The Kuqa Basin is a typical foreland basin in northwest China, characterized by compressive foreland fold-and-thrust belts and a regionally distributed huge salt layer. A large number of overthrust faults, fault-related folds, and salt-related structures are formed on the thrust belt due to strong compression and structural deformation, causing difficulty in simulation of the basin. In this study, modeling of the thermal history of the complicated compressional structural profiles in the Kuqa foreland basin was successfully conducted based on the advanced “Block” function introduced by the IES PetroMod software and the latest geological interpretation results. In contrast to methods used in previous studies, our method comprehensively evaluates the influence of overthrusting, a large thick salt layer with low thermal conductivity, fast deposition, or denudation on the thermal evolution history. The results demonstrate that the hydrocarbon generation center of the Kuqa foreland basin is in the deep layers of the Kelasu thrust belt and not in the Baicheng Sag center, which is buried the deepest. A surprising result was drawn about the center of hydrocarbon generation in the Kuqa foreland basin, which, although not the deepest in Baicheng Sag, is the deepest part of the Kelasu thrust Belt. In terms of the maturity of the source rock, there are obvious temporal and spatial differences between the different structural belts in the Kuqa foreland basin, such as the early maturation of source rocks and the curbing of uplift and hydrocarbon generation in the piedmont zone. In the Kelasu thrust belt, the source rock made an early development into the low mature-mature stage and subsequently rapidly grew into a high-over mature stage. In contrast, the source rock was immature at an early stage and subsequently grew into a low mature-mature stage in the Baicheng Sag–South slope belt. The time sequence of the thermal evolution of source rocks and structural trap formation and their matching determines the different accumulation processes and oil and gas compositions in the different structural belts of the Kuqa foreland basin. The matching of the multistage tectonic activity and hydrocarbon generation determines the characteristics of the multistage oil and gas accumulation, with the late accumulation being dominant. The effective stacking of the gas generation center, subsalt structural traps, reservoir facies of fine quality, and huge, thick salt caprocks creates uniquely favorable geological conditions for gas enrichment in the Kelasu foreland thrust belt.

Gas adsorption experiments are becoming one of the most common methods to quantify and analyze the pore structures of shale samples in the petroleum industry. In this regard, particle size of the specimen plays an important role in the results that could ultimately affect the pore structure interpretation. Hence, in this study, five shale samples at different thermal maturity levels are picked, and all are crushed into different groups of particle sizes: less than 40 mesh (375μm), less than 60 mesh (250μm), less than 80 mesh (187.5μm), and less than 100 mesh (150μm). Next, N₂ adsorption is used to characterize the pore structures of the samples within different particle sizes. Furthermore, to interpret the data, several attributes such as the pore volume, surface area, fractal dimension (from the fractal analysis), and heterogeneity index (from the multifractal analysis), are studied and compared between the samples and particle size intervals to provide us with the effect that particle size could have on the pore structure analysis. The results showed that as the particle size varies, the pore structures of the shale samples could get affected. Based on the comparison of the results, it is recommended that a suitable particle size for the shale pore structure characterization in N₂ adsorption experiments should be less than 60 mesh (250μm).

The Upper Ordovician Wufeng Formation and Lower Silurian Longmaxi Formation black shales are the critical targets for shale gas exploration in the Sichuan Basin of South China. The enrichment of organic matter (OM) in shale is the basis for the generation of large-scale shale gas; however, its controlling factors in Wufeng-Longmaxi shales are still under debate, and few studies have focused on the edge of the Sichuan Basin. Based on the mineral composition, total organic carbon (TOC), and systematic inorganic geochemistry analysis of 72 core samples from Wufeng and Longmaxi formations in Well Xike 1, southeastern Sichuan Basin, the sedimentary conditions (palaeoclimate, palaeoredox, and palaeoproductivity) were reconstructed, and the controlling factors of OM enrichment were identified. The mineral compositions are dominated by quartz, clay minerals, calcite, and feldspar, associated with minor dolomite, pyrite, and anhydrite. The TOC contents (0.31-6.84, avg. 2.22) show an upward decreasing trend from the Wufeng Formation to Longmaxi Formation. The chemical index of alteration (CIA) ranges from 65 to 71 (avg. 69), indicating warm and humid climate with moderate weathering. The diagrams of Al₂O₃-TiO₂, TiO₂-Zr, Zr/Sc-Th/Sc, La/Th-Hf, and La-Th-Sc jointly indicate the contribution from felsic and intermediate rock weathering. The P/Al, Cu/Al, and Ni/Al ratios suggest that marine paleoproductivity was relatively high in the Wufeng Formation and relatively low to moderate in the Longmaxi Formation. The V/Cr, V/Sc, U/Th, Mo_EF/U_EF, and C_org/P ratios indicate that the bottom water was anoxic during the Wufeng Formation deposition and then fluctuating dysoxic and/or oxic in the overlying Longmaxi Formation. The TOC content was positively correlated with productivity proxies (P/Al, Cu/Al, and Ni/Al) as well as redox proxies (U/Th, V/Cr, Mo_EF/U_EF, and C_org/P), indicating that the OM accumulation in Wufeng-Longmaxi shales is mainly controlled by high productivity and anoxic bottom water conditions.

The adsorption of crude oil in the tight sandstone reservoir is significant. Occurrence states of adsorbed tight oil and its pore and throat reduction effect are two significant directions in tight oil exploration and development. In this paper, the occurrence state of adsorbed tight oil and its porosity and permeability reduction effect is systematically analyzed based on a detailed description and discussion of occurrence space, states, changes of porosity and permeability, and its controlling factors. Five occurrence states are recognized based on the differences in spatial location and morphology of adsorbed tight oil. Adsorbed oil is distributed in all kinds of reservoir spaces and primarily concentrated in the μm. The distribution characteristics of reservoir spaces control the occurrence states of adsorbed tight oil. The emulsion form, cluster form, throat form, thin film form, and isolation form are mainly stored in intergranular pores, feldspar dissolved pores, throats, the surface of minerals, and intercrystalline pores, respectively. The massive development of quartz, feldspar, and illite is conducive to the distribution of emulsion form, cluster form, and the throat form of tight oil, while the abundance of clay, especially chlorite, controls the distribution of the thin film form and isolated form of tight oil. The adsorption of tight oil causes clogging in the pore network, resulting in reservoir damage. The adsorption of tight oil in the reservoir leads to increased reservoir density by 0.290 g/cm³ and the reduction of porosity and permeability by 3.14% and μm², respectively. And the damage of adsorbed oil to permeability (30.79%) is more severe than that of porosity (19.96%). The effect of pore and throat reduction is more evident in reservoirs with higher content of quartz and feldspar. However, the strong adsorption of clay makes it difficult to separate the tight oil adsorbed on its surface. The nature of adsorbed oil in different occurrence states also can determine the separation efficiency in the extraction process. The adsorbed tight oil with emulsion, cluster, and throat forms is easier to desorb than the isolation and thin film forms. The research results can provide a basis for analyzing the occurrence characteristics and reasonably formulating the development method of tight oil. In addition, it can even provide a new understanding and basis for the densification process of reservoir permeability under different conditions.

DF13-2 and YC13-1 are two large gas fields found in Yinggehai and Qiongdongnan Basins, respectively, and the gas-source correlation is a very challenging scientific exercise due to the similarity of their hydrocarbon isotoperatios and gas dryness. In this study, the chemical and isotopic compositions of natural gases (including rare gases and bulk gases) and the biomarkers of condensate were comprehensively integrated to identify their origins. The gases from the two fields are composed primarily of methane (87–91%), and isotope ratios of hydrocarbon compounds exhibit a thermogenic origin, with δ¹³C₁ values ranging from − 40.7 to 35.0‰, and δ¹³C₂ from − 27.0 to − 25.4‰. There are small yet distinct differences in the genetic characteristics of CH₄ He, Ar, CO₂, N₂ and condensate between the samples from two regions. The δ¹³C₁ values of DF13-2 (− 36.8 to − 33.7‰) are slightly larger than those (− 40.7 to − 35.5‰) of YC13-1, suggesting a slightly higher thermal maturity in DF13-2 field. In addition, DF13-2 gases contain lower Ar (0.0096–0.016%) and He (11–15 ppm). The ³He/⁴He ratios range from 3.31 × 10⁻⁸ to 7.72 × 10⁻⁸, indicating a typical crustal origin, likely representative of pristine source-rock signatures. The gases have higher N₂ (8.4–9.66%) but lower CO₂ contents (0.10–0.36%), which are co-generated with the thermogenic hydrocarbon gases. The condensate coexisted with gas contains abundant terrestrial-derived oleanane but a low abundance of bicadinanes. These characteristics correlate well with the Miocene neritic shales in Yinggehai Basin. Fractures associated with the diapiric activity provide key conduits for gas up-migration into the Huangliu Formation reservoir, implying that the flank of a diapiric structure is a favorable site for gas accumulation. In contrast, the gases from YC13-1 field show lower N₂ but higher CO₂ amounts. He and Ar abundances are both higher with a small amount contribution (2–9%) of mantle-derived He. The elevated amounts of mantle-derived ³He may come from mantle-enriched groundwater circulating in the petroleum system. The coexisted condensate is rich in terrestrial biomarkers such as oleanane and bicadinane, which is significantly different from DF13-2 condensate, and has a close affinity with the coal-bearing source rocks of the Oligocene Yacheng Formation. Unconformities and faults serve as important conduits for lateral and vertical migration from the source rocks to the traps. This suggests that short-distance migration and source facies control the distribution of the natural gases in Qiongdongnan Basin. This study provides novel insights into the origin and accumulation model of natural gases in Yinggehai and Qiongdongnan Basins.

There is great potential for tight oil as an alternative to conventional fossil fuels throughout the world. Adsorption, mineralogy, and pore structure of tight sandstone are very important factors for the efficient development of adsorbed tight oil from tight sandstone oil reservoirs. In this study, the occurrence morphology of tight oil adsorbed to varying pore structures was examined, as well as the relationship between adsorption content and occurrence morphology. X-ray energy dispersive spectra, environmental scanning electron microscope observations, and thin fluorescence sections were used to describe the occurrence morphology of adsorbed tight oil in tight sandstone reservoirs. It was found that adsorbed tight oil can be classified into five types: emulsion, cluster, throat, thin-film, and isolation, with average contents of 34.9%, 14.5%, 3.1%, 42.7%, and 4.7%, respectively. In addition, a Soxhlet extraction was developed with four pore structures to describe the geological effects of adsorbed tight oil in reservoirs. The adsorption content of tight oil ranges from 4.015 mg/g to 16.987 mg/g, with an average of 10.115 mg/g. The order of adsorption content for different occurrence morphologies is as follows: emulsion form > throat form > cluster form > isolation form > thin-film form. It is the size and connectivity of the porous throat that determines the desorption efficiency of tight oil. An important outcome of this study can be the introduction of rational development plans and the improvement of oil recovery efficiency for tight oil reservoirs.