Experimental and numerical model of anisotropic permeability and CO2 injectivity of coal during CO2 enhanced coalbed methane recovery process - Niu, Qinghe; Hu, Mingwei; Leng, Bing; He, Xiang; Su, Wenjie; Wang, Wei; Wang, Qizhi; Chang, Jiangfang; Ji, Zhongmin; Qi, Xiaofei (Frontiers in Earth Science, 2023)
The CO2 injectivity is the precondition for implementing the CO2 enhanced coalbed methane recovery (CO2-ECBM), however, it dramatically decreases during CO2 injection process because it is influenced by the dynamic change of the anisotropic permeability of coal. To reveal and evaluate the CO2 injectivity of coal, the anisotropic permeability test and the CO2 injectivity simulation test were first conducted, then the corresponding numerical models was established and verified by the experimental data. The results show that the permeability of coal in parallel face cleat direction is the largest, followed by the permeability of coal in parallel butt cleat direction, and that in vertical bedding direction is the minimum. The peak value of instantaneous injectivity rate is enhanced and the injection time is prolonged with the increase of the CO2 injection pressure. The total CO2 injectivity rate is nonlinearly increased from 13.61 cm2/MPa·min to 311.87 cm2/MPa·min when the CO2 injection pressure raises from 2 MPa to 10 MPa. The anisotropic permeability model is appropriate to describe the dynamic evolution of permeability under different boundary conditions, the CO2 injectivity prediction model can be used to evaluate the CO2 injectivity during CO2 injection process. Increasing the CO2 injection pressure may temporarily promote the CO2 injectivity, while the CO2 injection increment is limited. The CO2 fracturing by phase transition may be an available reservoir stimulation method for enhanceing the CO2 injection and should be focused on in the future.