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.

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.

The characterization of geothermal reservoirs and their genetic mechanisms is critical for understanding geothermal system evolution and evaluating geothermal resource potential. The eastern Gushi Sag of the Weihe Basin hosts three Neogene sandstone geothermal reservoirs, including the Gaoling Group, Lantian–Bahe Formation, and Zhangjiapo Formation; however, their reservoir characteristics and genetic mechanisms remain poorly constrained. This study integrates geological structures, geothermal well logging, core petrophysical properties, and hydrochemical data to characterize reservoir conditions and establish a genetic model. The results show that the Neogene reservoirs are mainly composed of feldspathic sandstone, with the Lantian–Bahe Formation identified as the primary geothermal reservoir due to its moderate porosity, low permeability, large sandstone thickness, and favorable continuity. The geothermal field exhibits an average geothermal gradient of 3.35 °C/100 m with a south-to-north decreasing trend. Hydrochemical evidence suggests that geothermal fluids originate mainly from meteoric water recharged from the northern Qinling Orogenic Belt and paleo-sedimentary water, with deep faults and pore networks controlling fluid migration and accumulation. The Quaternary strata and Zhangjiapo Formation provide effective sealing conditions. This study reveals the coupled controls of thermal conditions, reservoir architecture, fluid circulation, and preservation on sandstone geothermal systems, providing insights into geothermal resource assessment, exploration strategy optimization, and the formation mechanisms of similar sedimentary basin geothermal systems.