Understanding the evolution of sandstone mechanical behavior under high pressure and high temperature (HPHT) is crucial for the efficient development of ultra-deep tight reservoirs. In this study, triaxial compression tests on ultra-deep core samples and true triaxial hydraulic fracturing experiments on 200 mm × 200 mm × 200 mm sandstone cubes were conducted under HPHT conditions. The brittle–ductile transition behavior and fracture initiation and propagation characteristics of rocks in ultra-deep reservoirs were investigated, and four classical break-down models were employed to evaluate break-down pressures under different stress state and temperature conditions. The results show that, at elevated confining pressures and temperatures, ultra-deep rocks undergo a transition from brittle failure dominated by shear cracks to ductile deformation involving numerous microcracks; pre-peak plastic strain increases markedly, and a pronounced post-peak stress plateau appears in the stress–strain curves, indicating a significant enhancement of overall ductility. Under HPHT conditions, breakdown pressure increases and fracture propagation resistance becomes stronger, and hydraulic fractures tend to exhibit an intermittent “initiation–arrest–reinitiation” propagation pattern, which is unfavorable for the development of a complex fracture network. Comparison of model predictions with experimental and field data further demonstrates that, for reservoirs deeper than 5000 m, thermally induced stresses should be incorporated into break-down pressure prediction. Among the four models considered, the T-H-W model exhibits superior physical plausibility and predictive reliability for ultra-deep tight reservoirs. These findings provide important experimental and theoretical support for optimizing hydraulic fracturing design and enhancing stimulation effectiveness in ultra-deep tight formations.

China's shale oil and gas resources are widely distributed in shale-sandstone interbedded reservoirs, whose complex lithology and strong heterogeneity pose significant challenges to hydraulic fracturing design. To address issues such as the difficulty in controlling fracture height and the challenge of forming an effective fracture network, this study utilizes synthetic rock samples that can represent the characteristics of interbedded reservoirs and investigates the initiation and propagation of hydraulic fractures under different viscosity, injection rate, and construction scheme. By combining real-time monitoring of injection pressure with acoustic emission, the temporal and spatial evolution characteristics of hydraulic fractures as well as the mechanisms of their vertical and horizontal extension are revealed. The results indicate that a higher fracturing fluid viscosity is essential for ensuring the vertical cross-layer propagation of hydraulic fractures, while a lower fluid viscosity facilitates the activation of weak interlayer surfaces, promoting sufficient horizontal propagation along these planes and forming branched fractures. Although a higher injection rate enhances the vertical cross-layer propagation of hydraulic fractures, it also causes greater diversion of the main fracture plane, resulting in simpler fracture morphology and limiting the stimulation effect. Additionally, an alternating injection of high and low viscosity fracturing fluids allows hydraulic fractures to both break through weak interlayer surfaces and achieve uniform horizontal propagation, resulting in a more complex fracture morphology. The findings are expected to provide a scientific basis and practical guidance for optimizing hydraulic fracturing designs in interbedded reservoir conditions.