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Field applications of conformance improvement foams

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This page discusses field applications of foams for conformance improvement purposes, along with references to the applicable literature. Included are applications of foam for mobility control and for blocking gas.

Foams used during steamflooding

In 1989, Hirasaki[1] reviewed early steam-foam-drive projects. In 1996, Patzek[2] reviewed the performance of seven steam-foam pilots conducted in California. Early and delayed production responses were discussed for these pilots. Gauglitz et al.[3] review a steam-foam trial conducted at the Midway-Sunset field of California.

Foams used during CO2 flooding

The design, results, and analysis of a two-year CO2 foam field trial at the North Ward-Estes field in Texas have been documented.[4] The alternate injection of CO2 and surfactant foaming solution was reported to have reduced injectivities by 40 to 85%. Gas production at an offset problematic production well decreased dramatically, while gas and oil production at the other offset producers increased, indicating favorable areal diversion. CO2 foam application during this field trial was reported to have significantly improved CO2 sweep efficiency and to have been economically successful.

Stephenson et al.[5] reported that a foam bank could only be propagated several meters from the wellbore during an extended foam test at the Joffre Viking miscible CO2 flood in Canada, where the foaming aqueous solution and the CO2 were coinjected.

Hoefner and Evans[6] reviewed four pattern-scale CO2 -foam field trials to determine the technical and economic potential for reducing channeling during CO2 flooding. The field trials involved two different foaming surfactants, alternating and coinjection of the CO2 and the aqueous foaming solution, and two field trials each in a San Andres carbonate reservoir of West Texas and one trial in a platform carbonate formation in southeast Utah. In all, 161,000 lbm of active foaming surfactant were injected, with one of the field trials lasting 18 months. The CO2 foam treatments resulted in reduced CO2 production and indications of increased oil production.

Henry, R.L. et al.[7] reports on a 3,000-reservoir-bbl CO2 foam treatment that was applied to reduce CO2 channeling in the Wasson ODC Unit in Texas. The foam treatment was reported to have been a technical success, but an economic failure. Foam performance was noted to decrease with time and to be a treatment success issue.

Martin, Stevens, and Harpole[8] provides a review of a four-year CO2 foam mobility-control pilot test conducted in a dolomitic carbonate reservoir of the East Vacuum Grayburg/San-Andres Unit in New Mexico. During the CO2 foam pilot, CO2 mobility of the ongoing CO2 water alternating gas (WAG) flooding operation was reduced, incremental oil production was noted at three of the eight offsetting producers, and gas cycling was significantly reduced.

Foam gas-blocking treatments

Eight production wells in Nigeria were treated with foam gas-blocking treatments to reduce gas coning or cusping and to reduce excessive gas/oil ratio (GOR).[9] The producing formation was thin and overlain by a gas gap. The reported set of applied nitrogen foam gas-blocking treatments included the use of polymer-enhanced foams, sequential and coinjection of the gas and foamer solution, and fluorosurfactants. The treatments were designed to place the foam barrier 5 to 10 m radially from the wellbore. A volume of 600 to 800 bbl of foam solution was injected per treatment. The success rate of the foam gas-blocking treatments was reported to be 50+%. Results ranged from significant reductions in GOR that lasted for twelve months (reduced GOR from 7,000 to 2,000 scf/bbl and increased the oil production rate from 340 to 450 BOPD) to minor reductions in GOR that lasted only for a few weeks. The foam treatments were said to be easy to apply and relatively inexpensive. The preliminary conclusion based on this set of foam gas-blocking treatments is that for this type of foam treatment, the sequential injection mode is preferred over the coinjection mode. Four out of six foam gas-blocking treatments that used the polymer-enhanced foam formulas were successful, while neither of the foam gas-blocking treatments using the fluoro-surfactant foam formula were successful.

Surguchev and Hanssen[10] presents a review of the application of two foam gas-blocking treatments that were applied to high GOR problems occurring at production wells in the North Sea. The first foam pilot test was applied to a sandstone formation of a production well in the Oseberg field in the Norwegian North Sea, where the high GOR production problem involved gas coning. The upper producing interval was selectively treated with a strong and “oil-resistant” foam. This Norwegian foam pilot was reported to have been successful (at a minimum, technically successful) and delayed the onset of gas coning by several months.

Foam alkaline-surfactant-polymer flooding

The reported use in China of foamed alkaline-surfactant-polymer (ASP) flooding is noteworthy for several reasons[11]:

  • The field trial of foam flooding in this manner was reported to be both a technical and economic success with the reported economics being quite attractive.
  • Definitive positive reservoir and flooding responses were noted during this foam pilot test. Positive responses included:
    • Substantial incremental oil production
    • Substantial increases in the injection pressure
    • Significantly lower GOR indicating reduced gas mobility, fingering, and channeling
    • Favorable changes in the produced water salinity which indicated improved sweep efficiency
  • Substantial increases in injection pressure occurred during the pilot test.

The implications of the higher injection pressures are three fold:

  • For an older waterflood operation in a mature field, this situation may require installing relatively expensive high-pressure injection equipment, injection lines, and wellheads.
  • Even if the foam should happen to have an effective viscosity identical to water, it will require substantially more horsepower to inject the foam at the same rate as compared to waterflooding because of the lower density and lower wellbore hydrostatic pressure of the foam.
  • If the previous waterflood injection pressure was just below reservoir parting pressure, any increase in injection pressure would require lower injection rates that might pose a possible negative impact on the economics of the project.

On the positive side (although. at first, a foam-ASP flood may appear to be quite complex), if an oil operator is conducting either an ASP or a WAG flood and if the operator has excess natural gas being produced in the field, then flooding in the WAG mode, using the ASP solution as the water phase of the WAG flood, could prove to be relatively easy to implement and relatively attractive if the conformance of the flooding operation could be improved in a similar fashion as reported for the Chinese foam-ASP pilot test.


  1. Hirasaki, G.J. 1989. The Steam-Foam Process. J Pet Technol 41 (5): 449–456. SPE-19505-PA.
  2. Patzek, T.W. 1996. Field Applications of Steam Foam for Mobility Improvement and Profile Control. SPE Res Eng 11 (2): 79–86. SPE-29612-PA.
  3. Gauglitz, P.A., Smith, M.E., Holtzclaw, M.I. et al. 1993. Field Optimization of Steam/Foam for Profile Control: Midway-Sunset 26C. Presented at the SPE International Thermal Operations Symposium, Bakersfield, California, 8-10 February 1993. SPE-25781-MS.
  4. Chou, S.I., Vasicek, S.L., Pisio, D.L. et al. 1992. CO2 Foam Field Trial at North Ward-Estes. Presented at the SPE Annual Technical Conference and Exhibition, Washington, D.C., 4-7 October 1992. SPE-24643-MS.
  5. Stephenson, D.J., Graham, A.G., and Luhning, R.W. 1993. Mobility Control Experience in the Joffre Viking Miscible CO2 Flood. SPE Res Eng 8 (3): 183–188. SPE-23598-PA.
  6. Hoefner, M.L., Evans, E.M., Buckles, J.J. et al. 1995. CO2 Foam: Results From Four Developmental Field Trials. SPE Res Eng 10 (4): 273-281. SPE-27787-PA.
  7. Henry, R.L., Fisher, D.R., Pennell, S.P. et al. 1996. Field Test of Foam to Reduce CO2 Cycling. Presented at the SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 21-24 April 1996. SPE-35402-MS.
  8. Stevens, J.E. 1995. CO2 Foam Field Verification Pilot Test at EVGSAU: Phase IIIB--Project Operations and Performance Review. SPE Res Eng 10 (4): 266-272. SPE-27786-PA.
  9. Chukwueke, V.O., Bouts, M.N., and van Dijkum, C.E. 1998. Gas Shut-Off Foam Treatments. Presented at the SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 19-22 April 1998. SPE-39650-MS.
  10. Surguchev, L.M. and Hanssen, J.E. 1996. Foam Application in North Sea Reservoirs, I: Design and Technical Support of Field Trials. Presented at the SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 21–24 April. SPE-35371-MS.
  11. Demin, W., Jiecheng, C., Qun, L. et al. 2001. First Ultra-Low Interfacial Tension Foam Flood Field Test Is Successful. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 30 September-3 October 2001. SPE-71491-MS.

Noteworthy papers in OnePetro

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External links

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See also


Foams as mobility control agents

Foams as blocking agents

Foam behavior in porous media

Foam properties