| Citation: | DING Jiaming，GONG Haolin，ZHAO Xueqin，et al. Characterization of hydraulic-fracturing-induced fractures in tight sandstone of Shaximiao Formation using multi-scale microseismic monitoring[J]. Bulletin of Geological Science and Technology，2026，45（5）：1-15 doi: 10.19509/j.cnki.dzkq.tb20250345
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The Jurassic Shaximiao Formation in the Sichuan Basin represents a critical tight sandstone target for both tight gas production and enhanced geothermal system (EGS) exploitation. Strong reservoir heterogeneity complicates the characterization of hydraulic fracture evolution, restricting the optimization of fracturing treatments and the joint development of tight gas and geothermal energy. This study aims to characterize multi-scale fracture behaviors and reveal the underlying rock-rupture mechanisms of tight sandstone during hydraulic stimulation, providing theoretical support for reservoir stimulation and production enhancement in heterogeneous tight reservoirs.
Large-scale true-triaxial hydraulic fracturing experiments were performed on two groups of tight sandstone specimens (samples α and β). Acoustic emission (AE) signals were recorded to capture microcrack activity at laboratory scale. Field monitoring data collected from six drilling platforms and 12 wells within the study area were analyzed. Laboratory AE responses were integrated with the spatiotemporal distributions of field multi-scale microseismic events to characterize fracture propagation under coupled geological and mechanical controls.
① The complexity of pre-existing natural fractures exerted a dominant control on rock-rupture behaviors. Under true-triaxial confining stress conditions, natural fractures acted as mechanical weak planes and produced localized stress concentrations at fracture tips. Pore pressure generated by hydraulic fracturing reduced the normal stress on fracture planes and activated natural fractures. Pore pressure was transmitted along the fracture planes and continuously accumulated at fracture tips. Once the local pressure exceeded the critical rupture threshold, the fractures propagated forward and generated detectable AE signals. ② Final fracture geometry was jointly governed by the interactions between pre-existing natural fractures and artificially induced hydraulic fracture networks. Where natural fractures were poorly developed, induced hydraulic fractures prevailed and formed complex multi-scale coupled fracture systems. The strike and distribution of subaqueous distributary-channel sand bodies determined the initial orientation of fracture propagation. Fractures preferentially extended along the orientation of sand-body deposition. Thick sand bodies with favorable reservoir properties promoted fracture initiation and propagation, yielding planar fracture patterns closely associated with sedimentary facies distributions. ③ Porosity was a vital parameter controlling fracturing responses. The Shaximiao Formation comprised typical low-porosity and low-permeability reservoirs. Its low matrix permeability increased the difficulty of triggering microseismic events. Rock anisotropy significantly influenced the initiation pressure, AE responses, and the geometric configuration of hydraulic microfracture networks. Intervals with low brittleness index produced sparse microseismic events and poor stimulation performance. By contrast, intervals with favorable logging interpretations showed dense microseismic clusters and effective reservoir stimulation. Reservoirs with higher porosity required larger volumes of fracturing fluid. Porosity, brittleness index, and in-situ stress-difference coefficient were mutually coupled and jointly controlled fracture complexity and stimulated reservoir volume (SRV).
Fracture development within the Shaximiao Formation tight sandstone is governed by a multi-factor coupling mechanism. The interactions among natural and hydraulic fractures, spatial restrictions imposed by sedimentary facies (sand-body distribution), geostress conditions, and intrinsic reservoir properties (low porosity and permeability, brittleness index, rock anisotropy) collectively generate heterogeneous multi-scale fracture networks. Fracture generation follows a mixed tension-shear rupture mode, jointly controlled by geological factors (brittle-mineral fraction, bedding-induced anisotropy) and mechanical factors (in-situ stress contrast and pore-pressure accumulation). The integration of laboratory physical simulation and field microseismic monitoring provides an effective approach for elucidating fracture evolution in highly heterogeneous tight sandstone reservoirs.
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