Mechanics of Hydraulic-Fracture Growth from a Wellbore Intersecting Natural Fractures

Abstract

SummaryThe creation and propagation of hydraulic fractures (HFs) emanating from a well in a naturally fractured rock is important not only to the success of fracturing treatments, but also for interpretation of the data from diagnostic fracture injection tests (DFITs). In this paper, we consider the reservoir rock to consist of an impermeable rock matrix and a system of discrete natural fractures (NFs) that are permeable. The well is assumed to intersect two sets of NFs at their midpoints, and injection into the wellbore might open the NFs and/or create new fractures that extend along the maximum-principal-stress direction. Both new fractures and pre-existing NFs can act as either a main HF or a fluid-loss path. In this near-well transient-fracture analysis, the NFs are short segments characterized by size, orientation, and aperture. A fully coupled HF model is used to investigate the interaction between the fractures to determine how the fluid injected is distributed to the fractures for a range of stress, fluid-injection-rate, and NF-geometry conditions. We find that a more-isotropic stress condition and a lower value of the fluid-viscosity/injection-rate product favor propagation of NFs. These conditions cause the NFs to accept more fluid, and, as a result, the growth of new fractures is suppressed. The post-shut-in pressure responses for the cases with propagating new fractures and nonpropagating NFs are studied.