In the coal exploration of China, the commonly used direct method within 120 min has potential errors in lost gas calculation of deep coal seam for its complex geological conditions. The exploration of deep coal resources by drilling holes in Huainan of Eastern China offered an opportunity to starting research into developing a new method. A developed method with error analysis was constructed to estimate the lost gas using the total desorption process obtained from exploratory coal cores. The accuracy of the direct method was also evaluated comparatively. The result shows that the desorption curve of tested coal samples matches the fitted curve equation. Desorption temperature and the tectonic coal with associated pore characteristics significantly affect the variation of the adsorption characteristics and the estimation of lost gas. The direct method obviously underestimates the lost gas, and methodology using a new lost gas estimation procedure with additional residual gas allows for achieving relatively accurate results of the determination of gas content in coal seams. The calculated result of the new method is about 1.00–1.41 times that of the direct method. The error analysis of desorption results allowed us to determine the dependence between the time (retrieval time and desorption time) and determination method. The time used for desorption in the tank is allowed to extend to less than 400 min or more than 1000 min, which is very potentially important to accurately get the coalbed gas content for coring samples, especially deep exploratory cores for field application.

The connectivity and permeability of the coal seam pore structures control the occurrence and migration of coalbed methane. Coal samples were used from Huainan–Huaibei to reconstruct three-dimensional models of the pores and an equivalent pore network model, Statistical pore structure characteristic parameters. The pore structure of the coal reservoir was analyzed from the direction of multidimensional and multiangle. It shows that based on quantitative analysis, the representative Elementary volume of 500 × 500 × 500 was the most suitable experimental volume. The Y-axis direction of the Renlou sample had poor pore connectivity compared to that of other samples. Large volume connected pores dominated their pore systems. In terms of coal sample pore connectivity, the coal samples from the Liuzhuang and Qidong regions had pore connectivity better than those from the other regions. The pore connectivity of the Liuzhuang coal samples was the best. In terms of coal permeability, the Liuzhuang sample had better permeability than the other three samples, and the permeability was the best in the Y-axis direction. For all the combinations of the different types of throats, the shorter the throat, the greater the equivalent radius and the better the permeability. Conversely, the worse the permeability. During gas injection production, the closer the gas injection area was to the gas injection well, the poorer the connectivity and the lower the permeability over time. Near the production area, where the CO₂ did not reach the production area, the fracture porosity and effective connected porosity of the coal reservoir increased over time. When CO₂ reached the production area, the change in its connected pore structure was consistent with the change in the connected pores in the gas injection area. With this study, the coal seam pore structure on a microscale was characterized. A comprehensive analysis of the coal reservoir pore connectivity and permeability was completed. The study results are significant for the exploration and development of coalbed methane in the Huainan–Huaibei coalfield.

Indentifying reservoir characteristics of coals and their associated shales is very important in understanding the co-exploration and co-production potential of unconventional gases in Guizhou, China. Accordingly, comprehensive experimental results of 12 core samples from well LC-1# in the northern Guizhou were used and analyzed in this paper to better understand their vertical reservoir study. Coal and coal measured shale, in Longtan Formation, are rich in organic matter, with postmature stage of approximately 3.5% and shales of type III kerogen with dry gas generation. All-scale pore size analysis indicates that the pore size distribution of coal and shale pores is mainly less than 20 nm and 100 nm, respectively. Pore volume and area of coal samples influenced total gas content as well as desorbed gas and lost gas content. Obvious relationships were observed between residual gas and BET specific surface area and BJH total pore volume (determined by nitrogen adsorption). For shale, it is especially clear that the desorbed gas content is negatively correlated with BET specific surface area, BJH total pore volume and clay minerals. However, the relationships between desorbed gas and TOC (total organic carbon) as well as siderite are all well positive. The coals and shales were shown to have similar anoxic conditions with terrestrial organic input, which is beneficial to development of potential source rocks for gas. However, it may be better to use a low gas potential assessment for shales in coal-bearing formation because of their low S₁+S₂ values and high thermal evolution. Nevertheless, the coalbed methane content is at least 10 times greater than the shale gas content with low desorbed gases, indicating that the main development unconventional natural gas should be coalbed methane, or mainly coalbed methane with supplemented shale gas.