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Foam behavior in porous media

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Understanding how foams behave and perform in porous media is critical to the effective application of foams for conformance improvement applications in matrix-rock reservoirs. How foam exists and functions in porous media is not always intuitively obvious on the basis of how foam behaves in bulk form (e.g., when existing in a bottle).


In addition to the properties of bulk foams, which for the most part, are applicable to foam that resides in porous media, there are two specialized properties of foams that reside in porous media.

In general, foams in matrix rock pores do not exist as a continuous interconnected liquid/film structure that contains gas bubbles, as is the case for a bulk foam. Foam in porous media exists as individual gas bubbles that are in direct contact with the wetting fluid of the pore walls. These in-situ microgas bubbles are separated by liquid lamellae that bridge the pore walls and form a liquid partition on the pore scale between the in-situ foam gas bubbles. Foam propagates in most matrix reservoir rock as a bubble train, where each gas bubble is separated from the next gas bubble by a liquid lamellae film. The length of a foam gas bubble in porous media is on the order of, or exceeds, one pore length.[1]

See Foam properties for additional discussion of the nature of foams in porous media. Foam stability and performance in porous media is strongly influenced by lamellae/pore-wall interactions. Foam texture in porous media is believed to most often be controlled by the porous media.

Mobility reduction

Compared with the mobility of the gas phase from which a foam is formulated, the mobility of the resultant foam is dramatically reduced. Often, the mobility of the foam in foam-saturated reservoir matrix rock is less that the mobility of the aqueous phase alone that is used in the foam formula. For a given foam formula, there often is a general trend of decreasing foam mobility with increasing foam quality (gas content) up to the upper foam-quality stability limit.

Foam mobility reduction results from a combination of foam-induced permeability reduction and, on the macro scale, apparent foam-induced viscosity enhancement. Foam-induced mobility reduction is caused by at least two different mechanisms: the formation of, or an increase in, the trapped residual gas saturation; and increased resistance to flow of the gas phase resulting from the drag of propagating the foam-lamellae aqueous films through constricting pore bodies and, especially, through constricted pore throats.

As the texture of a foam becomes finer, the apparent viscosity of the foam increases, and the foam mobility decreases. This occurs because the number of foam lamellae films within a given volume of the porous rock has increased; thus, foam texture is an important variable in determining the amount of mobility reduction that will occur during foam flow.

Rheology, flow, and transport

The apparent viscosity of foam (on the macro scale), as it is being propagated through porous media, frequently exhibits shear-thinning behavior. Such foams on the macro scale are a pseudoplastic fluid in porous media. Foams used in oilfield conformance treatments usually exhibit a yield stress. That is, the shear rate remains zero until a threshold stress and/or pressure gradient is reached, and, thereafter, foam flow begins.

Foam placement and saturation in water-wet reservoir matrix rock with normal permeabilities greatly reduces permeability to subsequent flow of gas. The reduction in gas permeability can be on the order of several hundred-fold. Following such foam placement in matrix reservoir rock, the relative permeability to water has often experienced little change.[2] The substantial selective reduction of the gas permeability has been attributed, in part, to a higher trapped gas saturation than occurred before foam flooding. Such foam trapped gas saturations have been reported to range between 10 and 70% PV, depending on surfactant type and the presence of oil during the foam flood.[2]

It is the drag and the resistance to flow of the lamellae through the pore structure that imparts much of the mobility reduction of foam flow. Fig. 1 shows a schematic drawing of a flowing train of foam gas bubbles and the trapped gas saturation during foam flow through a foam-saturated porous media. Only a small percentage, typically 1 to 15%, of the foam gas saturation actually flows. The stationary portion of the foam blocks gas flow in intermediate and small-sized flow paths and lowers the effective permeability to gas flow. In the flowing portion of the foam, interactions of the foam gas bubbles and the interspaced lamellae determine the effective foam viscosity of the foam that flows in the largest pore flow paths. The resultant effective foam viscosity is most often larger than the effective viscosity of the water when water alone saturates the same flow channels.[2]

The rheology of flowing foam in porous media is controlled by the dynamics of foam generation and decay, in combination with the resulting foam texture and bubble size distribution of the equilibrium in-situ foam.[2] Foam flow in porous media is a complex process that involves a number of interacting microscopic foam events. Macroscopic manifestations of foam flow in porous media are the result of the combination of many pore-scale events that involve foam bubble evolution and foam bubble/lamellae pore-wall interactions during multiphase flow. Fully understanding the macroscopic manifestation of foam flow in porous media requires understanding the pore-level phenomena of foam flow.

Foam lamellae formation during foam flow in porous media results from a combination of three foam-generation mechanisms: snap off, division, and leave behind.[2] The snap-off mechanism is believed to be the dominant foam-generation mechanism during foam flow and transport in porous media.

During foam flow through porous media, foam destruction (decay and coalescence) is primarily brought on by capillary suction and gas diffusion. In certain instances, gravity can also contribute to foam decay when there is a significant density difference between the gas and liquid phases of the foam. The gas diffusion mechanism leads to coursing of the flowing foam and is normally of minor consequence for foam flow in porous media. Capillary suction coalescence is the dominant mechanism for lamellae breakage during foam flow in porous media and is strongly affected by the surfactant used in the foam.[2] If the lamellae of a foam can withstand the imposed capillary suction pressure, such a foam is termed a "strong foam."

Coalescence of flowing foam bubbles in porous media is more complicated than the coalescence of static bulk foam. A limiting capillary pressure, Pc*, exists above which foam coalescence is significant and below which coalescence in minimal. Limiting capillary pressure varies with gas flow rate, absolute permeability, and the surfactant used in the foam. The limiting capillary pressure of flowing foam in porous media is typically on the order of 0.44 psi (3 kPa).[2]

Many foams flowing in matrix sand reservoir rock do so under steady flow at, or near, Pc*. Such foam flow occurs when the gas fractional flow rate is in the high range (i.e., high foam quality) and when the gas and liquid flow rates are fixed. In the Pc* foam-flow regime, the wetting-liquid (usually water) saturation is nearly constant and is independent of gas and liquid velocities over a wide range. This limiting wetting-phase saturation is thought to result from the constant Pc*.[2]

Foam flow in the limiting capillary pressure (Pc*) regime is quite interesting. When the liquid (water) velocity is held constant and the gas velocity is varied, the pressure drop is highly independent of the gas flow rate. Increasing the liquid velocity while holding the gas velocity constant usually results in a linearly increasing pressure drop. Increasing both the liquid and gas velocities, while holding the fractional flow constant, produces a linear response of pressure drop vs. total flow rate. Steady-state liquid and gas saturations are independent of gas fractional flow.[2]

Foam flow in the Pc* regime has a number of important ramifications. Under such foam-flow conditions, the aqueous phase saturation remains constant, as does the relative permeability of the water phase.[2]

However, not all foam flow occurs under the limiting capillary pressure regime. The Pc* regime for foam flow does not necessarily apply for low gas fractional flow (i.e., flow of low-quality foams). Osterloh and Jante[3] studied a wide range of flow rates and fractional flows (foam qualities) for foam flow in a 6,200 md sand pack at 302°F. During their flooding experiments involving a nitrogen foam and an alpha olefin-sulfonate-surfactant foam formula, they observed two foam-flow regimes when varying the foam quality. During flow of foam with foam qualities exceeding 94%, the pressure gradient was quite independent of gas velocity at a fixed liquid velocity and varied with liquid velocity to approximately the 0.33 power. The liquid saturation remained nearly constant. During flow of foam with lower foam qualities (< 94%), the opposite behavior was noted. The pressure gradient increased little with increased liquid velocities, but increased with gas velocity to the 0.31 power. It was suggested that the transition between these two foam flow regimes occurred at the point where the limiting capillary pressure was attained. Subsequently, Alvarez et al.[4] reported on what is described to be a unified model for steady-state foam flow at both high and low foam qualities and a model that helps reconcile apparently contradictory foam flow data for foam flow occurring in reservoir-rock porous media. The unified model is predicated on the contention that, in the high-foam-quality flow regime of Osterloh and Jante, foam flow behavior is dominated by capillary pressure and coalescence and that, in the low-foam-quality flow regime, foam flow behavior is dominated by bubble trapping and mobilization.

Steady-state foam flow refers to foam flow in a given length of porous media after foam has been propagated and formed throughout the entire length of the porous media in question, and the liquid saturation profile is nearly uniform throughout the entire length of the porous media. Transient foam flow in a given length of porous media refers to foam flow as foam is progressively being formed and propagated along the length of the porous media and, as the liquid saturation profile varies from low to high along the length of the porous media, in the direction of flow.

An alternative definition for "strong foam" to the one given previously is based on the continuity of foam within porous media. For a given volume of porous media that contains foam, a "continuous gas foam" exists when there is at least one continuous flow path along the length of the porous media that is uninterrupted by the existence a foam lamellae. A "discontinuous gas foam" exits when there is at least one foam lamellae along all the gas flow paths over the entire length of the porous media volume. Thus, when gas must flow through a discontinuous gas foam in a given porous media, the gas must mobilize and propagate (or possibly rupture) at least one foam lamellae. A strong foam is said to exist when a discontinuous gas foam occurs. A weak foam is said to exist when a continuous gas foam occurs.[1]

Chang and Grigg[5] have studied and reported on the effect of foam quality and flow rate on the imparted mobility reduction resulting from the steady state flow of dense CO2 foam in porous media at reservoir-like temperature and pressure conditions. Over the range of foam qualities normally used in oil reservoirs and for the studied conditions and foam formula, CO2 foam mobility was observed to increase with increasing flow rate and to decrease with increasing foam quality.

Magnetic resonance imaging has been reported to be a useful tool for high-resolution viewing of foam flow in selected porous media.[6]

Foams have been reported to have the very desirable feature, under certain conditions, of being able to reduce mobility to a greater extent in high-permeability porous media, as compared with lower-permeability porous media.[7][8][9][10][11]

Questions persist about the ability to propagate and place foams deep within matrix rock. One aspect of this concern is the often destabilizing effect of oil on foam transport. The next subsection discusses the effect of the presence of oil. Another aspect of this concern is the pressure gradient that is normally required for initiating and maintaining foam flow. Can foam flow be maintained in the far-wellbore regime where pressure gradients are inherently low? [12][13][14]

As a result, in part, of the low surface tension of CO2, CO2 foam is more easily propagated (than nitrogen, steam, and natural-gas foams) at the relatively small pressure gradients that exist in the far-wellbore region of most reservoirs.[1] Gauglitz, et al.[15] reports on laboratory results and literature references indicating that for dense/supercritical CO2 foams, minimum pressure gradients in porous media of less than 1 psi/ft can exist for foam flow when flooding with strong CO2 foams. However, under similar conditions, the minimum pressure gradients for the formation and flow of strong nitrogen foams are reported to be a factor of 20 psi/ft or greater. Viewed conversely, the relatively high minimum pressure gradient for foam flow in many instances can be advantageously used as the basis for foam treatments to block gas flow.

Another important aspect of the problem of deep foam placement is surfactant adsorption/retention (see below).

Effects of oil and wetting

Much has been published on the interaction of crude oil and foam within porous media—with much of this literature discussing negative interactions.[7][14][16][17][18][19][20][21][22][23][24][25][26][27][28][29][30][31][32] When oil contacts a foam, the oil often has a destabilizing effect.[33] The probability that oil will destabilize foams has been a major impediment to the widespread use of foams for oilfield conformance-improvement applications. The destabilizing effects of oil can range from minor to very deleterious. Schramm[17] reviews the mechanisms by which crude oil can destabilize foam in porous media. Foams are more stable in the presence of some crude oils as compared to others. In general, foams are more highly destabilized when contacted with lighter, lower viscosity crude oils.

The degree of sensitivity of foam to oil as foam flows through matrix reservoir rock depends on both the nature of the foam and the nature of the crude oil. Although many conformance-improvement foams are sensitive to oil contact, some foam formulas are quite resistant to destabilization by crude oil.

It has been suggested that even foams sensitive to crude oil can still be effective in matrix reservoir rock if the residual oil saturation is < 10%.[17] On the other hand, oil-sensitive foams will be significantly destabilized by the contact with the crude oil at higher oil saturations (e.g., 20% oil saturation). It has also been suggested that foam sensitivity to oil might be advantageously exploited. That is, by using foams to selectively reduce gas or water mobility in high-gas or water-saturation flow paths within an oil reservoir where the oil saturation is low, while the foam is simultaneously being destabilized and unable to reduce the oil mobility and productivity in the high-oil-saturation flow paths within the reservoir.

The general consensus of several investigators is that oil wetting is detrimental to foam stability and propagation in matrix reservoir rock; however, there is not universal agreement on this point.[1][17][18][19][20]

Surfactant adsorption/retention

The degree of surfactant adsorption/retention often can "make or break" the oil recovery performance and the economics of a foam application. "Retention" is the combination of all other mechanisms, other than adsorption, that retards surfactant propagation during foam propagation through reservoir matrix rock.

Surfactant adsorption/retention under reservoir conditions should be one of the key factors considered and is one of the first parameters that should be examined and/or estimated when considering the application of foam injection for mobility-control purposes during a gas flooding operation.

The use of low-cost adsorption/retention sacrificial agents in the foam or such agents injected before the foam have been proposed as a means to alleviate the adsorption/retention problem.[34] Surfactant adsorption is often lower when foam is transported though an oil-wet reservoir.


  1. 1.0 1.1 1.2 1.3 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.
  2. 2.0 2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8 2.9 Kovscek, A.R. and Radke, C.J. 1994. Fundamentals of Foam Transport in Porous Media. Foams: Fundamentals and Applications in the Petroleum Industry, L.L. Schramm ed., 115-163. Washington, DC: Advances in Chemistry Series 242, American Chemical Soc.
  3. Osterloh, W.T. and Jante Jr., M.J. 1992. Effects of Gas and Liquid Velocity on Steady-State Foam Flow at High Temperature. Presented at the SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, 22–24 April. SPE 24179.
  4. Alvarez, J.M., Rivas, H.J., and Rossen, W.R. 2001. A Unified Model for Steady-State Foam Behavior at High and Low Foam Qualities. SPE J. 6 (3): 325–333. SPE-74141-PA.
  5. Chang, S.-H. and Grigg, R.B. 1999. Effects of Foam Quality and Flow Rate on CO2-foam Behavior at Reservoir Temperature and Pressure. SPE Res Eval & Eng 2 (3): 248–254. SPE-56856-PA.
  6. Wassmuth, F.R., Green, K.A., and Randall, L. 2001. Details of In-Situ Foam Propagation Exposed With Magnetic Resonance Imaging. SPE Res Eval & Eng 4 (2): 135–149. SPE-71300-PA.
  7. 7.0 7.1 Casteel, J.F. and Djabbarah, N.F. 1988. Sweep Improvement in CO2 Flooding by Use of Foaming Agents. SPE Res Eng 3 (4): 1186–1192. SPE-14392-PA.
  8. Llave, F.M., Chung, F.T.-H., Louvier, R.W. et al. 1990. Foams as Mobility Control Agents for Oil Recovery by Gas Displacement. Presented at the SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 22-25 April 1990. SPE-20245-MS.
  9. Tsau, J.-S., Yaghoobi, H., and Grigg, R.B. 1998. Smart Foam to Improve Oil Recovery in Heterogeneous Porous Media. Presented at the SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 19-22 April 1998. SPE-39677-MS.
  10. Tsau, J.-S. and Heller, J.P. 1996. How Can Selective Mobility Reduction of CO2-Foam Assist in Reservoir Floods? Presented at the Permian Basin Oil and Gas Recovery Conference, Midland, Texas, 27-29 March 1996. SPE-35168-MS.
  11. Lee, H.O., Heller, J.P., and Hoefer, A.M.W. 1991. Change in Apparent Viscosity of CO2 Foam With Rock Permeability. SPE Res Eng 6 (4): 421-428. SPE-20194-PA.
  12. Albrecht, R.A. and Marsden, S.S. 1970. Foams as Blocking Agents in Porous Media. SPE J. 10 (1): 51–55. SPE-2357-PA.
  13. Rossen, W.R. 1988. Theories of Foam Mobilization Pressure Gradient. Presented at the SPE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 16-21 April 1988. SPE-17358-MS.
  14. 14.0 14.1 Minssieux, L. 1974. Oil Displacement by Foams in Relation to Their Physical Properties in Porous Media. J Pet Technol 26 (1): 100–108. SPE-3991-PA.
  15. 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.
  16. Hirasaki, G.J. 1989. The Steam-Foam Process. J Pet Technol 41 (5): 449–456. SPE-19505-PA.
  17. 17.0 17.1 17.2 17.3 Schramm, L.L. 1994. Foam Sensitivity to Crude Oil in Porous Media. In Foams: Fundamentals and Applications in the Petroleum Industry, L.L. Schramm ed., 165-197. Washington, DC: Advances in Chemistry Series 242, American Chemical Soc.
  18. 18.0 18.1 Kanda, M. and Schechter, R.S. 1976. On the Mechanism of Foam Formation in Porous Media. Presented at the SPE Annual Fall Technical Conference and Exhibition, New Orleans, Louisiana, 3-6 October 1976. SPE-6200-MS.
  19. 19.0 19.1 Suffridge, F.E., Raterman, K.T., and Russell, G.C. 1989. Foam Performance under Reservoir Conditions. Presented at the Annual Technical Conference and Exhibition, San Antonio, Texas, 8–11 October. SPE-19691-MS.
  20. 20.0 20.1 Sanchez, J.M. and Hazlett, R.D. 1992. Foam Flow Through an Oil-Wet Porous Medium: A Laboratory Study. SPE Res Eng 7 (1): 91-97. SPE-19687-PA.
  21. Raza, S.H. 1970. Foam in Porous Media: Characteristics and Potential Applications. SPEJ (December): 328.
  22. Friedmann, F. and Jensen, J.A. 1986. Some Parameters Influencing the Formation and Propagation of Foams in Porous Media. Presented at the SPE California Regional Meeting, Oakland, California, USA, 2–4 April. SPE-15087-MS.
  23. Jensen, J.A. and Friedmann, J. 1987. Physical and Chemical Effects of an Oil Phase on the Propagation of Foam in Porous Media. Presented at the SPE California Regional Meeting, Ventura, California, 8–10 April. SPE-16375-MS.
  24. Lau, H.C. and O'Brien, S.M. 1988. Effects of Spreading and Nonspreading Oils on Foam Propagation Through Porous Media. SPE Res Eng 3 (3): 893-896. SPE-15668-PA.
  25. Raterman, K.T. 1989. An Investigation of Oil Destabilization of Nitrogen Foams in Porous Media. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-11 October 1989. SPE-19692-MS.
  26. Schramm, L.L. and Novosad, J.J. 1990. Micro-visualization of foam interactions with a crude oil. Colloids Surf. 46 (1): 21-43.
  27. Kuhlman, M.I. 1990. Visualizing the Effect of Light Oil on CO2 Foams. J Pet Technol 42 (7): 902-908. SPE-17356-PA.
  28. Manlowe, D.J. and Radke, C.J. 1990. A Pore-Level Investigation of Foam/Oil Interactions in Porous Media. SPE Res Eng 5 (4): 495–502. SPE-18069-PA.
  29. Hornbrook, J.W., Castanier, L.M., and Pettit, P.A. 1991. Observations of Foam/Oil Interactions in a New High Resolution Micromodel. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 6–9 October. SPE-22631-MS.
  30. Kristiansen, T.S. and Holt, T. 1992. Properties of Flowing Foam in Porous Media Containing Oil. Presented at the SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 22–24 April. SPE-24182-MS.
  31. Law, D.H.-S., Yang, Z.-M., and Stone, T.W. 1992. Effect of the Presence of Oil on Foam Performance: A Field Simulation Study. SPE Res Eng 7 (2): 228–236. SPE-18421-PA.
  32. Hamida, F.M. et al. 1992. Further Characterization of Surfactants as Steamflood Additives. In Situ 16 (2): 137.
  33. 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.
  34. Tsau, J.-S., Syahputra, A.E., and Grigg, R.B. 2000. Economic Evaluation of Surfactant Adsorption in CO2 Foam Application. Presented at the SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 3-5 April 2000. SPE-59365-MS.

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See also

Fluid flow through permeable media

Foams as mobility control agents

Foams as blocking agents


Foam properties

Field applications of conformance improvement foams