The water adsorption performance of shale gas reservoirs is a very important factor affecting their gas in place (GIP) contents, but the water-holding capacity and mechanism of over-mature shale, especially organic pores, are still not fully understood. In this study, systematic water vapor adsorption (WVA) experiments were carried out on the Lower Cambrian over-mature shale and its kerogen from the Sichuan Basin, China to characterize their WVA behaviors, and combined with the low-pressure gas (N₂ and CO₂) adsorption experiments, the main influencing factors of WVA capacity of the shale and the absorbed-water distribution in its organic and inorganic nanopores were investigated. The results show that the WVA isotherms of shale and kerogen are all type Ⅱ, with an obvious hysteresis loop in the multilayer adsorption range, and that the positive relationship of the shale TOC content with the WVA capacity (including total adsorption capacity, primary adsorption capacity and secondary adsorption capacity) and WVA hysteresis index (AHIW), and the greater adsorption capacity and AHIW of kerogen than the shale, all indicate that the hydrophilicity of organic matter (OM) in the over-mature shale was underestimated in previous research. Although both the shale OM and clay minerals have a significant positive effect on the WVA, the former has a stronger adsorption ability than the latter. The WVA capacity of the studied Lower Cambrian shale is significantly greater than that of the Longmaxi shale reported in literatures, which was believed to be mainly attributed to its higher maturity, with a significant graphitization of OM. The shale micropores and non-micropores play an important role in WVA, especially OM pores. There are primary and secondary adsorption for water vapor in both the micropores and non-micropores of OM, while these adsorptions of minerals mainly occur in their non-micropores. These results have important guides for understanding the gas storage mechanism and exploration and development potential of marine over-mature shale in southern China, especially the Lower Cambrian shale.

Methane adsorption is a critical assessment of the gas storage capacity (GSC) of shales with geological conditions. Although the related research of marine shales has been well-illustrated, the methane adsorption of marine-continental transitional (MCT) shales is still ambiguous. In this study, a method of combining experimental data with analytical models was used to investigate the methane adsorption characteristics and GSC of MCT shales collected from the Qinshui Basin, China. The Ono-Kondo model was used to fit the adsorption data to obtain the adsorption parameters. Subsequently, the geological model of GSC based on pore evolution was constructed using a representative shale sample with a total organic carbon (TOC) content of 1.71%, and the effects of reservoir pressure coefficient and water saturation on GSC were explored. In experimental results, compared to the composition of the MCT shale, the pore structure dominates the methane adsorption, and meanwhile, the maturity mainly governs the pore structure. Besides, maturity in the middle-eastern region of the Qinshui Basin shows a strong positive correlation with burial depth. The two parameters, micropore pore volume and non-micropore surface area, induce a good fit for the adsorption capacity data of the shale. In simulation results, the depth, pressure coefficient, and water saturation of the shale all affect the GSC. It demonstrates a promising shale gas potential of the MCT shale in a deeper block, especially with low water saturation. Specifically, the economic feasibility of shale gas could be a major consideration for the shale with a depth of <800 m and/or water saturation >60% in the Yushe-Wuxiang area. This study provides a valuable reference for the reservoir evaluation and favorable block search of MCT shale gas.

The Lower Cambrian shale gas in the western Hubei area, South China has a great resource prospect, but the gas-in-place (GIP) content in different sedimentary facies varies widely, and the relevant mechanism has been not well understood. In the present study, two sets of the Lower Cambrian shale samples from the Wells YD4 and YD5 in the western Hubei area, representing the deep-water shelf facies and shallow-water platform facies, respectively, were investigated on the differences of pore types, pore structure and methane adsorption capacity between them, and the main controlling factor and mechanism of their methane adsorption capacities and GIP contents were discussed. The results show that the organic matter (OM) pores in the YD4 shale samples are dominant, while the inorganic mineral (IM) pores in the YD5 shale samples are primary, with underdeveloped OM pores. The pore specific surface area (SSA) and pore volume (PV) of the YD4 shale samples are mainly from micropores and mesopores, respectively, while those of the YD5 shale samples are mainly from micropores and macropores, respectively. The methane adsorption capacity of the YD4 shale samples is significantly higher than that of the YD5 shale samples, with a maximum absolute adsorption capacity of 3.13 cm³/g and 1.31 cm³/g in average, respectively. Compared with the shallow-water platform shale, the deep-water shelf shale has a higher TOC content, a better kerogen type and more developed OM pores, which is the main mechanism for its higher adsorption capacity. The GIP content models based on two samples with a similar TOC content selected respectively from the Wells YD4 and YD5 further indicate that the GIP content of the deep-water shelf shale is mainly 3−4 m³/t within a depth range of 1000–4000 m, with shale gas exploration and development potential, while the shallow-water platform shale has normally a GIP content of <1 m³/t, with little shale gas potential. Considering the geological and geochemical conditions of shale gas formation and preservation, the deep-water shelf facies is the most favorable target for the Lower Cambrian shale gas exploration and development in the western Hubei area, South China.

In the past 15 years, the shale gas revolution and large-scale commercial developments in the United States have driven the exploration and development of shale plays worldwide. Among many factors affecting shale gas exploration potential, the gas-bearing properties of shale (quantity, storage state, composition) and their controlling factors are the essential research attracting wide attention in the academic community. This paper reviews the research progress on the retention mechanism, influencing factors, and evaluation methods for resource potential of the shale gas system, and proposes further research directions. Sorption is the main mechanism of gas retention in organic-rich shales; the gas is mainly stored in nanopores of shale in free and sorption states. The presence of water and non-hydrocarbon gases in pores can complicate the process and mechanism of methane (CH₄) sorption, and the related theoretical models still need further development. The in-situ gas content and gas-bearing properties of shale are governed by the geological properties (organic matter abundance, kerogen type, thermal maturity, mineral composition, diagenesis), the properties of fluids in pores (water, CH₄, non-hydrocarbon gases), and geological conditions (temperature, pressure, preservation conditions) of the shale itself. For a particular basin or block, it is still challenging to define the main controlling factors, screen favorable exploration areas, and locate sweet spots. Compared to marine shales with extensive research and exploration data, lacustrine and marine-continental transitional shales are a further expanding area of investigation. Various methods have been developed to quantitatively characterize the in-situ gas content of shales, but all these methods have their own limitations, and more in-depth studies are needed to accurately evaluate and predict the in-situ gas content of shales, especially shales at deep depth.