The marine carbonates in the Ordovician Majiagou Formation in the Ordos Basin have significant exploration potential. Research has focused on their thermal history and hydrocarbon accumulation stages, as these are essential for guiding the exploration and development of hydrocarbons. In this paper, we study the thermal evolution history of the carbonate reservoirs of the Ordovician Majiagou Formation in the east-central Ordos Basin. Furthermore, petrographic and homogenization temperature studies of fluid inclusions were carried out to further reveal the hydrocarbon accumulation stages. The results demonstrate that the degree of thermal evolution of the Ordovician carbonate reservoirs is predominantly influenced by the deep thermal structure, exhibiting a trend of high to low values from south to north in the central region of the basin. The Fuxian area is located in the center of the Early Cretaceous thermal anomalies, with the maturity degree of the organic matter ranging from 1 to 3.2%, with a maximum value of 3.2%. The present geothermal gradient of the Ordovician Formation exhibits the characteristics of east–high and west–low, with an average of 28.6 °C/km. The average paleo-geotemperature gradient is 54.2 °C/km, the paleoheat flux is 55 mW/m², and the maximum paleo-geotemperature reaches up to 270 °C. The thermal history recovery indicates that the Ordovician in the central part of the basin underwent three thermal evolution stages: (i) a slow warming stage before the Late Permian; (ii) a rapid warming stage from the end of the Late Permian to the end of the Early Cretaceous; (iii) a cooling stage after the Early Cretaceous, with the hydrocarbon production of hydrocarbon source rocks weakening. In the central part of the basin, the carbonate rock strata of the Majiagou Formation mainly developed asphalt inclusions, natural gas inclusions, and aqueous inclusions. The fluid inclusions can be classified into two stages. The early-stage fluid inclusions are mainly present in dissolution holes. The homogenization temperature is 110–130 °C; this coincides with the hydrocarbon charging period of 210–165 Ma, which corresponds to the end of the Triassic to the end of the Middle Jurassic. The late-stage fluid inclusions are in the dolomite vein or late calcite that filled the gypsum-model pores. The homogenization temperature is 160–170 °C; this coincides with the hydrocarbon charging period of 123–97 Ma, which corresponds to the late Early Cretaceous. Both hydrocarbon charging periods are in the rapid stratigraphic warming stage.

The Yanchang Formation of the Triassic in the Ordos Basin comprises various stratigraphic intervals. The Chang 8 reservoir represents a significant oil-producing section of the Yanchang Formation, and its hydrocarbon accumulation mechanism is complex. In this study, we analyzed the diagenetic evolution and reservoir-forming stages of the Chang 8 member of the Yanchang Formation in the Late Triassic in the Fuxian area, the southern Ordos Basin, via thin-section casting, scanning electron microscopy (SEM), X-ray diffraction, and fluid inclusion petrology and homogenization temperature analyses. The relationship between the petrogenesis and hydrocarbon charging history was analyzed, which provided guidance for identifying and predicting the hydrocarbon reservoir distribution. The results show that the main diagenesis types of the Chang 8 reservoir are compaction, cementation, dissolution, and metasomatism. The comprehensive analysis of the reservoir mineral types, diagenesis, diagenetic sequence, and thermal evolution degree of organic matter shows that the Chang 8 reservoir of the Yanchang Formation is in the A stage of the middle diagenesis stage. Under the overpressure of hydrocarbon generation, oil and gas migrated into the Chang 8 reservoir along fractures and connected pores. The earlier-stage hydrocarbon charging occurred after compaction and later than the early clay film formation and early calcite precipitation, and it also occurred earlier than or simultaneously with the quartz overgrowth. The later hydrocarbon charging occurred after the significant quartz overgrowth and late calcite pore filling. Depending on the homogenization temperature and salinity, the fluid inclusions can be divided into two types: low-temperature, low-salt (90–105 °C, 1.4%–11.2%) fluid inclusions and high-temperature, high-salt (115–120 °C, 2.2%–12.5%) fluid inclusions. According to the analysis of the evolution of the burial history, hydrocarbon charging in the Chang 8 reservoir of the Yanchang Formation in the Fuxian area occurred in two consecutive periods: 133~126 Ma and 122~119 Ma, demonstrating one-scene, two-stage reservoir formation, characterized by simultaneous reservoir densification and hydrocarbon charging. In this research, we precisely ascertained the regional diagenetic characteristics and patterns and periods of hydrocarbon charging, thereby furnishing crucial evidence that deepens the comprehension of sedimentary basin evolution.

The Weibei uplift in the Ordos Basin has a distinctive tectonic setting and intricate evolutionary history. Along these lines, we have used the stratum temperature, apatite fission track, and vitrinite reflectance data to restore the thermal and hydrocarbon generation histories of the Weibei uplift. The average value of the present geothermal gradient of the Weibei uplift was 27.9°C/km, and the heat flow was 64.9 mW/m2. The Weibei uplift exhibited a moderate geothermal field. Three uplift cooling events occurred in the Weibei uplift during the Mesozoic era: the late Jurassic-early Cretaceous (162–125 Ma), the late Cretaceous (105–65 Ma), and the Eocene-Oligocene (40–27 Ma). The uplift history indicates an early uplift in the south region and a late uplift in the later stage. The thermal evolution history simulation demonstrates that the lower Palaeozoic Ordovician source rocks began to enter the hydrocarbon generation threshold in the middle Permian-late Permian (270 Ma) era and joined the hydrocarbon generation peak in the early-middle Jurassic event (180 Ma). The upper Palaeozoic Carboniferous-Permian source rocks began to enter the hydrocarbon generation threshold in the later period of the middle Permian period (235 Ma). They joined the hydrocarbon generation peak in the late Jurassic-early Cretaceous period (150 Ma). In addition, Triassic source rocks entered the hydrocarbon generation threshold in the early Cretaceous era (135 Ma) and did not enter the hydrocarbon generation peak until now. The low geothermal gradient of the Weibei uplift in the Palaeozoic-early Mesozoic reached the maximum paleotemperature in the early Mesozoic era (100 Ma) because of tectonic thermal events. The highest geothermal gradient of the early Cretaceous reached 51.5°C/km. The peak period of the hydrocarbon generation of source rocks of the different horizons in the Weibei uplift was regulated by the geothermal field of the early Cretaceous event. Since the late Cretaceous period, the stratum has been uplifted and cooled rapidly, and the hydrocarbon generation process of the source rocks has ceased.

Gas reservoirs with high CO₂ have been found in several wells in the Hailar Basin. In this paper, a composition analysis, stable carbon isotope analysis, and a rare gas helium isotope ³He/⁴He and argon isotope ⁴⁰Ar/³⁶Ar analysis were carried out. These comprehensive analyses show that the CO₂ in the Hailar Basin is inorganic-origin gas, which generally has the characteristics of crust–mantle-mixed CO₂, and the fraction of helium of mantle source can reach 15.12~18.76%. There are various types of CO₂ gas reservoirs. CO₂ gas mainly comes from deep crust. The distribution of gas reservoirs is mainly controlled by deep faults and volcanic rocks, as well as by reservoir properties and preservation conditions. Magmatic rocks provide gas source conditions for the formation of inorganic CO₂ reservoirs. Deep–large faults provide the main migration channels for CO₂ gas. The sandy conglomerate and bedrock weathering crust of the Nantun Formation and the Tongbomiao Formation provide favorable reservoir spaces for the formation of CO₂ gas reservoirs. The combination of volcanic rock mass and deep–large faults creates a favorable area for CO₂ gas accumulation. The age of magmatic intrusion and the homogenization temperature of oil–gas inclusions in Dawsonite-bearing sandstone indicate that 120 Ma in the Early Cretaceous was the initial gas generation period of the CO₂ reservoir and that oil and gas were injected into the reservoir in large quantities in 122~88 Ma. This period is the peak period of magmatic activity in Northeast China, as well as when the crust of Northeast China greatly changed. A large-scale CO₂ injection period occurred in 100~80 Ma, slightly later than the large-scale injection period of the oil and gas. Since the Cenozoic, the structure has been reversed, and the gas reservoir has been adjusted.

The Jurassic Tamulangou Formation in the Hongqi Depression has favorable hydrocarbon generation conditions and great resource potential. This study systematically analyzes the geochemical characteristics and thermal evolution history of the source rocks using data from multiple key wells. The dark mudstone of the Tamulangou Formation has a thickness ranging from 50 to 200 m, with an average total organic carbon (TOC) content of 0.14–2.91%, an average chloroform bitumen “A” content of 0.168%, and an average hydrocarbon generation potential of 0.13–3.71 mg/g. The organic matter is primarily Type II and Type III kerogen, with an average vitrinite reflectance of 0.71–1.36%, indicating that the source rocks have generally reached the mature hydrocarbon generation stage and are classified as medium-quality source rocks. Thermal history simulation results show that the source rocks have undergone two major thermal evolution stages: a rapid heating phase from the Late Jurassic to Early Cretaceous and a slow cooling phase from the Late Cretaceous to the present. There are differences in the thermal evolution history of different parts of the Hongqi Depression. In the southern part, the Tamulangou Formation entered the hydrocarbon generation threshold at 138 Ma, reached the hydrocarbon generation peak at approximately 119 Ma, and is currently in a highly mature hydrocarbon generation stage. In contrast, the central part entered the hydrocarbon generation threshold at 128 Ma, reached a moderately mature stage around 74 Ma, and has remained at this stage to the present. Thermal history simulations indicate that the Hongqi Depression reached its maximum paleotemperature at 100 Ma in the Late Early Cretaceous. The temperature evolution pattern is characterized by an initial increase followed by a gradual decrease. During the Late Jurassic to Early Cretaceous, the Hongqi Depression experienced significant fault-controlled subsidence and sedimentation, with a maximum sedimentation rate of 340 m/Ma, accompanied by intense volcanic activity that created a high-temperature geothermal gradient of 40–65 °C/km, with paleotemperatures exceeding 140 °C and a heating rate of 1.38–2.02 °C/Ma. This thermal background is consistent with the relatively high thermal regime observed in northern Chinese basins during the Late Early Cretaceous. Subsequently, the basin underwent uplift and cooling, reducing subsidence and gradually lowering formation temperatures.

Huhehu Sag is a sag with high exploration degree in Hailar Basin. With large sedimentary thickness, complete stratigraphic development and excellent oil generation conditions, it is the main oil- and gas-producing sag in Hailar Basin. The primary source rocks are the Nantun Formation, with the Tongbomiao and Damoguaihe Formations as secondary sources. Hydrocarbon accumulation periods in the sag were comprehensively analyzed using methodologies including source rock hydrocarbon generation-expulsion history, authigenic illite dating of reservoirs, and fluid inclusion homogenization temperature analysis. Results reveal two major accumulation stages: Stage 1 (125–90 Ma), corresponding to the depositional period of the Yimin Formation, represented the peak paleo-geothermal regime and the primary hydrocarbon accumulation phase. Intensive hydrocarbon generation and expulsion, coupled with robust migration dynamics, facilitated large-scale oil and gas pooling. Stage 2(65 Ma-now), from the deposition of Qingyuangang Formation to the present, uplift and denudation reduce the burial depth of source rocks, the hydrocarbon generation intensity is weakened. This phase involved secondary adjustments of pre-existing reservoirs and continued charging of newly generated hydrocarbons. The Huhehu Sag is a typical half-graben structure. Fault-block and fault-lithologic reservoirs dominate, distributed zonally along gentle and steep slopes. Lithologic reservoirs primarily occur near or within the central hydrocarbon-generating sub-sags. The most favorable hydrocarbon accumulation zones are located in the sub-sag centers and adjacent areas with high-quality reservoirs.