Numerical simulations of the safety of geologic CO₂ storage in saline aquifers in the Enping Sag, Pearl River Mouth Basin

Authors

YU Tao, Key Laboratory of Ocean Energy Utilization and Energy Conservation of Ministry of Education, Dalian University of Technology, Dalian 116024, ChinaFollow
LI Xiwen, Key Laboratory of Ocean Energy Utilization and Energy Conservation of Ministry of Education, Dalian University of Technology, Dalian 116024, China
YANG Yunshi, Key Laboratory of Ocean Energy Utilization and Energy Conservation of Ministry of Education, Dalian University of Technology, Dalian 116024, China
CHEN Bingbing, Key Laboratory of Ocean Energy Utilization and Energy Conservation of Ministry of Education, Dalian University of Technology, Dalian 116024, China
JI Zemin, State Key Laboratory of Enhanced Oil and Gas Recovery, Beijing 100083, China; Research Institute of Petroleum Exploration & Development, PetroChina, Beijing 100083, China
HE Chang, Key Laboratory of Ocean Energy Utilization and Energy Conservation of Ministry of Education, Dalian University of Technology, Dalian 116024, China; State Key Laboratory of Enhanced Oil and Gas Recovery, Beijing 100083, China; Research Institute of Petroleum Exploration & Development, PetroChina, Beijing 100083, China
JIANG Lanlan, Key Laboratory of Ocean Energy Utilization and Energy Conservation of Ministry of Education, Dalian University of Technology, Dalian 116024, ChinaFollow
SONG Yongchen, Key Laboratory of Ocean Energy Utilization and Energy Conservation of Ministry of Education, Dalian University of Technology, Dalian 116024, China

Abstract

Background Since the beginning of the Industrial Revolution, excessive CO₂ emissions have aggravated the greenhouse effect. Against this backdrop, CO₂ capture, utilization, and storage (CCUS) technology has emerged as a critical countermeasure. Particularly, geologic CO₂ storage holds enormous application potential. China has implemented a demonstration project of geologic CO₂ storage in saline aquifers located in the Enping Sag, Pearl River Mouth Basin. Nevertheless, this sag exhibits formation dip angles and widely distributed fracture zones, which affect CO₂ migration and storage. Methods Focusing on the Enping Sag, this study established a two-dimensional model of the saline aquifer with a fracture zone using the TOUGH3 software. Using the established model, this study analyzed the impacts of factors, including formation dip angle, fracture zone location, and injection pressure, on the distributions of formation pressure, free CO₂, and dissolved CO₂, as well as the time-varying amounts of storage of various phases of CO₂ within reservoirs, during CO₂ storage. Through comparison of the amounts of CO₂ storage in the reservoirs, the influential mechanisms of varying factors on the upward migration and leakage of CO₂ were elucidated. Additionally, by analyzing the proportions of the amounts of dissolved CO₂ storage in varying reservoirs, this study revealed the role of different factors in determining the storage safety.Results and Conclusions During CO₂ injection, the fracture zone could release the pressure from the lower reservoir to the upper reservoir, thus alleviating the pressure rise in the middle cap rocks caused by the accumulation of free CO₂. At 100 a, CO₂ storage in the upper reservoir proved safer than that in the lower reservoir. In the formation at dip angles ranging from 0° to 2°, a higher formation dip angle led to a longer migration distance of free CO₂ in the reservoirs towards the updip direction. After 70 a, the risks of the upward migration and leakage of CO₂ were reduced. Between 20 a and 100 a, the safety of CO₂ storage in the reservoirs was enhanced, especially in the upper reservoir. Within a horizontal distance range of 50‒200 m from the injection well, the risks of the upward migration and leakage of CO₂ decreased with an increase in the horizontal distance between the fracture zone and the injection well. However, the safety of CO₂ storage in the reservoirs decreased at 100 a. At injection pressure ranging from 16.5 MPa to 19.5 MPa, an increase in injection pressure corresponded to an increased total amount of CO₂ storage but a decreased proportion of the amount of the dissolved CO₂ storage at 100 a, with such storage tending to be unstable. At an injection pressure of 18.0 MPa, the proportion of the amount of CO₂ storage in the lower reservoir reached its maximum (42.21%), suggesting the lowest risks of the upward migration and leakage of CO₂. Among the three factors influencing CO₂ storage safety, formation dip angle and injection pressure determine the safety of CO₂ storage in the upper and lower reservoirs, respectively, while the horizontal distance between the fracture zone and the injection well serves as a major factor affecting the upward migration and leakage of CO₂. The results of this study will provide a theoretical basis for CO₂ storage projects in saline aquifers with fracture zones and deepen the understanding of the mechanisms behind CO₂ storage in analogous geological settings. Accordingly, the results will contribute to the large-scale application and industrial advancement of geologic CO₂ storage while also providing support for the attainment of peak carbon dioxide emissions and carbon neutrality.

Keywords

CO2 storage, CO2 capture, utilization, and storage (CCUS) technology, Enping Sag, saline aquifer, fracture zone, formation dip angle, injection pressure

DOI

10.12363/issn.1001-1986.25.07.0564

Recommended Citation

YU Tao, LI Xiwen, YANG Yunshi, et al. (2026) "Numerical simulations of the safety of geologic CO₂ storage in saline aquifers in the Enping Sag, Pearl River Mouth Basin," Coal Geology & Exploration: Vol. 54: Iss. 1, Article 20.
DOI: 10.12363/issn.1001-1986.25.07.0564
Available at: https://cge.researchcommons.org/journal/vol54/iss1/20

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