This work presents the adsorption behavior and appearance characteristics of CH₄ and CO₂ on the Longmaxi shale at high pressure and temperature. To investigate the variation of gas adsorption patterns under the constraint of pressure and temperature, the applicability of the theories of monolayer adsorption, multilayer adsorption, and micropore filling was discussed. The preferential selection coefficient of CO₂ for CH₄ under different conditions was characterized by the absolute adsorption capacity (V_abs) ratio of CO₂ to CH₄ (αCO₂/CH₄). Moreover, the implication of the CO₂ injection to enhance gas recovery and the CO₂ capture and storage (EGR–CCS) process was analyzed. The results exhibit that the excess adsorption curves of CH₄ are smooth, and the experimental temperature has no noticeable effect on the shape of curves. At the same time, a “sharp peak” is recorded in the excess adsorption curves of CO₂ at low temperatures (30 and 55 °C) near the critical pressure, which is quite distinct from the smooth curves at high temperatures (80 and 100 °C). Correspondingly, there are two “jump pressure” values in the density curves (30 and 55 °C) of the adsorption system and the density curves are divided into three stages. The Dubinin–Astakhov and Brunauer–Emmett–Teller (BET) models show an optimum degree of fit for CH₄ and CO₂ adsorption curves under all experimental temperature and pressure conditions. The Langmuir model fits the adsorption curves of 80 and 100 °C better, while the BET model is appropriate for 30 and 55 °C. The adsorption affinity of CO₂ is higher than CH₄, with the value of αCO₂/CH₄ in the range of 2.47–12.16. The value of αCO₂/CH₄ increases with a rise in pressure but is inhibited by high temperatures, while the inhibition is negligible when the experimental temperature exceeds 80 °C. The adsorption preferential of CO₂ is stronger in the shallow reservoir (αCO₂/CH₄ > 10.5), and the application prospect of the EGR process is promising. In contrast, the adsorption preferential is slightly weakened in the deep reservoir (αCO₂/CH₄ < 4.5), which can be considered for CO₂ capture, utilization, and storage. Results from this investigation provide novel insights on the adsorption characteristics of CH₄ and CO₂ on the shale matrix at high pressure and temperature. They are also expected to give certain enlightenment for the EGR–CCS process.

Superimposed accumulation mechanism and model of vertical source rock–reservoir system of coal-measure gas is crucial to evaluate the exploration potential, and also the basis of co-exploration and co-production of coal measure gas. This work investigates the formation mechanism of various types of reservoirs (coalbed methane, shale gas, tight sandstone) in the Taiyuan Formation (Yushe-Wuxiang Block, eastern Qinshui Basin). Source rocks (coal seams and coal-measure mudstones) in the study area are characterized by type III kerogen, organic rich and over-mature, and reach a gas generation peak during the Early to Late Cretaceous. Coalbed methane mainly adsorbs on the surface of micropores, shale gas mainly occurs in micropores, macropores and micro-factures in adsorbed and free states, and tight sandstone gas mainly occurs in macropores in a free state. The combinations of successions are identified, coalbed methane, shale gas, and tight sandstone gas horizons are divided into a mudstone-sandstone reservoir (combination I), a coal-mudstone-sandstone reservoir (combination II), and a coal-mudstone reservoir (combination III). This division occurs from top to bottom in the succession and is identified on the basis of lithology, total organic carbon content (TOC) of mudstones, gas logging, superimposition relationships, and the source rock-reservoir-caprock assemblage. The strata thickness, continuity, and gas logging results of combination III comprise the most favorable conditions for fairly good development potential, followed by combination I. The development potential of combination II is poor due to the small strata thickness and poor continuity. The identification of superimposed reservoirs can provide an engineering reference for the exploration of coal-measure gas.

Pore structure and methane adsorption of coal reservoir are closely correlated to the coalbed gas occurrence and outburst. Full-scale pore structure and its fractal heterogeneity of coal samples were quantitatively characterized using low-pressure N₂ gas adsorption (LP-N₂GA) and high-pressure mercury intrusion porosimetry (HP-MIP). Fractal pore structure and adsorption capacities between outburst and nonoutburst coals were compared, and their geological significance to gas occurrence and outburst was discussed. The results show that pore volume (PV) is mainly contributed by macropores (>1000 nm) and mesopores (100–1000 nm), while specific surface area (SSA) is dominated by micropores (<10 nm) and transition pores (10–100 nm). On average, the PV and SSA of outburst coal samples are 4.56 times and 5.77 times those of nonoutburst coal samples, respectively, which provide sufficient place for gas adsorption and storage. The pore shape is dominated by semiclosed pores in the nonoutburst coal, whereas open pores and inkbottle pores are prevailing in the outburst coal. The pore size is widely distributed in the outburst coal, in which not only micropores are dominant, but also, transition pores and mesopores are developed to a certain extent. Based on the data from HP-MIP and LP-N₂GA, pore spatial structure and surface are of fractal characteristics with fractal dimensions [ ] (2.81–2.97) and [ ] (2.50–2.73) calculated by Menger model and Frenkel–Halsey–Hill (FHH) model, respectively. The pore structure in the outburst coal is more heterogeneous as its [ ] and [ ] are generally larger than those of the nonoutburst coal. The maximum methane adsorption capacities ([ ]: 15.34–20.86 cm³/g) of the outburst coal are larger than those of the nonoutburst coal ([ ]: 9.97–13.51cm³/g). The adsorptivity of coal samples is governed by the micropores, transition pores, and [ ] because they are positively correlated with the SSA. The outburst coal belongs to tectonically deformed coal (TDC) characterized by weak strength, rich microporosity, complex pore structure, strong adsorption capacity, but poor pore connectivity because of inkbottle pores. Therefore, the area of TDC is at high risk for gas outburst as there is a high-pressure gas sealing zone with abundant gas enrichment but limited gas migration and extraction.

Abnormal H₂S concentration in coal mine gas is a serious threat to normal mining activities, which has caused serious loss of life and property in many coal mines. This study explores the genesis and influencing factors of abnormal H₂S concentration in coal mine gas, taking the Xishan coal mine in the Fukang mining area as a case study. The H₂S formation by bacterial sulfate reduction (BSR) is simulated with a bacterial culture experiment and that by thermochemical sulfate reduction (TSR) is simulated with a thermal reduction experiment. The potential for a magmatic genesis is assessed using data regarding the tectonic evolution and history of magma intrusion in the study area. The factors influencing H₂S formation and enrichment are then analyzed by a comprehensive consideration of the characteristics of coal, the gas composition, the coal seam groundwater geochemistry and other geological factors in the study area. The results show that the study area meets the necessary conditions for the BSR process to operate and that there is widespread BSR derived H₂S. TSR genesis H₂S mainly forms in coal fire areas and their vicinity, while there is little contribution from magmatically formed H₂S. The concentration of H₂S is negatively correlated with the buried depth of the coal seam, the concentrations of CH₄, N₂ and CO₂, and the ash yield; and it is positively correlated with the volatiles yield and total sulfur content. In addition, in areas with abnormally high H₂S concentration, the concentration of SO₄²⁻ is obviously lower, HCO₃⁻ + CO₃²⁻ concentration is higher, and the HCO₃⁻/SO₄²⁻ value is larger than that in non-anomalous areas. Geologically, H₂S enrichment is found to be controlled by lithology, tectonism, and hydrogeological conditions. Moreover, the results of predictive modeling show that areas prone to abnormal H₂S concentration are generally spatially correlated with coal fire areas. In this study, the genetic types of H₂S and the factors controlling their formation and retention are discussed, producing research results that have guiding significance for the prediction and prevention of the coal mine disasters that arises from abnormal H₂S concentration.

CO₂ is the main greenhouse gas in Earth's atmosphere, and has been causing global warming since the industrial revolution. Therefore, technologies to mitigate carbon emissions have attracted extensive research. Shale gas reservoirs could serve as potential sequestration space for CO₂. This paper aims to gain insight in the CO₂ adsorption behavior and mechanism in Longmaxi shale. The micropore filling theory is the best model for CO₂ adsorption in the shale samples with the smallest MSR (Mean Square of Residual). This model fits better than that of the monolayer adsorption and multi-layer adsorption theories. Specifically, micropore filling adsorption mainly occurs in micropores, including the closed end of slit pores, capillary pores, and ink-shaped pores. Molecular layer adsorption mainly occurs in mesopores and macropores, including the open end of slit pores, plate pores, capillary pores, and ink-shaped pores. Moreover, the prediction model of CO₂ storage quantity in deep shale gas reservoirs of China is established. This model shows that 91.5–388.89 × 10¹² m³ of CO₂ could in theory be stored in an adsorbed state. CO₂ is mostly stored by an adsorbed state (higher than 95%) and a free state with good security and low leakage risk. The results from this work are of specific interest for global research on CO₂ adsorption characteristics and adsorption mechanisms in different pore structures. Furthermore, it provides certain guidance for geological storage of CO₂ in shale.