Small-angle neutron scattering and high-pressure mercury intrusion capillary pressure testing are integrated to analyze the pore size distribution of the broad sense shale oil reservoir samples of the Permian Lucaogou Formation in the Jimsar Sag, Junggar Basin, China. The results show that, compared with the measurement method integrating gas adsorption and mercury intrusion, combination of small-angle neutron scattering and mercury intrusion can more accurately characterize full-scale pore size distribution. The full-scale pore size distribution curve of the rock samples in the study area includes two types: the declining type and submicron pore-dominated type. The declining type is mainly found with silty mudstone and dolomitic mudstone, and most of its pores are smaller than 80 nm. Silt-fine sandstones and dolarenite are mostly of the submicron pores-dominated type, with most pores smaller than 500 nm. They also present large specific pore volumes and average pore diameters of macropores and are the favorable lithogenous facies for development of high-quality reservoirs.

The rapid and cost-effective quantitative characterization of broad-sense shale oil reservoirs is highly challenging due to the complex lithology and strong heterogeneity of the strata. In this paper, the pore structures and surface roughness of samples of various lithologies from a shale oil reservoir were studied using atomic force microscopy (AFM) and the open-source Gwyddion analytical software. The surface morphology was reconstructed both two-dimensionally and three-dimensionally using the AFM data for the mudstone, siltstone, and dolarenite in a broad-sense shale oil reservoir. The surface roughness was evaluated with respect to parameters such as the arithmetic average roughness, root mean square roughness, surface skewness, and kurtosis coefficient. The pores of various scales were quantitatively identified using the watershed algorithm. The samples were also evaluated using focused ion beam scanning electron microscopy for comparison, and the derived pore scales are consistent with those obtained from the AFM analysis. In conclusion, the utilization of AFM and open-source software provides a new easy-to-operate method, which can be widely applied to characterize the surface roughness and pore structures of unconventional oil and gas reservoirs.

The micro distribution of residual oil in low-permeability sandstone reservoirs is closely related to pore structure, and the differences in pore structure often determine the reservoir’s productivity and development effectiveness from a macro perspective. On the basis of in-depth research, this paper analyzes the distribution law of the remaining microscopic oil, establishes the digital core multi-stage pore network modeling of the strongly sorted heterogeneous conglomerate reservoir in the Lower Wuerhe Formation of Block 8 of the Karamay Oilfield, the three-phase seepage simulation method considering the release of dissolved gas, and the three-phase permeability curve test. The research results are as follows: (1) Conventional physical property analysis shows that the permeability of core samples exhibits an inverse rhythmic distribution with layer depth. (2) CT core analysis and mercury injection experiments indicate that the area with porosity ranging from 9% to 21% accounts for 79% and is the main seepage channel area. Larger pores play an important role in seepage. (3) Through comparative experiments on cores with different permeability, it was found that the degassing phenomenon of low-permeability rock samples is more severe. In the actual process of reservoir development, it is necessary to reasonably handle the impact of water injection on development effectiveness, select appropriate water injection methods and cycles, and avoid premature water breakthrough in ultra low-permeability reservoirs.

To further clarify the optimal target layer in the horizontal section of Wufeng–Longmaxi shale, we selected 126 shale samples from the Wufeng–Longmaxi Formations (Long1₁¹ to Long1₁⁴ and Long1₂ submember) as the primary study objects from the perspective of the microscopic pore structure. We conducted this experimental study on the pore structure of shale samples according to various methods, including low-temperature nitrogen adsorption and carbon dioxide adsorption experiments, atomic force microscopy, and nano-computed tomography scanning. We calculated the fractal dimensions of samples at different horizons through the study of the characteristics of adsorption–desorption isotherms using the Frenkel–Halsey–Hill model. These results indicated that the shale samples had a complex pore structure (with a higher fractal dimension). The fractal dimensions were positively correlated with the specific surface area and total organic carbon content of the shale samples, weakly positively correlated with the micropore pore volume, and negatively correlated with the average pore radius. The samples from the Wufeng Formation and the Long1₁¹ and Long1₁² submembers had large fractal dimensions, whereas the samples from Long1₂ had the smallest fractal dimension. The pores of the shale samples generally were type H2/3, which were characterized by wedge, tabular, and ink-bottle shapes. Only three H3-type pore samples corresponded to the three smallest fractal dimension values. The Wufeng Formation’s Long 1₁¹ and Long 1₁² layers should be the target layers for horizontal wells. In this study, we identified the optimal target layer of the horizontal shale profile of Wufeng–Longmaxi Formation, which holds great significance for shale oil and gas development in this formation.

Regarding sandwich-type shale oil reservoir characterized by diversified lithologies and complex fluid mobility, we combined one- and two-dimensional (1D and 2D) nuclear magnetic resonance (NMR) core analysis techniques to quantitatively study the movable oil and fluid saturations of rock samples with different lithologies. First, we used 2D T₁-T₂ NMR to analyze the spectrum curve of the dolomitic mudstone and siltstone samples from a sandwich-type shale oil reservoir at initial and oil-saturated states. We evaluated the occurrence of movable oil saturations in source and reservoir rocks. Then, we analyzed samples of the siltstone serving as the reservoir rock using a centrifuge combined with 1D NMR approach to evaluate the characteristics of movable fluid saturations inside the reservoir. The results showed that the samples of dolomitic mudstone serving as the source rock in the sandwich-type shale oil reservoir in the Lucaogou Formation in Jimsar had the occurrence of kerogen and bitumen signals, the development of small- and medium-scale organic matter pores, and an average movable oil saturation of 15.6%. The siltstone serving as the reservoir rock had an average movable oil saturation of 53.8%, and its movable fluid saturation was positively correlated with porosity and permeability. For samples whose porosity was greater than 12% and permeability was greater than 0.1 mD, their movable fluid saturations usually were higher than 40%. Therefore, siltstone was the preferable diagenetic facies for the development of high-quality reservoirs.