Recent discoveries of oil and gas have principally been located in the central part of the Ordos Basin, which is a petroliferous basin with the largest discovered reserves and annual production of tight sandstone gas in China. For tight sandstone gas reservoirs in the transition zone of the basin margin, the process of natural gas accumulation has remained relatively vaguely understood, because of the transitional accumulation of geological conditions such as structure, sedimentation, and preservation. In this study, thin-section identification and scanning electron microscopic observations of the reservoir core, measurement of the physical properties of the reservoir, microscopic petrography research and measurement of the homogenization temperature of fluid inclusions, digital simulations, and laser Raman spectroscopy analysis were combined to analyze the process of natural gas accumulation of the Permian Lower Shihezi Formation in Duguijiahan block, Hangjinqi area, northern Ordos Basin. The results showed that the Lower Shihezi Formation reservoir in the Duguijiahan block began gas charging in the southern part as early as the Early Cretaceous (130–128 Ma), and then gradually charged in the northern part. Three stages were identified in the digital simulations of gas charging, i.e., the breakthrough, rapid, and fully saturated stages. The initial porosity of the Lower Shihezi Formation reservoir ranged between 28% and 40%. Later, because of strong compaction and interstitial filling during burial, the sandstone porosity decreased rapidly, and densification (porosity < 10%) occurred in the mid–late Jurassic. This late tectonic uplift caused a continuous reduction in ground temperature, and diagenesis had a weak effect on pore transformation. The present porosity of the Lower Shihezi Formation reservoir basically inherited its characteristics in the late Early Cretaceous. The current average porosity of the reservoir is 8.58%, and the average permeability is 0.88 mD, and it can thus be characterized as a tight reservoir. The gas accumulation process of the Lower Shihezi Formation has three stages: (1) the depositional stage (C–P), corresponding to the depositional stage of the source-reservoir-cap combination in gas reservoir; (2) the natural gas accumulation stage (T–K₁), corresponding to the period of rapid source rock maturation and natural gas charging step-by-step; and (3) the gas reservoir adjustment stage (K₂–present), corresponding to the period of uplift and natural gas charging in the early stage that gradually migrated and accumulated northward along the fracture zone. Finally, the gas accumulation model in the transition zone at the margin of basin was established.

Hangjinqi area is located in the northern margin of Ordos Basin in north China, the main body of which is on the inherited palaeo-uplift, and has been considered as a favorable oil-gas accumulation direction area. Duguijiahan block structurally located in the middle of Hangjinqi area, in the fault transition zone of Boerjianghaizi fault and Wulanjilinmiao fault, which is a transition area from quasi-continuous gas reservoir to continuous gas reservoir. By analyzing the reservoir characteristics and evolution process of tight sandstone gas reservoirs, the thermal maturation history of source rocks and the history of natural gas charging in Lower Shihezi Formation, this paper studies the natural gas accumulation process in the transition zone between quasi-continuous and continuous gas reservoirs, hoping to contribute to tight gas exploration in Ordos Basin and other basins with similar tectonic backgrounds in the world. The results show that the initial porosity of the Lower Shihezi Formation in Duguijiahan block is about 32~36%, and experienced the porosity decreasing of compaction (avg. = 18.58%) and cementation (avg. = 11.03%), and porosity increasing of dissolution (avg. = 1.24%). The sandstone densification (porosity <10%) occurred in the mid-late Jurassic (~170–150 Ma). Due to tectonic uplift from the end of the Early Cretaceous to the present day, the present porosity has basically inherited the characteristics of the end of the Early Cretaceous, and the average porosity is only 8.4%. On the other hand, based on the homogenization temperature test of fluid inclusions, laser Raman spectroscopy analysis of gas inclusions and basin simulation, the hydrocarbon charging time of the Lower Shihezi Formation gas reservoir in Duguijiahan block is early Cretaceous (~145-100Ma), indicating that the gas charging time of the gas reservoir in the study area is later than the reservoir densification time. Furthermore, the natural gas charging time in the study area is characterized by gradual charging from south to north, indicating that the early natural gas charging is mainly affected by the maturity of underlying source rocks. From the end of early Cretaceous to now, it is the adjustment period of natural gas accumulation in the study area. The continuous tectonic uplift leads to the decrease of geothermal temperature, the loss of reservoir pressure and the formation of fractures. The natural gas charged in the early stage gradually migrates and accumulates along the northern up-dip direction of the fracture zone. The Lower Shihezi Formation was pinched out in the northern Gongkahan uplift to form effective blocking. The migration process of natural gas has been confirmed by the present exploration findings, the relationship between porosity and permeability of reservoir physical properties and the difference of natural gas components in the north and south.

Semi-open hydrous pyrolysis experiments on coal-measure source rocks in the Xihu Sag were conducted to investigate the carbon isotope evolution of kerogen, bitumen, generated expelled oil, and gases with increasing thermal maturity. Seven corresponding experiments were conducted at 335 °C, 360 °C, 400 °C, 455 °C, 480 °C, 525 °C, and 575 °C, while other experimental factors, such as the heating time and rate, lithostatic and hydrodynamic pressures, and columnar original samples were kept the same. The results show that the simulated temperatures were positive for the measured vitrinite reflectance (Ro), with a correlation coefficient (R²) of 0.9861. With increasing temperatures, lower maturity, maturity, higher maturity, and post-maturity stages occurred at simulated temperatures (Ts) of 335–360 °C, 360–400 °C, 400–480 °C, and 480–575 °C, respectively. The increasing gas hydrocarbons with increasing temperature reflected the higher gas potential. Moreover, the carbon isotopes of kerogen, bitumen, expelled oil, and gases were associated with increased temperatures; among gases, methane was the most sensitive to maturity. Ignoring the intermediate reaction process, the thermal evolution process can be summarized as kerogen₀(original) + bitumen₀(original)→kerogen_r (residual kerogen) + expelled oil (generated) + bitumen_n+r (generated + residual) + C₂₊(generated + residual) + CH₄(generated). Among these, bitumen, expelled oil, and C_2-5 acted as reactants and products, whereas kerogen and methane were the reactants and products, respectively. Furthermore, the order of the carbon isotopes during the thermal evolution process was identified as: δ¹³C₁ < ¹³C_2-5 < δ¹³C_{expelled oil} < δ¹³C_bitumen < δ¹³C_kerogen. Thus, the reaction and production mechanisms of carbon isotopes can be obtained based on their changing degree and yields in kerogen, bitumen, expelled oil, and gases. Furthermore, combining the analysis of the geochemical characteristics of the Pinghu Formation coal–oil-type gas in actual strata with these pyrolysis experiments, it was identified that this area also had substantial development potential. Therefore, this study provides theoretical support and guidance for the formation mechanism and exploration of oil and gas based on changing carbon isotopes.