Numerical simulation of CO₂ sequestration combined with enhanced geothermal energy extraction in deep saline aquifers

Authors

XIE Zehao, State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu 610500, ChinaFollow
ZHANG Liehui, State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu 610500, China
ZHAO Yulong, State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu 610500, ChinaFollow
CAO Cheng, State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu 610500, China
KOU Zuhao, State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu 610500, China
ZHANG Deping, Carbon Dioxide Capture, Storage and Enhanced Oil Recovery, Jilin Oilfield Company, PetroChina, Songyuan 138000, China
LI Jinlong, Research Institute of Exploration and Development, Jilin Oilfield Company, PetroChina, Songyuan 138000, China

Abstract

Objectives and Methods Deep saline aquifers represent ideal spaces for geologic CO₂ sequestration while also featuring high geothermal gradients and abundant geothermal resources. The combination of CO₂ sequestration and geothermal energy extraction holds great significance for enhancing the CO₂ sequestration effect and achieving integrated resource development of deep saline aquifers. Therefore, this study proposed a development approach that combined CO₂ sequestration with geothermal energy extraction in deep saline aquifers and established a thermo-hydro-chemical coupling numerical simulation model of the gas-water two-phase flow. Accordingly, it explored the optimal injection mode, production and injection well patterns, and injection and production parameters Results and Conclusions Extracting formation water and geothermal energy during CO₂ injection can effectively delay the rise in formation pressure while also providing more spaces for CO₂ storage, with the CO₂ storage capacity increasing by 16 500 t. After the depletion of movable water, further geothermal energy extraction with CO₂ as the work fluid yielded an additional 6.60 MJ of heat while further increasing the CO₂ storage capacity by 30 800 t. Geochemical reactions occurred during CO₂ injection, increasing reservoir porosity and permeability by 0.0022 and 0.43×10^–3μm², respectively. This creates favorable conditions for continuous CO₂ injection and geothermal energy extraction. Intermittent injection can delay the rise in the formation pressure to the greatest extent, identified as the optimal injection mode. It is recommended that production and injection wells should be arranged in the same aquifer and that more injection wells should be arranged in the structurally lower parts of reservoirs compared to production wells. The optimal injection and production parameters include an injection rate of 10 000 m³/day, an injection-to-production rate ratio of 0.8, an injection cycle of three months, and a cyclic injection-to-production time ratio of 1. The proposed new development approach offers a novel philosophy for geologic CO₂ sequestration in deep saline aquifers while also serving as a valuable reference for reaching the goals of carbon neutrality and peak carbon dioxide emissions and promoting efficient, collaborative resource development.

Keywords

deep saline aquifer, geothermal energy, geologic CO2 sequestration, numerical simulation, injection mode, well pattern, selection of optimal parameters

DOI

10.12363/issn.1001-1986.25.05.0376

Recommended Citation

XIE Zehao, ZHANG Liehui, ZHAO Yulong, et al. (2026) "Numerical simulation of CO₂ sequestration combined with enhanced geothermal energy extraction in deep saline aquifers," Coal Geology & Exploration: Vol. 54: Iss. 1, Article 17.
DOI: 10.12363/issn.1001-1986.25.05.0376
Available at: https://cge.researchcommons.org/journal/vol54/iss1/17

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