What does this research mean for the field?

A newly developed fully coupled hydro-mechanical phase-field model demonstrates that in saturated porous media, increasing horizontal stress differences reduces fracture branching, while higher injection rates and fluid viscosities increase stimulated fracture area and breakdown pressure. Novelty: ClaimNovelty.METHODOLOGICAL. Consensus alignment: ConsensusAlignment.NEUTRAL.

What question did this study set out to answer?

To develop a fully coupled hydro-mechanical phase-field model to analyze hydraulic fracture initiation, branching morphology, and breakdown pressure in saturated porous rock media.

September 2, 2026ProcessesOpen Access

A Fully Coupled Hydro-Mechanical Phase-Field Model for Hydraulic Fracture Initiation and Complex Propagation in Porous Rock Media

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Authors

SSShanzhi ShiChina University of Petroleum, Beijing CXChenggang XIANChina University of Petroleum, Beijing

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Implication

Numerical modeling demonstrates that stress differences, fluid viscosity, and injection rates control crack propagation in porous rock, suggesting pathways to optimize hydraulic fracturing.

Key Points

To develop a fully coupled hydro-mechanical phase-field model to analyze hydraulic fracture initiation, branching morphology, and breakdown pressure in saturated porous rock media.
Integrated Biot poroelasticity, tensile–compressive strain energy decomposition, irreversible phase-field damage evolution, and damage-dependent permeability within a 2D finite element framework in COMSOL Multiphysics 6.4.
Conducted parametric sensitivity simulations varying horizontal principal stress differences (2 to 14 MPa), injection rates (3 to 6 m³/min), and fluid viscosities (1 to 100 mPa·s).
Increasing horizontal principal stress difference from 2 to 14 MPa reduced stimulated fracture area by 50.0% (from 42,640 to 21,300 m²) and secondary branches from 12 to 5.
Increasing injection rate from 3 to 6 m³/min increased stimulated fracture area by 23.4% (from 35,771 to 44,138 m²), secondary branches from 6 to 11, and breakdown pressure by 19.9% (from 135.19 to 162.11 MPa).
Increasing fluid viscosity from 1 to 100 mPa·s increased stimulated fracture area by 36.2% (from 35,771 to 48,722 m²) and breakdown pressure by 35.5% (from 135.19 to 183.21 MPa).

Cite This Study

Shi et al. (2026) studied this question.

synapsesocial.com/papers/6a97e29ec562ede874ec6de2 https://doi.org/10.3390/pr14172808

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Implication

Numerical modeling demonstrates that stress differences, fluid viscosity, and injection rates control crack propagation in porous rock, suggesting pathways to optimize hydraulic fracturing.

A Fully Coupled Hydro-Mechanical Phase-Field Model for Hydraulic Fracture Initiation and Complex Propagation in Porous Rock Media

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Key Points

Cite This Study

A Fully Coupled Hydro-Mechanical Phase-Field Model for Hydraulic Fracture Initiation and Complex Propagation in Porous Rock Media

Discussion

Member takes

Implication

Key Points

Cite This Study

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