**Abstract**

A recently developed unconventional fracture model (UFM\* ) is able to simulate complex fracture networks propagation in a formation with pre-existing natural fractures. Multiple fracture branches can propagate at the same time and crisscross each other. The behaviour of a hydraulic fracture when it intersects a natural fracture, whether being arrested, cross‐ ing, creating an offset, or dilating the natural fracture, plays a key role in predicting the re‐ sulting fracture footprint, microseismicity, and improving production evaluation. It is therefore critical to properly model the fracture interaction in a complex fracture model such as UFM.

A new crossing model, called OpenT, taking into account the effect of flow rate and fluid viscosity on the hydraulic/natural fracture crossing behaviour is integrated in UFM simula‐ tor. The previous fracture crossing model is primarily based on the stress field at the ap‐ proaching hydraulic fracture tip and its interaction with the natural fracture. A new elasticity solution for the fracture contact has been developed. The new OpenT semi-analyti‐ cal crossing model quantifies the localized stress field induced in the natural fracture and in the rock and evaluates the size and length of open and shear slippage zones along the natu‐ ral fracture. The natural fracture activation and stress field near the intersection point are strongly dependent on the contacting hydraulic fracture opening and thus on fluid flow rate and viscosity. This new model is validated against laboratory experimental results and an advanced numerical model.

In this paper we present the results of several test cases showing the influence of injection rate and fluid viscosity on the generated hydraulic fracture footprint in formations with pre-

© 2013 Kresse et al.; licensee InTech. This is an open access article distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited. © 2013 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

existing natural fractures. The influence of the stress field anisotropy, intersection angle, as well as natural fractures properties are also important and are discussed. The results are then compared with the simulations using the previous crossing model which does not ac‐ count for the influence of fluid properties.

The stimulated network was approximately 1500ft wide and 3,000 ft long (Figure 1b) with

), and showed the patterns of development that suggested the opening of both

Effect of Flow Rate and Viscosity on Complex Fracture Development in UFM Model

treatment

**Figure 1.** Single-well microseismic event locations for XL gel stimulation and water-frac re-fracturing treatment, hori‐

This field example indicates the importance of proper consideration of fluid properties when modelling the interaction of hydraulic fractures with pre-existing natural fractures. In general it is observed that for the same field conditions more viscous fluid tends to cross the natural fractures more easily, while slick water tends to penetrate into the natural fractures more easily and open them without crossing. Pumping rate as well as rock properties should also be taken

The importance of fluid properties on the created hydraulic fracture network has been mentioned in some experimental and numerical studies [9, 18, 19]. The experimental study of the influence of flow rate and fracturing fluid viscosity on the hydraulic fracture geometry have been performed in [9] based on analysis of different *Qμ* value (product of the injection rate and fracturing fluid viscosity). The experiments show that with low *Qμ* value fluid tends to leak into the pre-existing discontinuities despite the influence of fluid pressure and once the discontinuity accepts fluid, the pressure can rise far above the confining stress without inducing new fractures. With large *Qμ* value the hydraulic fracture tends to cross natural

The influence of fluid injection rate and viscosity on the amount of the tensile failure in the rock with natural fractures has been investigated based on 3DEC DEM model in [18, 19]. For low viscosity fluid the amount of area failing in shear is dramatically higher than in the case

stimulated a much larger volume of rock than the initial gel treatment (1450 million ft3

(a)XL gel fracturing (b)water-frac re-fracturing

. Clearly, the re-fracturing treatment

http://dx.doi.org/10.5772/56406

vs 430

185

considerable height growth and SRV of 1450 million ft3

northeast and northwest trending fractures [ 16].

fracture due to increase of the pressurization rate.

million ft3

zontal Barnett Shale well [16]

into account.
