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A Case Study on the CO 2 Sequestration in Shenhua Block Reservoir: The Impacts of Injection Rates and Modes

Author

Listed:
  • Ligen Tang

    (Research Institute of Petroleum Exploration & Development, PetroChina, Beijing 100083, China
    National Energy Underground Gas Storage R&D Center, Beijing 100083, China)

  • Guosheng Ding

    (Research Institute of Petroleum Exploration & Development, PetroChina, Beijing 100083, China
    National Energy Underground Gas Storage R&D Center, Beijing 100083, China)

  • Shijie Song

    (Shaanxi Coal and Chemical Industry Group Co., Ltd., Xian 710100, China)

  • Huimin Wang

    (Shaanxi Coal and Chemical Industry Group Co., Ltd., Xian 710100, China)

  • Wuqiang Xie

    (Shaanxi Coal and Chemical Industry Group Co., Ltd., Xian 710100, China)

  • Jiulong Wang

    (Computer Network Information Center, Chinese Academy of Sciences, Beijing 100190, China)

Abstract

Carbon capture and storage (CCS) is the most promising method of curbing atmospheric carbon dioxide levels from 2020 to 2050. Accurate predictions of geology and sealing capabilities play a key role in the safe execution of CCS projects. However, popular forecasting methods often oversimplify the process and fail to guide actual CCS projects in the right direction. This study takes a specific block in Shenhua, China as an example. The relative permeability of CO 2 and brine is measured experimentally, and a multi-field coupling CO 2 storage prediction model is constructed, focusing on analyzing the sealing ability of the block from the perspective of injection modes. The results show that when injected at a constant speed, the average formation pressure and wellbore pressure are positively correlated with the CO 2 injection rate and time; when the injection rate is 0.5 kg/s for 50 years, the average formation pressure increases by 38% and the wellbore pressure increases by 68%. For different injection modes, the average formation pressures of various injection methods are similar during injection. Among them, the pressure increases around the well in the decreasing injection mode is the smallest. The CO 2 concentration around the wellbore is the largest, and the CO 2 diffusion range continues to expand with injection time. In summary, formation pressure increases with the increase in injection rate and injection time, and the decreasing injection mode has the least impact on the increase in formation pressure. The CO 2 concentration is the largest around the well, and the CO 2 concentration gradually decreases. The conclusion helps determine the geological carrying capacity of injection volumes and provides insights into the selection of more appropriate injection modes. Accurate predictions of CO 2 storage capacity are critical to ensuring project safety and monitoring potentially hazardous sites based on reservoir characteristics.

Suggested Citation

  • Ligen Tang & Guosheng Ding & Shijie Song & Huimin Wang & Wuqiang Xie & Jiulong Wang, 2023. "A Case Study on the CO 2 Sequestration in Shenhua Block Reservoir: The Impacts of Injection Rates and Modes," Energies, MDPI, vol. 17(1), pages 1-19, December.
    • Handle: RePEc:gam:jeners:v:17:y:2023:i:1:p:122-:d:1307115
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    References listed on IDEAS

    as
    1. Du, Shuyi & Wang, Meizhu & Yang, Jiaosheng & Zhao, Yang & Wang, Jiulong & Yue, Ming & Xie, Chiyu & Song, Hongqing, 2023. "An enhanced prediction framework for coalbed methane production incorporating deep learning and transfer learning," Energy, Elsevier, vol. 282(C).
    2. Ratnakar, Ram R. & Chaubey, Vivek & Dindoruk, Birol, 2023. "A novel computational strategy to estimate CO2 solubility in brine solutions for CCUS applications," Applied Energy, Elsevier, vol. 342(C).
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