This paper describes the development of a 3-dimensional Discrete Fracture Network (DFN) approach for simulation and evaluation of hydraulic fracturing in low permeability fractured rock in the FracMan® reservoir analysis tool. The approach is based on an empirical algorithm approximating the effect of natural fractures and in-situ stress on hydraulic fracture propagation. The algorithm distributes frac-fluid between the propagating hydraulic fracture and pre-existing natural fractures to predict both the geometry of the hydraulic fracture, and the reactivation of the natural fracture network. The technique is demonstrated by comparison against ELFEN® geo-mechanical simulations, and by comparison of simulated and observed microseismic responses.
Hydraulic fracturing is increasingly critical for development of natural gas resources in tight sands and gas shales [1-8]. Hydraulic fracturing can be significantly influenced by the geometry and properties of pre-existing natural fractures. While the geometry of hydraulic fractures is driven primarily by the in situ stress field, rock mass anisotropy, and natural fractures in particular, can determine the details of hydrofrac location, size, and orientation. Hydraulic fracture size can be limited by leak-off to natural fractures, but can also be increased where the hydrofrac can extend by propagation of new and reactivation of natural fractures, rather than expending energy on intact rock breakage. This paper describes the development and verification of a discrete fracture network (DFN) approach for modeling the interaction between natural fractures and hydraulic fractures during the hydro fracturing process, see (Figure 1).
The propagation of hydraulic fractures is assumed to be controlled by:
? The reservoir in situ effective stress, defined by the total stress tensor and reservoir pressure.
? The rock matrix strength, deformability, heterogeneity and anisotropy.
? The geometry, mechanical, and flow properties of the natural fracture system.
? The configuration and operation of the hydraulic injection process itself.
Since hydraulic fracture propagation generally occurs in tension, the minimum principal stress determines both the direction and extent of the hydraulic fracture. In many tectonic settings, the vertical stress is the major principal stress, with the maximum and minimum horizontal stresses on the order of 60% or more of the lithostatic stress. Hydraulic fractures propagate where the effective normal stress on the plane of hydrofracturing is less than the tensile strength of the rock in that direction, reffered to as the “rock toughness” (Zobak, 2007). For sedimentary rocks such as shale, this toughness can be highly anisotropic, such that the direction of hydraulic fracture propagation can deviate from the normal to the normal to the direction of minimum stress (i.e, the direction of maximum horizontal stress), see (Warpinski, 1982). This same fracture fluid pressure propagates into the connected natural fracture system. Where the resulting effective minimum stress is less than the fracture toughness, natural fractures can open and extend in tension. Where the resulting effective stress state exceeds the shear strength, the natural fractures are reactivated, and can move and potentially propagate in shear.