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NMR-Based Shale Core Imbibition Performance Study

Author

Listed:
  • Yuping Sun

    (Research Institute of Petroleum Exploration and Development, Beijing 100083, China)

  • Qiaojing Li

    (Research Institute of Petroleum Exploration and Development, Beijing 100083, China)

  • Cheng Chang

    (PetroChina Southwest Oil and Gasfield Company, Chengdu 610000, China)

  • Xuewu Wang

    (Shandong Institute of Petroleum and Chemical Technology, Dongying 257061, China)

  • Xuefeng Yang

    (PetroChina Southwest Oil and Gasfield Company, Chengdu 610000, China)

Abstract

Shale gas reservoirs are unconventional resources with great potential to help meet energy demands. Horizontal drilling and hydraulic fracturing have been extensively used for the exploitation of these unconventional resources. According to engineering practice, some shale gas wells with low flowback rate of fracturing fluids may obtain high yield which is different from the case of conventional sandstone reservoirs, and fracturing fluid absorbed into formation by spontaneous imbibition is an important mechanism of gas production. This paper integrates NMR into imbibition experiment to examine the effects of fractures, fluid salinity, and surfactant concentration on imbibition recovery and performance of shale core samples with different pore-throat sizes acquired from the Longmaxi Formation in Luzhou area, the Sichuan Basin. The research shows that the right peak of T 2 spectrum increases rapidly during the process of shale imbibition, the left peak increases rapidly at the initial stage and changes gently at the later stage, with the peak of the left peak shifting to the right. The result indicates that water first enters the fracture system quickly, then enters the small pores near the fracture wall due to the effect of the capillary force, and later gradually sucks into the deep and large pores. Both imbibition rate and capacity increase with increased fracture density, decreased solution salinity, and decreased surfactant concentration. After imbibition flowback, shale permeability generally increases by 8.70–17.88 times with the average of 13.83 times. There are also many microcracks occurring on the end face and surface of the core sample after water absorption, which may function as new flowing channels to further improve reservoir properties. This research demonstrates the imbibition characteristics of shale and several relevant affecting factors, providing crucial theory foundations for the development of shale gas reservoirs.

Suggested Citation

  • Yuping Sun & Qiaojing Li & Cheng Chang & Xuewu Wang & Xuefeng Yang, 2022. "NMR-Based Shale Core Imbibition Performance Study," Energies, MDPI, vol. 15(17), pages 1-10, August.
  • Handle: RePEc:gam:jeners:v:15:y:2022:i:17:p:6319-:d:901455
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    References listed on IDEAS

    as
    1. Wenquan Deng & Tianbo Liang & Shuai Yuan & Fujian Zhou & Junjian Li, 2022. "Abnormal Phenomena and Mathematical Model of Fluid Imbibition in a Capillary Tube," Energies, MDPI, vol. 15(14), pages 1-15, July.
    2. Weiyao Zhu & Guodong Zou & Yuwei Liu & Wenchao Liu & Bin Pan, 2022. "The Influence of Movable Water on the Gas-Phase Threshold Pressure Gradient in Tight Gas Reservoirs," Energies, MDPI, vol. 15(14), pages 1-12, July.
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    Cited by:

    1. Qitao Zhang & Wenchao Liu & Jiaxin Wei & Arash Dahi Taleghani & Hai Sun & Daobing Wang, 2022. "Numerical Simulation Study on Temporary Well Shut-In Methods in the Development of Shale Oil Reservoirs," Energies, MDPI, vol. 15(23), pages 1-24, December.

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