Journal Home > Volume 4 , Issue 4
Capillarity 2021, 4(4): 66-75 https://doi.org/10.46690/capi.2021.04.02
Original Article | Open Access | Issue | Published: 17 August 2021

An experimental study of imbibition process and fluid distribution in tight oil reservoir under different pressures and temperatures

Show Author's Information Yisheng Liang1,2,  Fengpeng Lai1,2( ),  Yuting Dai1,2,  Hao Shi1,2,  Gongshuai Shi1,2
School of Energy Resources, China University of Geosciences (Beijing), Beijing 100083, P. R. China
Beijing Key Laboratory of Unconventional Natural Gas Geological Evaluation and Development Engineering, Beijing 100083, P. R. China
Keywords:
Imbibition, tight reservoir, fluid distribution, pore-size distribution
Cite this article:
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. https://doi.org/10.46690/capi.2021.04.02
Download citation
EndNote(RIS)
BibTeX

673

Views

46

Downloads

Citations

14

Crossref

N/A

WoS

20

Scopus

N/A

CSCD

Abstract Full text About this article

Tight reservoirs are a major focus of unconventional reservoir development. As a means to improve hydrocarbon recovery from tight reservoirs, imbibition has been received increasing attentions in recent years. This study evaluates how the changes in temperature and pressure affect imbibition through conducting experimental tests under various conditions on samples from the Yan Chang formation, a tight reservoir in Ordos Basin. The fluid distribution is compared before and after imbibition in core samples by nuclear magnetic resonance method. The results show that the imbibition recovery is significantly improved through increasing temperature and pressure. A high temperature facilitates molecular thermal movements, increasing oil-water exchange rate. The core samples are characterized with nano-mesopores, which is followed by nano-macropores, micropores, mesopores, and nano-micropores. Comparative analysis of nuclear magnetic resonance shows that the irreducible water saturation increases after imbibition and is mainly distributed in nano-pores. Increasing pressure increases the amount of residual water in nano pores, with the relatively more significant increase in the amount of residual water in nanomacro-pores compared with other types of pores.


menu
Abstract
Full text
Outline
About this article

An experimental study of imbibition process and fluid distribution in tight oil reservoir under different pressures and temperatures

Show Author's information Yisheng Liang1,2, Fengpeng Lai1,2( ), Yuting Dai1,2, Hao Shi1,2, Gongshuai Shi1,2
School of Energy Resources, China University of Geosciences (Beijing), Beijing 100083, P. R. China
Beijing Key Laboratory of Unconventional Natural Gas Geological Evaluation and Development Engineering, Beijing 100083, P. R. China

Abstract

Tight reservoirs are a major focus of unconventional reservoir development. As a means to improve hydrocarbon recovery from tight reservoirs, imbibition has been received increasing attentions in recent years. This study evaluates how the changes in temperature and pressure affect imbibition through conducting experimental tests under various conditions on samples from the Yan Chang formation, a tight reservoir in Ordos Basin. The fluid distribution is compared before and after imbibition in core samples by nuclear magnetic resonance method. The results show that the imbibition recovery is significantly improved through increasing temperature and pressure. A high temperature facilitates molecular thermal movements, increasing oil-water exchange rate. The core samples are characterized with nano-mesopores, which is followed by nano-macropores, micropores, mesopores, and nano-micropores. Comparative analysis of nuclear magnetic resonance shows that the irreducible water saturation increases after imbibition and is mainly distributed in nano-pores. Increasing pressure increases the amount of residual water in nano pores, with the relatively more significant increase in the amount of residual water in nanomacro-pores compared with other types of pores.

Keywords: Imbibition, tight reservoir, fluid distribution, pore-size distribution

References(39)

Adibhatla, B., Mohanty, K. K. Parametric analysis of surfactant-aided imbibition in fractured carbonates. Journal of Colloid and Interface Science, 2008, 317(2):513-522.
DOI Google Scholar
Akbarabadi, M., Piri, M. Nanotomography of the spontaneous imbibition in shale. Paper URTEC 1922555 Presented at SPE/AAPG/SEG Unconventional Resources Technology Conference in Denver, Colorado, USA, 25-27 August, 2014.
Aronofsky, J. S., Jenkins, R. A. Simplified analysis of unsteady radial gas flow. Journal of Petroleum Technology, 1954, 6(7):23-28.
DOI Google Scholar
Babadagli, T. Dynamics of capillary imbibition when surfactant, polymer, and hot water are used as aqueous phase for oil recovery. Journal of Colloid and Interface Science, 2002, 246(1):203-213.
DOI Google Scholar
Cai, J., Li, C., Song K., et al. The influence of salinity and mineral components on spontaneous imbibition in tight sandstone. Fuel, 2020, 269:117087.
DOI Google Scholar
Cai, J., Perfect, E., Cheng, C. L., et al. Generalized modeling of spontaneous imbibition based on Hagen-Poiseuille flow in tortuous capillaries with variably shaped apertures. Langmuir, 2014, 30(18):5142-5151.
DOI Google Scholar
Dou, L., Xiao, Y., Gao, H., et al. The study of enhanced displacement efficiency in tight sandstone from the combination of spontaneous and dynamic imbibition. Journal of Petroleum Science and Engineering, 2021, 199:108327.
DOI Google Scholar
Dou, L., Yang, M., Gao, H., et al. Characterization of the dynamic imbibition displacement mechanism in tight sandstone reservoirs using the NMR technique. Geofluids, 2020, 2020:8880545.
DOI Google Scholar
Fini, M. F., Riahi, S., Bahramian, A. Experimental and QSPR studies on the effect of ionic surfactants on n-decane-water interfacial tension. Journal of Surfactants and Detergents, 2012, 15(4):477-484.
DOI Google Scholar
Gao, Z. Y., Hu, Q. H. Investigating the effect of median pore-throat diameter on spontaneous imbibition. Journal of Porous Media, 2015, 18(12):1231-1238.
DOI Google Scholar
Ghasemi, F., Ghaedi, M., Escrochi, M. A new scaling equation for imbibition process in naturally fractured gas reservoirs. Advances in Geo-Energy Research, 2020, 4(1):99-106.
DOI Google Scholar
Gong, Y. B., Sedghi, M., Piri, M. Dynamic pore-scale modeling of residual trapping following imbibition in a rough-walled fracture. Transport in Porous Media, 2021, . (in press)
DOI Google Scholar
Hendraningrat, L., Torsæter, O. Effects of the initial rock wettability on silica-based nanofluid-enhanced oil recovery processes at reservoir temperatures. Energy & Fuels, 2014, 28(10):6228-6241.
DOI Google Scholar
Hu, Y. F., Ren, F., Li, J., et al. Effect of dynamic imbibition on the development of ultralow permeability reservoir. Geofluids, 2021, 2021:5544484.
DOI Google Scholar
Jiang, Y., Shi, Y., Xu, G., et al. Experimental study on spontaneous imbibition under confining pressure in tight sandstone cores based on low-field nuclear magnetic resonance measurements. Energy & Fuels, 2018, 32(3):3152-3162.
DOI Google Scholar
Lai, F. P., Li, Z. P., Dong, H. K., et al. Micropore structure characteristics and water distribution in a coalbed methane reservoir. Australian Journal of Earth Sciences, 2019, 66(5):741-750.
DOI Google Scholar
Lai, F. P., Li, Z. P., Wei, Q., et al. Experimental investigation of spontaneous imbibition in a tight reservoir with nuclear magnetic resonance testing. Energy & Fuels, 2016, 30(11):8932-8940.
DOI Google Scholar
Li, K., Chow, K., Horne, R. N. Effect of initial water saturation on spontaneous water imbibition. Paper SPE 76727 Presented at SPE Western Regional/AAPG Pacific Section Joint Meeting in Anchorage, 20-22 May, 2002.
Loucks, R. G., Reed, R. M., Ruppel, S. C., et al. Spectrum of pore types and networks in mudrocks and a descriptive classification for matrix-related mudrock pores. AAPG Bulletin, 2012, 96(6):1071-1098.
DOI Google Scholar
Ma, S., Morrow, N. R., Zhang, X. Generalized scaling of spontaneous imbibition data for strongly water-wet systems. Journal of Petroleum Science and Engineering, 1997, 18(3-4):165-178.
DOI Google Scholar
Mason, G., Fischer, H., Morrow, N. R., et al. Correlation for the effect of fluid viscosities on counter-current spontaneous imbibition. Journal of Petroleum Science and Engineering, 2010, 72(1-2):195-205.
DOI Google Scholar
McWhorter, D. B., Sunada, D. K. Exact integral solutions for two-phase flow. Water Resources Research, 1990, 26(3):399-413.
DOI Google Scholar
Meng, Q., Cai, J. Recent advances in spontaneous imbibition with different boundary conditions. Capillarity, 2018, 1(3):19-26.
DOI Google Scholar
Mohammadi, S., Kord, S., Moghadasi, J. An experimental investigation into the spontaneous imbibition of surfactant assisted low salinity water in carbonate rocks. Fuel, 2019, 243:142-154.
DOI Google Scholar
Nasralla, R. A., Bataweel, M. A., Nasr-El-Din, H. A. Investigation of wettability alteration and oil-recovery improvement by low-salinity water in sandstone rock. Journal of Canadian Petroleum Technology, 2013, 52(2):144-154.
DOI Google Scholar
Schechter, D. S., Zhou, D., Orrjr, F. M. Low IFT drainage and imbibition. Journal of Petroleum Science and Engineering, 1994, 11(4):283-300.
DOI Google Scholar
Schmid, K. S., Geiger, S. Universal scaling of spontaneous imbibition for arbitrary petrophysical properties: Water-wet and mixed-wet states and Handy’s conjecture. Journal of Petroleum Science and Engineering, 2013, 101:44-61.
DOI Google Scholar
Schmid, K. S., Geiger, S., Sorbie, K. S. Semianalytical solutions for cocurrent and countercurrent imbibition and dispersion of solutes in immiscible two-phase flow. Water Resources Research, 2011, 47(2):2144-2150.
DOI Google Scholar
Shen, A., Liu, Y., FarouqAli, S. M. A model of spontaneous flow driven by capillary pressure in nanoporous media. Capillarity, 2020, 3(1):1-7.
DOI Google Scholar
Sohi, M. L., Sola, B. S., Rashidi, F. Experimental investigation of effective parameters on efficiency of capillary imbibition in naturally fractured reservoirs. Journal of the Japan Petroleum Institute, 2009, 52(2):36-41.
DOI Google Scholar
Tinni, A., Odusina, E., Sulucarnain, I., et al. Nuclear-magnetic-resonance response of brine, oil, and methane in organic-rich shales. SPE Reservoir Evaluation & Engineering, 2015, 18(3):400-406.
DOI Google Scholar
Wang, C., Gao, H., Gao, Y., et al. Influence of pressure on spontaneous imbibition in tight sandstone reservoirs. Energy & Fuels, 2020, 34(8):9275-9282.
DOI Google Scholar
Wang, X. K., Sheng, J. J. Dynamic pore-scale network modeling of spontaneous water imbibition in shale and tight reservoirs. Energies, 2020, 13(18):4709.
DOI Google Scholar
Washburn, E. W. The dynamics of capillary flow. Physical Review, 1921, 17(3):273-283.
DOI Google Scholar
Xu, X., Wan, Y. J., Li, X., et al. Microscopic imbibition characterization of sandstone reservoirs and theoretical model optimization. Scientific Reports, 2021, 11(1):8509.
DOI Google Scholar
Yang, L., Ge, H., Shen, Y., et al. Experimental research on the shale imbibition characteristics and its relationship with microstructure and rock mineralogy. Paper SPE 176882 Presented at SPE Asia Pacific Unconventional Resources Conference and Exhibition in Brisbane, Brisbane, Australia, 9-11 November, 2015.
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.
DOI Google Scholar
Zhang, X., Morrow, N. R., Ma, S. X. Experimental verification of a modified scaling group for spontaneous imbibition. SPE Reservoir Engineering, 1996, 11(4):280-285.
DOI Google Scholar
Zou, C. N., Yang, Z., He, D. B., et al. Theory, technology and prospects of conventional and unconventional natural gas. Petroleum Exploration and Development, 2018, 45(4):604-618.
DOI Google Scholar
Publication history
Copyright
Acknowledgements
Rights and permissions

Publication history

Received: 26 July 2021
Revised: 12 August 2021
Accepted: 13 August 2021
Published: 17 August 2021
Issue date: December 2021

Copyright

© The Author(s) 2021.

Acknowledgements

We sincerely appreciate financial support from the National Natural Science Foundation of China (No. 51774255), the National Major Science and Technology Projects of China (No. 2017ZX05009-005), and the Fundamental Research Funds for the Central Universities (2-9-2018-210).

Rights and permissions

Open Access This article is distributed under the terms and conditions of the Creative Commons Attribution (CC BY-NC-ND) license, which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

Return