Since shale gas mainly occurs in shale pores, research on pore structure characteristics is the key to understanding the shale gas accumulation mechanism. The pore structure of the Lower Carboniferous Dawuba Formation shale in the Qianxi area, represented by the well QSD-1, which obtains a daily shale gas flow of 10,000 m³ and represents an important breakthrough in the investigation of marine shale gas in the Upper Paleozoic region of southern China, is characterized by high-pressure mercury compression experiments and low-temperature gas adsorption (N₂ and CO₂) experiments with whole pore size. The main controlling factors affecting the pore development of the shale are discussed. (i) The micropores and mesopores are more developed in the shale, and the macropores are the second most developed in the shales of the Dawuba Formation in the Qianxi area, among which the mesopores and macropores contribute most to the pore volume and the micropores and mesopores contribute most to the pore-specific surface area. (ii) The microfractures and interlayer pores of clay minerals are developed in the shales of the Dawuba Formation, which are the main storage spaces for hydrocarbon gases. (iii) The main factors affecting the adsorption capacity of the shales of the Dawuba Formation in the Qianxi area are the organic carbon content and clay mineral content of the shales, both of which have an obvious positive correlation with the variation of pore structure.

Organic matter (OM) enrichment is a fundamental control on source-rock quality and shale-gas potential, yet the relative roles of organic matter supply, preservation, and mineralogical dilution remain poorly constrained in the Lower Cambrian Niutitang Formation at the northwestern margin of the Upper Yangtze Platform. Nineteen shale samples from Well ZHD1 in the Zhenba area, on the northwestern Upper Yangtze Platform, were analyzed for total organic carbon (TOC), mineral composition, and major and trace elements. TOC contents range from 0.98% to 9.09%, with an average of 3.82%, while quartz and clay minerals range from 25% to 44% and from 27% to 53%, respectively. Among the sampled intervals, the middle interval (1694.00~1709.75 m) is characterized by the highest TOC contents (4.48~9.09%), accompanied by elevated Si_excess (10.95~11.67), U/Th (2.60~6.84), Mo_EF (16.83~34.38), and U_EF (9.74~23.85). In contrast, Ti/Al and CIA show relatively limited variations across the sampled section. Quartz is positively related to TOC, whereas clay and carbonate minerals show negative relationships with TOC. Paleoproductivity increased from the lower interval to a maximum during the middle interval and then declined during the upper interval. Redox conditions evolved from moderately reducing to persistently anoxic during the middle interval before becoming less reducing. The middle interval records the highest TOC contents, greatest paleoproductivity, and most favorable preservation conditions. The combined Si_excess, mineralogical, and detrital-input evidence is consistent with a significant biogenic contribution to the non-detrital silica, although subordinate hydrothermal or authigenic contributions cannot be completely excluded. The negative relationships of clay and carbonate minerals with TOC are consistent with a net dilution effect at the bulk-rock scale, although potential clay-surface protection of OM cannot be excluded. These results emphasize the coupled effects of productivity and preservation rather than a single dominant control and provide region-specific constraints on OM enrichment in the northwestern Upper Yangtze Platform.

Recent shale gas drilling wells in southern China confirms significant resource potential within the Lower Carboniferous marine shale of the Yaziluo Rift Trough, yet exploration efficiency is hindered by poorly understood sedimentological heterogeneity and gas accumulation mechanisms. This study integrates major and trace elements, high-resolution field emission scanning electron microscopy, and adsorption analyses (low-pressure N₂/CO₂, high-pressure CH₄) to systematically characterize sedimentary facies, reservoir properties, and gas enrichment patterns. The trough exhibits an asymmetric "platform-basin" model with three distinct sedimentary facies. Basin facies comprise siliceous shale formed in deep-water anoxic settings, yielding the highest total organic carbon (TOC) content (average 3.63%) controlled by redox conditions and paleoproductivity. Lower slope facies consist of mixed shale in dysoxic environments, with moderate TOC (average 1.80%), dominated by redox conditions. Upper slope facies are calcareous shale in shallow, weakly reducing settings, showing the lowest TOC (average 0.99%), influenced by clay-mediated organic preservation. Reservoir analysis reveals that basin facies are dominated by organic pore, whereas lower slope facies display reduced organic pores but increased inorganic pores and micro-fractures, and upper slope facies shift predominantly to inorganic pores and microfractures. Moving from basinward to upper slope, increasing carbonate content expands dissolution pore networks, yet declining TOC diminishes organic pore development, promoting organic-clay complexes and weakening pore structure. Additionally, three shale associations classified by shale-to-argillaceous limestone ratios correspond to specific sedimentary facies. The lower slope shale association demonstrates optimal gas preservation due to high TOC, argillaceous limestone interlayers acting as direct caps, and fracture-enhanced porosity facilitating gas migration. The upper slope association shows promise for self-sealing bodies via acid fracturing despite lower TOC. In contrast, the basin facies shale association exhibits constrained gas retention capacity owing to clay-dominated mineralogy and absence of argillaceous limestone interlayers. This study emphasizes the critical role of lithofacies heterogeneity and integrated "source-reservoir-seal" configurations in evaluating of shale gas accumulation under "slope-basin" depositional architectures, providing a theoretical basis for reservoir development in analogous geological settings.

A breakthrough has been achieved in shale gas exploration of the Lower Carboniferous Shale in the Yaziluo Rift Trough, Dianqiangui Basin, with Well SY-1 yielding a daily gas production of 1.1 × 10⁴ m³. To clarify the main controls and evolutionary patterns of shale pore structure, shale samples from different sedimentary environments were analyzed using TOC content, X-ray diffraction (XRD), low-pressure gas adsorption (CO₂ and N₂), and field emission-scanning electron microscopy (FE-SEM). The results show that shale from the basin sedimentary environment (BSE) exhibits the highest TOC, is dominated by siliceous minerals (quartz + feldspar), and contains minor carbonate minerals (calcite + dolomite). Shale from the upper slope sedimentary environment (USSE) has the lowest TOC and is rich in carbonate minerals. The lower slope sedimentary environment (LSSE) shows intermediate compositions. From BSE to USSE, pore volume and specific surface area decrease, while fracture development increases. A quantitative model for volumes of organic pores, clay mineral-associated pores, and brittle mineral-associated pores was established. Organic pores dominate in BSE shale (65.42%), followed by clay mineral-associated and brittle mineral-associated pores, while inorganic pores dominate in USSE shale (63%). Pore structure in BSE and LSSE is primarily controlled by TOC content, with pore volume and surface area increasing with TOC content, while mesopore development is influenced by organic matter type and mineral compositions. In USSE, pore structure is mainly governed by inorganic minerals, with clay minerals promoting pore volume and surface area development, whereas brittle minerals facilitate the preservation of macropores. Evolutionary models of pore development were established for these distinct sedimentary environments.

The thermal history of carbonate successions is fundamental to constraining hydrocarbon generation and reservoir diagenesis, yet traditional proxies such as vitrinite reflectance and apatite fission-track analysis are often inapplicable to marine carbonates because organic matter and suitable heavy minerals are scarce. This study evaluates an integrated carbonate isotope (Δ₄₇) thermometry and in situ U-Pb geochronology approach using a micrite matrix and three dolomite-bearing samples from the Upper Permian Changxing Formation in the Yuanba area, northern Sichuan Basin, southwestern China. The measured apparent clumped isotope temperatures (TΔ₄₇) range from 127.8 to 174.6 °C. The micrite matrix yields a U-Pb age of 257 ± 1.2 Ma, consistent with an early depositional or syndepositional origin, whereas the dolomite samples yield younger diagenetic ages. Coupling these time–temperature constraints with an exchange–diffusion model for solid-state reordering provides a preliminary, well-scale thermal scenario for the sampled intervals. The preferred model suggests rapid heating during Late Permian–Early Triassic and Middle Jurassic burial, followed by peak heating to approximately 220 °C in the Late Cretaceous at modeled maximum burial depths exceeding 8000 m, and subsequent cooling during Yanshan–Himalayan uplift and denudation. A conditional maturity model predicts that the underlying Wujiaping Formation source rocks entered the main gas-generation window (1.3% < Ro < 2.6%) by the Middle Jurassic and became overmature during peak heating in the Late Cretaceous. This dual-proxy framework is promising for carbonate-dominated petroleum systems but requires validation with a larger sample set and independent thermal indicators.