Abstract

Previous works have presented the results of successful simulations of fluid injection into naturally fractured shale using a Discrete Element Model (DEM). The simulations included coupled fluid flow-deformation analysis, failure type and extent calculations, as well as a series of parametric analyses. The parameters investigated included: 1) injection rate and its effect on the overall fracturing results, and 2) fluid viscosity, which had a significant influence on the ratio of tensile (mode 1) failure versus shear failure.

With the huge growth in the stimulation of naturally fractured formations such as fractured shales, it is clear that the industry needs new hydraulic fracturing simulation tools beyond the limits imposed by pseudo3D fracturing models. DEMs, in which both matrix block behavior and fracture behavior are explicitly modeled, offer one option for the specific modeling of hydraulic fracture creation and growth in a naturally fractured formation without, for example, the assumption of bi-planar fracture growth.

In this paper, we extend the previous works to quantify, for fractured shale gas plays, the effect of stress orientation, fluid viscosity, and rock mechanical properties in terms of changes in fracture aperture and transmissivity. Changes in fracture transmissivity directly correlate with improvements in well productivity – the primary goal of the stimulation.

The results of the study provide a means to improve shale completions by understanding the effects of the DFN orientation relative to the stress field, fluid viscosity, and rock mechanical properties on changes in fracture aperture, fracture transmissivity, and formation effective permeability, which directly relate to well productivity.

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