supercritical/dense CO2. Except as specially noted, all foams discussed in this chapter that are used to impart oilfield conformance improvement are aqueous-based foams. This chapter is limited primarily to the discussion of surfactant-stabilized aqueous-based foams for use in improving conformance during oil-recovery operations.
Fig. 1 shows a 2D slice of a generalized bulk foam system. The thin liquid films separating the foam gas bubbles are defined to be foam lamellae. The connection of the three lamellae of a gas bubble at a 120° angle is referred to as the Plateau border. In persistent bulk foams, spherical foam gas bubbles become transformed into foam cells, polyhedra separated by nearly flat thin liquid films. Such a foam is referred to as a dry foam. The polyhedra foam cells are almost, but not quite, regular dodecahedra. In three dimensions, four Plateau borders of a foam cell meet at a point at a tetrahedral angle of approximately 109°.
Foams in porous media generally have bubbles that are as large as, or larger than, the pore bodies. Foam exists in reservoir-rock porous media as bubble trains where the Plateau border of the foam lamellae is formed at the pore wall and has, for static nonflowing foam in the pore body, an angle of about 90° between the liquid lamellae and the pore wall.
Surfactants are the necessary third ingredient required for the formation of the foams discussed in this article. An understanding of basic surfactant chemistry is essential when selecting a proper surfactant for a given oilfield foam application.
A surfactant molecule contains, within the same molecule, both a polar and nonpolar segment. The polar or hydrophilic segment of a surfactant molecule has a strong chemical affinity for water. The nonpolar or lipophilic segment has a strong chemical affinity for nonpolar hydrocarbon molecules. When water and oil or water and gas are in contact, surfactant molecules tend to partition to the oil/water or gas/water interface and reduce the interfacial tension of the interface. Fig. 2 depicts a surfactant molecule residing at an oil/water interface. The partitioning of the surfactant molecule to the gas/water interface and the ensuing reduction of the interfacial tension is the primary mechanism through which surfactants stabilize dispersions of gas in water to form metastable foam.
Surfactants are classified into four types that are distinguished by the chemistry of the surfactant molecule’s polar group.
- Anionics—The polar group of an anionic surfactant is a salt (or possibly an acid) where the polar anionic group is directly attached to the surfactant molecule and the counter and surface-inactive cation (often sodium) is strongly partitioned into the aqueous side of an oil/water or gas/water interface. Anionic surfactants are often used in oilfield foams because they are relatively good surfactants, generally resistant to retention, quite chemically stable, available on a commercial scale, and fairly inexpensive.
- Cationics—The polar group of a cationic surfactant is a salt where the polar cationic group is directly attached to the surfactant molecule and the counter and surface-inactive anion is strongly partitioned into the aqueous side of an oil/water or gas/water interface. Cationic surfactants are infrequently used in oilfield foams because they tend to strongly adsorb on the surfaces of clays and sand and are relatively expensive.
- Nonionics—The polar group of a nonionic surfactant is not a salt, but rather a chemical specie, such as an alcohol, ether, or epoxy group, which promotes surfactant properties by imposing electronegativity contrast. Nonionic surfactants are less sensitive to high salinities and can be relatively inexpensive.
- Amphoterics—Amphoteric surfactants contain two or more characteristics of the previously listed chemical types of surfactants.
Fig. 3 illustrates the chemical structure of selected surfactants. Within any of the surfactant types, there can be substantial variations in their chemistries and performance. The chemistry, size, and degree of branching of the lipophilic segment of a surfactant molecule can have a major impact on foam-surfactant performance, just as the chemistry of the hydrophilic portion of a surfactant molecule can have. Even small and subtle differences in the lipophilic segment can alter surfactant properties dramatically. Most commercial surfactant products contain a distribution of surfactant types and sizes that adds further complexity of the surfactants used in conformance-improvement foams.
When using foam in conjunction with steam flooding or any elevated reservoir temperature application, it is important to choose a surfactant that will be thermally stable over the needed life of the foam in the reservoir. Historically, alpha-olefin surfactants and petroleum sulfonate surfactants have been most widely used in foams applied to high-temperature (> 170°F) reservoirs. Sulfate surfactants have been used at times in low-temperature (< 120°F) reservoirs.
Alpha-olefin sulfonates have emerged to be one of the most popular and widely employed surfactant chemistries for use in foams. This has resulted in large part because of their combined good foaming characteristics, relatively good salt tolerance, good thermal stability, availability, and relatively low cost. Mixtures of different surfactant chemistries have been suggested to provide advantages when formulating conformance foams.
The use of fluorinated surfactants in foam formulas has shown some promise. Fluorinated surfactants used with other surfactants have been reported to often improve the tolerance of the foam to oil. Fluorinated surfactants have not been widely used in field applications of oilfield foams largely because of their relatively high cost.
Several properties important to the characterization of bulk foam, as might exist in a bottle, are foam quality, foam texture, bubble size distribution, foam stability, and foam density. Foam quality is the volume percent gas within foam at a specified pressure and temperature. Foam qualities can exceed 97%. Bulk foams, having sufficiently high foam quality such that the foam cells are made of polyhedra liquid films, are referred to as dry foams. Oilfield conformance improvement foams typically have foam qualities in the range of 75 to 90%. When propagated through porous media, the mobility of many foams decreases as foam quality increases up to the upper limit of foam stability in terms of foam quality (an upper limit of often > 93% foam quality). When dealing with oilfield steam foams, steam quality refers to the mass fraction of water that is converted to steam.
Foam texture is a measure of the average gas bubble size. In general, as a foam texture becomes finer, the foam will have greater resistance to flow in matrix rock.
Bubble size distribution is a measure of the gas bubble size distribution in a foam. When holding all other variables constant, a bulk foam with a broad gas-bubble size distribution will be less stable because of gas diffusion from small to large gas bubbles. The imparted resistance to fluid flow in porous media by a foam will be higher when the bubble size is relatively homogeneous.
Stability of an aqueous-based foam is dependent on the chemical and physical properties of the surfactant-stabilized water film separating the foam’s gas bubbles. Foams are metastable entities; therefore, all foams will eventually break down. Foam breakdown is a result of the foam liquid films excessively thinning and rupturing with time and a result of gas diffusing from smaller bubbles into the larger bubbles, thus coarsening the foam’s bubble size. External effects, such as contact with a foam breaker (e.g., oil or adverse salinities), contact with a hydrophobic surface, and local heating can break foam structure.
Factors affecting foam lamellae stability include gravity drainage, capillary suction, surface elasticity, viscosity (bulk and surface), electric double-layer repulsion, and steric repulsion. The stability of foam residing in porous media evokes a whole series of additional considerations that are addressed in the next subsection of this chapter.
One of the attractive features of foams for use with gas-flooding operations is the relatively low effective density of foams. (As a countervailing note of reference, conformance improvement foams formulated with supercritical CO2 can attain densities exceeding the density of some crude oils.) The low-density feature has positive ramifications for foams used in both mobility-control flooding and for blocking fluid-flow. The low effective density causes the foam to be selectively placed higher in the reservoir interval where gas-flooding flow or gas production is most likely occurring.
For technical clarification, foam flow in porous media actually occurs as bubble trains of gas bubbles separated by liquid lamellae. Thus, strictly speaking, foam flow in porous media occurs as two phase flow—namely, gas bubble flow and liquid lamellae flow. In this more technically correct view, it is really the low density of the gas phase that promotes favored placement of the foam higher in the reservoir. During gas flooding, such as steam or CO2 flooding, low-density foams used for mobility control are well suited to address and reduce the common problem of gas override that often precludes injectant oil recovery gas from contacting the oil saturation lower in the reservoir vertical interval. Selective mobility-control by low-density foams in the upper portion of the reservoir will force more displacing fluid gas to contact oil-saturated sections lower in the reservoir.
The low density of foam used during a gas-blocking treatment will tend to drive the placement of the foam higher up in the reservoir interval where the offensive gas flow and production is most likely occurring. In this respect, foams for use in blocking-agent treatments are well suited to treat gas coning and gas cusping problems occurring at production wells. Also, gas override in a relative homogeneous reservoir with good vertical permeability causes excessive gas production in the upper interval of production wells. Low density gas-blocking foam helps favorable placement around such problem wells.
When considering the potential benefit of low density during foam placement of a conformance-improvement operation, the relative effects of gravity forces vs. viscous forces that are operating during the foam placement need to be carefully considered. That is, the horizontal differential pressure gradient vs. vertical differential pressure gradient that the foam will experience during its flow and/or placement in the reservoir needs to be evaluated.
One of three distinctly different modes is used for injecting conformance-improvement foams:
- Sequential injection
- Preformed foam created on the surface before injection.
Sequential injection involves the alternate injection into the oil reservoir of the foam’s gas and aqueous phases. Co-injection involves the co-injection into the reservoir of the foam’s gas and liquid phases. Because of the substantial effective viscosities of foams and the associated poor injectivity of preformed foams, early applications of conformance improvement foams tended to involve the sequential-injection or co-injection mode. Also, sequential-injection and co-injection are substantially simpler to implement in the field. Sequential injection also avoids tubular corrosion problems if the gas and the foaming solution form a corrosive mixture, such as found in CO2 foams.
The concept, which is supported by laboratory evidence, is that during the sequential or coinjection mode, foam will form in situ in the matrix reservoir rock. Supporting this contention is the expectation that low-viscosity and high-mobility gas will tend to finger into the aqueous foaming solution and generate the foam in situ.
However, there are two significant countering concerns. First, as the gas begins to finger into the aqueous solution and form foam in situ, the newly formed foam will substantially reduce subsequent gas fingering and divert subsequent gas flow away from the remaining aqueous foaming solution residing just ahead of the initially formed foam. This phenomenon results in ineffective and inefficient use of the injected foam chemicals and fluids in generating foam. Second, in intermediate and far wellbore locations, there may not be enough mechanical energy and/or differential pressure to generate foam in situ when using common foaming solutions. This is especially of concern for steam, nitrogen, and natural-gas foams.
Krause et al. reported on relatively near-wellbore production-well foam treatments that were applied at the Prudhoe Bay field to reduce excessive GOR emanating from the production of reinjected natural gas. The first treatment involved the injection of the foaming solution into the reservoir, followed by a series of overflushes. It was thought that the subsequent production of gas through the emplaced foaming solution, in a similar manner to the sequential injection mode, would cause the generation of a gas-blocking foam in situ. The second foam gas-blocking treatment involved the sequential injection of the foaming solution and a slug of nitrogen. Neither of these first two foam gas-blocking treatments showed any post-treatment GOR decline. The third foam gas-blocking treatment was a nitrogen foam of 65% quality that was preformed at the surface before injection. This treatment significantly reduced GOR at the treated production well for several weeks. These results suggest that, for many applications of natural-gas and nitrogen conformance-improvement foams, foam injection using the preformed mode, as compared to the sequential injection or coinjection mode, will result in superior performance of the foam within the oil reservoir when conducting "near-wellbore" treatments. Unless compelling arguments for a specific application can be made to the contrary, foams for most applications of near and intermediate wellbore conformance-improvement treatments should be preformed at the surface before injection.
The sequential process, alternately known as the water alternating gas (WAG) process, of injecting sequentially and repeatedly alternating slugs of CO2 and aqueous foaming solution is often favored when using CO2 foam for mobility-control purposes during CO2 flooding. This is because CO2 dissolved in an aqueous surfactant solution forms carbonic acid that is corrosive to steel tubulars. Because of the low surface tension of CO2, foam generation and propagation is much more feasible (than steam, nitrogen, or natural-gas foams) at realistic field pressure gradients that occur throughout the reservoir.
Computer simulation studies have been reported to show that the optimal injection strategy for overcoming gas override during gas-flooding operations is the alternate/sequential injection of separate large slugs of gas and the foaming liquid at the maximum allowable fixed injection pressure. This study was limited to foam injection into a homogeneous reservoir and did not account for any foam interactions with oil. The surfactant-alternating-gas-ameliorated (SAGA) injection mode for forming in situ mobility-control foam has been proposed for use when conducting large-volume WAG flooding projects in North Sea reservoirs.
- Rossen, W.R. 1996. Foams in Enhanced Oil Recovery. Foams—Theory, Measurement, and Applications, R.K. Prud’homme and S.A. Khan ed., 413-464. New York: Marcel Dekker Inc.
- Gauglitz, P.A., Friedmann, F., Kam, S.I. et al. 2002. Foam Generation in Porous Media. Presented at the SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 13-17 April 2002. SPE-75177-MS. http://dx.doi.org/10.2118/75177-MS
- Schramm, L.L. and Wassmuth, F. 1994. Foams: Basic Principles. Foams: Fundamentals and Applications in the Petroleum Industry, L.L. Schramm ed., 3-45. Washington, DC: Advances in Chemistry Series 242, American Chemical Soc.
- Llave, F.M. and Olsen, D.K. 1994. Use of Mixed Surfactants To Generate Foams for Mobility Control in Chemical Flooding. SPE Res Eng 9 (2): 125-132. SPE-20223-PA. http://dx.doi.org/10.2118/20223-PA
- Dalland, M. and Hanssen, J.E. 1999. GOR-Control Foams:Demonstration of Oil-Based Foam Process Efficiency in a Physical Flow Model. Presented at the SPE International Symposium on Oilfield Chemistry, Houston, Texas, 16-19 February 1999. SPE-50755-MS. http://dx.doi.org/10.2118/50755-MS
- Mannhardt, K., Novosad, J.J., and Schramm, L.L. 2000. Comparative Evaluation of Foam Stability to Oil. SPE Res Eval & Eng 3 (1): 23-34. SPE-60686-PA. http://dx.doi.org/10.2118/60686-PA
- Krause, R.E., Lane, R.H., Kuehne, D.L. et al. 1992. Foam Treatment of Producing Wells To Increase Oil Production at Prudhoe Bay. Presented at the SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 22-24 April 1992. SPE-24191-MS. http://dx.doi.org/10.2118/24191-MS
- Shan, D. and Rossen, W.R. 2002. Optimal Injection Strategies for Foam IOR. Presented at the SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 13-17 April 2002. SPE-75180-MS. http://dx.doi.org/10.2118/75180-MS
- Hanssen, J.E. et al. 1995. SAGA Injection: A New Combination IOR Process for Stratified Reservoirs. Geological Society, London, Special Publication. 84: 111-123. http://dx.doi.org/10.1144/GSL.SP.1995.084.01.12
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