Marine shales from the Niutitang Formation and marine–continental transitional shales from the Longtan Formation are two sets of extremely important hydrocarbon source rocks in South China. In order to quantitatively compare the pore complexity characteristics between marine and marine–continental transitional shales, the shale and kerogen of the Niutitang Formation and the Longtan Formation are taken as our research subjects. Based on organic petrology, geochemistry, and low-temperature gas adsorption analyses, the fractal dimension of their pores is calculated by the Frenkel–Halsey–Hill (FHH) and Sierpinski models, and the influences of total organic carbon (TOC), vitrinite reflectance (R_o), and mineral composition on the pore fractals of the shale and kerogen are discussed. Our results show the following: (1) Marine shale predominantly has wedge-shaped and slit pores, while marine–continental transitional shale has inkpot-shaped and slit pores. (2) Cylindrical pores are common in organic matter of both shale types, with marine shale having a greater gas storage space (CRV) from organic matter pores, while marine–continental transitional shale relies more on inorganic pores, especially interlayer clay mineral pores, for gas storage due to their large specific surface area and high adsorption capacity (CRA). (3) The fractal characteristics of marine and marine–continental transitional shale pores are influenced differently. In marine shale, TOC positively correlates with fractal dimensions, while in marine–continental shale, R_o and clay minerals have a stronger influence. R_o is the primary factor affecting organic matter pore complexity. (4) Our two pore fractal models show that the complexity of the shale in the Longtan Formation surpasses that of the shale in the Niutitang Formation, and type I kerogen has more complex organic matter pores than type III, aiding in evaluating pore connectivity and flow effectiveness in shale reservoirs.

High burial temperature and a lack of material for traditional thermal proxies significantly impede the understanding of the thermal history of carbonate stratigraphic sequences in deep time. Carbonate clumped isotope thermometry interpreted through models of solid‐state isotopic reordering and in situ U‐Pb dating provides a new methodology for reconstructing thermal histories of such successions. Calcite fabrics (micrite cements and veins) from deeply buried (5,000–8,000 m) Ordovician carbonate intervals in the Tarim Basin were analyzed for their carbonate clumped isotope compositions and U‐Pb ages, and the results were used to estimate maximum peak burial temperatures. Reconstructed burial temperatures reveal a previously ignored thermal pulse in the range of 160°C–190°C during the Permian period. Maximum geothermal gradients at the time of peak burial temperature varied from 26.8°C/km to 69.3°C/km, with higher values in the northern Tarim Basin. We show that the spatial patterns of peak burial temperature and geothermal gradients closely correspond to the distribution of the Tarim Large Igneous Province, which emplaced during the Permian following the emplacement of a mantle plume beneath the Tarim Basin. We thus propose that the thermal pulse recorded in Tarim Ordovician limestones resulted from Permian mantle plume activity. The reconstructed thermal history has important implications for our understanding of source‐rock hydrocarbon generating history, hydrocarbon accumulation, and fluid flow history in the Tarim Basin. This study also demonstrates the potential of the integration of Δ₄₇, U‐Pb dating of carbonates and solid‐state reordering models as an integrated thermochronological method for reconstructing thermal histories of deeply buried carbonate intervals.

In the northern Tarim Basin (northwestern China), Cambrian source rocks are widely distributed, especially within the Lower Cambrian Yuertusi Formation (Є₁y). Understanding the hydrocarbon generation process of the Yuertusi Formation source rocks is essential for reconstructing the evolutionary history of the ultra-deep petroleum system in the Tarim Basin. We employed a novel method of reconstructing hydrocarbon generation history by determining the episodes and absolute ages of hydrocarbon generation and expulsion in source rock via the integration of the fluorescence of oil inclusions, inclusion homogenization temperatures, and in situ U-Pb dating of calcite veins containing hydrocarbon inclusions. In the QT1 well area of the Tabei uplift belt, our reconstructed hydrocarbon generation history indicates that during the Late Hercynian (ca. 288−270 Ma), the source rocks generated oil inclusions with yellow-green fluorescence color (λ_max [wavelength at maximal light absorbance] ranging from 490 nm to 545 nm, a maturity of ∼0.8%). In the Himalayan period (ca. 10 Ma), oil inclusions were generated with blue-white fluorescence color (λ_max ranging from 430 nm to 490 nm, a maturity level of ∼1.2%). In the central part of the Tabei uplift belt, in the Late Hercynian (ca. 270−260 Ma), oil inclusions with blue-white fluorescence color (λ_max ranging from 430 nm to 490 nm, a maturity of ∼1.2%) were generated (reaching their hydrocarbon generation peak). Combining basin modeling and constraints from fluid inclusions indicates that the source rocks mainly generated oils at the Late Hercynian period in the Tabei area.

Multistage hydrocarbon remigration is common in foreland-basin thrust belts, but its timing and pathways remain poorly constrained. We investigated the Lower Cretaceous Yageliemu and Bashijiqike reservoirs in the Kela-2 gas field, Kuqa foreland basin. Molecular geochemical analyses of reservoir extracts and oil inclusions, combined with fluid-inclusion observations, were used to reconstruct the hydrocarbon charging and remigration history. Reservoir extracts and oil inclusions from both reservoirs show consistent molecular signatures, indicating a common origin from the Triassic Huangshanjie lacustrine source rocks. Fluid-inclusion thermometry combined with burial-history reconstruction indicates that lacustrine oil charged the deeper K₁y reservoir earlier than the shallower K₁bs reservoir, supporting a later phase of upward cross-stratal remigration associated with progressive fault reactivation. From approximately 5.3 Ma onward, large-scale coal-derived gas charging increasingly modified the earlier oil accumulations, and after ca. 2.5 Ma of sustained gas charging, the fully developed Kela-2 anticlinal trap became the dominant accumulation process.

Light oil is a high-quality crude oil. The formation and chemical composition of light oil is a matter of great concern to petroleum geologists. Yakela Field and Shunbei Field, which are located in Yakela and Shunbei regions, respectively, are the two main light oil fields in the Tabei uplift of the Tarim Basin. In order to identify the causative mechanism of light oils in these two fields, 17 crude oil samples were selected and analyzed by gas chromatography (GC) for saturated hydrocarbons and gas chromatography–mass spectrometry (GCMS) for saturated and aromatic biomarkers. Then, the compounds were measured via the mass spectrometry detector after GC separation. The molecular geochemical characteristics showed that the light oils in the two fields are sourced from similar marine source rocks deposited under weak oxidative and reductive environments. The maturity of crude oil in the Shunbei Field is higher than that in the Yakela Field. Simulation results of hydrocarbon generation history of source rocks in two fields showed that the formation mechanism of the two light oils is different. The light oil in the Yakela Field is directly generated by the source rock in the late oil-generating window. The crude oil in the Shunbei Field is formed by the deep burial and maturation of the crude oil generated in the early stage of the source rock.