In this paper, the limestone reservoir of the Upper Permian Taiyuan Formation in the Ordos Basin is taken as the research object. Through various analysis and testing methods, the characterization and classification evaluation of pore structure were carried out. The core porosity and pore structure characteristics were analyzed using nuclear magnetic resonance, gas measurement, and CT scanning. Based on the characteristics of the limestone reservoir, the optimal parameters of NMR testing were calibrated, the NMR testing method of limestone reservoir properties was established, and the NMR porosity of limestone was calculated. Using the core gray map obtained using CT scanning imaging technology, the three-dimensional digital core model of limestone was constructed, its pore space was extracted, and the porosity, pore fractal dimension, and tortuosity were calculated. The results show that with the thermodynamic experiment, the porosity of the sample will remain basically unchanged after 180 min, and the pressure in the sample was measured after 4 h and no air leakage was found. The T2 spectrum of saturated marlite is in the form of three peaks, two peaks, and one peak. On the whole, the p1 peak of the T2 spectrum of limestone corresponds to micropores, and most of the p2 and p3 peaks correspond to mesopores–macropores. The pore size of high porosity samples is 150–350 nm, and the micropores are well developed; the pore size of medium porosity samples is 80–150 nm, and some samples are well developed; the pore size of low porosity samples is mostly bimodal, with two peaks >> 300 nm and <<100 nm. With the increase in depth, the porosity decreases gradually, the fractal dimension decreases, and the tortuosity increases. The research results provide data support for the characterization of the pore structure of the limestone reservoir in the Taiyuan Formation of the Ordos Basin.

The lithology and lithofacies assemblage of shale are highly complex and heterogeneous in the continental shale formations due to rapid changes in the sedimentary environment and source material, complicating the evaluation of shale oil enrichment areas, such as the member 3 of the Shahejie Formation in the Qikou sag, Bohaibay Basin, China. We used core observations and descriptions of well F39 × 1 and performed X-ray diffraction, scanning electron microscopy, nitrogen adsorption analysis, and nuclear magnetic resonance analysis to investigate the shale lithofacies characteristics and types in member 3 of the Shahejie Formation, and their effects on shale oil enrichment. The results showed the following. (1) The lithofacies are divided into four types according to the shale’s laminar structure, lithological characteristics, mineral composition, and organic matter content: thin laminar shale, thick laminar shale, massive mudstone, and argillaceous siltstone. These are divided into six subcategories. Each lithofacies has thin vertical layers. (2) The thin and thick laminar shale layers have favorable conditions for shale oil enrichment, such as a high total organic carbon content (TOC) (1.1–1.6%), many micropores (with the diameter of 0.5–2 µm) and fissures, a high residual hydrocarbon content (1.0–2.3 mg/g), and a good source-reservoir relationship, making them suitable for shale oil exploration. (3) The degree of lamina development influences the organic matter and residual hydrocarbon contents, the number of micropores, and the degree of shale oil enrichment. The semi-deep and deep lake facies are favorable areas for shale oil development.

In recent years, gas reservoirs containing high levels of hydrogen sulfide have been found in salinized lacustrine carbonate rocks in the upper member of the Lower Ganchaigou Formation (E₃²) in the Yingxiongling area of the western Qaidam Basin. This poses great safety risks to drilling and development. To clarify the genetic mechanisms of hydrogen sulfide, we have analyzed the geochemical characteristics and sulfur isotopes of natural gas and predicted the distribution of hydrogen sulfide. The results show that (1) natural gas in the Yingxiongling area is dominated by wet gas, with relatively high nonhydrocarbon content. The gas is E₃²oil-type gas in a mature stage. (2) Hydrogen sulfide in natural gas reservoirs is less likely to originate from biological and volcanic geneses, and it is primarily a product of thermochemical sulfate reduction. The high-quality Oligocene source rocks distributed across a large area, the saline-deposit formations widely distributed in the western Qaidam Basin, and the high geothermal gradients and large numbers of developed pore-type reservoirs, all combine to provide favorable conditions for the formation of hydrogen sulfide reservoirs. (3) During the E₃² deposition period, rock salt developed in the center of the lake basin, the sealing conditions for oil and gas were favorable, and the formation temperature was high during the reservoir formation period. Development of subsalt porous reservoirs is conducive to enrichment of hydrogen sulfide, and comprehensive prediction indicates that the subsalt formation in the Central Yingxiongling-Ganchaigou area is an enrichment zone for hydrogen sulfide. The research results are of considerable significance for the exploration and deployment, and the production safety, of hydrogen sulfide-containing reservoirs.

To study the impact of faults on the enrichment and mobility of shale oil in the Gulong area, representative rock samples were selected in this paper. Based on geochemical data and chemical kinetics methods, coupled with shale oil enrichment and mobility analysis techniques, the shale oil generation quantity and in situ oil content were evaluated from the perspectives of shale oil generation and micro migration, and the mobility of shale oil was revealed. At the same time, the hydrocarbon expulsion efficiency (HEE) of shale was qualitatively and quantitatively characterized, combined with the development of faults. The research results indicate that the study area mainly develops organic-rich felsic (ORF)/organic-containing felsic (OCF) shale, their proportion in both wells exceeds 65%, and the resource amount is the largest in this type of lithofacies. The development of a fault controls the enrichment of shale oil, and the in situ oil content and oil saturation index (OSI) of the shale in well Y58, which is close to the fault, are significantly worse than those in well S2. Well Y58 has 9.52 mg/g and 424.83 mg/g TOC respectively, while well S2 has 11.34 mg/g and 488.73 mg/g TOC respectively. The fault enhanced the migration of shale oil, increasing the efficiency of oil expulsion. As a result, the components with weak polarity or small molecules, such as saturated hydrocarbons and low carbon number n-alkanes, are prone to migration, reducing the mobility of shale oil.