The characterization of shale micropore structure and micromechanical properties is of great significance to shale gas reserve evaluation and fracturing plan design. The mechanical properties such as Young’s modulus and hardness of the Longmaxi shale were tested by dot matrix nanoindentation measurements. The characterization of pore structure and the minerals of the indentation were analyzed by scanning electron microscopy (SEM) and energy dispersive X-ray spectroscopy (EDS). We established the correlation between mineral composition-nanoindentation topology and the displacement load curve. The influence of pore/fracture on nanoindentation was studied by finite element analysis. A method for evaluating shale porosity based on the displacement-load curve is proposed. Mori-Tanaka and dilute methods are used to upscale the results of nanoindentation. The main conclusions are as follows: The relationship between the pop-in characteristics of the displacement-load curve and the horizontal pores, mixed pores and vertical pores is clarified, and the elastic modulus of the rock where the horizontal pores are developed is small. A method for evaluating shale porosity based on the displacement load curve is proposed, and the calculation result is close to its macroscopic porosity of 2.64%. The Longmaxi shale has strong heterogeneity in its micromechanical properties, with Young’s modulus ranging from 22.5 to 51 GPa, with an average of 41 GPa, and hardness ranging from 0.53 GPa to 2.25 GPa, with an average of 1.30 GPa. The upscaled calculation value of the dilute method is closer to the uniaxial compression value of shale. The research results are expected to accurately characterize the pore structure and micromechanical characteristics of shale and provide basic theory and scientific basis for shale fracturing design.

The shale reservoir is well stratified, and the conventional horizontal well volume fracturing has insufficient longitudinal penetration ability, leading to a limited degree of reconstruction. In this paper, based on a new idea of radial well fracturing, the fracture network model of the radial well fracturing is built, and the 3-D matrix-cracks-wellbore flow coupling model is established.The shale oil productivity under horizontal well fracturing and radial well fracturing is compared and analyzed, and the influence of natural fractures on shale oil productivity is studied. The results show that radial well fracturing can surpass the conventional limit of fracture height and improve the reservoir reconstruction performance. More radial wells and main wells lead to higher productivity,which can be exemplified by the Gulong shale reservoir in the Songliao Basin. With the presence of natural fractures, the hydraulic fractures directly intersecting the fracture network of 3-well, 3-layer radial wells with 4 branches have 1.35 times overall productivity and more than 2.2 times the oil production rate and total oil production in the third year, compared to the ones created by horizontal well fracturing. The research results can provide a theoretical basis for the efficient development of shale oil by radial well fracturing.

This paper introduces a novel approach combining radial borehole fracturing with Water-Alternating-Gas (WAG) injection, enabling simultaneous WAG injection and shale oil production in a single vertical well. A numerical reservoir model incorporating the modified exponential non-Darcy law, stress sensitivity, and diffusion is established. The spatial distribution of permeability reduction shows that stress sensitivity enhances the non-Darcy effect, with apparent permeability decreasing to 0–92.1% of the initial value, highlighting the importance of maintaining reservoir pressure. Continuous CO₂ flooding leads to early gas breakthrough, while continuous water flooding has less displacement efficiency. A 30% water-to-gas injection time ratio improves oil production and delays gas breakthrough compared to continuous CO₂ injection. Optimal conditions for effective recovery are identified as an initial production period of 100 d and a well vertical spacing of 30 m. This study compares the production capacity of WAG operations under radial borehole fracturing and horizontal well fracturing. When the number of wells is two for both cases, the production capacity of radial borehole fracturing is comparable to that of five-stage horizontal well fracturing, indicating that radial borehole fracturing can serve as an alternative or supplement to horizontal well fracturing when the reservoir volume is limited. This study offers a new method and theoretical basis for the efficient development of shale oil.

This study introduces a novel method integrating CO₂ flooding with radial borehole fracturing for enhanced oil recovery and CO₂ underground storage, a solution to the limited vertical stimulation reservoir volume in horizontal well fracturing. A numerical model is established to investigate the production rate, reservoir pressure field, and CO₂ saturation distribution corresponding to changing time of CO₂ flooding with radial borehole fracturing. A sensitivity analysis on the influence of CO₂ injection location, layer spacing, pressure difference, borehole number, and hydraulic fractures on oil production and CO₂ storage is conducted. The CO₂ flooding process is divided into four stages. Reductions in layer spacing will significantly improve oil production rate and gas storage capacity. However, serious gas channeling can occur when the spacing is lower than 20 m. Increasing the pressure difference between the producer and injector, the borehole number, the hydraulic fracture height, and the fracture width can also increase the oil production rate and gas storage rate. Sensitivity analysis shows that layer spacing and fracture height greatly influence gas storage and oil production. Research outcomes are expected to provide a theoretical basis for the efficient development of shale oil reservoirs in the vertical direction.