Identifying the variation of fracture structure and coal permeability with effective stress is important for protecting coalbed methane (CBM) reservoirs and formulating a reasonable drainage system. This study characterizes the coal fracture and permeability variations with effective stress using three-dimensional (3-D) micro-CT and digital core techniques. Dual-resolution scanning is adopted to characterize the variation of three types of fractures with effective stress and to clarify the stress sensitivity of the porosity of each type of fracture. Type-A fractures (>109 μm3) are most sensitive to effective stress and tend to close as effective stress increases. Moreover, the porosity of this fracture has a negative exponential relationship with effective stress. Type-B fractures (107–109 μm3) are moderately sensitive to effective stress and have the highest contribution of total porosity at high effective stress. Type-C fractures (<107 μm3) are least sensitive to effective stress, and the porosity of this fracture changes slightly. The seepage simulation in the two directions with digital core techniques confirms that the permeability of coal samples presents an exponential decrease with effective stress and shows an anisotropic behavior with space. Combined with the quantitative analysis of variation of pore–fracture models, the compression model of coal under effective stress can be established, which can reveal the reason that the permeability loss rate in the y-axis is more than that in the z-axis. The sensitivity of porosity and permeability is stronger under low stress and weaker under high stress. Therefore, digital core technology can quantitatively analyze the stress sensitivity of coal fracture structure and permeability based on 3-D models. This method is more intuitive to study the stress sensitivity of coal compared with traditional methods.

Coal measure gas resources, including coalbed methane (CBM), shale gas, and tight gas are abundant in the Daning–Jixian Block. The complexity of the source–reservoir–cap relationship in the coal measure strata leads to unclear symbiotic characteristics and gas accumulation, which in turn, restrict the exploration and exploitation of the coal measure gas. In this study, the enrichment and accumulation of coal measure gas are discussed and summarized in detail. The results show that there are eight lithofacies and six reservoir combinations in the superposed strata of the coal measures in the study area. Controlled by the tidal flat-lagoon facies, the “sand-mud-coal” type mainly distributes in P1s2 and P1t, showing a good gas indication. Based on the variation of the total hydrocarbon content, key strata, and pressure coefficient of the coal measure gas reservoir, four superposed gas-bearing systems are identified in the vertical direction. According to the relationship between the gas-bearing system and gas reservoir, the enrichment of coal measure gas in the study area can be divided into three modes, including an intra-source enrichment mode, a near-source migration enrichment mode, and a far-source migration enrichment mode. The symbiotic accumulation of a coal measure gas model is further proposed, that is, an “Adjacent to co-source reservoir” type superimposed coalbed methane and shale gas reservoir model, a “Three gas symbiosis” superimposed reservoir model in the local gas-bearing system, and a “Co-source far reservoir” tight sandstone gas reservoir model. Clarifying the symbiotic relationship of coal measure gas reservoirs is beneficial to the exploration and further production of unconventional gas in the study area.