The micropore structure of a tight sandstone is the decisive factor in determining its reserve and seepage characteristics. An accurate description of

The production of coalbed methane (CBM) wells varies greatly in the Qinshui Basin, North China. Analyzing the primary factors controlling the CBM well productivity is essential to improve their development efficiency. Based on the geological conditions and production data of CBM wells in the Zheng zhuang area, the principal component analysis (PCA) method was used to classify the drainage types and screen the key factors influencing the production of gas and water. The drainage types of the CBM wells in the study area can be divided into four categories. The gas production shows an increasing trend with the increase of the comprehensive score of the PCA. The key controlling factors of productivity for CBM wells can be summarized by the gas-bearing property, permeability, groundwater fluid potential, and burial depth. The impact of burial depth on CBM well productivity is manifested in its control of gas content and permeability. The groundwater flows to a low fluid potential area, which leads to a high water production and a small pressure drop. The gas production shows a positive correlation with post-fracturing permeability. The gas content is a key factor for controlling the critical desorption pressure, critical gas production pressure, and pressure drop at the gas breakthrough point. High gas content is a prerequisite for the high productivity of CBM wells.

Hydraulic fracturing is a widely used reservoir stimulation technique to exploit CBM in China. Compared with the original permeability of coal reservoir, the postfracturing permeability is more critical for the productivity evaluation of CBM wells. Based on hydraulic fracturing, microseismics monitoring, and well test data of the CBM wells in Zhengzhuang block of Qinshui Basin, this paper proposes a simple method to obtain the fitting pressure by the classic fracturing pressure decline analysis theory under the condition of corrected dynamic overall leakoff coefficient. In addition, the postfracturing permeability of coal reservoir is predicted by the injection well testing theory. The morphology of hydraulic fractures in the study area is mainly determined by in‐situ stress, and most fractures are vertical ones propagating along the direction of the maximum principal stress. The fracturing curves of the study area can be classified into stable curves, stably fluctuating curves, descending curves, ascending curves, and fluctuating curves, where the stable and descending fracturing curves represent better fracturing effect. The length of hydraulic fractures is much greater than the height. The PKN model has been selected as the hydraulic fracture propagation model to analyze the fracturing pressure decline. The slope value of liner segment of G(δ,0) curve is proposed as the criterion for the fitting pressure calculation. The postfracturing permeabilities of coal reservoir range from 1.55 to 8.83 × 10⁻³ μm², all of which are remarkably higher than that of the original reservoir.