Determining the causes of gas production difference among wells and regions is crucial for future coalbed methane (CBM) exploration and development. Combined with gas content and equivalent drainage radius (ER), the vertical characteristics that different coal texture types overlaid are researched and compared between the north and south regions in the Zaoyuan area of Shizhuangnan Block, Southern Qinshui Basin. The results indicate that the vertical relationship of different coal textures has a great impact on gas/water production. Thicker granulated coal may contribute to adsorb more gas, but may also increase the possibility of blocking the seepage channel with coal powder in the coals. CBM in granulated coals could flow into the wellbore through the fractures in the upper and lower cataclastic or undeformed coals, and the mudstone contact directly below the granulated coals in the north may restrict gas production, as mudstone could obstruct the seepage passage that CBM in granulated coal flows downward.

Hydraulic fracturing plays a vital role in the development of coalbed methane (CBM). Coal seam structures can, however, affect the fracturing operations, further affecting gas and water production from the coal seam. Within the research area—the Shizhuangnan Block, Southern Qinshui Basin, China—three types of coal body textures are relevant, including original, cataclastic, and granulated structure. This research describes the impacts of different coal seam types on fracturing operations and gas and water production. The results show that different types of coal seams have different impacts on hydraulic fracturing and the resultant production of gas and water. The coal seams are classified according to the vertical variation characteristics of the coal seam structures. The first type of coal seam (Type I) only develops the original and cataclastic coal structure. The effects of fracturing reconstruction for Type I are good. A high degree of coal breakage and fracture formation is observed. Gas production from CBM wells in Type I coalbeds is usually high because the water in the coal reservoir can be discharged smoothly at an early stage. The second type of coal seam (Type II) develops an additional layer of granulated coal compared with Type I. During the fracturing process, breakage of the coal seam is obvious, and the granulated coal can easily produce fine-grained coal that can block the pores and fractures, which causes an increase and fluctuation of oil pressure and can affect the effectiveness of fracturing. The gas production curve from CBM wells in Type II coal seams is mostly bimodal and water production depends on whether the pulverized coal blocks the pores and fractures. The third type of coal seam (Type III) develops two additional layers of granulated coal compared with Type I, with a greater proportion of granulated coal present. A low degree of coal breakage and fracture formation is observed, and fractures are easily blocked by pulverized coal. The effects of fracturing reconstruction for Type III are bad. Forming an effective seepage channel in this type of coal seam and extending the fracture to the far end is difficult. The gas production from CBM wells in Type III coal seams is usually low, and water production is generally low during the whole drainage period.

In order to determine the optimum lithofacies for continental shale, the reservoir characteristics of different lithofacies types were studied based on a series of experiments. The lacustrine organic-rich shale of the Shahezi Formation is divided into siliceous (ORS), argillaceous (ORA), calcareous (ORC), and mixed (ORM) shales. The ORS, ORA, ORC, and ORM shales all carried out comprehensive reservoir comparative analysis. The results showed that the moderate content of clay minerals (45%) can significantly improve porosity, and high and low clay mineral contents are not conducive to the improvement of porosity. The ORM shale tends to have better pore connectivity than the ORS and ORA shales, and the ORC shale has the poorest pore-throat connectivity in micron-size. Internal pores in bitumen and clay shrinkage cracks are the dominant pore type and are well developed in ORS and ORM shales. The two types of pores are less developed in the ORA shale; however, dissolution pores are better developed than those of ORS and ORM shales. Inorganic pores are well-developed in the ORC shale, but organic pores are not. Organic and inorganic pores tend to be better connected in the ORM shale than those of the other three types, which could help improve the gas storage capacity. The ORM shale may have more irregular surfaces and lower liquid/gas surface tension. The higher capillary condensation on pore surfaces is more likely to occur in the ORA shale. The ORS shale offers fewer adsorption sites for CH₄ and has lower adsorption capacity. The ORC shale has weak heterogeneity of the pore structure. Therefore, the ORM shale may be the most favorable lithofacies for shale gas enrichment and development, which has high porosity, good pore connectivity, moderate brittleness, and strong gas adsorption and storage capacity, followed by the ORS and ORA shales. The ORC shale is the worst.