**1. Introduction**

Hydraulic fracture operations involve the injection of fluids from a wellbore into a formation to maximize the extraction of oil and gas resources from the reservoir. These stimulations allow the development of previously uneconomical reserves, for example shales gas. However, it has been well established that these fluid injections also induce seismicity (e.g., Hollister and

© 2013 Zangeneh 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.

Weimer [1], Ohtake [2], Fletcher and Sykes [3], Pearson, [4], Talwani and Acree, [5], Simpson et al. [6], Zoback and Harjes [7]).

[15]). For stimulations carried out in 2000, 2003 and 2004 the largest seismic events occurred just after or after shut-in. Similar experiences were encountered at Basel, Switzerland where induced seismicity reached a Richter Magnitude of 3.4 despite precautionary reductions of the injection rate, leading to suspension of its hot dry rock enhanced geothermal systems project

A Numerical Investigation of Fault Slip Triggered by Hydraulic Fracturing

http://dx.doi.org/10.5772/56191

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Experiences with hydraulic fracturing treatments in gas shales have generated similar seismicity, generally viewed as low risk due to the remote nature of the locations. In the Bowland shale, Lancashire, UK, two notable events were recorded with Richter Magnitudes of 1.5 and 2.3. These occurred almost 10 hours after shut-in (de Pater and Baisch [17]). de Pater and Baisch [17] suggested that reducing the treatment volume is one means to mitigate induced seismicity. In a detailed study in the Horn River Basin in northeastern British Columbia, Canada, approximately 38 events ranging between Richter Magnitudes 2.2 and 3.8 were recorded between 2009 and 201l, with only one being felt on surface in this remote region (BCOG, [18]). In their 2012 report of the findings from this investigation, the B.C. Oil and Gas Commission found that several of the Horn River events greater than M 2.0 were located along faults intersecting the wellbores. They also note that there were other instances where faults

The Distinct Element Method (DEM) applies a Lagrangian formulation to compute the motion and interaction between a series of discrete deformable blocks, representing the problem domain, via compliant contacts and Newton's equation of motion (Cundall and Hart, [19]). This enables the problem domain to be divided through by one or more discontinuity sets of variable orientation, spacing and persistence. One fundamental advantage of the DEM is that pre-existing (natural) joints in the rock mass can be modeled explicitly and allow for joints to undergo large deformations in shear (slip) or opening (dilation). The 2-D commercial code UDEC (Universal Distinct Element Code; Itasca Consulting Group, 1999) is used here to model the response of a jointed rock mass subjected to static loading and hydraulic injection.

UDEC is capable of modeling the behavior of weak jointed rock masses in which both the deformation and yielding of weak rock and slip along pre-existing discontinuities are impor‐ tant controlling factors. Progressive failure associated with crack propagation and fault slip can be simulated by the breaking of pre-existing contacts between the pre-defined joint

Key for simulating hydrofracturing, UDEC has the capability to model fluid flow through the defined fracture network. A fully coupled hydro-mechanical analysis can be performed, in which fracture conductivity is dependent on mechanical deformation of joint apertures and, conversely, joint water pressures can affect the mechanical computations of joint aperture. The blocks in this assemblage are treated as being impermeable, and fracture flow is calculated

bounded blocks, which although deformable, remain intact.

using a cubic law relationship for joint aperture:

intersected wellbores without anomalous events being detected (BCOG, [18]).

(Haring et al. [16]).

**3. Methodology**

The occurrence of induced seismicity, whether through hydraulic fracturing, enhanced geothermal systems, or carbon dioxide (CO2) sequestration, represents an important consid‐ eration in the risk profile of an injection well. Zoback [8] suggested that because of the critically stressed nature of the crust, fluid injection in deep wells can trigger earthquakes through increases in pore pressure (and decreases in effective stress) in the vicinity of the pre-existing faults. The increased pore pressure reduces the shear resistance to fault slip, allowing elastic energy already stored in the surrounding rocks to be released (Healy et al. [9]).

This paper describes a numerical experiment investigating the influence of pore pressure diffusion on the modeling of seismicity after a hydraulic fracture treatment. One objective is to evaluate the utility of 2-D distinct element techniques to model both pore pressure buildup and diffusion along existing rock weakness planes in response to fluid injection and subsequent changes to the effective stress field. A second objective is to estimate the corre‐ sponding maximum seismic magnitude that is likely to occur in response to the hydraulic fracture treatment.
