Tight oil is an important unconventional hydrocarbon resource. The differences in occurrence characteristics between light components (LCs) and heavy components (HCs) of tight oil profoundly affect its mobility and recovery. Current research has focused mainly on the rapid evaluation of the relative contents of LCs, whereas few studies have systematically analyzed the occurrence characteristics of LCs and HCs and their controlling factors. In this study, the differential occurrence characteristics between LCs and HCs are clarified on the basis of data from thin-section petrography, X-ray diffraction, nuclear magnetic resonance, confocal laser scanning microscopy, and reservoir pyrolysis analysis. An innovative quantitative characterization methodology for the relative occurrence volumes of LCs and HCs is proposed. On the basis of this method, the controlling factors that cause the different occurrence characteristics of LCs and HCs are elucidated. Furthermore, the occurrence characteristics of LCs and HCs in various source–reservoir combinations, physical properties, and development intensities of argillaceous laminae are summarized. Finally, an occurrence model of the crude oil components in the Chang 7 tight reservoir is established. The results show that LCs and HCs in the Chang 7 tight reservoir exhibit differences in occurrence volume, state, morphology, and pore size. These differences are primarily controlled by the hydrocarbon generation intensity of the source rock, the source-to-reservoir distance (SRD), and the content of oil-wet minerals in the reservoir. The source sandwich combination exhibits high physical properties, low hydrocarbon generation intensity, high SRD, and low oil-wet mineral content, resulting in relatively high LCs. The source–reservoir interbed and reservoir sandwich combinations feature a high content of argillaceous laminae, high hydrocarbon generation intensity, low SRD, and high oil-wet mineral content, resulting in relatively low LCs. There are three occurrence models of crude oil components in the Chang 7 tight reservoir: the charging force controlling model, the adsorption effect controlling model, and the argillaceous laminae controlling model. The results of this study provide significant guidance for predicting the fluidity of tight oil, accurately assessing the amount of recoverable tight oil resources, and achieving efficient extraction of tight oil.

In tight reservoirs deposited in diverse sedimentary settings, the pore structure governs tight oil enrichment features and sweet-spot distribution. Taking the tight sandstone reservoirs of the lower third member of the Shahejie Formation in the Linnan Subsag of Bohai Bay Basin in China as an example, this study employs XRD to delineate petrological characteristics, while porosity and permeability measurements are used to quantify physical properties. In addition, thin section, SEM, HPMI, NMR, fractal theory, and cathodoluminescence experiments are applied to investigate pore structure characteristics and influencing factors. The results reveal two sedimentary systems: turbidity current and delta front deposits. Turbidite reservoirs exhibit the coarse pore-coarse throats (Type A), medium pore-medium throats (Type B), and fine pore-medium throats (Type C) pore structures. Delta front reservoirs are characterized by medium-pore-coarse-throat (Type D), medium-pore-fine-throat (Type E), and fine-pore-fine-throat (Type F) pore structures. Turbidite reservoirs show more favorable pore structures for oil exploration compared to delta fronts, in which lithofacies and diagenetic facies are the key influences. A genetic model identifies the highest-quality Type A forms in fine sandstone lithofacies under medium compaction–medium cementation–strong dissolution, with pore diameters averaging 10.84 μm in turbidite reservoirs. Conversely, the poorest Type F forms in argillaceous layered siltstone lithofacies under strong compaction, cementation, and weak dissolution diagenetic facies in delta fronts, with pore diameters averaging 0.88 μm. Consequently, the control effect of the pore quality means that Type A has the highest and Type F has the lowest oil-bearing capacity. These findings provide valuable guidance for the classification, evaluation, and exploration of tight oil sweet spots.