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Coal structure directly correlates to permeability and hydraulic fracturing effects. Underground coal mining indicates that a single coal section generally contains multiple coal structures in superposition, making how to recognise the coal structure combination and predict its influence on coal permeability a challenging problem. Based on well-drilling sampled cores, the geological strength index (GSI), and well-logging data, the DEN, GR, CALX, and CALY were selected to establish a model to predict GSI by multiple regression to identify coal structure from 100 coalbed methane wells. Based on fitting GSI and corresponding permeability test values, injection fall-off (IFO) testing, and hydraulic fracturing results, permeability prediction models for pre- and post-fracturing behaviour were established, respectively. The fracturing effect was evaluated by the difference in permeability. The results show that a reservoir can be classified into one of nine types by different coal structure thickness proportion (and combinations thereof) and the fracturing curves can be classified into four categories (and eight sub-categories) by the pressure curve. Up-down type I and type II reservoirs (proportion of hard coal >60%) and intervening interval type I reservoir (proportion of hard coal >70%) are prone to form stable and descending fracturing curves and the fracturing effects are optimal. Intervening interval type II (hard coal:soft coal:hard coal or soft coal:hard coal:soft coal ≈1:1:1) and up-down type III (hard coal:soft coal =1:1) form descending type II, rising type I and fluctuating type I fracturing curves and fracturing effect ranks second; up-down type IV and V (proportion of hard coal <40%), interval type III (proportion of hard coal <30%), and multi-layer superposition-type reservoirs readily form fluctuating and rising fracturing curves and fracturing effects therein are poor. The research results provide guidance for the targeted stimulation measured under different coal structure combinations.

Coal fines migration and intrusion in coal fractures affect coalbed methane (CBM) wells performance by reducing reservoir permeability and production continuity. Physical simulations are conducted to investigate the permeability variation under different diameter coal fines intrusion at various flow velocities and confining pressures. The results show that the conductivity of fractures is dramatically reduced and hardly recover to its initial condition after coal fines intrusion. The permeability after coal fines intrusion (Pcfi) has no direct correlation with the increase of flooding velocity, while decreases with the increase of confining pressures. The fractures can be totally blocked by coal fines, while penetration also happened during the flooding process, causing permeability fluctuation. The permeability loss rates value for 80-120 mesh coal fines intrusion are generally <60% compared with the initial permeability, including the flow velocity of 2, 3, 4, 6, 8, and 10 mL/min with confining pressure of 6 MPa and the confining pressure of 2, 3, 4, 5, and 6 MPa with flow velocity of 3 mL/min. However, under 120+ mesh coal fines condition, the permeability loss rates are higher than 85% under most flow velocities and confining pressures. When coal fines become smaller, the permeability loss rates decrease to be lower than 45%, and part the coal fines are discharged with the water flow. Thus, coal fines proper dischargement can partly maintain the reservoir permeability during coalbed methane production. The results would be useful in understanding coal fines intrusion behaviors and its controlling strategies during CBM drainage.