1887

Abstract

Summary

Low-Tension Gas (LTG) process has been studied for sandstone reservoirs. In the prior publication ( ), LTG was successfully used to achieve high oil recoveries with the proposed surfactant formulation and injection strategy. Sensitivity to change in optimum salinity was also investigated. However, some questions remained, particularly linked to the sudden drop of effluent salinity and the consequential oil recovery under Type I conditions. In this work, in-depth experimental investigations are carried out to understand the underlying mechanisms. Surfactant flooding without presence of gas is conducted to establish the incremental impact of the microemulsion on oil recovery and pressure drop. Constant salinity core flood experiments were carried out under Winsor Type I conditions at varying capillary numbers to examine the desaturation efficiency. Dynamic foamability tests were carried in the absence of oil to probe the foamability of the developed formula and the contribution of alkyl polyether sulfonate (APS). Effluent salinity when injecting brine only was compared with the case where both brine and gas are co-injected to better understand the role of gas. Further, the importance of foam in the drive was evaluated by conducting LTG without the foaming surfactant in the drive. The dynamic foam tests showed good foamability with the proposed formulation, presence of APS in the surfactant formulation further enhanced the foamability. Surfactant flooding without gas resulted in only 30% remaining oil recovery. Constant salinity coreflood confirmed that the oil recoveries observed under Type I conditions in LTG process indeed can be achieved at the prevailing capillary numbers. The effluent salinity comparison between brine only and brine/gas injections showed significant impact of gas on salinity distribution in the core. Much lower oil recovery was observed and the salinity propagation was delayed when no foaming agent was used in the drive. This implies that foam mobility control is critical for the success of LTG process. It is the first time that in-depth experimental studies were conducted for the LTG process. It improves the interpretation of the findings in prior work, and provides the guidance to the future experimental and theoretical studies.

Loading

Article metrics loading...

/content/papers/10.3997/2214-4609.201900067
2019-04-08
2020-03-29
Loading full text...

Full text loading...

References

  1. Adkins, S., Pinnawala Arachchilage, G. W. P., Solairaj, S., Lu, J., Weerasooriya, U., & Pope, G. A.
    (2012, January1). Development of Thermally and Chemically Stable Large-Hydrophobe Alkoxy Carboxylate Surfactants. Society of Petroleum Engineers. doi:10.2118/154256‑MS
    https://doi.org/10.2118/154256-MS
  2. Baviere, M., Glenat, P., Plazanet, V., & Labrid, J.
    (1995, August1). Improvement of the Efficiency/Cost Ratio of Chemical EOR Processes by Using Surfactants, Polymers, and Alkalis in Combination. Society of Petroleum Engineers. doi:10.2118/27821‑PA
    https://doi.org/10.2118/27821-PA [Google Scholar]
  3. Bear, J.
    1972. Dynamics of flows in porous media. P579–663. Dover, NY.
    [Google Scholar]
  4. Bernard, G. G., & Jacobs, W. L.
    (1965, December1). Effect of Foam on Trapped Gas Saturation and on Permeability of Porous Media to Water. Society of Petroleum Engineers. doi:10.2118/1204‑PA
    https://doi.org/10.2118/1204-PA [Google Scholar]
  5. Bian, Y., Penny, G. S., & Sheppard, N. C.
    (2012, January1). Surfactant Formulation Evaluation for Carbon Dioxide Foam Flooding in Heterogeneous Sandstone Reservoir. Society of Petroleum Engineers. doi:10.2118/154018‑MS
    https://doi.org/10.2118/154018-MS [Google Scholar]
  6. BondDC, HolbrookCC
    . Gas drive oil recovery process. U.S. Patent. No. 2866507, December, 1958.
    [Google Scholar]
  7. Cao, R., Yang, H., Sun, W., Ma, T.Z.
    A new laboratory study on alternate injection of high strength foam and ultra-low interfacial tension foam to enhance oil recovery. Journal of Petroleum Science and Engineering125 (2015) 75–89.
    [Google Scholar]
  8. Chevallier, E., Tchamba, O., Chabert, M., Bekri, S., Martin, F., & Gautier, S.
    (2015, August11). Foams with Ultra-Low Interfacial Tensions for an Efficient EOR Process in Fractured Reservoirs. Society of Petroleum Engineers. doi:10.2118/174658‑MS
    https://doi.org/10.2118/174658-MS [Google Scholar]
  9. Chevallier, E., Chabert, M., Gautier, S., Ghafram, H., Khaburi, S., & Alkindi, A.
    (2018, March26). Design of a Combined Foam EOR Process for a Naturally Fractured Reservoir. Society of Petroleum Engineers. doi:10.2118/190363‑MS
    https://doi.org/10.2118/190363-MS [Google Scholar]
  10. Das, A., Nguyen, N., Alkindi, A., Farajzadeh, R., Azri, N., Southwick, J., … Nguyen, Q. P.
    (2016, March21). Low Tension Gas Process in High Salinity and Low Permeability Reservoirs. Society of Petroleum Engineers. doi:10.2118/179839‑MS
    https://doi.org/10.2118/179839-MS [Google Scholar]
  11. Das, A., Nguyen, N., Farajzadeh, R., Southwick, J. G., Vicent-Bonnieu, S., Khaburi, S., … Nguyen, Q. P.
    (2018, March26). Laboratory Study of Injection Strategy for Low-Tension-Gas Flooding in High Salinity, Tight Carbonate Reservoirs. Society of Petroleum Engineers. doi:10.2118/190348‑MS
    https://doi.org/10.2118/190348-MS [Google Scholar]
  12. Delshad, M., Delshad, M., Pope, G. A., & Lake, L. W.
    (1987, September1). Two- and Three-Phase Relative Permeabilities of Micellar Fluids. Society of Petroleum Engineers. doi:10.2118/13581‑PA
    https://doi.org/10.2118/13581-PA [Google Scholar]
  13. Dong, P., Puerto, M., Ma, K., Mateen, K., Ren, G., Bourdarot, G., … Hirasaki, G.
    (2017, April3). Low-Interfacial-Tension Foaming System for Enhanced Oil Recovery in Highly Heterogeneous/Fractured Carbonate Reservoirs. Society of Petroleum Engineers. doi:10.2118/184569‑MS
    https://doi.org/10.2118/184569-MS [Google Scholar]
  14. (2018a, April14). Ultralow-Interfacial-Tension Foam Injection Strategy Investigation in High Temperature Ultra-High Salinity Fractured Carbonate Reservoirs. Society of Petroleum Engineers. doi:10.2118/190259‑MS
    https://doi.org/10.2118/190259-MS [Google Scholar]
  15. Dong, P., Puerto, M., Jian, G., Ma, K., Mateen, K., Ren, G., … Hirasaki, G.
    (2018b, September24). Exploring Low-IFT Foam EOR in Fractured Carbonates: Success and Particular Challenges of Sub-10-mD Limestone. Society of Petroleum Engineers. doi:10.2118/191725‑MS
    https://doi.org/10.2118/191725-MS [Google Scholar]
  16. Flaaten, A. K., Nguyen, Q. P., Zhang, J., Mohammadi, H., & Pope, G. A.
    (2010, March1). Alkaline/Surfactant/Polymer Chemical Flooding Without the Need for Soft Water. Society of Petroleum Engineers. doi:10.2118/116754‑PA
    https://doi.org/10.2118/116754-PA [Google Scholar]
  17. Garrett R.Peter
    , 2014. The Science of Defoaming - Theory, Experiment and Applications. Surfacing Science Series Volume 155, Taylor & Francis Group.
    [Google Scholar]
  18. Glover, C. J., Puerto, M. C., Maerker, J. M., & Sandvik, E. L.
    (1979, June1). Surfactant Phase Behavior and Retention in Porous Media. Society of Petroleum Engineers. doi:10.2118/7053‑PA
    https://doi.org/10.2118/7053-PA [Google Scholar]
  19. Hahn, R., Spilker, K., Alexis, D., Linnemeyer, H., Malik, T., & Dwarakanath, V.
    (2018, September24). Low Tension Foam Flooding for Chemical Enhanced Oil Recovery in Heterogeneous Systems. Society of Petroleum Engineers. doi:10.2118/191706‑MS
    https://doi.org/10.2118/191706-MS [Google Scholar]
  20. Hirasaki, G. J., van Domselaar, H. R., & Nelson, R. C.
    (1983, June1). Evaluation of the Salinity Gradient Concept in Surfactant Flooding. Society of Petroleum Engineers. doi:10.2118/8825‑PA
    https://doi.org/10.2118/8825-PA [Google Scholar]
  21. Hirasaki, G., Miller, C. A., & Puerto, M.
    (2011, December1). Recent Advances in Surfactant EOR. Society of Petroleum Engineers. sdoi:10.2118/115386‑PA
    https://doi.org/10.2118/115386-PA [Google Scholar]
  22. Huh, C.
    Interfacial Tensions and Solubilizing Ability of a Microemulsion Phase That coexists with Oil and Brine. Journal of Colloid interface Science, Vol. 71, No 2, September1979.
    [Google Scholar]
  23. Jimenez, A.I. and Radke, C.J.
    Dynamic Stability of Foam Lamellae Flowing Through a Periodically Constricted Pore. (1989). Chapter 25 in Oil-Field Chemistry. ACS Symposium Series: American Chemical Society: Washingron, DC.
    [Google Scholar]
  24. Jong, S., Nguyen, N. M., Eberle, C. M., Nghiem, L. X., & Nguyen, Q. P.s
    (2016, April11). Low Tension Gas Flooding as a Novel EOR Method: An Experimental and Theoretical Investigation. Society of Petroleum Engineers. doi:10.2118/179559‑MS
    https://doi.org/10.2118/179559-MS [Google Scholar]
  25. Jong, S.Y., Nguyen, Q.P.
    Effect pf microemulsion on foam stability. Applied Nanoscience (2018) 8:231–239.
    [Google Scholar]
  26. Kamal, M., & Marsden, S. S.
    (1973, January1). Displacement of a Micellar Slug Foam in Unconsolidated Porous Media. Society of Petroleum Engineers. doi:10.2118/4584‑MS
    https://doi.org/10.2118/4584-MS [Google Scholar]
  27. LakeLW.
    Enhanced oil recovery. New York: Prentice Hall. 1989.
    [Google Scholar]
  28. Lawson, J. B.
    (1978, January1). The Adsorption Of Non-Ionic And Anionic Surfactants On Sandstone And Carbonate. Society of Petroleum Engineers. doi:10.2118/7052‑MS
    https://doi.org/10.2118/7052-MS [Google Scholar]
  29. Lawson, J. B., & Reisberg, J.
    (1980, January1). Alternate Slugs Of Gas And Dilute Surfactant For Mobility Control During Chemical Flooding. Society of Petroleum Engineers. doi:10.2118/8839‑MS
    https://doi.org/10.2118/8839-MS [Google Scholar]
  30. M’barki, O., Ma, K., Ren, G., Mateen, K., Bourdarot, G., Morel, D. C., & Nguyen, Q. P.
    (2017, October9). Repeatable Steady-State Foam Experimental Data and Investigations of Foam Hysteresis in a Sand Pack. Society of Petroleum Engineers. doi:10.2118/187084‑MS
    https://doi.org/10.2118/187084-MS [Google Scholar]
  31. Nelson, R. C., & Pope, G. A.
    (1978, October1). Phase Relationships in Chemical Flooding. Society of Petroleum Engineers. doi:10.2118/6773‑PA
    https://doi.org/10.2118/6773-PA [Google Scholar]
  32. Nemeth, Z., Racz, G., Koczo, K.
    Foam Control bby Silicon Polyethers-Mechanims of “Cloud Point Antifoaming”. Journal of Colloid and Interface Science207, 386–394 (1998).
    [Google Scholar]
  33. Nguyen, N., Ren, G., Mateen, K., Cordelier, P. R., Morel, D. C., & Nguyen, Q. P.
    (2015, August11). Low-Tension Gas (LTG) Injection Strategy in High Salinity and High Temperature Sandstone Reservoirs. Society of Petroleum Engineers. doi:10.2118/174690‑MS
    https://doi.org/10.2118/174690-MS [Google Scholar]
  34. Novosad, J.
    (1982, December1). Surfactant Retention in Berea Sandstone- Effects of Phase Behavior and Temperature. Society of Petroleum Engineers. doi:10.2118/10064‑PA
    https://doi.org/10.2118/10064-PA [Google Scholar]
  35. Osei-Bonsu, Kofi, Grassia, Paul, Shokri, Nima
    , 2017. Relationship between bulk foam stability, surfactant formulation and oil displacement efficiency in porous media. Fuel203, 403–410.
    [Google Scholar]
  36. Pavan C.Paulo, Crepaldi L.Eduardo, Gomes de A.Gilmar, Valim B.Joao
    . Adsorption of sodium dodecylsulfate on a hydrotalcite-like compound. Effect of temperature, pH and ionic strength. Colloids and Surfaces A: Physicochemical and Engineering Aspects154 (1999) 399–410.
    [Google Scholar]
  37. Princen, H.M., Goddard, E.D.
    The Effect of Mineral Oil on Surface Properties of Binary Surfactant Systems. Journal of Colloid and Interface Science, Vol. 38, No.2, February1972.
    [Google Scholar]
  38. RenG., NguyenP. Q.
    , 2017. Understanding of Aqueous Foam with Novel CO2 Soluble Surfactants for Controlling CO2 Vertical Sweep in Sandstone Reservoirs. Pet. Sci. (2017) 14:330–361. DOI 10.1007/s12182‑0170149‑2
    https://doi.org/10.1007/s12182-0170149-2 [Google Scholar]
  39. RossenWR
    . Foams in enhanced oil recovery. In: Prud’hommeRK, KhanSA. eds. Foams: theory, measurements and applications. New York: Marcel Dekker, 1996.
    [Google Scholar]
  40. Seong-GeunOh, Shah, D.O.
    Relationship between Micellar Lifetime and Foamability of Sodium Dodecyl Sulfate and Sodium Dodecyl Sulfate/1-Hexanol Mixtures. Langmuir1991, 7, 1316–1318.
    [Google Scholar]
  41. Strey, R.
    (1994). Microemulsion microstructure and interfacial curvature. Colloid & Polymer Science, 272 (8), 1005–1019.
    [Google Scholar]
  42. Tang, S., Tian, L., Lu, J., Wang, Z., Xie, Y., Yang, X., & Lei, X.
    (2014, April12). A Novel Low Tension Foam Flooding for Improving Post-Chemical-Flood in Shuanghe Oilfield. Society of Petroleum Engineers. doi:10.2118/169074‑MS
    https://doi.org/10.2118/169074-MS [Google Scholar]
  43. Tennouga, L., Mansri, A., Chetouani, A., Warad, I.
    The micelle formation of cationic and anionic surfactants in aqueous medium: Determination of CMC and thermodynamic parameters at different temperatures. J. Mater. Environ. Sci.6 (10) (2015) 2711–2716.
    [Google Scholar]
  44. Torres, R., Podzimek, M., Friberg, S.E.
    Foaming of microemulsions I. Microemulsions with ionic surfactants. Colloid & Polymer Sci.258, 855–863 (1980).
    [Google Scholar]
  45. Winsor, P.A.
    1954. Solvent Properties of Amphiphilic Compounds. Butterworths Scientific Publications. London.
    [Google Scholar]
http://instance.metastore.ingenta.com/content/papers/10.3997/2214-4609.201900067
Loading
/content/papers/10.3997/2214-4609.201900067
Loading

Data & Media loading...

This is a required field
Please enter a valid email address
Approval was a Success
Invalid data
An Error Occurred
Approval was partially successful, following selected items could not be processed due to error