PEH:Polymers, Gels, Foams, and Resins: Difference between revisions

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.<ref name="r145">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.</ref> 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.<br/><br/>Foam lamellae formation during foam flow in porous media results from a combination of three foam-generation mechanisms: snap off, division, and leave behind.<ref name="r145">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.</ref> The snap-off mechanism is believed to be the dominant foam-generation mechanism during foam flow and transport in porous media.<br/><br/>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.<ref name="r145">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.</ref> If the lamellae of a foam can withstand the imposed capillary suction pressure, such a foam is termed a "strong foam."<br/><br/>Coalescence of flowing foam bubbles in porous media is more complicated than the coalescence of static bulk foam. A limiting capillary pressure, ''P''_''c''*, 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).<ref name="r145">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.</ref><br/><br/>Many foams flowing in matrix sand-reservoir rock do so under steady flow at, or near, ''P''_''c''*. 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 ''P''_''c''* 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 ''P''_''c''*.<ref name="r145">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.</ref><br/><br/>Foam flow in the limiting capillary pressure (''P''_''c''*) 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.<ref name="r145">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.</ref><br/><br/>Foam flow in the ''P''_''c''* 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.<ref name="r145">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.</ref><br/><br/>However, not all foam flow occurs under the limiting-capillary-pressure regime. The ''P''_''c''* regime for foam flow does not necessarily apply for low gas fractional flow (i.e., flow of low-quality foams). Osterloh and Jante<ref name="r146">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. http://dx.doi.org/10.2118/24179-MS.</ref> 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.''<ref name="r147">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. http://dx.doi.org/10.2118/74141-PA.</ref> 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.<br/><br/>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.<br/><br/>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.<ref name="r139">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.</ref><br/><br/>Chang and Grigg<ref name="r148">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. http://dx.doi.org/10.2118/56856-PA.</ref> 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.<br/><br/>Magnetic resonance imaging has been reported to be a useful tool for high-resolution viewing of foam flow in selected porous media.<ref name="r149">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. http://dx.doi.org/10.2118/71300-PA.</ref><br/><br/>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.<ref name="r150">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. http://dx.doi.org/10.2118/14392-PA.</ref><ref name="r151">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. http://dx.doi.org/10.2118/20245-MS.</ref><ref name="r152">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. http://dx.doi.org/10.2118/39677-MS</ref><ref name="r153">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. http://dx.doi.org/10.2118/35168-MS.</ref><ref name="r154">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. http://dx.doi.org/10.2118/20194-PA.</ref><br/><br/>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? <ref name="r155">Albrecht, R.A. and Marsden, S.S. 1970. Foams as Blocking Agents in Porous Media. SPE J. 10 (1): 51–55. SPE-2357-PA. http://dx.doi.org/10.2118/2357-PA.</ref><ref name="r156">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. http://dx.doi.org/10.2118/17358-MS.</ref><ref name="r157">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. http://dx.doi.org/10.2118/3991-PA.</ref><br/><br/>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.<ref name="r139">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.</ref> Gauglitz, ''et al.''<ref name="r140">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.</ref> 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.<br/><br/>Another important aspect of the problem of deep foam placement is surfactant adsorption/retention. The upcoming subsection Surfactant Adsorption/Retention discusses adsorption and retention of surfactant during foam transport through matrix reservoir rock.<br/><br/>''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.<ref name="r150">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. http://dx.doi.org/10.2118/14392-PA.</ref><ref name="r157">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. http://dx.doi.org/10.2118/3991-PA.</ref><ref name="r158">Hirasaki, G.J. 1989. The Steam-Foam Process. J Pet Technol 41 (5): 449–456. SPE-19505-PA. http://dx.doi.org/10.2118/19505-PA.</ref><ref name="r159">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.</ref><ref name="r160">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. http://dx.doi.org/10.2118/6200-MS.</ref><ref name="r161">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. http://dx.doi.org/10.2118/19691-MS.</ref><ref name="r162">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. http://dx.doi.org/10.2118/19687-PA</ref><ref name="r163">Raza, S.H. 1970. Foam in Porous Media: Characteristics and Potential Applications. SPEJ (December): 328.</ref><ref name="r164">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. http://dx.doi.org/10.2118/15087-MS.</ref><ref name="r165">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. http://dx.doi.org/10.2118/16375-MS.</ref><ref name="r166">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. http://dx.doi.org/10.2118/15668-PA.</ref><ref name="r167">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. http://dx.doi.org/10.2118/19692-MS.</ref><ref name="r168">Schramm, L.L. and Novosad, J.J. 1990. Micro-visualization of foam interactions with a crude oil. Colloids Surf. 46 (1): 21-43. http://dx.doi.org/http://dx.doi.org/10.1016/0166-6622(90)80046-7.</ref><ref name="r169">Kuhlman, M.I. 1990. Visualizing the Effect of Light Oil on CO2 Foams. J Pet Technol 42 (7): 902-908. SPE-17356-PA. http://dx.doi.org/10.2118/17356-PA.</ref><ref name="r170">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. http://dx.doi.org/10.2118/18069-PA.fckLR</ref><ref name="r171">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. http://dx.doi.org/10.2118/22631-MS.</ref><ref name="r172">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. http://dx.doi.org/10.2118/24182-MS.</ref><ref name="r173">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. http://dx.doi.org/10.2118/18421-PA.</ref><ref name="r174">Hamida, F.M. et al. 1992. Further Characterization of Surfactants as Steamflood Additives. In Situ 16 (2): 137.</ref> When oil contacts a foam, the oil often has a destabilizing effect.<ref name="r141">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.</ref> 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<ref name="r159">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.</ref> 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.<br/><br/>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.<br/><br/>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%.<ref name="r159">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.</ref> 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.<br/><br/>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.<ref name="r139">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.</ref><ref name="r159">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.</ref><ref name="r160">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. http://dx.doi.org/10.2118/6200-MS.</ref><ref name="r161">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. http://dx.doi.org/10.2118/19691-MS.</ref><ref name="r162">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. http://dx.doi.org/10.2118/19687-PA</ref><br/><br/>''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.<br/><br/>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.<br/><br/>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.<ref name="r175">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. http://dx.doi.org/10.2118/59365-MS.</ref> Surfactant adsorption is often lower when foam is transported though an oil-wet reservoir.<br/><br/>'''''Injection Mode.''''' One of three distinctly different modes is used for injecting conformance-improvement foams: sequential injection, coinjection, or 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. Coinjection involves the coinjection 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 coinjection mode. Also, sequential-injection and coinjection 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.<br/><br/>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.<br/><br/>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.<br/><br/>Krause ''et al.''<ref name="r176">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.</ref> 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.<br/><br/>The sequential process, alternately known as the 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.<ref name="r139">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.</ref><br/><br/>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.<ref name="r177">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.</ref> 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.<ref name="r178">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.</ref>

Conversion factor is exact.</div></div>[[Category:PEH]] [[Category:Volume V – Reservoir Engineering and Petrophysics]]  [[Category:5.4.5 Conformance improvement]]