The low permeability of shale matrices necessitates overcoming a threshold pressure gradient to initiate hydrocarbon flow, which poses a major constraint on recovery efficiency. However, the microscopic mechanisms underlying the threshold pressure gradient, particularly the roles of interfacial interactions and pore confinement, remain unclear. A comprehensive understanding of the threshold pressure gradient is essential for enhancing recovery strategies and improving shale oil extraction efficiency. This study provides a comprehensive analysis of the interfacial and size effects on the threshold pressure gradient within kerogen, quartz, and portlandite pores using molecular dynamics simulations. A method for assessing molecular thermal motion and quantifying the threshold pressure gradient was developed using molecular dynamics simulations. The results indicate that the threshold pressure gradient decreases in the order of kerogen, quartz, and portlandite pores. The adsorption characteristics of shale oil components at the interface were clarified through density distribution and molecular behavior analysis, and the factors contributing to the threshold pressure gradient were identified. It was found that the threshold pressure gradient is significantly influenced by the strength of interfacial interactions between the polar shale oil components and the solid matrix. Additionally, an analytical model was proposed to predict the correlation between the threshold pressure gradient and the pore size, which can extend the prediction of the threshold pressure gradient to a larger scale of thousands of nanometers. These findings offer insights into shale oil recoverability in nanopores and provide theoretical guidance for its extraction.

The Gulong shale oil represents China’s first attempt at large-scale exploration and exploitation of the oil contained in shale sequences without intercalations. Clarifying the rock mechanical characteristics and fracture propagation mechanisms of the Gulong shale is vital for guiding the selection of landing zones and fracturing design and engineering parameter optimization. In this study, the mineral distribution, thin section observation and rock mechanics tests are performed to clarify the Gulong shale as “fine layered” texture in mechanics and reveal the fracture propagation mechanisms under the control of multiple geological and engineering factors. It is shown that the Gulong shale is characterized by high clay mineral content (Avg. 46.6 %), strong plasticity, a foliation intensity of up to 1000~3000 stripes per meter and strong mechanical anisotropy. Unlike the brittle fracturing of conventional shale, the typical rock samples from Gulong exhibit high-frequency fluctuation in mechanical property, with a fluctuation frequency of 3.33 times per cm for a compressive strength greater than 20 MPa. The fracturing process is observed as a steady gradual process with a slow post-peak stress decline, and along a random path in a zigzagged shape. Meanwhile, in the case of high-density foliation fractures, the hydraulic fractures in the Gulong shale are of complex morphology, with their height and length being significantly constrained. The limited vertical and horizontal extension of hydraulic fractures has been a major constraint for the effective stimulation of the Gulong shale oil reservoir. It is thereby suggested that the hydraulic stimulation of the Gulong shale oil reservoir should follow the principle of controlling near-wellbore fracture branching and further extending distal fracture networks, while placing the fracturing treatment under more effective control to suppress the development of near-wellbore fractures and boost the extension of main fractures to sufficiently expand the stimulated reservoir volume.

Reliable prediction of the shale fracturing process is a challenging problem in exploiting deep shale oil and gas resources. Complex fracture networks need to be artificially created to employ deep shale oil and gas reserves. Randomly distributed minerals and heterogeneities in shales significantly affect mechanical properties and fracturing behaviors in oil and gas exploitation. Describing the actual microstructure and associated heterogeneities in shales constitutes a significant challenge. The RFPA^3D (rock failure process analysis parallel computing program)-based modeling approach is a promising numerical technique due to its unique capability to simulate the fracturing behavior of rocks. To improve traditional numerical technology and study crack propagation in shale on the microscopic scale, a combination of high-precision internal structure detection technology with the RFPA^3D numerical simulation method was developed to construct a real mineral structure-based modeling method. First, an improved digital image processing technique was developed to incorporate actual shale microstructures (focused ion beam scanning electron microscopy was used to capture shale microstructure images that reflect the distributions of different minerals) into the numerical model. Second, the effect of mineral inhomogeneity was considered by integrating the mineral statistical model obtained from the mineral nanoindentation experiments into the numerical model. By simulating a shale numerical model in which pyrite particles are wrapped by organic matter, the effects of shale microstructure and applied stress state on microcrack behavior and mechanical properties were investigated and analyzed. In this study, the effect of pyrite particles on fracture propagation was systematically analyzed and summarized for the first time. The results indicate that the distribution of minerals and initial defects dominated the fracture evolution and the failure mode. Cracks are generally initiated and propagated along the boundaries of hard mineral particles such as pyrite or in soft minerals such as organic matter. Locations with collections of hard minerals are more likely to produce complex fractures. This study provides a valuable method for understanding the microfracture behavior of shales.