Fracture propagation in naturally fractured reservoirs
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Investigations of hydrocarbons in tight formations require understanding of hydraulic fracturing in order to optimize the production and recovery of oil and natural gas. The classic description of hydraulic fracture is a single bi-wing planar feature, however, field observations show that hydraulic fracture growth in naturally fractured formations like shale is complex. Lack of knowledge concerning the remote stress impact and the interaction with planes of weakness on the fracture propagation trajectory leads to inaccurate predictions of the fracture geometry and the surface area required for the production estimation. Most studies in engineering mechanics extended the standard mixed-mode fracture propagation models, based on the near-tip approximations, to include the impact of the tensile crack-parallel stress on the fracture propagation path. However, for fractures in the subsurface, the remote stress is compression, and internal fluid pressure or frictional stress become important in the near-tip stress field and the propagation trajectory. The Modified Maximum Tangential Principal Stress criterion (MMTPS-criterion) was introduced to address and evaluate the remote and internal crack stresses in the propagation path. The predictions of the fracture propagation angles by the MMTPS-criterion agreed with published experimental results of fractures propagating under both tensile and compressive external loads. In addition, the predictions matched well with uniaxial compression tests on hydrostone samples with the critical radial distance, defined by the process zone size, for open fractures that satisfy the Small Scale Yielding conditions. For short open fractures, a larger critical radial distance was required to correspond with the experimental results. The MMTPS-criterion was also capable of predicting lower propagation angles for closed cracks with higher friction coefficients. Preexisting discontinuities in shale, including natural fractures and bedding, act as planes of weakness that divert fracture propagation. To investigate the influence of weak planes on hydraulic fracture propagation, I performed Semi-Circular Bend (SCB) tests on Marcellus shale core samples containing calcite-filled natural fractures (veins). The approach angle of the induced fracture to the veins and the thickness of the veins had a strong influence on propagation. As the approach angle became more oblique to the induced fracture plane, and as the vein got thicker, the induced fracture was more likely to divert into the vein. Microstructural analysis of tested samples showed that the induced fracture propagated in the middle of the vein rather than the interface between vein and the rock matrix. Cleavage planes and fluid inclusion trails in the vein cements exerted some control on the fracture path. […] A Discrete Element Method (DEM) based numerical modeling software, Particle Flow Code in three-dimensions (PFC3D), was utilized to reproduce and analyze the experimental results of Marcellus shale samples. The trend of numerical results correlated with the interaction feature of the experimental results for various approach angle and thickness (i.e., aperture) of the vein. Further sensitivity analysis on vein properties indicated that veins with lower strength and higher stiffness contribute to more fracture diversion than veins with higher strength and lower stiffness. Additionally, parallel bond breakages in the model show that microcracks were Fgenerated inside the vein before the induced fracture encountered the vein especially for the veins with higher stiffnesses when compared to the rock matrix. Most of the bond failure mode inside the vein and the induced fracture was tensile rather than shear mode.