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Investigating the micro-migration processes of hydrocarbons within interbedded shale reservoirs, and quantitatively characterizing the movability of shale oil, are highly important for the exploration and development of continental shale oil. However, due to complex pore-fracture structures, the characterization of the micro-migration and movability of shale oil presents significant difficulties, and the lack of suitable technology restricts the understanding of shale oil accumulation mechanisms and the evaluation of movability. This study employs nuclear magnetic resonance imaging (NMRI) technology in conjunction with oil charging and water flooding experiments, to innovatively visualize and quantitatively characterize the dynamic micro-migration features and movability of hydrocarbons within the pore-fracture structures of shale. The results indicate a significant increase in oil saturation within the interbedded shale oil reservoir during the oil charging process, with the oil phase primarily accumulating in larger pores (T 2 = 1–100 ms). The micro-migration and accumulation process of interbedded shale oil can be divided into three stages: the initial stage dominated by water phases in the pore spaces due to insufficient oil filling pressure, the intermediate stage marked by a rapid increase in hydrocarbons in the pore spaces, and the final stage where oil fills the entire pore system resulting in high oil saturation. The movability of different types of shale oil during water flooding varies significantly and is mainly influenced by pore-fracture structures. Interbedded shale oil reservoirs with larger pores exhibits a higher movable oil saturation (approximately 36.94%), while matrix-type shale oil reservoirs shows greater heterogeneity and lower fluid movability (approximately 14%). However, the shale oil movability of matrix-type shale oil reservoir with developed microfractures can reach 40%. More specifically, the fluid movability in smaller pore-microfracture structures (T 2 < 0.5 ms) is as high as 56.88%, surpassing that in larger pores (T 2 > 0.5 ms) (32.78%). Larger pores and microfractures substantially enhance the movability of hydrocarbons in the shale matrix, thus improving shale oil recoverability. In contrast, due to the higher capillary pressure (P c) and flow resistance (P v), smaller pores contribute less to the movability of shale oil. Overall, the outcomes of this study not only advance our understanding of the micro-migration and accumulation patterns of interbedded shale oil but also offer new insights for geological and engineering integration research on shale oil. • Visualization of dynamic micro-migration in interbedded shale oil using NMRI. • The influence of pore-fracture structure on shale oil movability was studied. • The development of microfractures significantly enhance matrix shale oil movability. • Wettability and other factors need to be considered to further improve shale oil movability [ABSTRACT FROM AUTHOR]

Zhanhua Sag is a widely accepted target zone with huge exploration and development potential for shale oil and shale gas resources. Many detailed studies have been undertaken around the geochemistry of the lower section of the third member of the Shahejie Formation (Es3x), while few studies have focused on the reservoir. In this study, based on the mineralogical features and geochemical characteristics, and by using statistical methods, the characteristics and controlling factors of reservoir space of mudstone and shale in Es3x in the Zhanhua Sag are explored through field-emission scanning electron microscopy (FE-SEM), high pressure mercury injection capillary pressure (MICP), and nuclear magnetic resonance (NMR) techniques. Three major findings were obtained. ① There are micropores and microfractures in the reservoir space, which include intergranular pores, clay intercrystal pores, pyrite intercrystal pores, dissolved pores, structural microfractures, and bedding microfractures. ② According to the features of pore size distribution (PSD), the pore distribution can be divided into the following three categories: 0–50 nm, 50 nm–2 μm, and >2 μm; the average volumes of these components are 0.01079 mL g −1 , 0.00361 mL g −1 , and 0.00355 mL g −1 , respectively, thus showing that the pores whose radii are distributed at 0–50 nm form the most important reservoir space (though those with the 50 nm–2 μm and >2 μm radii are also important and cannot be ignored). ③ There are different controlling factors when it comes to different scale pores. Based on statistics and FE-SEM results, the dissolved pores in calcite were determined to be the controlling factor for the 0–50 nm portion, the intercrystalline pores in clay and pyrite, and intergranular pores between authigenic minerals (calcite, dolomite, and pyrite) and clastic minerals (calcite and dolomite) were determined to be the controlling factors for the 50 nm–2 μm portion, and the structural microfractures and bedding microfractures were determined to be the main factors for the >2 μm portion. Furthermore, it is the brittle minerals content and bedded structure that control the microfractures. This study thus clarifies the types and characteristics of reservoir space and identifies pore structure controlling factors of mudstone and shale in Es3x in the Zhanhua Sag; this information has important significance for future reservoir evaluations. [ABSTRACT FROM AUTHOR]

Pore structure is of great importance in the occurrence of shale gas. In this study, pores in shale samples from the Lower Silurian Longmaxi and Lower Cambrian Niutitang shales in Chongqing, in the Upper Yangtze Platform, South China, were examined using focused ion beam–He ion microscopy (FIB–HIM), nano-computerized tomography (nano-CT), and gas adsorption analysis. The results show that most pores in measured samples of the Niutitang shale are mineral matrix pores and have poor connectivity, including both intraparticle and interparticle pores. Organic matter pores in measured samples of the Niutitang shale are rare and have small diameters. In measured samples of the Longmaxi shale, OM pores—mostly macropores and large mesopores—are the most abundant. The nano-CT results revealed that the abundance of OM pores led to good pore connectivity in the Longmaxi shale samples, whereas the prevalence of mineral matrix pores resulted in poor connectivity in the Niutitang shale samples. N 2 and CO 2 adsorption analyses showed that the mean value of micropore–mesopore volumes in the Niutitang and Longmaxi shales samples are 0.0332 ml/g and 0.0261 ml/g, respectively. The mean values of micropores–mesopores surface area in the Niutitang and Longmaxi shales samples are 33.84 m 2 /g and 32.46 m 2 /g, respectively. Thus, there is little difference between measured samples of the Longmaxi and Niutitang shales in terms of volume and surface area of micropores–mesopores. The equal-vitrinite reflectance (equal-Ro) values of measured samples of the Longmaxi shale are lower than those of the Niutitang shale samples. Over-maturity (equal-Ro>3%) resulted in a reduction of the number of pores in organic matter, small pore size, and poor connectivity in measured samples of the Niutitang shale. Relatively low maturity (2%