Recently, the accumulation of shale gas and shale oil in the rifted lacustrine basin of China has garnered increasing interest. In this paper, the shale located in the Shahejie Formation of the Liaohe western depression of the Bohai Bay Basin was selected as the focus of a comprehensive evaluation of the geological controls of shale gas and shale oil accumulation. (1) In a rifted lacustrine basin, the subsidence rate of the stratigraphy is rapid, which results in a massive sedimentation of organic-rich shale. The shale that developed in the deep and semi-deep lacustrine facies is characterized by a high concentration of organic matter, with an average total organic carbon (TOC) content over 2.0% being measured. The TOC consists primarily of type I-II 1 kerogen, which contains abundant sapropelic materials and has relatively low thermal maturity, ranging from 0.4 to 0.9%R o , due to the shallow burial depth and the young deposition epoch. (2) Various pore-fractures in the core samples and erosion occurring in the calcareous and dolomitic shales were observed, which provide storage space for oil-gas accumulations. Furthermore, the mechanisms of the accumulation of shale gas and shale oil in the study area were established according to analyses of the geochemistry characteristics and the sedimentary environment, as well as a thermal pressure simulation experiment. Overall, the accumulation model of shale oil-gas is characterized by "upper oil and lower gas". In addition, oil-gas resources in siltstone, dolomite and limestone, which are adjacent to or interbedded with organic-rich shale, are also important targets in shale reservoirs.

The southeastern Chongqing area, one of the highest potential shale gas accumulation areas in China, experienced strong tectonic movements. Due to the tectonic uplift in Himalayan period, the target shale formation is characterized by shallow burial depth and abundant fractures. The Lower Silurian Longmaxi shale was deposited under deep and shallow continental shelf environments with abundant pyrites and graptolite fossils. The lithology of the formation includes black carbonaceous shale, calcareous shale, and siliceous shale. The thickness of the shale varies greatly from 40 to 200 m from southeast to northwest with obvious zonation. Total organic carbon (TOC) content ranges from 1.0 to 4.0% and decreases upward in the formation owing to the change of sedimentary facies. The organic matter reaches dry gas zone. Porosity ranges from 0.5 to 7.9%, and the permeability is measured in the microdarcy to nanodarcy range. Abundant fragile minerals exist in the shales which benefit the hydraulic stimulation. Isothermal adsorption tests show that the sorption gas content in place of the Longmaxi shale ranges from 1.0 to 4.5 m 3 /t and the gas content in place reaches the standard of commercial exploitation. Factors impacting gasbearing characteristics were analyzed using a mathematical statistic method, which demonstrates that TOC is the most important factor, especially to the sorption gas content. Meanwhile, clay content, thermal maturity, porosity, and mineral components are also significant factors regarding shale gas-bearing characteristics.

In situ gas content is an important parameter associating coalbed methane, while the influence of pressure and temperature on methane adsorption and desorption still needs to be revealed. In this study, the molecular structure and methane adsorption capacity of anthracite coal collected from Diandong Coalfield (China) were studied based on 13C nuclear magnetic resonance (13C NMR), Fourier transform infrared spectroscopy (FT-IR), and methane isothermal adsorption experiment. The results show that the carbon skeleton of coal sample is mainly composed by aromatic carbon (72%), followed by aliphatic carbon structure (14.2%). Carbons connected to the oxygen atoms contribute 13.7% of the total carbons in coal molecule, and the oxygen atoms are mainly in the form of carbonyl. The 2-dimension structure and 3-dimension molecular structure of coal sample was also reconstructed. The average chemical formula of the coal molecule is C200H133O21N3. The experimental methane adsorption isothermal data of the coal sample under different temperatures shows that with increasing the temperature, the methane adsorption amount at each pressure decreases obviously. At 7 MPa and 20°C, the methane adsorption amount of the coal sample is 28.5 cm3/g. Comparably, at 100°C and 7 MPa, the methane adsorption amount is only 15.9 cm3/g, decreasing by 44%. In mesopores, temperature has stronger influence on methane adsorption under higher pressure than that of lower pressure. On the contrary, in micropores, temperature has weaker effects on methane adsorption at higher pressure than that at lower pressure. The results can be beneficial for understanding methane adsorption characteristics of deep coal.

Geological storage of carbon dioxide is receiving more and more attention as one of the efficient carbon reduction technologies, as China's carbon-neutral strategic plan moves forward. There is an increasing demand for more effective and thorough methodologies to assess the potential of CO 2 storage in deep saline aquifers. This study proposes a method for evaluating the geological storage potential of CO 2 in deep saline aquifers and constructs an automatic evaluation system for the comprehensive potential of CO 2 geological storage using ArcGIS Model Builder visual modeling technology. The automatic evaluation system consists of four functional parts: information collating and database constructing, data pre-processing, model building evaluation and result validation evaluation. First, structured and unstructured data including underlying geology, tectonic geology, oil and gas geology, and drilling data are collated and established in a geodatabase. Second, pre-processing models of the deep saline reservoir-caprock data are established based on the analysis of the geological evolution history of the study area to determine the effective storage thickness, effective porosity, and the influence range of faults; kriging methods are then used to realize the spatial interpolation of the evaluation parameters. Third, the volume coefficient method is adopted to construct the underground storage space model and to establish the density distribution model of the supercritical CO 2 with nonlinear function while taking into account four evaluation factors (i.e. area, effective porosity, effective thickness, effective coefficient) and two limiting factors (i.e. fault, burial depth). Finally, the geological storage potential of CO 2 in the study area is evaluated with the classification of the potential level and compared with the numerical simulation results to verify the model's accuracy. The model is first applied in this paper using a suitable target in China as a case study. The results show that this target area's anticipated storage potential value reaches 52.557 Mt. The total precision error, according to a comparison of the numerical simulation results, is 8.20%. Based on the results obtained, it can be concluded that the automatic GIS-based modeling approach is suitable for a comparable study of potential evaluation of CO 2 geological storage in deep saline aquifers.

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