Submarine gas hydrate systems store vast carbon inventories (~1500–12,400 Gt C) yet pose dual risks as potential geohazard multipliers and climate feedback agents under oceanic warming. Conventional seal assessment fails catastrophically in unconsolidated Quaternary hydrate-bearing sediments due to core-retrieval artifacts, hydrate morphology controls on capillary trapping, and meter-scale heterogeneity unresolved by seismic methods. Here, we pioneer methane carbon isotope (δ¹³C₁) gradients as a dynamic proxy for seal capacity in the Qiongdongnan Basin. Integrating petrographic features, natural gas geochemical characteristics, downhole logging data, and principal component analysis (PCA) from six wells, we: (1) quantified the thermogenic gas contribution of wells W6 and W8 to be 55%–73%, and that of well W1 to be 28%–32% via binary mixing models, (2) establish that methane carbon isotope gradients >0.5‰/m diagnose effective capillary barriers, correlating with zones of pore-throat disconnection, and (3) develop a PCA-integrated logging model (cumulative variance: 84.02%, R² = 0.78) predicting seal capacity from conventional petrophysical parameters. Furthermore, the results validate a charge-dynamic barrier-mixing accumulation model where thermogenic gas influx elevates hydrate saturation, creating self-sealing horizons that trap underlying microbial gases and subsequently charged thermogenic gases, recorded in diagnostic methane carbon isotope reversals. This approach bridges molecular-scale fractionation and reservoir-scale processes, enabling targeted identification of high-integrity seals for optimized carbon storage and safer hydrate exploitation in rapidly deposited marginal basins.

In recent years, extensive exploration and exploitation activities in tight sandstone gas reservoirs have highlighted the common phenomenon of water production, indicating complex gas-water contacts. Exploring gas layers while avoiding water layers has become critical to the efficient exploration and exploitation of tight sandstone gas reservoirs. This study presents comprehensive geological analyses of gas-water contacts in simple gentle tectonic zones (tight sandstone gas reservoirs in the Sulige and Daniudi areas in the Ordos Basin), a transition zone of simple gentle to complex uplift (Hangjin Banner in the Ordos Basin), and complex uplift zones (tight-gas reservoirs in the western Sichuan Basin). Combined with the core-scale and pore-scale physical simulations of gas-water contact in tight sandstone, we clarify the types and characteristics of gas-water contacts in tight-gas sandstone reservoirs, reveal the dominant factors controlling the formation and distribution of intricate gas-water contacts based on the sand bodies, cores, and pores, and establish corresponding gas-water distribution patterns. Key findings are as follows. In terms of sand body, there are primarily six types of gas-water contacts within, including (1) the simple type of gas layer without water layer; (2) the normal type with gas layer underlain by water layer; (3) the inverted type with gas layer overlaid by water layer; (4) the hybrid type with gas and water in the same layer; (5) the isolated type with water layer within a gas layer; and (6) the simple type of water layer without gas. The distribution range, style, and boundary of gas-water contacts are governed by hydrocarbon-generating intensity, reservoir heterogeneity, and a combination of source rock-reservoir pressure differences and tectonic activity, respectively. At core-scale, permeability coupled with charging dynamics of the tight sandstone governs the critical conditions for the formation and distribution of gas-water contacts. At pore-scale, the coupling of pore throat size and coordination number with charging pressure dictates the fluid occurrence and seepage characteristics, determining the critical conditions for the formation and distribution of gas-water contacts. Owing to the collective effects of dominant factors from sand body, core-scale, and pore scale and their differences, tight-gas reservoirs with different source rock-reservoir assemblages exhibit different gas-water distribution patterns.

In recent years, breakthroughs have been achieved in hydrocarbon exploration efforts in the ultra-deep marine carbonate rocks of strike-slip fault systems in the northern Tarim Basin. However, the Fuman oilfield in the basin exhibits pronounced differences in hydrocarbon distribution and enrichment, with the mechanisms driving the differential hydrocarbon accumulation in ultra-deep reservoirs governed by strike-slip faults remaining unclear. In this study, we investigate the geometric structures and evolution of strike-slip faults in the Fuman area, as well as their role in hydrocarbon migration and accumulation. By analyzing the hydrocarbon accumulation and enrichment mechanisms, we identify the dominant factors controlling hydrocarbon accumulation in ultra-deep carbonate reservoirs in the area. The results indicate that the strike-slip faults in the study area experienced a dynamic evolutionary process consisting of the early extension or weak compression, the middle-stage transpression, extension, or translation slip, and the late-stage stabilization, successive development, or tenso-shear inversion. The F_I5 and F_I17 fault zones underwent alternating compression, shear, and tensile stresses, resulting in significant evolutionary differences across their various parts. In contrast, the F_I7 and F_Il6 fault zones were primarily subjected to shear and tensile stresses, leading to relatively simple evolutionary processes. The faults with differential evolutionary processes exhibit distinct geometric structures, resulting in varying configurations of their connection to source rocks, hydrocarbon transport capacities, and reservoir properties. Consequently, three hydrocarbon charging models are formed: vertical charging as represented by F_I5 and F_I16, lateral migration for adjustment by F_I7, and a combination of the former two patterns by F_I17. The hydrocarbon charging process is governed by the differential evolution of fault zones. The late-stage strong activity of faults in the eastern part of the Fuman area, combined with the charging and accumulation of substantial highly mature pyrolysis gas during the Himalayan movement, results in the formation of a hydrocarbon distribution pattern characterized by “oil in the west and gas in the east”. Furthermore, the evolutionary differences across various parts of the fault zones cause more complex changes in hydrocarbon properties. For reservoirs dominated by vertical hydrocarbon charging, the degree of hydrocarbon enrichment is determined by the coupling of the connection to source rocks, hydrocarbon transport capacities, and reservoir properties of fault zones. Meanwhile, the hydrocarbon properties of the reservoirs are governed by the various hydrocarbon charging stages. For reservoirs dominated by lateral hydrocarbon migration, the degree of hydrocarbon enrichment and hydrocarbon property changes are controlled by their properties and the extent of lateral connections within.