Physics-based Modeling of Hydraulic Fracture Propagation And Permeability Evolution
of Fracture Network In Shale Gas Formation
Hai Huang, Earl Mattson and Rob Podgorney
Shale gas production is enabled by horizontal drilling, hydraulic fracturing and fracture
propping, but despite many innovations, recovery factors are low. Thus a robust and
reliable numerical model for fracture initiation and propagation, which includes the
interactions between hydraulic fractures and natural existing fractures and the coupling
between deformation, fracturing and fluid flow in fracture apertures and in the permeable
rock matrix, would be an important tool for developing a better understanding of
hydraulic fracturing process and for practical applications.
We have developed a physics-based simulator for hydraulic fracturing by coupling a
quasi-static discrete element model (DEM) for deformation and fracturing with both
Darcy flow and pore network models for fluid flow. In the quasi-static DEM model, the
rock matrix is represented by a network of discrete mechanical elements connected by
“bonds” such as springs, elastic beams or bonds that have more complex properties such
as stress-dependent elastic constants. Fracturing is represented explicitly by removing
broken bonds from the network to represent microcracks. Initiation of new microfractures
and growth and coalescence of the microcracks leads to the formation of macroscopic
fractures when external and/or internal loads are applied. Naturally preexisting fractures
are conveniently represented by removal of bonds along line segments in 2D or planes in
3D. To simulate fluid flow, a more physics-based network flow model that uses a flow
network conjugate to the DEM network and accounts for flow in both the fractures and
matrix was developed and coupled to the DEM model.
The coupled DEM-flow model reproduces a variety of fracture growth patterns, including
bi-wing fracture growth, dendritic fractures, and bi-wing fractures with branching and
curving. The effects of in situ stress, fluid viscosity, heterogeneity of rock mechanical
properties and injection rate on the fracture patterns will be discussed. Under suitable
combinations of in situ stress and injection rate, it is feasible to generate a net like
fracture pattern. The simulation also indicates only reactivated natural fractures that
intersect the hydraulic fractures contribute significantly for fluid flow.