Molecular and stable carbon isotopic compositions of 32 crude oils from the Kekeya area of the Southwest Depression, Tarim Basin, were analyzed comprehensively to clarify oil groups and trace oil sources. The results indicate that lacustrine shale sequences within the Upper-Middle Permian Pusige Formation (P_3–2p) are the major effective oil sources; the thermal maturation effects exert the crucial impact on geochemical compositions of crude oils. In the Kekeya structural belt, crude oils produced from the Lower-Neogene, Middle-Paleogene and Middle-Cretaceous sandstone reservoirs were generated mainly from deeply buried P_3–2p at the late-to-high maturity stage. These condensates are depleted in terpanes, steranes and triaromatic steranes and enriched in adamantanes and diamantanes. The evaluated thermal maturity levels of crude oils by terpanoids and steranes are generally lower than that of diamondoids, implying at least two phases of oil charging. In the Fusha structural belt, oils produced from the Lower-Jurassic reservoirs (J₁s) of Well FS8 were generated from the local P_3–2p at the middle to late mature stage. On the contrary, these oils are relatively rich in molecular biomarkers such as terpanes and steranes and depleted in diamondoids with only adamantanes detectable. The P_3–2p-associated oils can migrate laterally from the Kekeya to Fusha structural belt, but not to the location of Well FS8. The Middle-Lower Jurassic (J_1–2) lacustrine shales as the major oil sources are limited to the area around Well KS101 in the Kekeya structural belt. Crude oils originated from J_1–2 and P_3–2p can mix together within the Cretaceous reservoirs of Well KS101 by presenting the concurrence of high concentrations of terpane and sterane biomarkers and diamondoids as well as 2–4% ¹³C-enriched n-alkanes than those of P_3–2p derived oils. This study provides a better understanding of hydrocarbon sources and accumulation mechanisms and hence petroleum exploration in this region.

The carbon isotope sequence of alkanes is a key indicator used to distinguish organic from inorganic gas. A negative carbon isotope sequence (i.e., δ¹³C₁ > δ¹³C₂ > δ¹³C₃ > δ¹³C₄) is a characteristic feature of inorganic gas. Some gas samples from the Qingyang gas field in the southwestern Ordos Basin exhibit a negative carbon isotope sequence, but the geological conditions necessary for the development of inorganic gas are not present. There is currently no reasonable explanation for this phenomenon. This study takes into account the geological background of the Ordos Basin and comprehensively investigates the causes of the anomalous carbon isotope sequence of alkanes in the Qingyang gas field; this is done through an analysis of natural gas geochemical characteristics and adsorption/desorption experiments on high-rank coal. Our results show that: (1) Natural gas from the Qingyang gas field is over-mature coal-type gas derived from Carboniferous‒Permian formations. Its negative carbon isotope sequence is mainly related to the adsorption of gases by coal. During the over-mature stage, the content of heavier hydrocarbon gases (C₂₊) is very low, and the adsorption capacity of coal for C₂₊ gases is stronger than that for methane. Heavier hydrocarbon gases (e.g., ethane), with lighter carbon isotope signatures, preferentially desorb, resulting in a relatively light observed carbon isotope composition. Owing to its high abundance, the isotopic composition of methane is impacted relatively little by adsorption. (2) The anomalous geochemical characteristics of over-mature coal-type gas result in the failure of the negative carbon isotope sequence method for identifying inorganic gas; this also invalidates the criterion for classifying oil-type gas and coal-type gas based on thresholds of δ¹³C₂ = − 28‰ and δ¹³C₃ = − 25‰. Additionally, previously proposed empirical formulae (e.g., δ¹³C₂‒Ro and δ¹³C₃‒Ro) are not applicable to over-mature natural gas. Furthermore, the δ¹³C₂−δ²H₁ cross-plot method, used for determining the type of source rock, is rendered ineffective because over-mature samples deviate from the coal-type gas range. (3) The methane carbon isotope signature (δ¹³C₁) and gas dryness coefficient (C₁/C_1–5) are reliable indicators of source rock maturity.

The hydrocarbon source rocks of the marine carbonates of the Ordovician Majiagou Formation in the Ordos Basin are generally in the high-overmature stage and are, therefore, not suitable for hydrocarbon thermal simulation experiments. Their hydrocarbon generation potential and hydrocarbon generation characteristics are not clearly understood. Meanwhile, Nordic Cambrian carbonates are similar in lithology, parent material type, and sedimentary age, and are in the low evolution stage, which is suitable for hydrocarbon thermal simulation experiments. Therefore, in this study, we selected the Nordic carbonates for the gold tube thermal simulation experiment to analyze the content and geochemical characteristics of the thermal simulation products. The experimental results are also compared and analyzed with the characteristics of thermal simulation products of Pingliang Formation mud shale (contemporaneous with the Majiagou Formation) and Shanxi Formation coal (in the upper part of the Majiagou Formation), which are similar to the Majiagou Formation in the Ordos Basin. The results showed that the Nordic carbonate has different hydrocarbon production characteristics from the mud shale of the Pingliang Formation of the same parent material type, and although the hydrocarbon production yields of the two are not very different, the carbonate still produces methane at 600 °C. The hydrocarbon production yield of the Nordic carbonates is almost equivalent to that of type-II₂ kerogen, indicating that the hydrocarbon production yield is not related to lithology and only to the organic matter type; however, the Nordic carbonate can produce a large amount of H₂S. The alkane carbon isotope changes are mainly controlled by the degree of thermal evolution, showing gradual heaviness with increasing temperature. No carbon isotope sequence reversal occurred during the thermal simulation, and its distribution range is roughly the same as that of the alkane carbon isotope composition of the mud shale of the Pingliang Formation. The ethane carbon isotope composition is as heavy as −21.2‰ at the high-temperature stage, showing similar coal-type gas characteristics. The addition of calcium sulphate (CaSO₄) causes the TSR reaction to occur, which has a significant impact on the methane content under high maturity conditions, reducing its content by more than 50% at 600 °C. However, the addition of CaSO₄ increases the yield of heavy hydrocarbon gases, such as ethane, and promotes the production of C_6-14 hydrocarbons and C₁₄₊ hydrocarbons at high-temperature stages, and the addition of CaSO₄ substantially increases the yield of H₂, CO₂, and H₂S. The thermal simulation results have implications for the hydrocarbon formation mechanism of the early Paleozoic marine carbonate formation system in the stacked basins of the Ordos Basin and the Tarim Basin in China.