Experimental Study on the Distribution and Height of Spontaneous Imbibition Water of Chang 7 Continental Shale Oil
Abstract
:1. Introduction
2. Theory and Method
2.1. Conversion between the T2 Spectrum and Pore Radius
2.2. Relationship between T2 and the Imbibition Water Content
2.3. Imbibition Height Based on Fractal Theory and NMR T2 Spectrum
3. Experiment
3.1. Materials
3.2. Procedure and Setup
- The four cores were dried at 120 °C in an oven until the mass changes were less than 0.005 g again and vacuumized with a vacuum pump for 48 h.
- A high-pressure container was placed and filled with #7 white oil and another filled with n-dodecane in a thermotank where the temperature was set at 60 °C for 24 h. Then Cores #H1 and #Z11 were put into the former container, and Cores #B14 and #B15 were placed into the other container, and then soaked at 30 MPa and 60 °C for about 5 days until the mass showed little change.
- The saturated oil cores were taken out and the side covered in Teflon tape, exposing only the end face for 2–3 mm. Next, the whole samples were immersed in a beaker containing heavy water to carry out the imbibition experiments at 60 °C. The cores were taken out of the beaker at different times and the NMR T2 spectrum curves measured. The measuring time should be limited to within 2 min. The SI experiments are illustrated in Figure 3.
4. Results and Discussion
4.1. Pore Radius Distribution
4.2. NMR T2
4.3. Imbibition Water Saturation Characteristics
4.4. Distribution Characteristics of Imbibition Water in Different Pores
4.5. Distribution Characteristics of Imbibition Water Height
5. Conclusions
- According to HPMI experiments, the displacement pressures of samples drilled from the three wells were 0.676, 0.676, and 2.736 MPa, and the higher the displacement pressure, the smaller the maximum connected pore radius, such that Well B20 was the smallest at about 0.269 μm. Meanwhile, there were three peaks for the NMR T2 spectra with saturated distilled water, and the overall pore distribution of shale was divided into three types: micropores (<100 nm), mesopores (100–1000 nm), and macropores (>1000 nm), with the volume of micropores and mesopores accounting for 90%, indicating that Chang 7 continental shale pore-fracture had strong heterogeneity and distinct micro–nano characteristics.
- The NMR T2 spectra of the remaining oil in four shale samples decreased significantly with time, reflecting a strong imbibition effect in the shale pore. The peaks of T2 spectra in micropores and macropores initially declined faster and finally dropped more than those in mesopores, showing that there was a bigger gap between imbibition driving force and imbibition resistance in micro- and macropores, but a smaller difference in mesopores. It ultimately led to the above differences in sizes.
- After SI experiments, the cumulative proportion of imbibition water content was the largest in micropores, exceeding 43%, followed by mesopores around 30%, and that of macropores was the lowest, basically less than 20%. The cumulative proportion curves of micropores were basically a “V” shape and kept decreasing to a stable level in macropores and increasing to an equilibrium state in mesopores. This reflects that imbibition first occurred in micropores and macropores, then expanded to mesopores. Additionally, the stage proportion fluctuated in different pores during the SI process, and the negative values of stage water content in the macropore or mesopore indicated that these pores became a water supply channel for other dominant imbibition pores;
- Based on the fractal theory and NMR T2 spectrum, the relative imbibition water and actual height were calculated in different pores. There were significant differences in the shape of the height distribution curve for samples drilled from different wells and saturated with different oils, and the shorter the core, the higher the relative height. This indicates that the height distribution was affected by the pore structure, oil viscosity, and core length.
- Moreover, after hydraulic fracturing, the imbibition process will be affected by the change in pressure and temperature of the shale oil reservoir, and then the distribution of imbibition fluid and its height will also change. Therefore, carrying out experiments with changes in pressure and temperature can investigate further the distribution and height of the IWS.
Author Contributions
Funding
Data Availability Statement
Acknowledgments
Conflicts of Interest
References
- Xiao, L.; Hou, J.; Wen, Y.; Qu, M.; Wang, W.; Wu, W.; Liang, T. Imbibition mechanisms of high temperature resistant microemulsion system in ultra-low permeability and tight reservoirs. Pet. Explor. Dev. 2022, 49, 1398–1410. [Google Scholar]
- Liu, Y.F.; Dai, C.L.; Zou, C.W.; You, Q.; Zhao, M.W.; Zhao, G.; Sun, Y.P. Impact of flow rate on dynamic imbibition in fractured tight sandstone cores. Pet. Sci. 2022, 19, 2895–2904. [Google Scholar] [CrossRef]
- Shun, L.; Jun, N.; Xianli, W.; Xiong, L.; Zhaoqin, H.; Desheng, Z.; Pengju, R. A dual-porous and dual-permeable media model for imbibition in tight sandstone reservoirs. J. Pet. Sci. Eng. 2020, 194, 107477. [Google Scholar] [CrossRef]
- Li, Q.; Wu, J. Factors affecting the lower limit of the safe mud weight window for drilling operation in hydrate-bearing sediments in the Northern South China Sea. Geomech. Geophys. Geo-Energy Geo-Resour. 2022, 8, 82. [Google Scholar] [CrossRef]
- Liu, K.; Sheng, J.J. Experimental study of the effect of stress anisotropy on fracture propagation in Eagle Ford shale under water imbibition. Eng. Geol. 2019, 249, 13–22. [Google Scholar] [CrossRef]
- Liu, J.; Sheng, J.J. Experimental investigation of surfactant enhanced spontaneous imbibition in Chinese shale oil reservoirs using NMR tests. J. Ind. Eng. Chem. 2019, 72, 414–422. [Google Scholar] [CrossRef]
- Sheng, J.J. What type of surfactants should be used to enhance spontaneous imbibition in shale and tight reservoirs? J. Pet. Sci. Eng. 2017, 159, 635–643. [Google Scholar] [CrossRef]
- Thilagashanthi, T.; Gunasekaran, K.; Satyanarayanan, K.S. Microstructural pore analysis using SEM and ImageJ on the absorption of treated coconut shell aggregate. J. Clean. Prod. 2021, 324, 129217. [Google Scholar] [CrossRef]
- Wang, Y.; Zhu, Y.; Chen, S.; Li, W. Characteristics of the Nanoscale Pore Structure in Northwestern Hunan Shale Gas Reservoirs Using Field Emission Scanning Electron Microscopy, High-Pressure Mercury Intrusion, and Gas Adsorption. Energy Fuels 2014, 28, 945–955. [Google Scholar] [CrossRef]
- Zhang, Q.; Liu, Y.; Wang, B.; Ruan, J.; Yan, N.; Chen, H.; Wang, Q.; Jia, G.; Wang, R.; Liu, H.; et al. Effects of pore-throat structures on the fluid mobility in chang 7 tight sandstone reservoirs of longdong area, Ordos Basin. Mar. Pet. Geol. 2022, 135, 105407. [Google Scholar] [CrossRef]
- Makhanov, K.; Dehghanpour, H.; Kuru, E. An Experimental Study of Spontaneous Imbibition in Horn River Shales. In Proceedings of the SPE Canadian Unconventional Resources Conference, Calgary, AB, Canada, 30 October–1 November 2012. SPE-162650-MS. [Google Scholar]
- Zhou, Z.; Abass, H.; Li, X.; Bearinger, D.; Frank, W. Mechanisms of imbibition during hydraulic fracturing in shale formations. J. Pet. Sci. Eng. 2016, 141, 125–132. [Google Scholar] [CrossRef]
- Eslahati, M.; Mehrabianfar, P.; Isari, A.A.; Bahraminejad, H.; Manshad, A.K.; Keshavarz, A. Experimental investigation of Alfalfa natural surfactant and synergistic effects of Ca2+, Mg2+, and SO42− ions for EOR applications: Interfacial tension optimization, wettability alteration and imbibition studies. J. Mol. Liq. 2020, 310, 113123. [Google Scholar] [CrossRef]
- Gao, Z.; Hu, Q. Initial water saturation and imbibition fluid affect spontaneous imbibition into Barnett shale samples. J. Nat. Gas Sci. Eng. 2016, 34, 541–551. [Google Scholar] [CrossRef]
- Sun, Y.; Dai, C.; Fang, Y.; Sun, X.; You, Q.; Wu, Y.; Zhao, M.; Zhao, G. Imaging of Oil/Water Migration in Tightsand with Nuclear Magnetic Resonance and Microscope during Dynamic Surfactant Imbibition. In Proceedings of the SPE/IATMI Asia Pacific Oil & Gas Conference and Exhibition, Jakarta, Indonesia, 17–19 October 2017. D031S025R001. [Google Scholar]
- Jiang, Y.; Fu, Y.; Lei, Z.; Gu, Y.; Qi, L.; Cao, Z. Experimental NMR Analysis of Oil and Water Imbibition during Fracturing in Longmaxi Shale, SE Sichuan Basin. J. Jpn. Pet. Inst. 2019, 62, 1–10. [Google Scholar] [CrossRef] [Green Version]
- Liu, J.; Sheng, J.J.; Wang, X.; Ge, H.; Yao, E. Experimental study of wettability alteration and spontaneous imbibition in Chinese shale oil reservoirs using anionic and nonionic surfactants. J. Pet. Sci. Eng. 2019, 175, 624–633. [Google Scholar] [CrossRef]
- Lyu, C.; Ning, Z.; Chen, M.; Wang, Q. Experimental study of boundary condition effects on spontaneous imbibition in tight sandstones. Fuel 2019, 235, 374–383. [Google Scholar] [CrossRef]
- Zhu, Y.; Li, Z. Imbibition Behavior and Fluid Dynamic Distribution of Longmaxi Formation Shale in Pengshui Area. Chinese J. Comput. Phys. 2021, 38, 555–564. [Google Scholar]
- Fang, S.; Sun, J.; Liu, D.; Yao, Z.; Nie, B. Experimental Study on Spontaneous Imbibition Characteristics of Fracturing Fluid at Cores from Different Layers in Fuling Shale Gas Reservoir. Geofluids 2021, 2021, 1–12. [Google Scholar] [CrossRef]
- Xu, S.; Yassin, M.R.; Dehghanpour, H.; Kolbeck, C. The effects of kerogen maturity on pore structure and wettability of organic-rich calcareous shales. J. Mol. Liq. 2022, 362, 119577. [Google Scholar] [CrossRef]
- Wang, X.; Wang, M.; Li, Y.; Zhang, J.; Li, M.; Li, Z.; Guo, Z.; Li, J. Shale pore connectivity and influencing factors based on spontaneous imbibition combined with a nuclear magnetic resonance experiment. Mar. Pet. Geol. 2021, 132, 105239. [Google Scholar] [CrossRef]
- Zhang, S.; Li, Y.; Pu, H. Studies of the storage and transport of water and oil in organic-rich shale using vacuum imbibition method. Fuel 2020, 266, 117096. [Google Scholar] [CrossRef]
- Li, Y.; Li, M.; Li, H.; Chen, S.; Long, S. Investigation of shale imbibition capability and the influencing factors based on a convenient method. Arab. J. Geosci. 2023, 16, 65. [Google Scholar] [CrossRef]
- Cai, J.; Yu, B.; Zou, M.; Luo, L. Fractal Characterization of Spontaneous Co-current Imbibition in Porous Media. Energy Fuels 2010, 24, 1860–1867. [Google Scholar] [CrossRef]
- Jian-Chao, C.; Bo-Ming, Y.; Mao-Fei, M.; Liang, L. Capillary Rise in a Single Tortuous Capillary. Chin. Phys. Lett. 2010, 27, 054701. [Google Scholar] [CrossRef]
- Cai, J.C.; Yu, B. A Discussion of the effect of tortuosity on the capillary imbibition in porous media. Transp. Porous Media 2011, 89, 251–263. [Google Scholar] [CrossRef]
- Wang, F.; Zhao, J. A mathematical model for co-current spontaneous water imbibition into oil-saturated tight sandstone: Upscaling from pore-scale to core-scale with fractal approach. J. Pet. Sci. Eng. 2019, 178, 376–388. [Google Scholar] [CrossRef]
- Shi, Y.; Yassin, M.R.; Dehghanpour, H. A modified model for spontaneous imbibition of wetting phase into fractal porous media. Colloids Surf. A: Physicochem. Eng. Asp. 2018, 543, 64–75. [Google Scholar] [CrossRef]
- Cai, J.; Jin, T.; Kou, J.; Zou, S.; Xiao, J.; Meng, Q. Lucas–Washburn Equation-Based Modeling of Capillary-Driven Flow in Porous Systems. Langmuir 2021, 37, 1623–1636. [Google Scholar] [CrossRef]
- Meng, Q.; Cai, Z.; Cai, J.; Yang, F. Oil recovery by spontaneous imbibition from partially water-covered matrix blocks with different boundary conditions. J. Pet. Sci. Eng. 2019, 172, 454–464. [Google Scholar] [CrossRef]
- Li, Y.; Lu, J.; Churchwell, L.; Tagavifar, M.; Weerasooriya, U.; Pope, G.A. Scaling of Low IFT Imbibition in Oil-Wet Carbonates. In Proceedings of the SPE Improved Oil Recovery Conference, Tulsa, OK, USA, 11–13 April 2016. SPE-179684-MS. [Google Scholar]
- Ghaedi, M.; Riazi, M. Scaling equation for counter current imbibition in the presence of gravity forces considering initial water saturation and SCAL properties. J. Nat. Gas Sci. Eng. 2016, 34, 934–947. [Google Scholar] [CrossRef]
- Agihtias, S.; Xiuyu, W. An analytical solution on spontaneous imbibition coupled with fractal roughness, slippage and gravity effects in low permeability reservoir. J. Pet. Sci. Eng. 2022, 208, 109501. [Google Scholar]
- Meng, Q.; Zhao, L.; Li, P.; Yang, F.; Cai, J. Experiments and phase-field simulation of counter-current imbibition in porous media with different pore structure. J. Hydrol. 2022, 608, 127670. [Google Scholar] [CrossRef]
- Diao, Z.; Li, S.; Liu, W.; Liu, H.; Xia, Q. Numerical study of the effect of tortuosity and mixed wettability on spontaneous imbibition in heterogeneous porous media. Capillarity 2021, 4, 50–62. [Google Scholar] [CrossRef]
- Qin, C.Z.; Wang, X.; Zhang, H.; Hefny, M.; Jiang, H.; Tian, J.; Deng, W. Numerical studies of spontaneous imbibition in porous media: Model development and pore-scale perspectives. J. Pet. Sci. Eng. 2022, 218, 110961. [Google Scholar] [CrossRef]
- Dutta, R.; Lee, C.H.; Odumabo, S.; Ye, P.; Walker, S.C.; Karpyn, Z.T.; Ayala, H.L.F. Experimental Investigation of Fracturing-Fluid Migration Caused by Spontaneous Imbibition in Fractured Low-Permeability Sands. SPE Reserv. Eval. Eng. 2014, 17, 74–81. [Google Scholar] [CrossRef]
- Wang, M.; Wang, R.; Yuan, S.; Zhou, F. A pore-scale study on the dynamics of spontaneous imbibition for heterogeneous sandstone gas reservoirs. Front. Energy Res. 2023, 11, 1135903. [Google Scholar] [CrossRef]
- Zhmud, B.V.; Tiberg, F.; Hallstensson, K. Dynamics of Capillary Rise. J. Colloid Interface Sci. 2000, 228, 263–269. [Google Scholar] [CrossRef]
- Fries, N.; Dreyer, M. An analytic solution of capillary rise restrained by gravity. J. Colloid Interface Sci. 2008, 320, 259–263. [Google Scholar] [CrossRef]
- Shen, A.; Xu, Y.; Liu, Y.; Cai, B.; Liang, S.; Wang, F. A model for capillary rise in micro-tube restrained by a sticky layer. Results Phys. 2018, 9, 86–90. [Google Scholar] [CrossRef]
- Xiao, B.; Huang, Q.; Chen, H.; Chen, X.; Long, G. A Fractal model for capillary flow through a single tortuous capillary with roughened surfaces in fibrous porous media. Fractals 2021, 29, 2150017. [Google Scholar] [CrossRef]
- Amadu, M.; Pegg, M.J. Theoretical and experimental determination of the fractal dimension and pore size distribution index of a porous sample using spontaneous imbibition dynamics theory. J. Pet. Sci. Eng. 2018, 167, 785–795. [Google Scholar] [CrossRef]
- You, L.; Cai, J.; Kang, Y.; Luo, L. A fractal approach to spontaneous imbibition height in natural porous media. Int. J. Mod. Phys. C 2013, 24, 1350063. [Google Scholar] [CrossRef]
- Shengting, Z.; Jing, L.; Zhangxing, C.; Tao, Z.; Keliu, W.; Dong, F.; Jianfei, B.; Shang, Z. Simulation of dynamic wetting effect during gas-liquid spontaneous imbibition based on modified LBM. Chin. J. Theor. Appl. Mech. 2023, 55, 355–368. [Google Scholar]
- Cai, J.; Li, C.; Song, K.; Zou, S.; Yang, Z.; Shen, Y.; Meng, Q.; Liu, Y. The influence of salinity and mineral components on spontaneous imbibition in tight sandstone. Fuel 2020, 269, 117087. [Google Scholar] [CrossRef]
- Shi, G.; Kou, G.; Du, S.; Wei, Y.; Zhou, W.; Zhou, B.; Li, Q.; Wang, B.; Guo, H.; Lou, Q.; et al. What role would the pores related to brittle minerals play in the process of oil migration and oil & water two-phase imbibition? Energy Rep. 2020, 6, 1213–1223. [Google Scholar]
- Alvarez, J.O.; Schechter, D.S. Improving oil recovery in the Wolfcamp unconventional liquid reservoir using surfactants in completion fluids. J. Pet. Sci. Eng. 2017, 157, 806–815. [Google Scholar] [CrossRef]
- Alvarez, J.O.; Schechter, D.S. Application of wettability alteration in the exploitation of unconventional liquid resources. Pet. Explor. Dev. Online 2016, 43, 832–840. [Google Scholar] [CrossRef]
- Morsy, S.; Sheng, J.J. Effect of Water Salinity on Shale Reservoir Productivity. Adv. Pet. Explor. Dev. 2014, 8, 9–14. [Google Scholar]
- Xiaoyu, G.; Chunsheng, P.; Huang, H.; Huang, F.; Yuejing, L.I.; Yang, L.; Hengchao, L. Micro-influencing mechanism of permeability on spontaneous imbibition recovery for tight sandstone reservoirs. Pet. Explor. Dev. Online 2017, 44, 1003–1009. [Google Scholar]
- Huang, H.; Sun, W.; Ji, W.; Zhang, R.; Du, K.; Zhang, S.; Ren, D.; Wang, Y.; Chen, L.; Zhang, X. Effects of pore-throat structure on gas permeability in the tight sandstone reservoirs of the Upper Triassic Yanchang formation in the Western Ordos Basin, China. J. Pet. Sci. Eng. 2018, 162, 602–616. [Google Scholar] [CrossRef]
- Jiang, Y.; Xu, G.; Bi, H.; Shi, Y.; Gao, Y.; Han, X.; Zeng, X. A new method to determine surface relaxivity of tight sandstone cores based on LF-NMR and high-speed centrifugation measurements. J. Pet. Sci. Eng. 2021, 196, 108096. [Google Scholar] [CrossRef]
- Brooks, R.H.; Corey, A.T. Hydraulic Properties of Porous Media; Colorado State University: Fort Collins, CO, USA, 1964. [Google Scholar]
- Li, K. Analytical derivation of Brooks–Corey type capillary pressure models using fractal geometry and evaluation of rock heterogeneity. J. Pet. Sci. Eng. 2010, 73, 20–26. [Google Scholar] [CrossRef]
- Dai, F.; Hu, H.; Zhang, A. Suitability study on fractal model of organic shale pore. Coal Sci. Technol. 2019, 47, 168–175. [Google Scholar]
- Mandelbrot, B.B.; Mandelbrot, B.B. The Fractal Geometry of Nature; WH Freeman: New York, NY, USA, 1982. [Google Scholar]
- Cai, J.; Hu, X.; Standnes, D.C.; You, L. An analytical model for spontaneous imbibition in fractal porous media including gravity. Colloids Surf. A: Physicochem. Eng. Asp. 2012, 414, 228–233. [Google Scholar] [CrossRef]
- Yu, B. Some fractal characters of porous media. Fractals 2001, 9, 365–372. [Google Scholar] [CrossRef]
- Yu, B. Fractal Character for Tortuous Streamtubes in Porous Media. Chin. Phys. Lett. 2005, 22, 158–160. [Google Scholar]
- Liu, Y.; Yu, B.; Xu, P.; Wu, J. Study of the effect of capillary pressure on permeability. Fractals 2007, 15, 55–62. [Google Scholar] [CrossRef]
- Jacques, C.; Maurice, R. A new model for determining mean structure parameters of fixed beds from pressure drop measurements: Application to beds packed with parallelepipedal particles. Chem. Eng. Sci. 1989, 44, 1539–1545. [Google Scholar]
- Yu, B.; Cheng, P. A fractal permeability model for bi-dispersed porous media. Int. J. Heat Mass Transf. 2002, 45, 2983–2993. [Google Scholar] [CrossRef]
- Wheatcraft, S.W.; Tyler, S.W. An explanation of scale-dependent dispersivity in heterogeneous aquifers using concepts of fractal geometry. Water Resour. Res. 1988, 24, 566–578. [Google Scholar] [CrossRef]
- Zhu, J.; Chen, J.; Wang, X.; Fan, L.; Nie, X. Experimental Investigation on the Characteristic Mobilization and Remaining Oil Distribution under CO2 Huff-n-Puff of Chang 7 Continental Shale Oil. Energies 2021, 14, 2782. [Google Scholar] [CrossRef]
- Lai, F.; Li, Z.; Wei, Q.; Zhang, T.; Zhao, Q. Experimental Investigation of Spontaneous Imbibition in a Tight Reservoir with Nuclear Magnetic Resonance Testing. Energy Fuels 2016, 30, 8932–8940. [Google Scholar] [CrossRef]
- Xiuchuan, Z.; Qinhong, H.; Mianmo, M.; Junjian, Z.; Tao, Z.; Na, Y.; Xiaohui, S.; Jing, C.; Yushan, D.; Huimin, L. Microscopic distribution of water in the imbibition process of shale reservoir and dynamic response characteristics of its gas logging permeability. Acta Pet. Sin. 2022, 43, 533–547. [Google Scholar]
Well# | Core# | Diameter, cm | Length, cm | Porosity, % | Permeability, 10−3 μm2 |
---|---|---|---|---|---|
H38 | H1 | 2.501 | 4.132 | 9.81 | 0.222 |
Z55 | Z11 | 2.500 | 3.002 | 7.31 | 0.223 |
B20 | B14 | 2.499 | 3.422 | 6.99 | 0.0476 |
B15 | 2.495 | 3.774 | 8.96 | 0.0486 |
Fluid | Density (g/cm3) | Viscosity (mPa·s) |
---|---|---|
DW | 0.998 | 1.002 |
HW | 1.105 | 1.095 |
WO7 | 0.830 | 5.477 (40 °C) |
C12 | 0.7847 | 1.508 |
Well# | Displacement Pressure, MPa | Maximum Connected Pore Radius, μm | Maximum Mercury Intrusion Saturation, % | Mercury Snap-Off, % | Extrusion Efficiency, % |
---|---|---|---|---|---|
H38 | 0.676 | 1.087 | 95.346 | 72.731 | 23.719 |
Z55 | 0.676 | 1.087 | 94.187 | 71.950 | 23.609 |
B20 | 2.736 | 0.269 | 65.002 | 21.840 | 66.401 |
Core# | C | 1/n | R2 | Pore Volume Ratio, % | ||
---|---|---|---|---|---|---|
Micropores | Mesopores | Macropores | ||||
H1 | 0.0295 | 0.7343 | 0.972 | 46.56 | 48.91 | 4.53 |
Z11 | 0.0388 | 0.7241 | 0.8805 | 57.49 | 32.90 | 9.61 |
B14 | 0.0388 | 0.6175 | 0.7720 | 61.25 | 29.81 | 8.94 |
B15 | 0.0375 | 0.5695 | 0.7915 | 53.26 | 37.19 | 9.55 |
Disclaimer/Publisher’s Note: The statements, opinions and data contained in all publications are solely those of the individual author(s) and contributor(s) and not of MDPI and/or the editor(s). MDPI and/or the editor(s) disclaim responsibility for any injury to people or property resulting from any ideas, methods, instructions or products referred to in the content. |
© 2023 by the authors. Licensee MDPI, Basel, Switzerland. This article is an open access article distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (https://creativecommons.org/licenses/by/4.0/).
Share and Cite
Zhu, J.; Chen, J.; Duanmu, X.; Wang, X.; Gong, D.; Nie, X. Experimental Study on the Distribution and Height of Spontaneous Imbibition Water of Chang 7 Continental Shale Oil. Fractal Fract. 2023, 7, 428. https://doi.org/10.3390/fractalfract7060428
Zhu J, Chen J, Duanmu X, Wang X, Gong D, Nie X. Experimental Study on the Distribution and Height of Spontaneous Imbibition Water of Chang 7 Continental Shale Oil. Fractal and Fractional. 2023; 7(6):428. https://doi.org/10.3390/fractalfract7060428
Chicago/Turabian StyleZhu, Jianhong, Junbin Chen, Xiaoliang Duanmu, Xiaoming Wang, Diguang Gong, and Xiangrong Nie. 2023. "Experimental Study on the Distribution and Height of Spontaneous Imbibition Water of Chang 7 Continental Shale Oil" Fractal and Fractional 7, no. 6: 428. https://doi.org/10.3390/fractalfract7060428