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<p>Coalbed methane (CBM) reservoirs have emerged as a crucial source of natural gas, but their efficient recovery remains challenging due to complex interactions between mechanical deformation, fluid migration, and permeability evolution. CO<sub>2</sub>-enhanced coalbed methane (CO<sub>2</sub>-ECBM) recovery has gained attention as a promising technique for improving gas extraction while simultaneously sequestering CO<sub>2</sub>. However, a comprehensive understanding of the reservoir's mechanical behaviour and permeability evolution during CO<sub>2</sub> injection is still lacking. To address this gap, we develop a 3D thermo-hydro-mechanical (THM) coupled numerical model to simulate the CO<sub>2</sub>-ECBM process. This model captures reservoir deformation, geological formation shifts, and surface responses while integrating field monitoring data to enhance accuracy and reliability. A key innovation of this study is the coupled analysis of simulated surface deformations with measured data, enabling a more precise assessment of permeability evolution and mechanical responses. A representative 2D cross-section of the coal seam is analysed to examine how injection pressure and production temperature influence gas pressure, permeability, and reservoir deformation. The results indicate that surface micro-deformation induced by CO<sub>2</sub> injection arises from the interplay of geo-stress, injection pressure, gas adsorption/desorption, and temperature effects. Notably, CO<sub>2</sub> adsorption-driven expansion outweighs CH<sub>4</sub> desorption-induced contraction, leading to net volumetric expansion. In the vicinity of the injection well, higher injection pressures cause significant permeability reductions, whereas near the production well, permeability initially increases due to extraction-induced pressure drops before later declining due to rising effective stress. However, increased CH<sub>4</sub> migration toward the production well under higher injection pressures partially mitigates this permeability loss. Elevated temperatures further expand the adsorption/desorption zone, induce coal matrix thermal expansion, and compress pores, collectively reducing permeability and volumetric strain. This study offers critical insights into the dynamic coupling between stress redistribution and fluid flow in CO<sub>2</sub>-ECBM operations. The findings provide a theoretical foundation for optimizing CO<sub>2</sub> injection strategies, enhancing methane recovery efficiency, and ensuring the mechanical stability of the reservoir-caprock system.</p>

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Revealing reservoir dynamics: how CO2 injection reshapes permeability in coalbed methane recovery

  • 期刊论文

  • 出版模式：

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  • 发表日期：

    2025年10月2日

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  • Yu Zhao,
  • Hong Li,
  • Xuanhui Li,
  • Kaoshan Dai

摘要

Coalbed methane (CBM) reservoirs have emerged as a crucial source of natural gas, but their efficient recovery remains challenging due to complex interactions between mechanical deformation, fluid migration, and permeability evolution. CO2-enhanced coalbed methane (CO2-ECBM) recovery has gained attention as a promising technique for improving gas extraction while simultaneously sequestering CO2. However, a comprehensive understanding of the reservoir's mechanical behaviour and permeability evolution during CO2 injection is still lacking. To address this gap, we develop a 3D thermo-hydro-mechanical (THM) coupled numerical model to simulate the CO2-ECBM process. This model captures reservoir deformation, geological formation shifts, and surface responses while integrating field monitoring data to enhance accuracy and reliability. A key innovation of this study is the coupled analysis of simulated surface deformations with measured data, enabling a more precise assessment of permeability evolution and mechanical responses. A representative 2D cross-section of the coal seam is analysed to examine how injection pressure and production temperature influence gas pressure, permeability, and reservoir deformation. The results indicate that surface micro-deformation induced by CO2 injection arises from the interplay of geo-stress, injection pressure, gas adsorption/desorption, and temperature effects. Notably, CO2 adsorption-driven expansion outweighs CH4 desorption-induced contraction, leading to net volumetric expansion. In the vicinity of the injection well, higher injection pressures cause significant permeability reductions, whereas near the production well, permeability initially increases due to extraction-induced pressure drops before later declining due to rising effective stress. However, increased CH4 migration toward the production well under higher injection pressures partially mitigates this permeability loss. Elevated temperatures further expand the adsorption/desorption zone, induce coal matrix thermal expansion, and compress pores, collectively reducing permeability and volumetric strain. This study offers critical insights into the dynamic coupling between stress redistribution and fluid flow in CO2-ECBM operations. The findings provide a theoretical foundation for optimizing CO2 injection strategies, enhancing methane recovery efficiency, and ensuring the mechanical stability of the reservoir-caprock system.