A two-dimensional (2D) model is presented for initiation and growth of one or more hydraulic fractures from a vertical borehole that is aligned with one of the principal stresses. The coupling of fluid flow and rock deformation plays a key role in reorientation and pattern evolution of the multiple fractures formed. The simulation results provide the spatiotemporal variations of injection pressure, fracture trajectory, fracture opening and pressure in the fracture. After fracture initiation, the fracture can rotate as it extends from the borehole until it becomes aligned with the preferred direction for fracture growth under the specified far-field stresses. For fractures that extend in a toughness dominated regime, fracture closure may occur along the portion of the fracture path adjacent to the borehole since for this case the fluid pressure is uniform and cannot attain a locally higher value. Local fracture closure does not typically occur when fluid viscous dissipation is introduced, producing high injection pressures. Initiation of a fracture using a viscous fluid and a higher injection rate is a practical way to reduce near wellbore fracture tortuosity. The results demonstrate that the initiation misalignment angle and the in situ stress magnitudes are also important in their affect on fracture path near the borehole.


One important role of hydraulic fracturing is to connect the wellbore and the reservoir with a high conductivity pathway. However, the development of the fractures and, ultimately, the treatment effectiveness depend on the evolution of the fracture path in the near-wellbore region. Near the wellbore multiple subparallel fractures can be generated because of fracture initiation from perforations phased along and around the wellbore or from flaws that are commonly not aligned with the farfield stress direction. Fractures initiated from those defects will reorient themselves to a plane perpendicular to the minimum far-field stress direction as they grow away from the wellbore [1-4]. The overall result of such a fracture initiation process produces near-wellbore fracture tortuosity. As a consequence, the net pressure required to extend the fractures is increased considerably. Methods to reduce near-wellbore tortuosity and potential proppant placement problems have been developed that involve using higher viscosity fluids to initiate the fracture. Proppant slugs are also often pumped in an effort to reduce the fracture complexity. Hydraulic fracture initiation from a borehole has been studied theoretically and numerically, but still remains a subject of interest for petroleum industry research. Numerical hydraulic fracturing models have been applied to this problem to analyze competing fracture growth, width reduction, and increased viscous frictional pressure loss. Daneshy [2] considered the conditions for fracture initiation and propagation from vertical and deviated wellbores to find factors controlling nearwellbore effects. Weng [3] numerically studied the interaction and linkage of multiple fractures initiating from a deviated well. Based on these and other analyses, various operational remedial techniques have been proposed to overcome the near-wellbore effects, such as using higher injection rate, higher viscosity fluids and orienting fracture initiation sites [5-7].

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