Accurate evaluation of pore systems in shale reservoirs is critical for understanding fluid flow, gas storage capacity, and overall reservoir performance. Extensive research has been conducted on the micro- and nano-pore structure of shale reservoirs using various experimental methods and shale samples. However, discrepancies in sample preparation standards and experimental parameters—such as observation techniques and data interpretation—raise concerns about the reliability and comparability of these results across different shale reservoirs. This review systematically evaluates the current methods for characterizing shale pore systems, with particular emphasis on commonly used techniques such as scanning electron microscopy (SEM), gas adsorption, and CT scanning. Key challenges related to sample preparation (e.g., sample size) and experimental conditions (e.g., voltage and current) are discussed, as these factors can introduce significant inaccuracies into pore structure characterization, even for well-established methods. Additionally, we examine the difficulties in integrating these methods to achieve a comprehensive understanding of shale pore parameters, including the quantification of organic and inorganic porosity, full-scale pore size distribution, and pore connectivity. Addressing these challenges requires the establishment of standardized processing workflows to enhance the comparability of results and minimize experimental errors. We also highlight often-overlooked issues, such as the potential discrepancy between pore structures observed under laboratory conditions and those at in-situ depths. The review concludes with recommendations for future research, including the development of advanced experimental techniques and more efficient data processing strategies to improve pore characterization in shale reservoirs. This review provides a new perspective for future research and addresses a critical gap in understanding the impact of experimental conditions on pore structure characterization outcomes.

Intracratonic strike-slip faults in central-western China's Tarim Basin serve as critical conduits for hydrocarbon migration and accumulation. This study integrates geochemical characterization, in-situ calcite U-Pb geochronology, and fluid inclusion microthermometry to resolve the long-debated temporal relationships between tectonic reactivation and hydrocarbon charging processes in the ultra-deep Shunbei fault system. Through systematic analysis of reservoir oils and fracture-filling calcites from the Shunbei Nos. 4, 6, and 8 fault zones, we establish a novel chronological framework combining differential hydrocarbon accumulation with fault activation phases. Building upon previous structural analyses, our U-Pb geochronology resolves four distinct tectonic phases for the No. 4 fault: Middle–Late Caledonian (473 ± 12 Ma and 443 ± 17 Ma), Late Caledonian–Early Hercynian, Middle–Late Hercynian, and Indosinian–Yanshanian, while the No. 8 fault exhibits four episodes spanning Middle–Late Caledonian (453.5 ± 2.5 Ma, 413 ± 29 Ma) to Indosinian-Yanshanian (196 ± 57 Ma). Hydrocarbon charging occurred through four discrete phases, with No. 8 fault demonstrating earlier petroleum emplacement (principal oil: 294 ± 29 Ma; principal gas: 196 ± 57 Ma) relative to No. 4 fault (principal oil: 282–205 Ma; principal gas: 196–11 Ma). MDR-MPI-1 correlations reveal hydrothermal influence on select oils, causing maturity overestimation. Fluorescence spectra (λ_max <445 nm) and geochemical indices (vitrinite reflectance equivalent: 1.2%–1.6%) confirm high thermal maturity. Stable carbon isotopes (δ¹³C₁ < δ¹³C₂) confirm normal genetic oil-type gas with low thermal maturity. Diamondoid indices and gas compositional trends (ln(C₂/C₃) vs. δ¹³C₂–δ¹³C₃) demonstrate predominant kerogen-derived methane with subordinate oil-cracked contributions. Enhanced vertical connectivity and elevated source maturity in No. 8 fault account for its preferential hydrocarbon enrichment. This work establishes a genetic linkage between multi-phase fault activation and differential hydrocarbon accumulation, providing an innovative methodology for evaluating ultra-deep reservoirs in cratonic basins through coupled geochronological-hydrocarbon fluid inclusion analysis.

The natural gas heavy carbon isotope and high dryness coefficients genesis in Tabei uplift, Tarim Basin has been highly controversial. To investigate the generation mechanisms of natural gas in the Tabei Uplift. Natural gas chemical composition, carbon isotopes were used to analyze the genesis of natural gas, source rock maturity, and basin modeling were conducted to reconstruct the natural gas generation process, and the influences of instantaneous and cumulative effects on natural gas properties was discussed. The results show that the dryness coefficients of natural gas range from 0.62 to 0.99 (average: 0.92), the methane contents range from 30.42% to 96.4% (average: 85.10%), ethane contents from 0.43% to 15.58% (average: 3.39%), propane contents from 0.11% to 11.43% (average: 1.78%), and the methane carbon isotopes range from −47.30‰ to −33.80‰ (average: −36.96‰), ethane carbon isotopes range from −39.60‰ to −33.20‰ (average: −35.57‰), propane carbon isotopes range from −36.90‰ to −28.50‰ (average: −35.49‰). Compared with the actual regional thermal evolution of the source rock (R_o% range from 1.4%–1.7%), the natural gas exhibits excessively high dryness coefficients and heavy methane carbon isotope characteristics. The natural gas is primary cracking gas and sourced from marine type Ⅱ kerogen. The dryness coefficient, methane carbon isotopes, and source rock maturity gradually increases from the west to the east. Instantaneous effects and leakage led to the dry gas and relative heavy methane carbon isotopes generated at a low maturity level. The current natural gas in the Ordovician reservoirs was all generated during the Himalayan orogeny. Long period pause of the gas generation between the two hydrocarbon generation phases is the main cause for the instantaneous effects.