Effect of pressure, temperature, and solution gas on oil recovery from surfactant polymer floods

M. Roshanfekr, Russell Taylor Johns, G. Pope, L. Britton, H. Linnemeyer, C. Britton, A. Vyssotski

Research output: Chapter in Book/Report/Conference proceedingConference contribution

26 Citations (Scopus)

Abstract

Surfactant-polymer (SP) and alkali-surfactant-polymer (ASP) flooding is of great current interest owing to the need to recover oil left behind after primary and secondary recovery. If designed properly, these enhanced oil recovery processes can give very high oil recoveries. Microemulsion phase behavior plays a central role in process performance and is typically measured by doing salinity scans in glass pipettes at atmospheric pressure and reservoir temperature using dead crude oil from the reservoir of interest. There have been only a few experiments reported in the literature on live oil at reservoir pressure and temperature and the importance of those experimental results are conflicting. This paper investigates the effect of pressure, temperature, and solution gas on microemulsion phase behavior and its impact on oil recovery. We examine previous data reported in the literature, and report new measurements with live oil to show that the optimum parameters can change significantly. The experiments show that while pressure induces a phase transition from upper microemulsion (Winsor type 11+) to lower microemulsion (Winsor type II-), solution gas does the opposite. An increase in pressure decreases the optimum solubilization ratio and shifts the optimum salinity to a larger value. Adding methane to dead oil at constant pressure does the reverse. Thus, these effects are coupled and both must be taken into account. We derive a new thermodynamic model to explain why the logarithm of oil and water solubilization ratios is linear with pressure or inverse temperature. We also use a numerical simulator to show how to design the chemical processes to account for phase behavior shifts with pressure and solution gas to achieve good oil recovery.

Original languageEnglish (US)
Title of host publicationSociety of Petroleum Engineers - SPE Annual Technical Conference and Exhibition 2009, ATCE 2009
Pages4398-4412
Number of pages15
StatePublished - Dec 1 2009
EventSPE Annual Technical Conference and Exhibition 2009, ATCE 2009 - New Orleans, LA, United States
Duration: Oct 4 2009Oct 7 2009

Publication series

NameProceedings - SPE Annual Technical Conference and Exhibition
Volume7

Other

OtherSPE Annual Technical Conference and Exhibition 2009, ATCE 2009
CountryUnited States
CityNew Orleans, LA
Period10/4/0910/7/09

Fingerprint

Surface active agents
Recovery
Polymers
Gases
Microemulsions
Phase behavior
Temperature
Petroleum reservoirs
Secondary recovery
Oils
Atmospheric pressure
Methane
Crude oil
Simulators
Phase transitions
Experiments
Thermodynamics
Glass
Water

All Science Journal Classification (ASJC) codes

  • Fuel Technology
  • Energy Engineering and Power Technology

Cite this

Roshanfekr, M., Johns, R. T., Pope, G., Britton, L., Linnemeyer, H., Britton, C., & Vyssotski, A. (2009). Effect of pressure, temperature, and solution gas on oil recovery from surfactant polymer floods. In Society of Petroleum Engineers - SPE Annual Technical Conference and Exhibition 2009, ATCE 2009 (pp. 4398-4412). (Proceedings - SPE Annual Technical Conference and Exhibition; Vol. 7).
Roshanfekr, M. ; Johns, Russell Taylor ; Pope, G. ; Britton, L. ; Linnemeyer, H. ; Britton, C. ; Vyssotski, A. / Effect of pressure, temperature, and solution gas on oil recovery from surfactant polymer floods. Society of Petroleum Engineers - SPE Annual Technical Conference and Exhibition 2009, ATCE 2009. 2009. pp. 4398-4412 (Proceedings - SPE Annual Technical Conference and Exhibition).
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abstract = "Surfactant-polymer (SP) and alkali-surfactant-polymer (ASP) flooding is of great current interest owing to the need to recover oil left behind after primary and secondary recovery. If designed properly, these enhanced oil recovery processes can give very high oil recoveries. Microemulsion phase behavior plays a central role in process performance and is typically measured by doing salinity scans in glass pipettes at atmospheric pressure and reservoir temperature using dead crude oil from the reservoir of interest. There have been only a few experiments reported in the literature on live oil at reservoir pressure and temperature and the importance of those experimental results are conflicting. This paper investigates the effect of pressure, temperature, and solution gas on microemulsion phase behavior and its impact on oil recovery. We examine previous data reported in the literature, and report new measurements with live oil to show that the optimum parameters can change significantly. The experiments show that while pressure induces a phase transition from upper microemulsion (Winsor type 11+) to lower microemulsion (Winsor type II-), solution gas does the opposite. An increase in pressure decreases the optimum solubilization ratio and shifts the optimum salinity to a larger value. Adding methane to dead oil at constant pressure does the reverse. Thus, these effects are coupled and both must be taken into account. We derive a new thermodynamic model to explain why the logarithm of oil and water solubilization ratios is linear with pressure or inverse temperature. We also use a numerical simulator to show how to design the chemical processes to account for phase behavior shifts with pressure and solution gas to achieve good oil recovery.",
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Roshanfekr, M, Johns, RT, Pope, G, Britton, L, Linnemeyer, H, Britton, C & Vyssotski, A 2009, Effect of pressure, temperature, and solution gas on oil recovery from surfactant polymer floods. in Society of Petroleum Engineers - SPE Annual Technical Conference and Exhibition 2009, ATCE 2009. Proceedings - SPE Annual Technical Conference and Exhibition, vol. 7, pp. 4398-4412, SPE Annual Technical Conference and Exhibition 2009, ATCE 2009, New Orleans, LA, United States, 10/4/09.

Effect of pressure, temperature, and solution gas on oil recovery from surfactant polymer floods. / Roshanfekr, M.; Johns, Russell Taylor; Pope, G.; Britton, L.; Linnemeyer, H.; Britton, C.; Vyssotski, A.

Society of Petroleum Engineers - SPE Annual Technical Conference and Exhibition 2009, ATCE 2009. 2009. p. 4398-4412 (Proceedings - SPE Annual Technical Conference and Exhibition; Vol. 7).

Research output: Chapter in Book/Report/Conference proceedingConference contribution

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AU - Roshanfekr, M.

AU - Johns, Russell Taylor

AU - Pope, G.

AU - Britton, L.

AU - Linnemeyer, H.

AU - Britton, C.

AU - Vyssotski, A.

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N2 - Surfactant-polymer (SP) and alkali-surfactant-polymer (ASP) flooding is of great current interest owing to the need to recover oil left behind after primary and secondary recovery. If designed properly, these enhanced oil recovery processes can give very high oil recoveries. Microemulsion phase behavior plays a central role in process performance and is typically measured by doing salinity scans in glass pipettes at atmospheric pressure and reservoir temperature using dead crude oil from the reservoir of interest. There have been only a few experiments reported in the literature on live oil at reservoir pressure and temperature and the importance of those experimental results are conflicting. This paper investigates the effect of pressure, temperature, and solution gas on microemulsion phase behavior and its impact on oil recovery. We examine previous data reported in the literature, and report new measurements with live oil to show that the optimum parameters can change significantly. The experiments show that while pressure induces a phase transition from upper microemulsion (Winsor type 11+) to lower microemulsion (Winsor type II-), solution gas does the opposite. An increase in pressure decreases the optimum solubilization ratio and shifts the optimum salinity to a larger value. Adding methane to dead oil at constant pressure does the reverse. Thus, these effects are coupled and both must be taken into account. We derive a new thermodynamic model to explain why the logarithm of oil and water solubilization ratios is linear with pressure or inverse temperature. We also use a numerical simulator to show how to design the chemical processes to account for phase behavior shifts with pressure and solution gas to achieve good oil recovery.

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M3 - Conference contribution

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Roshanfekr M, Johns RT, Pope G, Britton L, Linnemeyer H, Britton C et al. Effect of pressure, temperature, and solution gas on oil recovery from surfactant polymer floods. In Society of Petroleum Engineers - SPE Annual Technical Conference and Exhibition 2009, ATCE 2009. 2009. p. 4398-4412. (Proceedings - SPE Annual Technical Conference and Exhibition).