Tight gas is the fastest developing unconventional natural gas resource, becoming the principal part for gas reserves and production growth in China. The Sulige gas field is the largest gas field and also the typical low porosity and low permeability tight sandstone gas field discovered in China, with an annual natural gas output exceeding 300 billion and cumulative output exceeding 290 billion, playing an important role in ensuring national energy provision, helping China’s energy transformation, and promoting green, low-carbon, environmental protection and high-quality development. Based on sample collection and laboratory analysis, natural gas compositions including hydrocarbons, non-hydrocarbons, light hydrocarbons, and noble gases of the Sulige gas field are systematically analyzed, their genetic identifications are identified, and finally gas source originations and contribution proportions are comprehensively discussed from the perspectives of noble gases and hydrocarbon gases. The main achievements are as follows: 1) natural gases in the Sulige gas field are mainly alkane gases, with high methane content, high drying coefficient, low heavy hydrocarbon contents, low non-hydrocarbon gas contents of CO₂ and N₂, and relatively low noble gas contents. The helium content is relative 2 order of magnitude higher than the atmospheric value, while neon, argon, krypton, and xenon are relatively about 1–2 orders of magnitudes lower than the atmospheric values. 2) The carbon and hydrogen isotopes of alkanes are generally positive sequence distributions with some part inversion. The ³He/⁴He values are mainly distributed in magnitude of 10⁻⁸, the ⁴⁰Ar/³⁶Ar is ranged from 506 to 1940, the ¹²⁹Xe is relative loss, and the ¹³²Xe is relative surplus. 3) Natural gases in the Sulige gas field are typical coal-formed gases generated from a humic organic mother material with maturity from high mature to over mature according to C₇ and C₈ light hydrocarbons and alkane carbon isotopes. Noble gases are typical crustal genesis, mainly originating from the radioactive decay of crustal source materials. 4) The gas source correlations of noble gases and alkane gases and their quantitative evaluations on source contributions show that natural gases in the Sulige gas field are originated from Carboniferous-Permian coal measure source rocks in Ordos Basin, mainly contributed by coals and supplemented by mudstones, accounting for 55–60% and 40–45%, respectively.

It is generally accepted that organic–inorganic interactions involving H-rich fluids (i.e., H₂O and H₂) contribute significantly to hydrocarbon (HC) generation in sedimentary basins. However, the effects of two hydrogenation processes involving H₂O and H₂ on the generation and C/H isotope fractionation of HC gases from organic matter (OM) remain unclear. In this study, two groups of hydrothermal experiments involving low-mature kerogen without (Group 1) and with FeS (Group 2) at 330–420 °C and 50 MPa were conducted to simulate the hydrogenation of OM by H₂O and H₂, respectively. The experimental results show that the redox reactions between H₂O and FeS lead to the generation of considerable amounts of H₂ in the Group 2 experiments. HC gas yield in the Group 2 experiments reaches 1.8–3.6 times that in the Group 1 experiments at Easy%Ro of 1.05–2.50%. In addition, indirect hydrogenation via H₂O-derived H₂ generates HC gases with smaller ¹³C fractionation and more negative δ²H compared with direct hydrogenation via H₂O. On this basis, the mechanisms for HC gas generation from two hydrogenations were addressed. Additionally, it is demonstrated that the equilibrium isotope effect (EIE) is responsible for the ¹³C and ²H isotope fractionation in the hydrogenation of OM by H₂.

The Lower Cambrian petroleum system in the Tarim Basin has undergone multiple periods of tectonic movements, leading to successive hydrocarbon expulsion events and adjustments. The complex process of hydrocarbon accumulation occurred under deep burial conditions, persisting at depths of nearly 6,000 m over an extended period. This has resulted in the current occurrence of various phases including light oil, condensate, and gas in the deep-ultradeep strata of the Tarim Basin. The intricacies of formation of hydrocarbon accumulations and phase evolution have posed challenges to understanding the accumulation mechanisms and enrichment patterns of the Cambrian in the Tarim Basin, consequently lowering the success rate of oil and gas exploration. Such characteristics of multi-stage accumulation and adjustment are prevalent in deep hydrocarbon systems. Therefore, based on data from Well ZH1 in the Tazhong Uplift, combined with basin simulation, Compositional kinetics model, and PVT performance simulation, this study investigates the hydrocarbon generation and phase evolution processes in the deep hydrocarbon systems of the Tazhong Uplift. The results indicate that Well ZH1 entered the hydrocarbon generation peak during the Late Ordovician, followed by secondary cracking as the predominant hydrocarbon evolution process. Hydrocarbon fluids within the Lower Cambrian reservoir transitioned into the condensate phase towards the end of the Cambrian, with increasing depth resulting in higher gas-oil ratios and a decreasing trend in viscosity and density.

Geothermal field characteristics fundamentally control hydrocarbon generation, phase evolution, and preservation, and are particularly critical in deep to ultra-deep hydrocarbon exploration. The Tazhong Uplift is a key area for deep to ultra-deep hydrocarbon exploration in the Tarim Basin; however, its deep thermal regime and controlling factors remain inadequately characterized. This study aims to accurately characterize the geothermal field and crustal thermal structure of the Tazhong Uplift to provide thermal constraints for ultra-deep exploration. We systematically compiled system steady-state temperature data from 24 wells, bottom-hole temperature (BHT) data from 51 wells, and rock thermal property measurements. Using the one-dimensional steady-state heat conduction equation, present-day geothermal gradients at 0–5000 m depths and terrestrial heat flow were calculated, and formation temperatures were predicted at deep horizons (6000–10,000 m). Results show geothermal gradients at 0–5000 m of 18.5–26.7 °C/km (average 23.06 °C/km) and heat flow of 39.3–59.8 mW/m² (average 48.1 mW/m²), both significantly higher than basin averages. The distribution of the geothermal field is jointly controlled by basement structure and rock thermophysical properties. Basement highs typically exhibit elevated geothermal gradients and high heat flow. The dual-layer structure of “upper clastic rocks (low thermal conductivity, high heat production) + lower carbonate rocks (high thermal conductivity, low heat production)” results in a vertical differentiation characterized by a “high-upper, low-lower” geothermal gradient. Notably, the thick Upper Ordovician mudstone acts as a regional “thermal blanket”, significantly reducing geothermal parameters in the northern slope area. Crustal thermal structure analysis indicates a “cold mantle” signature of cratonic basins, with a thermal lithosphere thickness of ~134–145 km and a Moho temperature of ~581 °C. These findings reveal that despite the ultra-deep burial (>8000 m), the “cold” thermal background and the thermal regulation of the overlying diverse lithologies maintain formation temperatures within a range favorable for liquid hydrocarbon preservation, significantly expanding the depth limit for oil exploration in the Tarim Basin.