Hydraulic fracturing is widely used in the petroleum industry to enhance oil and gas production, especially for the extraction of shale gas from unconventional reservoirs. A good understanding of the vertical distance which should be preserved between hydraulic stimulation and overlying aquifers (potable water) has been demonstrated as being greater than 600 m (2000 feet). However, the effective application of this technique depends on many factors; one of particular importance is the influence of the fracturing process on pre-existing fractures and faults in the reservoir, which, however, to date, has had little analysis. Specifically, the identification of the required respect distance which must be maintained between the hydraulic fracturing location and pre-existing faults is of paramount importance in minimizing the risk of felt, induced seismicity.
Rachel F. Westwood, Samuel M. Toon, Peter Styles, Nigel J. Cassidy
School of Geography, Geology and the Environment, Keele University, Keele, Staffordshire ST5 5BG, UK. Learning and Professional Development Centre, 59/60 The Covert, Keele University, Keele, Staffordshire ST5 5BG, UK. School of Engineering, University of Birmingham, Edgbaston, Birmingham B15 2TT, UK
Received: 28 February 2017 / Accepted: 12 June 2017 / Published online: 28 June 2017
The Author(s) 2017.
This must be an important consideration for setting the guidelines for operational procedures by legislative authorities. We investigate the respect distance using a Monte Carlo approach, generating fifty discrete fracture networks for each of three fracture intensities, on which a hydraulic fracturing simulation is run, using FracMan®. The Coulomb stress change of the rock surrounding the simulated injection stage is calculated for three weighted source mechanisms combining inflation, strike-slip and reverse. The lateral respect distance is obtained using values from literature of the amount of stress required to induce movement on a pre-existing fault. We find that the lateral respect distance is dependent on fracture intensity and the failure threshold. However, the weighting of the source mechanism has limited effect on the lateral respect distance.
Over the last decade, the development of shale gas, shale oil and shale liquids has transformed the energy industry, especially in the USA and Canada, where the shale industry is worth billions of dollars. However, there is still considerable debate over the risks associated with the extraction and exploitation of shale gas and oil, be they real or perceived. One of the key risks and operational concerns is felt seismicity and the requirement to mitigate this as much as possible by not reactivating pre-existing faults. This requires knowledge of the location of these faults and how far away, both laterally and vertically, hydraulic fracturing should occur in order not to reactivate the fault.
Exploitation and extraction of shale gas and oil has involved millions of hydraulic stimulations (commonly known as fracks). The process of hydraulic fracturing, through the injection of high-pressure water, along with sand or synthetic ceramic proppants and a small component of other chemicals (<0.5% generally), intentionally stimulates new fracture growth, generating a connected fracture network and increasing permeability. The process induces a multitude of microseismic events (very small-scale earthquakes), which are routinely monitored from instrumented boreholes and a densely distributed network of surface sensors. This allows the location of fracturing to be identified and provides a means of tracking the efficiency, and the spatial and temporal progress of the hydraulic fracturing.
These events normally have magnitudes below zero (Maxwell 2013; Verdon et al. 2010); however, since 2011, there have been several recorded examples of seismicity at magnitudes greater than 2.0 (Holland 2013), of which three (BC Oil and Gas Commission 2012; Clarke et al. 2014; Schultz et al. 2015) were felt and reported by local populations. In at least one of these cases (Clarke et al. 2014), hydraulic fracturing has influenced a pre-existing fault causing it to slip to a sufficient extent and length to produce a felt earthquake. This has raised concerns with regulators, operators and the general public. Given the number of fracks performed over the last decade, statistically this is a very rare occurrence. However, the fact that it has occurred, demands that we attempt to understand the processes and situations which might lead to such an event.
Felt seismicity occurring near Blackpool, Lancashire, UK (Clarke et al. 2014), was associated with the first fracked well for shale gas in the UK, commencing just before and during the second stage of hydraulic fracturing and, as such, has become of considerable interest to all parties in the shale gas debate. Analysis of the seismicity shows that these felt events were caused by fluid injection reactivating pre-existing faults (Clarke et al. 2014).
It is critically important to attempt to understand how the process of hydraulic fracturing might precipitate minor movements on faults, whether by the direct injection of fluid (Rutqvist et al. 2013, 2015) or by changing the ambient stress system sufficiently to overcome friction/mechanical impeding forces.
To our knowledge no attempt has been made to address the distance at which potential faults could be activated. The purpose of this paper is to investigate, using geomechanical modelling and Coulomb failure analysis, the magnitude of stress changes caused by hydraulic fracturing operations and the potential influence this might have on pre-existing structures. This paper investigates the respect distance from a fault for three different fracture intensities and weighted source contributions, using a combination of geomechanical modelling in FracMan® and Coulomb failure analysis in MATLAB®, with input parameters taken from real-world operational data, including injection volumes, pressure and pump time.
2 Induced seismicity from hydraulic fracturing for shale gas
In Oklahoma in the USA, an area where wastewater injection has been known to cause seismicity (Ellsworth 2013; Keranen et al. 2013, 2014; McGarr et al. 2015), a series of earthquakes, sixteen greater than Mw 2.0 and the largest at ML 2.9, were correlated to hydraulic fracturing treatment (Holland 2013). In Ohio, USA, another area where deep well fluid injection has caused seismicity (Kim 2013), hydraulic fracturing operations in at least two separate areas have caused events including a Mw 2.2 (Friberg et al. 2014) and a ML 3.0 (Skoumal et al. 2015). The first documented account of felt seismicity from hydraulic fracturing for shale gas in Europe was near Blackpool, UK (Clarke et al. 2014; Eisner et al. 2013) and included a ML 2.3 event. Of these examples three were felt: Blackpool, Ohio and Oklahoma.
Fig. 1 Spire Slack open-cut coal mine. Coal face at Spire Slack open-cut coal mine, showing the fracture and fault networks down to a few cm. The exposed face is approximately 50 m high.
However, in Canada hydraulic fracturing has triggered larger felt events. At the Horn River Basin, hydraulic fracturing in the proximity of pre-existing faults caused a series of events, with 21 greater than Mw 3.0 (BC Oil and Gas Commission 2012) after some 8000 hydraulic stimulations had already taken place. Schultz et al. (2015) report a sequence of 160 earthquakes with magnitudes ranging from Mw 1.7 to 3.9 from the region of Crooked Lake, Alberta, which they correlate spatially and temporally with nearby hydraulic fracturing operations. Earthquakes of size ML 4.0 and 4.2 were reported near Fort St John in British Columbia (Atkinson et al. 2015a) and near Fox Creek, Alberta, dozens of events have been observed with the largest measuring M 4.4 (Atkinson et al. 2015b). At Doe-Dawson, in the Lower Montney, the same shale play as the events near Fort St John, at least six felt events have occurred (BC Oil and Gas Commission 2014).
3 Faults and fracture networks
Faults are rarely a single failure surface and usually consist of a region, throughout which numerous discontinuities branch, splay and rejoin. They usually have a broad range of lengths and throws which can be seen on a large-scale and on deep seismic reflection images as a single entity. However, on closer inspection, for example in an open-cut mine where the whole scale is visible (Fig. 1), they have a fractal distribution with discontinuities present down to scales of a few cm and possibly even smaller. An example is shown in the detailed mapping of faults visible from coal mine workings in the East Pennine coalfield (Bailey et al. 2005). This means that the influence of anthropogenic activities may stimulate movement even when the activity is some distance from the ‘seismically imageable’ position.
Modelling of injection-induced fault activation based on the Marcellus Shale, conducted by Rutqvist et al. (2013, 2015), found that shear failure occurred simultaneously with tensile failure and that hydraulic fracturing stimulation on its own may only produce small microseismic events. However, when a fault is present, the events are larger. They showed that for a critically stressed, permeable fault, the total length of shear rupture can be up to 200 m and moment magnitudes ranged from −2.5 to 0.5.
Fig. 2 Relationship between magnitude and fault size (length) plus various scaling parameters for earthquakes. Earthquake stress drops generally range between 0.1 and 10 MPa. (Modified from Zoback and Gorelick 2012).
Zoback and Gorelick (2012) have analysed the relationship between magnitude and fault size (Fig. 2) constrained by slip length. For the size of events which have been reported from hydraulic fracturing for shale gas, it is likely that these faults have rupture lengths of less than a few hundred metres, with slips of the order of only a few millimetres to a few centimetres. These will be complex zones of faulting rather than individual faults.
Once hydraulic fracturing has been initiated, the fractures propagate perpendicular to the direction of the minimum stress and parallel to the direction of maximum stress. At depths of over 1000 m, the depths at which hydraulic fracturing for shale gas occurs, this is generally vertical, with fractures propagating upward but deviating to horizontal for very shallow depths where lithostatic load is not the maximum stress component. Two studies (Davies et al. 2012; Flewelling et al. 2013), use data from thousands of stimulations to show that the maximum vertical extent of hydraulic fracture propagation is, and all microseismicity occurs, less than 600 m vertically from the well perforation.
Horizontally, fractures will propagate in the direction of the maximum stress, opening against the smallest (minimum) stress. To our knowledge, no systematic study, similar to that of Davies et al. (2012) or Flewelling et al. (2013), has been carried out to examine the lateral distance at which seismicity could occur. However, seismicity at the Poland Township in Ohio occurred up to 850 m away from the well (Skoumal et al. 2015). Data analysis concluded that the hydraulic fracturing reactivated a pre-existing fault; although, it is not clear if this was due to direct injection into the fault or an alternative source of reactivation. These studies only considered microseismic event clouds and do not examine seismicity occurring as a result of changes to the stress field further afield from Coulomb stress.
Coulomb stress modelling has been used extensively to study failure in the context of earthquakes (Stein 1999; Kilb et al. 2002; Lin and Stein 2004; Toda et al. 2011; Sumy et al. 2014). However, limited work has been carried out to examine the Coulomb stress changes related to hydraulic fracturing. Vasudevan and Eaton (2011) demonstrate the technique by modelling the Coulomb stress change from the first 100 microseismic events, with magnitudes between −1 and −3, occurring during hydraulic fracturing in Alberta, Canada. However, their source mechanisms were based on a simplistic model, without inflation.
4 The shale reservoir model
A two-stage discrete fracture network (DFN) and Coulomb stress model is used to calculate the stresses originating from each stage of a hydraulic fracturing process and the effect this has on any critically stressed faults in the vicinity. It is acknowledged that poro-elastic contribution will also have an impact on the stress field, however, many argue that this is a 2nd or 3rd order effect. This work focuses purely on the Coulomb stress change, with poro-elastic contributions being planned to add to further work.
Fig. 3 A 2D-view of the layers, stresses and the well geometry used for modelling the 3D discrete fracture network. The maximum horizontal stress is perpendicular to the page, σH = 61.27 MPa.
The model represents a shale gas reservoir within a strike-slip faulting environment. The stresses are similar to those published for the Bowland and Worston Shale Groups in the North West of England (de Pater and Baisch 2011). These formations lie at a depth of between 1957 and 2690 m, with an approximately 60 m thick layer of limestone separating the two groups. A horizontal well is defined in the top shale group with a single stimulation stage at a depth of 2220 m (Fig. 3).
Table 1 The properties used for creating the discrete fracture network.
The DFN was generated using the fracture modelling software FracMan® (Golder Associates (UK) Ltd 2015) by Golder Associates. The parameters of the DFN are provided in Table 1. The model was discretized over a 1 km cube, extending vertically from −1800 to −2800 m, bounding the shales at the top and bottom. The cube is layered vertically following the stratigraphy in Fig. 3. The elastic properties for each rock type are homogeneous across the layer and are provided in Table 2.
Table 2 Rock characteristics for the model.
The stress regime is defined to be strike-slip. This means that the maximum and minimum compressive stresses, σ1 and σ3, are in the horizontal direction and the intermediate stress, σ2, lies in the vertical direction. Hence, the maximum and minimum compressive horizontal stresses, σH and σh respectively, and the vertical stress, σv, are σH > σv > σh . We use a vertical stress gradient of 23,530 Pa/m, based on the calculations of Baisch and Vorös (2011), which at 2220 m, gives σv = 52.24 MPa. The fracture closure pressure (FCP) can be used as a means of constraining the lower bound of the minimum horizontal stress gradient and the instantaneous shut in pressure (ISIP) can be used as an upper bound. These values vary with depth and for the Bowland Basin are in the range of 0.69–0.78 psi/feet (15,608–17,644 Pa/m) (de Pater and Baisch 2011; Harper 2011; GMI Geomechanics Services 2011). Based on this range, we use σh = 36.65 MPa and define the maximum horizontal stress as σH = 61.27 MPa.
The Young’s modulus, E = 42.5 × 109 Pa, was calculated from the bulk and shear moduli provided in Harper (2011). The result is slightly higher than the static Young’s Modulus values for some of the gas-bearing shale plays in North America: Marcellus Shale 15.5 GPa (Dusseault 2013), Horn River 18–31 GPa (Dusseault 2013), but falls in the range of 20–80 GPa for the Barnett Shale (Agarwal et al. 2012; Dusseault 2013; Gale et al. 2007). The Poisson’s ratio is defined as 0.25, which is comparable to the Barnett Shale play (Dusseault 2013).
Natural fracture intensity can affect the distance and density of the resulting network of natural and hydraulic fractures. Fracture abundance (or intensity) is defined using a P32 measure type (fracture area/volume). Three intensities within the top shale layer were considered: 0.15, 0.25 and 0.35, with the natural fracture networks in the other layers remaining unchanged (Fig. 4). A Monte Carlo approach is taken whereby, for each P32 value, 50 random natural fracture sets are generated, each using the parameters given in Table 1.
Fig. 4 Examples of the DFN for three P32 fracture intensities within the top shale layer and the resultant connected hydraulic and natural fractures.
A hydraulic fracture simulation is performed on each of the natural fracture sets. FracMan® uses the theory of critical stress analysis to perform the hydraulic fracturing simulation, maintaining a balance between the pumped fluid and the expanded volume of natural fractures and the new hydro-fracture. Induced tensile fractures develop from the well, which have a normal parallel to the direction of the minimum stress and intersecting fractures are pumped if they are dilatable. The constitutive equation, which relates the volume of fractures to the elastic properties of the rock, regional stresses and the internal fracture pore pressure, is solved in time steps. For further information on the equations and processes used within FracMan®, see Golder Associates (UK) Ltd (2015).
Water is pumped at a rate of approximately 7000 l/min (1850 gal/min) for 2h, with a total volume of approximately 840,000l (221,900 gal) injected during the simulation. Differential pressure (the pressure difference between pore pressure and normal pressure on the fractures) at injection is set to 0.4 MPa. Hydraulic fracture growth is generated through new tensile fractures.