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<p>Natural bedding fractures are normally rich in shale oil reservoirs that restrict the fracture height during hydraulic fracturing. The aim of this study is to understand the characteristics and mechanics of hydraulic fracture propagation in the laminated shale. A 3D hydraulic fracture propagation model was proposed considering the combined effects of shale matrix mechanics, locally high-density natural bedding fractures, and in-situ stress. For the modeling of locally high-density distribution of natural bedding fractures, an equivalent method of a transverse isotropic mechanical layer to represent a bedding-rich area was made from the perspective of mechanical properties. Hybrid finite-discrete element method (FDEM) was used to model the hydraulic fracture propagation regime and mechanics in laminated shale. For the 3D fracture initiation and growth without a predefined path, the cohesive elements were applied in the entire modeling domain. The mechanics of hydraulic fracture propagation in the shale matrix and locally high-density natural bedding fractures area were quantitatively studied. Subsequently, simulations with different pumping rate and fluid viscosity were conducted to study their influence on hydraulic fracture evolution. Results indicate that the mechanics of hydraulic fracture propagation in the laminated shale matrix are dominated by Mode I tension faults, led by Mode II shear fractures in the locally high-density natural bedding fractures area, and supplemented by Mode I-II mixed tension and shear faults in both. Parametric studies reveal that injection parameters govern vertical growth: increasing pumping rate from 2 to 5 m<sup>3</sup>/min enhances maximum fracture height by over 75%, and raising fluid viscosity from 10 to 150 mPa·s produces a 43% increase. It also offered an optimization of fracturing parameters for specific scenarios, and the field application verified the reliability of the parameter preference. These findings provide critical insights for optimizing field-scale hydraulic fracturing designs in laminated shale reservoirs, enhancing fracture complexity and connectivity for improved shale oil recovery.</p>

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Numerical Modeling of 3D Hydraulic Fractures Propagation in Bedding-Riched Shale Oil Reservoir

  • 期刊论文

  • 发表日期：

    2026年1月29日

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  • Shizhong Cheng,
  • Mao Sheng,
  • Gensheng Li,
  • Shouceng Tian,
  • Lejia Ren

摘要

Natural bedding fractures are normally rich in shale oil reservoirs that restrict the fracture height during hydraulic fracturing. The aim of this study is to understand the characteristics and mechanics of hydraulic fracture propagation in the laminated shale. A 3D hydraulic fracture propagation model was proposed considering the combined effects of shale matrix mechanics, locally high-density natural bedding fractures, and in-situ stress. For the modeling of locally high-density distribution of natural bedding fractures, an equivalent method of a transverse isotropic mechanical layer to represent a bedding-rich area was made from the perspective of mechanical properties. Hybrid finite-discrete element method (FDEM) was used to model the hydraulic fracture propagation regime and mechanics in laminated shale. For the 3D fracture initiation and growth without a predefined path, the cohesive elements were applied in the entire modeling domain. The mechanics of hydraulic fracture propagation in the shale matrix and locally high-density natural bedding fractures area were quantitatively studied. Subsequently, simulations with different pumping rate and fluid viscosity were conducted to study their influence on hydraulic fracture evolution. Results indicate that the mechanics of hydraulic fracture propagation in the laminated shale matrix are dominated by Mode I tension faults, led by Mode II shear fractures in the locally high-density natural bedding fractures area, and supplemented by Mode I-II mixed tension and shear faults in both. Parametric studies reveal that injection parameters govern vertical growth: increasing pumping rate from 2 to 5 m3/min enhances maximum fracture height by over 75%, and raising fluid viscosity from 10 to 150 mPa·s produces a 43% increase. It also offered an optimization of fracturing parameters for specific scenarios, and the field application verified the reliability of the parameter preference. These findings provide critical insights for optimizing field-scale hydraulic fracturing designs in laminated shale reservoirs, enhancing fracture complexity and connectivity for improved shale oil recovery.