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The pores of continental shale reservoirs contain a large amount of complex shale oil fluid. Shale pore spaces are extremely small, primarily at the nanometer scale, and exhibit intense fluid–rock interactions, making it challenging to provide detailed fluid composition and distribution within the micronano pores of continental shale. Hence, this study uses lacustrine shale oil from the Jiufotang Formation and Shahai Formation in the Ludong Sag, Kailu Basin. The pore size distribution was measured by low-temperature nitrogen adsorption with the different grain-sized rock samples after extraction to compare the fluid presence within different shale pores. The results show that as the shale grain size decreases, the relative content of small-molecule hydrocarbon-like saturates of rock extracts decreases, while the resin and asphaltene content increases. Strong positive correlations exist between total organic carbon and free hydrocarbon (pyrolysis parameter, S1), as well as between EOM (extracted organic matter) and S1. With the free hydrocarbon (S1) increasing, the EOM contents also increase, indicating that shale oil in the pores becomes more mobile. Changes in specific surface area (SSA) and micropore volume have a strong correlation with EOM content, whereas the relationship between changes in mesopore and macropore volumes and EOM content is very weak. The SSA and micropore volume of the extracted residue increase compared to those of the original sample, while the macropore volume decreases. Shale pores are predominantly composed of medium to small pores with higher saturated hydrocarbon contents. Conversely, changes in macropore volume have the strongest correlation with the content among the hydrocarbon components, indicating higher resin proportions in the macropores. Shale pores are primarily occupied by mobile hydrocarbons, with smaller molecules like saturated hydrocarbons mainly found in medium to small pores, while larger polar molecules like resins are more abundant in larger pores. This study offers a new method for characterizing shale oil fluids within various micronano pore structures in shale.

Knowledge of CH4and CO2storage in pore systems of organic-rich shale can provide valuable perspectives on gas-bearing properties and CO2sequestration in shale reservoirs. To finely characterize the angstrom-scale pores and investigate their role in CH4/CO2storage behaviors, this study examines 14 Lower Cambrian Niutitang shale samples by using an array of experiments, including total organic carbon (TOC) content tests, optical observations, section analysis, X-ray diffraction analysis, field-emission scanning electron microscopy (FE-SEM), low-pressure CO2adsorption (LPGA-CO2), and isothermal adsorption experiments. FE-SEM images reveal the presence of three main types of pores in the studied samples: intraparticle organic pores, dissolved intrapores within quartz particles, and intercrystal pores of clay minerals. Furthermore, the pore size distribution (PSD) curves from LPGA-CO2possess two prominent peaks, and the pore structure parameters show significant linear covariations with the TOC, clay, quartz, and dolomite contents. The pore structure information exhibits multifractal behavior, and the Q-type cluster analysis on generalized fractal dimension spectrum parameters reveals two distinct types of samples. Type I samples have a stronger degree of PSD heterogeneity, whereas type II samples have better pore connectivity. By virtue of the spherical pore and conceptual pore-filling models, we demonstrate that CO2has a higher storage volume in the angstrom scale than CH4, whereas CH4has a higher ratio of the filling volume to the maximum adsorbed capacity. The filling capacity of CO2is 1.121–2.087 (an average of 1.473) times that of CH4. From the perspective of pore multifractality, higher pore heterogeneity results in stronger CH4and CO2storage capacities. The gas filling density in subnano-scale micropores changes with varying pore sizes, which differs from a constant value of the adsorbed gas density for mono-/multilayer adsorption in mesopores. Our findings can provide new geometrical constraints on gas storage behavior in shale reservoirs, which contributes to understanding the gas storage capacity and adsorbed-phase gas density.