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 Ordovician carbonate formations in the Ordos Basin provide a crucial stratigraphic unit for prospective oil and gas exploration. Significant progress has been made in the exploration of natural gas within the Ordovician subsalt formations. Nonetheless, understanding its accumulating properties requires additional investigation. Clarifying the formation periods of the carbonate rock reservoirs in the Majiagou Formation of the basin can furnish a theoretical foundation for advanced exploration of carbonate rock oil and gas. This study uses fluid inclusion petrography, laser Raman spectroscopy, and microscopic temperature measurement methods, along with information about the basin’s history of burial and thermal evolution, to look at the oil and gas charging periods of Majiagou Formation reservoir in the central-eastern basin. The results show that there are two stages of hydrocarbon inclusions. The first stage has blue fluorescence and temperature peaks between 85 and 95 °C in the central basin and between 105 and 115 °C in the eastern basin. For the second stage, no fluorescence can be observed. Meanwhile, the temperature peaks are between 175 and 185 °C in the central basin, and between 165 and 175 °C in the eastern basin. In the central part of the basin, oil charging began in the Late Triassic (231–203 Ma) and reached the gas generation stage in the Late Early Cretaceous (121–112 Ma), peaking in natural gas charging. In contrast, the reservoirs in the eastern part of the basin experienced a primary oil charging stage in the Early Jurassic (196–164 Ma) and entered the gas generation stage in the Late Early Cretaceous (110–101 Ma). The hydrocarbon charging process in the study area is mainly controlled by the thermal evolution history of the basin. The study determines that the central basin enters the threshold of hydrocarbon generation earlier than the eastern basin, leading to earlier oil and gas charging.

This study investigates the uplift and exhumation history of the southern segment of the western margin of the Ordos Basin using low-temperature thermochronology, including zircon (U-Th)/He (ZHe), apatite fission-track (AFT), and apatite (U-Th)/He (AHe) data, combined with thermal history modeling. The study area exhibits a complex structural framework shaped by multiple deformation events, leading to the formation of extensively developed fault systems. Such faulting can adversely affect hydrocarbon preservation. To better constrain the timing of fault reactivation in this area, we carried out an integrated study involving low-temperature thermochronology and burial history modeling. The results reveal a complex, multi-phase thermal-tectonic evolution since the Late Paleozoic. The ZHe ages (291–410 Ma) indicate deep burial and heating related to Late Devonian–Early Permian tectonism and basin sedimentation, reflecting early orogenic activity along the western North China Craton. During the Late Jurassic to Early Cretaceous (165–120 Ma), the study area experienced widespread and differential uplift and cooling, controlled by the Yanshanian Orogeny. Samples on the western side of the fault show earlier and more rapid cooling than those on the eastern side, suggesting a fault-controlled, basinward-propagating exhumation pattern. The cooling period indicated by AHe data and thermal models reflects the Cenozoic uplift, likely induced by far-field compression from the rising northeastern Tibetan Plateau. These findings emphasize the critical role of inherited faults not only as thermal-tectonic boundaries during the Mesozoic but also as a pathway for hydrocarbon migration. Meanwhile, thermal history models based on borehole data further reveal that the study area underwent prolonged burial and heating during the Mesozoic, reaching peak temperatures for hydrocarbon generation in the Late Jurassic. The timing of major cooling events corresponds to the main stages of hydrocarbon expulsion and migration. In particular, the differential uplift since the Mesozoic created structural traps and migration pathways that likely facilitated hydrocarbon accumulation along the western fault zones. The spatial and temporal differences among the samples underscore the structural segmentation and dynamic response of the continental interior to both regional and far-field tectonic forces, while also providing crucial constraints on the petroleum system evolution in this tectonically complex region.

In recent years, the exploration of the Baibei Sag, located in the west of the Erlian Basin, has remained relatively underdeveloped. The Lower Cretaceous of the Baibei Sag hosts multiple tight sandstone reservoirs; however, research on the macro- and micro-characteristics, as well as the controlling factors of these reservoirs, is relatively limited. This study selected 105 Lower Cretaceous sandstone samples from the Baibei Sag for core observation, casting thin sections, scanning electron microscopy, X-ray diffraction, and high-pressure mercury intrusion analysis. The reservoir’s physical properties, pore throat structure, and diagenesis process were studied. The results indicate that the reservoir lithology is mainly composed of feldspar lithic sandstone, with an average composition of 44.3% lithic, 34.6% quartz, and 21.2% feldspar. The clay minerals in the interstitial material are primarily illite (69.3%) and illite–smectite mixed layers (12.7%), with smaller amounts of chlorite (10.9%) and kaolinite (7.2%), while smectite content is very low. The physical property analysis results indicate that the average effective porosity of the Tengger Formation sandstone is 3.3%. The average permeability is 0.01 × 10⁻³ μm². The average effective porosity of the Aershan Formation sandstone is 0.86%, and the average permeability is 0.05 × 10⁻³ μm². The Tengger Formation and Aershan Formation are both tight sandstone reservoirs. The analysis of pore throat structure shows that the reservoir space is mainly composed of dissolution pores. Three types of pore throat structures were identified, and corresponding pore models were established. Based on burial history and organic matter evolution characteristics, this study establishes a diagenetic evolution sequence of the Lower Cretaceous sandstone reservoir. Analysis suggests that the pore throat structure of different reservoir types is mainly controlled by material composition. In the process of diagenetic evolution, the Tengger Formation and Aershan Formation are in the Middle diagenetic stage A. Compaction and cementation are the main reasons for low porosity, while the dissolution improves reservoir performance. The intergranular and intragranular dissolution pores formed by dissolution are the main storage spaces of the reservoir. The early tectonic fractures are filled with calcite, and the residual small-scale fractures play a role in improving permeability.

This study analyzes the lacustrine hydrocarbon source rocks of the Lower Cretaceous in the Erdengsumu sag of the Erlian Basin, evaluating their characteristics and identifying areas with oil resource potential, while also investigating the ancient lake environment, material source input, and controlling factors, ultimately developing a sedimentary model for lacustrine hydrocarbon source rocks. The findings suggest the following: (1) The lower Tengger Member (K₁bt₁) and the Aershan Formation (K₁ba) are the primary oil-producing strata, with an effective hydrocarbon source rock exhibiting a lower limit of total organic carbon (TOC) at 0.95%. The Ro value typically remains below 0.8%, indicating that high-maturity oil production has not yet been attained. (2) The oil generation threshold depths for the Dalestai and Sayinhutuge sub-sags are 1500 m and 1214 m, respectively. The thickness of the effective hydrocarbon source rock surpasses 200 m, covering areas of 42.48 km² and 88.71 km², respectively. The cumulative hydrocarbon generation intensity of wells Y1 and Y2 is 486 × 10⁴ t/km² and 26 × 10⁴ t/km², respectively, suggesting that the Dalestai sub-sag possesses considerable petroleum potential. The Aershan Formation in the Chagantala sub-sag has a maximum burial depth of merely 1800 m, insufficient to attain the oil generation threshold depth. (3) The research area’s productive hydrocarbon source rocks consist of organic matter types I and II₁. The Pr/Ph range is extensive (0.33–2.07), signifying a reducing to slightly oxidizing sedimentary environment. This aligns with the attributes of small fault lake basins, characterized by shallow water and robust hydrodynamics. (4) The low ratio of ∑nC₂₁₋/∑nC₂₂₊ (0.36–0.81), high CPI values (>1.49), and high C₂₉ sterane concentration suggest a substantial terrestrial contribution, with negligible input from aquatic algae–bacterial organic matter. Moreover, as sedimentation duration extends, the contribution from higher plants progressively increases. (5) The ratio of the width of the deep depression zone to the width of the depression in the Erdengsumu sag is less than 0.25. The boundary fault scale is small, its activity is low, and there is not much input from the ground. Most of the source rocks are in the reducing sedimentary environment of the near-lying gently sloping zone.

The Fujin Basin (FJ Basin) is a Cenozoic sedimentary basin located in the northern Junggar Basin. In response to key scientific issues, including unclear stratigraphic distribution and an inadequately constrained structural framework, this study utilizes measured resistivity data acquired through the controlled-source sounding method. By integrating profile interpretation and numerical simulation, the geological structure and stratigraphic distribution of the basin are investigated, and the exploration potential for deep oil and gas resources as well as shallow sandstone-hosted uranium deposits is evaluated. Using known logging resistivity curves, electromagnetic frequency responses at different burial depths were simulated to verify the effectiveness of the acquisition parameters and survey design for detecting strata ranging from shallow Tertiary formations to deep Carboniferous sequences. Based on the processed data, combined with the known physical properties of the strata and comprehensive geological interpretation, the geological structure, stratigraphic distribution, and tectonic framework of the FJ Basin were clarified. Integrated with borehole geochemical data, the CSEM resistivity sections suggest that the Upper Carboniferous Haerjiawu Formation constitutes a potential hydrocarbon source rock within the JTL sag, warranting further drilling verification. In addition, resistivity attributes and dual-frequency phase attributes were employed to predict the metallogenic conditions and favorable targets for shallow Tertiary sandstone-hosted uranium mineralization. The prediction results show strong consistency with known uranium deposits, providing important guidance for uranium exploration. The methodology proposed in this study can serve as a technical reference for integrated multi-mineral exploration in similar regions.