Microstructural characterisation of organic matter pores in coal-measure shale

Marine shales from the Niutitang Formation and marine–continental transitional shales from the Longtan Formation are two sets of extremely important hydrocarbon source rocks in South China. In order to quantitatively compare the pore complexity characteristics between marine and marine–continental transitional shales, the shale and kerogen of the Niutitang Formation and the Longtan Formation are taken as our research subjects. Based on organic petrology, geochemistry, and low-temperature gas adsorption analyses, the fractal dimension of their pores is calculated by the Frenkel–Halsey–Hill (FHH) and Sierpinski models, and the influences of total organic carbon (TOC), vitrinite reflectance (R_o), and mineral composition on the pore fractals of the shale and kerogen are discussed. Our results show the following: (1) Marine shale predominantly has wedge-shaped and slit pores, while marine–continental transitional shale has inkpot-shaped and slit pores. (2) Cylindrical pores are common in organic matter of both shale types, with marine shale having a greater gas storage space (CRV) from organic matter pores, while marine–continental transitional shale relies more on inorganic pores, especially interlayer clay mineral pores, for gas storage due to their large specific surface area and high adsorption capacity (CRA). (3) The fractal characteristics of marine and marine–continental transitional shale pores are influenced differently. In marine shale, TOC positively correlates with fractal dimensions, while in marine–continental shale, R_o and clay minerals have a stronger influence. R_o is the primary factor affecting organic matter pore complexity. (4) Our two pore fractal models show that the complexity of the shale in the Longtan Formation surpasses that of the shale in the Niutitang Formation, and type I kerogen has more complex organic matter pores than type III, aiding in evaluating pore connectivity and flow effectiveness in shale reservoirs.

The injection of CO₂ into shale gas reservoirs can not only enhance shale gas recovery (ESGR), but also realize CO₂ geological storage (CGS). In this study, the competitive adsorption behaviors of CO₂ and CH₄ in shale were systematically reviewed, and the implication for shale gas recovery efficiency and CO₂ storage potential were discussed. The adsorption advantage of shale for CO₂ compared to CH₄ provides a guarantee of the feasibility of supercritical CO₂ (ScCO₂) enhanced shale gas exploitation technology. The selective adsorption coefficient of CO₂ and CH₄ by shale (S CO₂/CH₄ ) is an important parameter in evaluating the competitive adsorption behavior of CO₂/CH₄ in shale gas reservoirs, which is closely related to the mineral composition, reservoir temperature, pressure conditions, water content, and mixed gas composition ratio. In addition, the injection type, injection mode, and injection rate of gases also exhibit different effects on CO₂/CH₄ competitive adsorption. Furthermore, the interaction between ScCO₂ and the water-rock system will change the mineral composition and microstructure of shale, which will lead to changes in the adsorption behavior of shale on CO₂ and CH₄, so its influence on the competitive adsorption of CO₂/CH₄ cannot be ignored. Future research should integrate different research methods and combine with practical engineering to reveal the competitive adsorption mechanism of CO₂/CH₄ in shale reservoirs from both micro and macro aspects. This study can provide support for the integration technology of ScCO₂ enhanced shale gas exploitation and its geological storage.

Natural gas generation is the result of organic matter degradation under the effects of biodegradation and thermal degradation. Early Cambrian black shales in the Upper Yangtze Region are rich in organic matter and have shown great shale gas potentiality in recent years. Nevertheless, the enrichment mechanism and distribution of organic matter in these black shales between different sedimentary settings, such as intra-platform basin, slope, and deep basin, are still poorly understood. In this paper, based mainly on elemental geochemistry, a comprehensive study of the marine redox conditions, primary productivity, sedimentation rate, terrigenous input, hydrothermal activity, and water mass restrictions was conducted on the Early Cambrian Niutitang black shale in the Upper Yangtze Region. Our data showed that an intra-platform basin received a higher terrigenous input and that it deposited under more restricted conditions than the slope and deep basin settings. The primary productivity in the slope and deep basin settings was higher than that in the intra-platform basin setting. In the intra-platform basin, the productivity increased from its inner part to its margin. For the slope and deep basin settings, the high paleoproductivity generated large amounts of organic matter and its preservation was synergistically affected by the redox conditions. In contrast to the slope and deep basin, the preservation of organic matter in the inner part of the intra-platform basin was mainly controlled by redox conditions because the paleoproductivity in it was much lower than in the slope and deep basin settings. The intra-platform basin margin was the most favorable area for accumulating organic matter.