화학공학소재연구정보센터
홈 로그인 로그아웃 연락처 사이트맵
Korean Journal of Chemical Engineering, Vol.37, No.12, 2124-2135, December, 2020
DOI10.1007/s11814-020-0645-8  Export Citation
A multiscale study on the effects of dynamic capillary pressure in two-phase flow in porous media
Jassem Abbasi1, 2, Mojtaba Ghaedi1, 3, †, and Masoud Riazi1
  • 1Department of Petroleum Engineering, School of Chemical and Petroleum Engineering, Shiraz University, Shiraz, Iran
  • 2Zodan Solutions Ltd., London, United Kingdom, Iran
  • 3Reservoir Modeling and Simulation Centre, School of Chemical and Petroleum Engineering, Shiraz University, Shiraz, Iran
E-mail:
Capillary pressure is usually considered as a function of the rock and fluid properties, and saturation. However, recent studies have shown that capillary forces also are a function of the rate of change of saturation. Moreover, although it was observed that dynamic forces are highly scale dependent, the role of these effects in large-scale flow practices is still unclear. In this study, using an innovative numerical simulation approach, the impact of the mentioned parameters was studied in a highly heterogeneous oil reservoir that is under waterflooding process. It is observed that the role of dynamic capillary pressure, using routinely measured dynamic capillary coefficient values, is not important in large-scale problems. However, it would be important in the higher capillary coefficient values that are several orders of magnitude larger than the values reported in previous experimental studies. Furthermore, the role of rock heterogeneity is discussed and it is shown that neglecting the dynamic capillary effects in heterogeneous media may lead to misleading results in the prediction of the injection front behavior in the reservoir. The dynamic capillary effects, by lowering the imbibition capillary pressure in the front, leads to more frontal movement of the injection fluid. Also, it is shown that the dynamic effects are more sensible at points close to the injection wells in homogenous reservoirs, but, in the heterogenous models it is more dependent on rock properties than the distance from the injection wells.
Keywords:Dynamic Capillary Pressure;Dynamic Capillary Coefficient;Capillary Number;Waterflooding
  1. Rahman MK, Chen ZX, Rahman SS, J. Energy Resour. Technol.-Trans. ASME, 125(3), 169 (2003)
  2. Bear J, Modeling phenomena of flow and transport in porous media, Vol. 31, Springer, New York (2018).
  3. Abbasi J, Riazi M, Ghaedi M, Mirzaei-Paiaman A, J. Pet. Sci. Eng., 150, 108 (2017)
  4. John RF, Principles of applied reservoir simulation, Elsevier, Netherland (2001).
  5. Fan Z, Yang D, Chai D, Li X, J. Energy Resour. Technol., 141, 2 (2018)
  6. Zhang M, Ayala LF, J. Energy Resour. Technol., 142, 4 (2019)
  7. Das DB, Hassanizadeh SM, Upscaling multiphase flow in porous media, Springer, Berlin (2005).
  8. Bottero S, Experimental study of dynamic capillary pressure effect in two-phase flow in porous media, Copenhagen, Denmark (2006).
  9. Das DB, Mirzaei M, AIChE J., 58(12), 3891 (2012)
  10. Mirzaei M, Das DB, Chem. Eng. Sci., 62(7), 1927 (2007)
  11. Juanes R, Adv. Water Resour., 31, 661 (2008)
  12. Barenblatt GI, Izv. Akad. Nauk SSSR, Mekh. Zhidk. Gaza, 5, 144 (1971).
  13. Shi Y, Yang D, J. Energy Resour. Technol., 139, 062902 (2017)
  14. Manthey S, Hassanizadeh SM, Helmig R, Upscaling multiph. Flow porous media from pore to core beyond, Springer, Berlin (2005).
  15. Hassanizadeh SM, Celia MA, Dahle HK, Vadose Zo. J., 1, 38 (2002)
  16. DiCarlo DA, Mirzaei M, Jessen K, SPE J., 16, 812 (2011)
  17. Abidoye LK, Das DB, Adv. Water Resour., 74, 212 (2014)
  18. Stauffer F, IAHR symposium on scale effects in porous media, Thessaloniki, Greece, 29, 3-35 (1978).
  19. Blunt MJ, Multiphase flow in permeable media, Cambridge University Press, London (2017).
  20. Hanspal NS, Das DB, AIChE J., 58(6), 1951 (2012)
  21. Joekar-Niasar V, Hassanizadeh SM, Int. J. Multiph. Flow, 37(2), 198 (2011)
  22. Amaziane B, Milisic JP, Panfilov M, Pankratov L, Phys. Rev. E, 31, 9 (2012)
  23. Abbasi J, Ghaedi M, Riazi M, Saint Petersburg 2018: Innovations in Geosciences, Saint Petersburg (2018).
  24. Bottero S, Hassanizadeh SM, Pyrak-Nolte LJ, AGU Fall Meeting Abstracts, Alberta (2009).
  25. Tian L, Feng B, Zheng S, Gu D, Ren X, Yang D, J. Energy Resour. Technol., 141, 2 (2018)
  26. Mohammad RS, Tareen MYK, Mengel A, Shah SAR, Iqbal J, J. Pet. Explor. Prod. Technol., 10, 1891 (2020)
  27. Li Y, Liu C, Li H, Chen S, Huang S, J. Hydrol., 584, 124709 (2020)
  28. Lie KA, Reservoir Simulation Toolbox (MRST), Cambridge University Press, 2019, London (2015).
  29. Nilsen HM, Lie KA, Andersen O, Comput. Geosci., 20, 49 (2016)
  30. Abbasi J, Ghaedi M, Riazi M, J. Pet. Sci. Eng., 162, 44 (2018)
  31. Lie KA, Krogstad S, Ligaarden IS, Natvig JR, Nilsen HM, Skaflestad B, Comput. Geosci., 16, 297 (2012)
  32. Gambolati G, Pini G, Int. J. Numer. Methods Fluids, 29, 343 (1999)
  33. Das DB, Thirakulchaya T, Deka L, Hanspal NS, Environ. Prog., 2, 1 (2015)
  34. Christie MA, Blunt MJ, SPE Reserv. Eval. Eng., 4, 308 (2001)
  35. Debbabi Y, Jackson MD, Hampson GJ, Salinas P, Transp. Porous Media, 120(1), 183 (2017)
  36. Debbabi Y, Jackson MD, Hampson GJ, Fitch PJR, Salinas P, Transp. Porous Media, 117(2), 281 (2017)
  37. Chatzis I, Morrow NR, Soc. Pet. Eng. J., 24, 555 (1984)
  38. Li Y, Li H, Chen S, Lu Y, Li X, Luo H, Liu C, Cui X, Int. Pet. Technol. Conf., IPTC 2019, Beijing (2019).
  39. Hou TY, Int. J. Numer. Methods Fluids, 47, 707 (2005)
  40. Dahle HK, et al., Upscaling multiph. Flow porous media from pore to core beyond, Springer, Berlin, Germany (2005).