Numerical simulation of CO-ECBM for deep coal reservoir with strong stress sensitivity.

CH production rate of coalbed methane (CBM) well decreases rapidly during primary recovery in the deeply buried coal seam, resulting in a lot of CH residues. CO pour into deep coal seam with high stress sensitivity is available for enhancing CH recovery by improving permeability for reservoir fracture and displacing CH adsorbed in matrix. A coupled adsorp-hydro-thermo-mechanical (AHTM) model for deep methane development is established by considering the coupling relationships of non-isothermal and non-constant pressure competitive adsorption between CO and CH, multi-phase flow, unsteady diffusion, heat transmission and in-situ stress variety. The model is verified by historical production and then used for CO enhanced CBM (CO-ECBM) of deep coal reservoir in a sedimentary basin in Northwest China. The simulation results show that: (1) For primary recovery, permeability in coal reservoir drops rapidly with the development of CBM, which seriously restricts the production of CH. The permeability of the reservoir decreases from 7.89 × 10 m to less than 1.50 × 10 m, CH production rate in CBM well reduces to below 2000 m/d, and the average total CH content of coal reservoir is reduced by 5.49 m/t with the decrease of only 1.12 m/t of average adsorbed CH in a production duration of 2000 d (2) With 10 MPa CO continuous injection into coal seam after 700d of primary, the permeability for reservoir and CH production rate increase while the total CH content and adsorption CH content in reservoir decrease compared with the primary recovery. (3) CO pouring into coal reservoir increases the CH production time and rate, which improves CH recovery of coal reservoir. And it increases by 23.36 %, 23.07 % and 22.46 % with shut-in thresholds of CH production rate of 1000 m/d, 800 m/d and 600 m/d, respectively. The investigation is of great significance for the development of deep coalbed methane.