Deep shale gas reservoirs in the southern Sichuan Basin are typically characterized by significant horizontal stress anisotropy (expressed as stress difference), variable brittleness–ductility in rock mechanics, and strong heterogeneity. These complex geomechanical conditions lead to pronounced differences in hydraulic fracturing outcomes among wells and sections. To investigate hydraulic fracture propagation and fracturing fluid injection behavior under varying geomechanical settings, true triaxial physical simulation tests were performed on 400 × 400 × 400 mm artificial rock samples. The samples were designed with different media properties based on similarity criteria. A sensitivity analysis was conducted to assess the effects of brittleness–ductility characteristics, natural fractures, and in-situ stress conditions. The results reveal that: (i) brittle samples with lower stress difference are favorable for forming complex, perforable fracture networks; (ii) brittle samples with higher stress difference tend to develop simple, planar hydraulic fractures, with natural fractures only slightly activated during very short injection periods; (iii) ductile behavior enhances the activation of natural fractures but reduces fracture complexity compared with brittle samples, even under lower stress difference; and (iv) for typical deep shale formations, larger fluid injection volumes combined with high-density, multi-cluster fracturing techniques are recommended.
Zeng et al. (Thu,) studied this question.