In this study, the formation mechanism of authigenic chlorite in tight reservoirs and its influence on the adsorption capacity to tight oil have been analyzed. The occurrence states of chlorite and the formation mechanism have been analyzed by thin section (TS) and field emission scanning electron microscopy (FE-SEM) measurements. Due to the alteration of volcanic rock fragments, the mudstone pressurized water, and the dissolution of early chlorite, the material source has been provided for the formation of chlorite. The formation time of chlorite with different occurrence states is in the following order: grain-coating chlorite → pore-lining chlorite → pore-lining chlorite in dissolved pores → rosette chlorite. Authigenic chlorite developed in the reservoirs has influenced the change of the reservoir quality in two respects. On the one hand, authigenic chlorite can protect the residual pores, improve the anti-compaction capacity of the reservoir, and provide certain inter-crystalline space. On the other hand, it can hinder pore space and inhibit throat, resulting in a decrease in the connectivity of pores and the increase in the heterogeneity of the reservoir. Tight oil absorbed by the chlorite is mainly in the form of the thin film and aggregates. Through in situ testing of environmental scanning electron microscope (ESEM) and energy dispersive spectrum (EDS), the adsorption capacity of chlorite with different occurrence states to tight oil, being in the following order: rosette chlorite > pore-lining chlorite > pore-lining chlorite in dissolved pores > grain-coating chlorite. Furthermore, the controlling factors on reservoir quality, the content of chlorite and content of Fe and K have been investigated, and the adsorption capacity of different chlorite types has been studied, which can provide guidance for analysis of the control factors on the difference in adsorption capacity of different occurrence states of chlorite to tight oil in tight reservoirs.

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.

Tight oil is a great potential resource for unconventional oil exploration and development. Determining the content of adsorbed tight oil in sandstone reservoirs and the factors controlling its content is crucial for the evaluation and development of tight oil resources. Using fluorescence petrography, environmental scanning electron microscopy, porosity as well as permeability analyses, high-pressure mercury intrusion, and nuclear magnetic resonance imaging, the present study analyzed the occurrence form, location, and relative content of free and adsorbed tight oils and effect of controlling factors on the content of adsorbed tight oil in sandstone reservoirs of the Chang 8 member in the Huaqing area of the Ordos Basin. The free tight oil mainly exists in residual intergranular, intergranular dissolved, intragranular dissolved, and dissolution-enlarged pores as well as some throats in the form of flakes with various areas and slender strips. The adsorbed tight oil mainly occurs on the surfaces of the mineral particles and mica fragments as well as in fractures, some throats or the intragranular as well as intergranular dissolved pores in the form of films with variable thicknesses and long strips. The lower limit of the pore radius at which free tight oil occurs in sandstone is approximately 0.1 μm and the adsorbed tight oil occurs on the surface of mineral particles and in spaces with pore radii of 0.02–0.3 μm. The contribution of free tight oil to total tight oil in the present study has highest and lowest content of 60.95% and 32.48%, respectively, with an average content of 50.14%. The contribution of adsorbed tight oil to total tight oil has highest and lowest content of 67.52% and 39.05%, respectively, with an average content of 49.86%. The content of adsorbed tight oil is generally proportional to the median pressure and inversely proportional to the porosity as well as permeability of the reservoir; particularly, porosity is relevant. The content of adsorbed tight oil is inversely proportional to the quartz content and directly proportional to the feldspar, carbonate cement, and clay mineral content of the sandstone.

Understanding the micro-occurrence mechanism of tight oil has long been a daunting challenge in the exploration and development of unconventional resources. This article discusses the micro-occurrence mechanism of tight oil through continuous extraction by combining thin casting, fluorescent thin sections, environmental scanning electron microscope observations, physical property testing, and X-ray diffraction experiments. The results indicated that in the tight sandstone of the Chang 8 Formation in the Ordos Basin, the average tight oil content was 35.46% for microscale pores, 35.74% for nanoscale pores, and 28.79% for mineral surfaces. Six types of micro-occurrence states of tight oil were identified: emulsion, cluster, throat, star-like, isolation, and thin film forms. Although clay minerals and heavy components dominate the adsorption of tight oil on mineral surfaces, micro-occurrence is fundamentally an oil–rock interaction process. Hence, oil–rock interactions and occurrence states were combined in this study to identify tight oil’s micro-occurrence mechanism. The van der Waals forces of attraction between asphaltene molecules and a mineral surface play a critical role, and minerals with hydroxyl groups can also combine with carboxyl and hydroxyl groups present in tight oil. As a consequence of the adsorption of heavy components by minerals, tight oil components remain in microscale and nanoscale pores with a higher saturation, increased aromatic hydrocarbon content, and greater fluidity. The heterogeneity of the components due to adsorption influences the physical properties and mineralization framework of tight oil reservoirs. These findings suggest that tight oil occurrence results from the coupling of microscopic occurrence and component heterogeneity in microscale and nanoscale pores.