Initiation and growth of a hydraulic fracture from a circular wellbore

A two-dimensional (2D) model is presented for initiation and growth of one or more hydraulic fractures from a well that is aligned with either the maximum or intermediate principal in situ stress. The coupling of fluid flow and rock deformation plays a key role in reorientation and pattern evolution of the fractures formed. Upon initiation, the fracture may reorient itself as it extends from the wellbore, until it becomes aligned with the preferred direction for fracture growth relative to the far-field stresses. We consider initiation and growth of multiple fractures to study their interaction and competition with each other. In such cases, some fractures are unable to extend at all, or they arrest after limited growth, but others can grow in length relative to earlier developed fractures. For fractures that are driven by a uniformly distributed internal pressure, which implies injection of an inviscid fluid, fracture closure may occur at the portion of the fracture path adjacent to the wellbore. The fracture closure does not typically occur when fluid viscous dissipation is introduced, but a fluid lag zone develops and the near-wellbore region of the fracture may have a narrowed width. The reduced fracture width results in an increase in fluid viscous friction and an associated pressure drop near the wellbore, which makes fracture stimulation more expensive and less successful and may reduce well productivity. Initiation of a fracture using a viscous fluid and a higher injection rate causes the fracture to curve more gradually as it seeks to align with the maximum principal stress direction, a result from our model that is consistent with widely used tortuosity remedy methods. A dimensionless parameter is developed that is shown to characterise near-wellbore reorientation and curving of hydraulic fractures driven by viscous fluid. For complex multiple fracture cases, the results demonstrate that the misalignment angle and the number of initiated fractures are important in near-wellbore fracture path selection.

► We model near-wellbore fracture tortuosity using a 2D BEM model. ► The fully coupled rock deformation and fluid flow model is used. ► High viscosity and high injection rate can remedy fracture tortuosity. ► Fracture angle, location and number can affect the fracture reorientation. ► A dimensionless parameter is presented to characterize fracture tortuosity.