Tectonism is one of the major controlling factors of shale gas accumulation and enrichment in China. To explore the relationship between tectonism and composition and pore characteristics of shale reservoirs, this research carried out mineralogy tests, organic geochemistry tests, field emission scanning electron microscopy (FE-SEM) experiments, and low-pressure gas adsorption (LPGA, N2 and CO2) experiments on the shale samples of various deformation intensities from Southwestern China. Based on the FE-SEM image analyses, it can be found that there are large differences in pore characteristics in shale samples with different deformation intensities. The samples with strong deformation have more organic pores, mainly related to the clay-organic aggregates and rigid grains. Tectonism can cause organic matter (OM) and clay minerals to be mixed or OM to fill in the clay layers, resulting in the retention of some organic pores. It is the presence of pressure shadows around the rigid grains that can resist tectonic extrusion and protect some organic pores. LPGA experiment results also show that micropore-specific surface areas and pore volumes of the samples with strong deformation are larger than those with weak deformation. The shale samples with strong deformation also have more microchannels and microfractures. Tectonism can also cause some micropores to become macropores; for example, tectonism can cause the rigid grains to slide and rotate, enlarging the dissolution pores at the edges of rigid grains. Shale samples with strong deformation have a smaller mesopore volume; but due to the presence of organic-clay aggregates, a larger mesopore-specific surface area embarks on these samples. According to fractal dimension calculations, it is found that in strong deformed shale, more multiple dimensions of the pore system tend to represent rougher pore surfaces and more irregular shapes. Besides, rougher pore surfaces are eager to provide more adsorption sites and enhance the adsorption capacity of the deformed shale. This study investigates the relationship between tectonism and composition and pore characteristics of shale reservoirs and may promote understanding of the accumulation of shale gas in highly deformed areas.

In the Luzhou Block of the southern Sichuan Basin, the deep Longmaxi shales have become important exploration targets in recent years. However, the water-bearing properties of these shales are still unclear, which significantly limits evaluations of reservoir pore structures and gas-in-place (GIP) contents. In this study, twelve fresh shale core samples were collected at the well site, and the pore water (CPW) and equilibrium water (CEW) contents, as well as the pore structures of the shales, were analyzed under both as-received and dried conditions. The results indicate that the deep shales have low water-bearing extents with a pore water content (CPW) of 3.82–16.67 mg/g, and that both the organic matter (OM) and inorganic matter (IM) pores can be used for pore water storage. The extent of influence of pore water on nonmicropores and IM pore structures is more significant than that on micropores and OM pore structures. Meanwhile, the pore water obviously reduces the retention effects of nanopores and may block nanopores with pore widths < 0.5 nm. An average of 40% of pore spaces were taken up by pore water in the studied deep shales in the Luzhou Block, and the residual pore surface area and pore volume of the shales were mainly contributed from micropores and nonmicropores, respectively.

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Shale strata generally contain a certain amount of pore water that accompanies the whole diagenetic and thermal evolution processes of shales. The distribution and occurrence characteristics of pore water significantly influence the nanopore structures of shales, which subsequently affects the accumulation and production of shale oil and gas resources. Based on a set of fresh Wufeng−Longmaxi (WL) shale samples from the deep marine strata in the southern Sichuan Basin, this study investigated the effects of pore water on the pore heterogeneity of shales by a multifractal method. The results show that (1) the deep WL shales have low pore water content (C PW ) and water saturation (S EW ), with average values of 7.47 mg/g and 35.21%, respectively, and the C PW and S EW of the shales are mainly controlled by clay mineral content. (2) Under dried conditions, the pore heterogeneity of high-probability measure areas has negative relationships with the clay mineral content and pore volumes with pore widths of 4−10 nm, and the pore connectivity is mainly controlled by clay mineral content. Under as-received conditions, however, the pore heterogeneity of low-probability measure areas and pore connectivity have positive relationships with clay mineral content and pore volumes with pore widths less than 4 nm. (3) Under as-received conditions, the pore water mainly occupies the nanopore with pore widths less than 4 nm and reduces the effective pore spaces and connectivity, which reduces the pore heterogeneity of high-probability measure areas and enhances the pore heterogeneity of low-probability measure areas.

Geological prediction models for gas content in marine-terrigenous shale under the effects of reservoir characteristics and in situ geological conditions, were established using methane isothermal adsorption, high temperature/pressure methane isothermal adsorption, total organic carbon, X-ray diffraction, mercury porosimetry, porosity in net confining stress, and field desorption methods. Results indicated that the adsorption capacity of marine-terrigenous shale has a linearly positive correlation with total organic carbon content and maturity. Clay and quartz minerals are the two main components of inorganic minerals in marine-terrigenous shale, with an average content of 54.3% and 36.9%, respectively. Adsorption capacity of marine-terrigenous shale is slightly positive correlated with clay content, while it exponentially decreases with increasing quartz content. The effects of in situ temperature and reservoir pressure on adsorption capacity in marine-terrigenous shale are also significant. The adsorption capacity of marineterrigenous shale shows a clear decreasing trend as temperature increases, while it increases with increasing reservoir pressure. The porosity of marine-terrigenous shale is characterized by highly stress-sensitive, decreasing exponentially with increasing effective stress, which results in a more complex occurrence of free gas in deep shale reservoirs. In addition, gas saturation for the shale samples was calculated based on the results of field desorption, after which geological prediction models of total gas, adsorbed gas, and free gas were established while considering the coupled

Due to breakthroughs in the Lower Silurian Longmaxi Formation in the Sichuan Basin and multiple strata around the basin, the northern part of Guizhou adjacent to the Sichuan Basin has become a key area for shale gas exploration. Compared with the Longmaxi Formation, the Niutitang Formation displays greater TOC (total organic carbon) content, depositional thickness and distribution area, but the details remain undetermined. In the study area, the Lower Cambrian Niutitang Formation typically has high TOC content, maturity and brittle mineral content. The study area has experienced multiple periods of tectonic movement, which have great influence on the fracture and pore characteristics. The fractures are mainly structural fractures and have obvious zoning. The primary types of pores are intraparticle pores, organic matter pores, and interparticle pores. Further, macropores and mesopores less than 50 nm contribute most of the pore volume, while pores less than 2 nm contribute most of the specific surface area. Many factors affect the pore-fracture system, such as tectonism, TOC content, mineral composition, and sedimentary environment. Tectonic movements produce fractures based on the changing stress field, but the degree of fracture development does not agree well with the degree of pore development. The TOC content has good positive correlations with the development of fractures and micropores, especially for nanoporosity, while clay minerals show a negative correlation with the development of fractures but a strong positive correlation with the growth of micropores. Quartz displays a positive correlation with the development of fractures but no good correlation with pore development. Finally, the lithofacies, lithologies and mineral compositions under the control of sedimentary environments are internal factors that can impact the development of pore-fracture systems.

Shales are widely developed in the strata of the Carboniferous-Permian coal measures in the Qinshui Basin, and these shales have great potential for shale gas exploration. In this paper, the shales of the Taiyuan Formation in the eastern Qinshui Basin are studied. The shales of the Taiyuan Formation in the study area are investigated through field investigation, organic geochemical testing, X-ray diffraction, scanning electron microscopy, high pressure mercury injection, low temperature liquid nitrogen adsorption and PetroMod simulation and through other tests to study the reservoir characteristics, such as organic geochemistry, mineralogy, petrology, pore permeability, and gas burial history. The results show that the shales of the Taiyuan Formation are well developed over the whole area with a thickness of more than 60 m. The average organic matter content is 2.95%, and the kerogen type is type III. The shale maturity (average value is 2.45%) corresponds to the stage of high maturity evolution, indicating that a large amount of shale gas has been generated in this area. A high content of quartz and clay minerals indicates a high fracturability. The nanopores in the shale reservoir are well developed at pore sizes between 2˜10 nm and greater than 1000 nm; however, the pores at the other pore sizes are poorly developed, resulting in weak pore connectivity in the reservoir. According to the results of the PetroMod simulation, the shale of the Taiyuan Formation has undergone two subsidence and two uplift processes. The Yanshanian magmatic intrusion is the key factor for the rapid increase in gas production. In addition, the geological structure of the area is relatively simple, and the burial history and caprock thickness are also the main controlling factors of gas generation and preservation. The shale-sandstone-shale combination and shale-coal-shale combination are the main models of shale gas preservation. This comprehensive study suggests that the shale gas of the Taiyuan Formation in the eastern Qinshui Bain has good potential for exploration and development.

Deep shale gas (>3500 m) is a promising fossil energy resource in the context of global efforts to achieve carbon neutrality. However, the accumulation, enrichment, and distribution of deep shale gas are complicated, which makes the gas-inplace (GIP) content and its main controlling factors of deep shales unclear. In this study, a group of deep shale samples with burial depths of 4200−4350 m were collected from the Wufeng-Longmaxi (WF-LMX) formations from the middle Luzhou block, southern Sichuan Basin, and the TOC contents, mineralogical compositions, porosities, pore water contents, water saturations, and GIP contents of the shales were systematically investigated. The results indicate that the TOC and brittle mineral contents, water-bearing characteristics, and effective porosities are the main factors controlling the GIP contents of deep shales. The deep WF-LMX shales in the middle Luzhou block have high TOC and brittle mineral contents, low pore water content (C PW ), and water saturation (S W ), and great effective porosity, which benefits the generation, storage, and development of shale gas. The GIP contents of the deep WF-LMX shales are in the range of 1.36−7.17 cm 3 /g and are higher for the shales located in the lower sublayer of the first member of the Longmaxi formation (LMX1 1−3 ). In general, the deep WF-LMX shales in the middle Luzhou block have advantageous reservoir properties and GIP contents, which indicate great shale gas potential, and the LMX1 1−3 shales are the most promising exploration and development targets.