Coupling mechanisms of displacement and imbibition in pore-fracture system of tight oil reservoir
Abstract view|0|times PDF download|0|times
Abstract
Fracturing and water flooding have been popular technologies to achieve the effective development of tight oil reservoirs in recent years. However, in the late stage of production, the oil recovery rate declines with a rapid increase in the water cut. Water huff-puff could improve reservoir energy; however, the displacement and imbibition in the micro-nano pore throat and fracture systems are complex processes with unclear characteristics and position. Therefore, it is urgent to study the coupling mechanisms of oil-water displacement and imbibition in tight oil reservoirs. In this work, based on the phase field method of COMSOL Multiphysics software, we establish a two-dimensional microscopic numerical simulation model of the pore-fracture system, and carry out displacement-imbibition simulation programs of different injection media (water and surfactant) and injection methods (displacement, displacement-imbibition). By comparing the saturations and pressure distributions of different simulation programs, we analyze the changes in the oil-water interface, and summarize the action conditions of counter-current imbibition and pore throat limit. Finally, reasonable development suggestions are proposed for tight oil reservoirs.
Document Type: Original article
Cited as: Pi, Z., Peng, H., Jia, Z., Zhou, J, Cao, R. Coupling mechanisms of displacement and imbibition in pore-fracture system of tight oil reservoir. Capillarity, 2023, 7(1): 13-24. https://doi.org/10.46690/capi.2023.04.02
Keywords
Full Text:
PDFReferences
Abbasi, J., Ghaedi, M., Riazi, M. A new numerical approach for investigation of the effects of dynamic capillary pressure in imbibition process. Journal of Petroleum Science and Engineering, 2018, 162: 44-54.
Abd, A. S., Elhafyan, E., Siddiqui, A. R., et al. A review of the phenomenon of counter-current spontaneous imbibition: Analysis and data interpretation. Journal of Petroleum Science and Engineering, 2019, 180: 456-470.
Alava, M., Dubé, M., Rost, M. Imbibition in disordered media. Advances in Physics, 2004, 53(2): 83-175.
Amiri, H. A., Hamouda, A. A. Evaluation of level set and phase field methods in modeling two phase flow with viscosity contrast through dual-permeability porous medium. International Journal of Multiphase Flow, 2013, 52: 22-34.
Amiri, H. A., Hamouda, A. A. Pore-scale modeling of non-isothermal two phase flow in 2D porous media: Influences of viscosity, capillarity, wettability and heterogeneity. International Journal of Multiphase Flow, 2014, 61:14-27.
Aronofsky, J. S., Jenkins, R. A simplified analysis of unsteady radial gas flow. Journal of Petroleum Technology, 1954, 6(7): 23-28.
Ashraf, S., Phirani, J. Capillary displacement of viscous liquids in a multi-layered porous medium. Soft Matter, 2019, 15(9): 2057-2070.
Bakhshian, S., Murakami, M., Hosseini, S. A., et al. Scaling of imbibition front dynamics in heterogeneous porous media. Geophysical Research Letters, 2020, 47(14): e2020GL087914.
Blunt, M. J., Jackson, M. D., Piri, M., et al. Detailed physics, predictive capabilities and macroscopic consequences for pore-network models of multiphase flow. Advances in Water Resources, 2002, 25(8-12): 1069-1089.
Cai, J. Key problems and Reflections on spontaneous imbibition of porous media. Chinese Journal of Computational Physics, 2021, 38(5): 505-512. (in Chinese)
Cai, J. Guo, S., You, L., et al. Fractal analysis of spontaneous imbibition mechanism in fractured-porous dual media reservoir. Acta Physica Sinica, 2013, 62(1): 014701.
Cai, J., Jin, T., Kou, J., et al. Lucas-Washburn equation-based modeling of capillary-driven flow in porous systems. Langmuir 2021, 37(5), 1623-1636.
Cao, Y., Tang, M., Zhang, Q., et al. Dynamic capillary pressure analysis of tight sandstone based on digital rock model. Capillarity, 2020, 3(2): 28-35.
Diao, Z., Li, S., Liu, W., et al. Numerical study of the effect of tortuosity and mixed wettability on spontaneous imbibition in heterogeneous porous media. Capillarity, 2021, 4(3): 50-62.
Feng, Q., Zhao, Y., Wang, S., et al. Pore-scale oil-water two-phase flow simulation based on phase field method. Chinese Journal of Computational Physics, 2020, 37(4): 439-447. (in Chinese)
Ghanbari, E., Dehghanpour, H. The fate of fracturing water: A field and simulation study. Fuel, 2016, 163, 282-294.
Gong, Y., Sedghi, M., Piri, M. Dynamic pore-scale modeling of residual trapping following imbibition in a rough-walled fracture. Transport in Porous Media, 2021, 140(1), 143-179.
Habibi, A., Xu, M., Dehghanpour, H., et al. Understanding Rock-Fluid interactions in the montney tight oil play. Paper SPE 175924 Presented at SPE/CSUR Unconventional Resources Conference. Calgary, Alberta, 20-22 October, 2015.
Handy, L. L. Determination of effective capillary pressures for porous media from imbibition data. Transactions of the AIME, 1960, 219(1): 75-80.
Haugen, Å., Ferno, M. A., Mason, G., et al. The effect of viscosity on relative permeabilities derived from spontaneous imbibition tests. Transport Porous Media, 2015, 106, 383-404.
Hu, Y., Guo, H. Microscopic mechanism of imbibition displacement in low permeability oilfield. Special Oil & Gas Reservoirs, 1998, 5(4): 18-22. (in Chinese)
Kazemi, H., Merrill, L. S. Numerical simulation of water imbibition in fractured cores. Society of Petroleum Engineers Journal, 1979, 19(3): 175-182.
Li, C., Mao, W., Wu, T., et al. Study on the mechanism of imbibition displacement. Xinjiang Petroleum Geology, 2019, 40(6): 687-694. (in Chinese)
Liang, Y., Lai, F., Dai, Y., et al. An experimental study of imbibition process and fluid distribution in tight oil reservoir under different pressures and temperatures. Capillarity, 2021, 4(4):66-75.
Liu, J., Sheng, J. J. Investigation of countercurrent imbibition in oil-wet tight cores using NMR technology. SPE Journal, 2020, 25(5): 2601-2614.
Lucas, R. Ueber das Zeitgesetz des kapillaren Aufstiegs von Flüssigkeiten. Kolloid-Zeitschrift, 1918, 23(1): 15-22.
Lyu, C., Ning, Z., Chen, M., et al. Experimental study of boundary condition effects on spontaneous imbibition in tight sandstones. Fuel, 2019, 235: 374-383.
Mason, G., Morrow, N. R. Developments in spontaneous imbibition and possibilities for future work. Journal of Petroleum Science and Engineering, 2013, 110, 268-293. Meng, Q., Cai, J., Wang, J. Scaling of countercurrent imbibition in 2D matrix blocks with different boundary conditions. SPE Journal, 2019, 24(3): 1179-1191.
Mogensen, K., Stenby, E. H. A dynamic two-phase pore-scale model of imbibition. Transport in Porous Media, 1998, 32, 299-327.
Nooruddin, H. A., Blunt, M. J. Analytical and numerical investigations of spontaneous imbibition in porous media. Water Resources Research. 2016, 52 (9): 7284-7310.
Rose, W. Fluid-fluid interfaces in steady motion. Nature, 1961, 191: 242-243.
Schechter, D. S., Zhou, D., Orr, F. M. Low IFT drainage and imbibition. Journal of Petroleum Science and Engineering, 1994, 11(4): 283-300.
Standnes, D. C. Calculation of viscosity scaling groups for spontaneous imbibition of water using average diffusivity coefficients. Energy & Fuels, 2009, 23(4): 2149-2156.
Tartakovsky, A. M., Meakin, P. Pore scale modeling of immiscible and miscible flows using smoothed particle hydrodynamics. Advances in Water Resources, 2006, 29(10): 1464-1478.
Wang, S., Feng, Q., Dong, Y., et al. A dynamic pore-scale network model for two-phase imbibition. Journal of Natural Gas Science and Engineering, 2015, 26: 118-129.
Wang, J., Salama, A., Kou, J. Experimental and numerical analysis of imbibition processes in a corrugated capillary tube. Capillarity, 2022, 5(5):83-90.
Washburn, E. W. The dynamics of capillary flow. Physical Review, 1921, 17(3): 273-283.
Xu, F., Chen, Q., Ma, M., et al. Displacement mechanism of polymeric surfactant in chemical cold flooding for heavy oil based on microscopic visualization experiments. Advances in Geo-Energy Research, 2020, 4(1): 77-85.
Xu, Z., Liu, H., Valocchi, A. J. Lattice Boltzmann simulation of immiscible two-phase flow with capillary valve effect in porous media. Water Resources Research, 2017, 53(5): 3770-3790.
Yildiz, H. O., Gokmen, M., Cesur, Y. Effect of shape factor, characteristic length, and boundary conditions on spontaneous imbibition. Journal of Petroleum Science and Engineering, 2006, 53(3-4): 158-170.
Zahasky, C., Benson, S. M. Spatial and temporal quantification of spontaneous imbibition. Geophysical Research Letters, 2019, 46(21): 11972-11982.
Zhou, X., Chen, D., Xia, Y., et al. Spontaneous imbibition characteristics and influencing factors of Chang 7 shale oil reservoirs in Longdong Area, Ordos Basin. Earth Science, 2022, 47(8): 3045-3055. (in Chinese)
Zhu, G., Yao, J., Zhang L., et al. Distribution and formation mechanism of remaining oil in ultra-high water cut period. Chinese Science Bulletin, 2017, 22(62): 2553- 564.
Zou, C., Yang, Z., He, D., et al. Theory, technology and prospects of conventional and unconventional natural gas. Petroleum Exploration and Development, 2018, 45(4): 604-618.
Refbacks
- There are currently no refbacks.
Copyright (c) 2023 The Author(s)
This work is licensed under a Creative Commons Attribution-NonCommercial-NoDerivatives 4.0 International License.