Laboratory Study of the Effect of Well Orientation, Completion Design, and Rock Fabric on Near-Wellbore Hydraulic Fracture Geometry in Shales

There is accepted evidence that multistage fracturing of horizontal wells in shale reservoirs results in significant production variation from perforation cluster to perforation cluster. In fact, only a fraction of the perforation clusters seem to contribute to production in many shale gas and shale oil plays. In many cases, the orientation of the lateral section of these wells is determined by lease boundaries rather than principal stress directions, and these often do not coincide. When horizontal wells are misaligned from the far-field principal stress directions, the fracture must reorient from the near-wellbore principal stress directions, which are aligned with the wellbore, to the far-field principal stress directions. The primary objective of this study is to learn how various completion designs influence the near-wellbore fracture geometry when such a misalignment exists. A secondary objective is to understand the influence of rock fabric features, such as mineralized natural fractures, on this reorientation process. To understand these effects, eight laboratory hydraulic fracturing tests were conducted using a true triaxial vessel with 914 mm × 762 mm × 762 mm samples of Niobrara shale. Several different completion designs were studied, including the use of fracture initiation slots with several different orientations and the use of perforations selectively located to encourage a smooth transition from the near- to far-wellbore region. The tests were carefully scaled as accurately as possible to provide insight into the field near-wellbore phenomena. Pressure and fluid flux at the wellbore, deformation of the block, acoustic velocity, and induced acoustic emissions were acquired during the tests. Additionally, sized particles were also injected to gauge the fracture width away from the wellbore. After the test, the blocks were dismantled, and the fracture geometry was mapped in 3D. These measurements allow one to clearly differentiate the fracture initiation and the breakdown—meaning the peak pressure—to be clearly differentiated; the fracture was already well developed when the maximum pressure was reached. The study reveals non-negligible tortuosity and aperture restriction in the near-wellbore region. In the field, this would translate to high treating pressures, uneven proppant distribution, and possibly near-wellbore screenouts. The test results show that, of the configurations tested, the best approach is to use deep slots that are aligned with the far-field principal stress directions. The oriented perforation design did not achieve the simple, smooth transition that was hoped for, and instead produced multiple competing near-wellbore fractures and considerable tortuosity. The study also demonstrated that the presence of planes of weakness, such as mineralized natural fractures, near the slot tip can result in poor near-wellbore fracture geometries, even for the best completion configuration. We conclude from these tests that the misalignment of the well with a principal stress direction creates near-wellbore complexity that, in turn, creates uncertainty in proppant distribution and, therefore, production; proppant might avoid up to a half of the created fracture. Regardless of the wellbore orientation, this uncertainty is further increased by the presence of mineralized features in the rock fabric that can strongly alter or stop the growth of the hydraulic fracture. Preventing those effects by changing the completion alone proves difficult, and new strategies are required to ensure a reliable stimulation of shales.