**2. Project objectives**

The practical justification for the overall HF project is different for the mining and O&G sector consortium sponsors. However, both sectors are interested in advancing the state of knowl‐ edge in three broad areas: (a) fracture network stimulation and development, (b) stress field modification, and (c) micro-seismic data interpretation during hydraulic fracturing and reservoir stimulation. Hence, the broad objectives of the program meets the primary needs of both sectors and will advance the understanding of hydraulic fracture network stimulation based on experiments permitting near-field monitoring followed by investigation of the treated volume via mapping and monitoring during mine-through.

#### **2.1. Mining perspective**

be achieved. The evaluation of these hypotheses is the focus of the current high level experi‐

**Keywords** stress management, stiffness modification, shale gas analogue, mine-back experi‐

Hydraulic fracturing (HF) has been widely used in the oil & gas (O&G) and mining industry: in O&G to stimulate reservoirs [1] and in mining, primarily to initiate caving and to improve fragmentation (e.g. [2-4]). Attempts have also been made to initiate slip on faults or shears [5] and research including mine-backs of hydraulically fractured zones has been conducted [6,7] in order to better understand the characteristics of the propagated hydraulic fractures. However, to the authors' knowledge, although there are many anecdotal indications of hydraulically induced changes to rock mass properties and stress, hydraulic fracturing has so far not been successful in inducing sufficient changes in the in situ or mining-induced stress field to be of practical value for risk mitigation related to violent seismic energy release in deep and high stress mining. It is speculated that the latter can only be achieved by the stimulation, mobilisation and enhancement of a natural fracture network rather than by solely generating a new system of induced hydraulic fractures. Hence, an innovative testing program, focussed on natural fracture network stimulation and the development of these techniques for stress management purposes is pursued. The mobilisation and development of a fracture network is also relevant for the optimal exploitation of tight gas or oil shale reservoirs, which closely resemble hard-rock situations (low permeability block, naturally fractured, stiff, low to moderate Poisson's ratio, etc.). The success of the proposed hydraulic injection program will be investigated

during a mine-back test, and the results applied to mining and O&G applications.

In this paper, the results of the experimental design phase, outlining objectives and justifica‐ tions for planned experimental layouts, are presented. Preliminary plans for the first minethrough trial at Newcrest Mining's Cadia East mine in New South Wales, Australia are

The practical justification for the overall HF project is different for the mining and O&G sector consortium sponsors. However, both sectors are interested in advancing the state of knowl‐ edge in three broad areas: (a) fracture network stimulation and development, (b) stress field modification, and (c) micro-seismic data interpretation during hydraulic fracturing and reservoir stimulation. Hence, the broad objectives of the program meets the primary needs of both sectors and will advance the understanding of hydraulic fracture network stimulation

ments, model calibration, hydraulic fracture, naturally fractured rocks

mental plan presented in the paper.

878 Effective and Sustainable Hydraulic Fracturing

**1. Introduction**

described.

**2. Project objectives**

Various hydraulic fracturing (HF) experiments have been undertaken in mines, some with mine-through experiments (e.g. [6]) for various purposes: to better understand fracture propagation, fracture interaction with natural joints, fragmentation changes, penetration of proppants, etc. Successes have been reported with respect to the use of HF for rock mass preconditioning, for rock fragmentation and cave initiation (e.g. [2]) but unanswered questions remain about its effectiveness in affecting stress redistribution and in controlling energy release from critically stressed rock mass structures. There are much anecdotal but little scientifically proven evidence that HF can help manage stresses, or not. The authors suggest that it may be the methodology of fracturing that may be the source of the apparent contra‐ dictions reported in the literature. As mines progress to greater depth stress management for the control of seismically releasable energy becomes of strategic importance. Furthermore, with the introduction of mechanized excavation techniques for rapid mine development (e.g., by Rio Tinto, AngloGold Ashanti, and others), new risks related to strain-bursting are introduced because of the less-damaging nature of these excavation techniques.

For the mining sector the motivations are to broaden the application of hydraulic fracturing and rock mass stimulation beyond cave initiation, propagation and fragmentation manage‐ ment by introducing methodologies for hydraulic stress and rock mass stiffness management that will eventually find introduction for risk mitigation in deep and high stress mining operations. In particular, the problem of fault-slip rockbursting is perplexing and, it is thought, can possibly be addressed through the creation of "damage zones" around potentially unstable structures, thereby reducing the energy emission levels and rates and improving constructa‐ bility in highly stressed ground.

It is hypothesised that current hydraulic injection techniques deployed in cave mine applica‐ tions are predominantly propagating hydraulic fractures and that shear dilation is a secondary process. Indeed, opening Mode I fractures develop within a narrow (almost planar) zone normal to σ3, and their irregular nature promotes asperity locking resulting in little final net shear strength or stiffness reduction. It is recognised that as fluids are lost in the rock mass surrounding the hydraulic fracture some distributed shearing of critically oriented natural fractures will also occur (e.g. [3]), however in order to enable stress management, one must promote volumetrically distributed irreversible changes to the rock mass and the development of injection techniques that achieve this objective is at the core of the planned research. Section 3 presents the output of a review of current injection practices for various applications and their effect on the rock mass. It served as background for the development of the experimental approach presented in Section 4.

#### **2.2. O&G perspective**

The advent of numerous staged HF stimulations along the lengths of deep horizontal wells [8] has unlocked huge quantities of natural gas and oil in low permeability formations that had heretofore been considered non-commercial. Typically, a 1 to 2 km long horizontal well (Fig. 1) is drilled parallel to σ3, and a series of hydraulic fractures are installed along the length of the well, injecting into one or several perforated or open sites each time, until from 10 to 40 sites are fracture-stimulated. The optimum design of each stage is still the subject of consid‐ erable debate, in part because existing mathematical models of fracturing, founded on singleplane Sneddon crack type assumptions in unjointed continua, are inadequate to predict fracture length, stimulated volume, or surface contact area in naturally fractured rock and more complex approaches using fracture network models are difficult to calibrate. Thus, design is largely empirical, based on remote field measurements that may be inadequate or difficult to interpret (tilt measurements, microseismic measurements and post-fracture well tests). For each new field, there is an extensive period of experimentation with different sequences of fluids and proppants, using different rates and materials, along with limited field measurements (generally microseismic monitoring) to try and optimize the stimulation process to achieve a maximum contacted volume without wasteful fracture propagation into non-productive overlying strata. Each stimulated well may cost 5-10 million dollars, and the eastern United States Marcellus Shale alone may require over 500,000 wells for complete development, as the deposit covers over 95,000 square miles, and at least 6 horizontal wells are needed for each square mile (100 acre spacing). Furthermore, the deeper lying Utica Shale, which also extends into Canada, will eventually be developed, requiring a similar number of wells [9, 10]. Sub-optimal fracture design because of incomplete understanding and inade‐ quate predictive tools quickly becomes a costly luxury.

These low permeability strata that contain natural gas or low-viscosity oil are often called "shales", although many of them are better classified as siltstones or even argillaceous limestones (marls). The rock matrix is a stiff (30 to 110 GPa), low-porosity (0.04-0.10), low permeability (microDarcy to nanoDarcy) material. The rock mass is naturally fractured, generally with one dominant set orthogonal to bedding, and one or two minor sets, also orthogonal to the bedding planes. Interestingly, these properties are substantially more similar to those of igneous and metamorphic rocks encountered in "hard rock" mines than they are to typical sedimentary rocks such as heavy oil-rich sandstones, or conventional higher porosity (0.15-0.25) limestones and sandstones. Hence, it is attractive for improving O&G reservoir

Hydraulic Fracturing Mine Back Trials — Design Rationale and Project Status

http://dx.doi.org/10.5772/56260

881

The O&G dimension of a HF mine-back experiment is to provide an experimental platform for testing predictive models and stimulation procedures suitable for the oil industry. Frac‐ turing igneous rock at depth in a mining context is therefore of interest because the rocks are similar (naturally fractured, stiff, low Poisson's ratio, anisotropic, almost impermeable matrix blocks…), because the deep mine provides access to a high stress environment (1.5 to 3 km deep) at one tenth the cost of a vertical oilfield borehole, and because a direct mine-back of a fracture-stimulated region can verify assumptions about stimulated volumes, fracture

The concept of a stimulated volume that is far larger than the sand-filled fracture propagation volume (Fig. 2) is fundamental to understanding shale oil or shale gas stimulation, but cannot be easily verified directly, nor can it be predicted by design models that are commonly available. The calibration and validation of advanced model permitting complex behaviour including branching needs data rarely available and the proposed experimental work will contribute to provide such validation data. Fig. 2 presents a 2-D simplification of a complex, 3-D process involving many natural fractures near a wellbore that have been propped, and a large zone surrounding the sand zone where block rotation and shear have created open fractures and self-propped dilated fractures [8]. In mining, this process is called rock mass *bulking* due to geometric incompatibilities between, displaced and rotated, strong blocks of rock. These bulking induced fractures are favored through high-rate injection, and they are thought to be the primary source of microseismic emissions, whereas the zone into which sand is transported, the propped aperture, and the number of near-wellbore propped natural fractures are favored by injection of a highly viscous fluid. Remote displacement measure‐ ments (i.e. tilt measurements) cannot distinguish amongst individual fractures, only suitable local instrumentation and a mine-back test can give confidence in the actual geometry and

Thus, the motivation for the O&G industry is to optimize HF treatment in tight reservoirs by calibrating design software and hydraulic fracturing propagation monitoring techniques, that is to relate the geophysical observables from fracture initiation and propagation, particularly in the case of microseismic monitoring, and to better understand the development of hydraulic fractures in tight and low permeability naturally fractured lithologies. These objectives can be achieved by performing experiments in deep mines, in which the rock properties are similar to the O&G lithological context because of their stiff, fractured, low permeability characteristics.

aperture, relationship to microseismic emissions, and the rock mass strains [11].

stimulation techniques to perform tests in a deep mining context.

disposition of the dilated or propped regions.

**Figure 1.** Staged hydraulic fracturing along a horizontal well axis for shale gas stimulation.

These low permeability strata that contain natural gas or low-viscosity oil are often called "shales", although many of them are better classified as siltstones or even argillaceous limestones (marls). The rock matrix is a stiff (30 to 110 GPa), low-porosity (0.04-0.10), low permeability (microDarcy to nanoDarcy) material. The rock mass is naturally fractured, generally with one dominant set orthogonal to bedding, and one or two minor sets, also orthogonal to the bedding planes. Interestingly, these properties are substantially more similar to those of igneous and metamorphic rocks encountered in "hard rock" mines than they are to typical sedimentary rocks such as heavy oil-rich sandstones, or conventional higher porosity (0.15-0.25) limestones and sandstones. Hence, it is attractive for improving O&G reservoir stimulation techniques to perform tests in a deep mining context.

**2.2. O&G perspective**

880 Effective and Sustainable Hydraulic Fracturing

quate predictive tools quickly becomes a costly luxury.

**Figure 1.** Staged hydraulic fracturing along a horizontal well axis for shale gas stimulation.

The advent of numerous staged HF stimulations along the lengths of deep horizontal wells [8] has unlocked huge quantities of natural gas and oil in low permeability formations that had heretofore been considered non-commercial. Typically, a 1 to 2 km long horizontal well (Fig. 1) is drilled parallel to σ3, and a series of hydraulic fractures are installed along the length of the well, injecting into one or several perforated or open sites each time, until from 10 to 40 sites are fracture-stimulated. The optimum design of each stage is still the subject of consid‐ erable debate, in part because existing mathematical models of fracturing, founded on singleplane Sneddon crack type assumptions in unjointed continua, are inadequate to predict fracture length, stimulated volume, or surface contact area in naturally fractured rock and more complex approaches using fracture network models are difficult to calibrate. Thus, design is largely empirical, based on remote field measurements that may be inadequate or difficult to interpret (tilt measurements, microseismic measurements and post-fracture well tests). For each new field, there is an extensive period of experimentation with different sequences of fluids and proppants, using different rates and materials, along with limited field measurements (generally microseismic monitoring) to try and optimize the stimulation process to achieve a maximum contacted volume without wasteful fracture propagation into non-productive overlying strata. Each stimulated well may cost 5-10 million dollars, and the eastern United States Marcellus Shale alone may require over 500,000 wells for complete development, as the deposit covers over 95,000 square miles, and at least 6 horizontal wells are needed for each square mile (100 acre spacing). Furthermore, the deeper lying Utica Shale, which also extends into Canada, will eventually be developed, requiring a similar number of wells [9, 10]. Sub-optimal fracture design because of incomplete understanding and inade‐

The O&G dimension of a HF mine-back experiment is to provide an experimental platform for testing predictive models and stimulation procedures suitable for the oil industry. Frac‐ turing igneous rock at depth in a mining context is therefore of interest because the rocks are similar (naturally fractured, stiff, low Poisson's ratio, anisotropic, almost impermeable matrix blocks…), because the deep mine provides access to a high stress environment (1.5 to 3 km deep) at one tenth the cost of a vertical oilfield borehole, and because a direct mine-back of a fracture-stimulated region can verify assumptions about stimulated volumes, fracture aperture, relationship to microseismic emissions, and the rock mass strains [11].

The concept of a stimulated volume that is far larger than the sand-filled fracture propagation volume (Fig. 2) is fundamental to understanding shale oil or shale gas stimulation, but cannot be easily verified directly, nor can it be predicted by design models that are commonly available. The calibration and validation of advanced model permitting complex behaviour including branching needs data rarely available and the proposed experimental work will contribute to provide such validation data. Fig. 2 presents a 2-D simplification of a complex, 3-D process involving many natural fractures near a wellbore that have been propped, and a large zone surrounding the sand zone where block rotation and shear have created open fractures and self-propped dilated fractures [8]. In mining, this process is called rock mass *bulking* due to geometric incompatibilities between, displaced and rotated, strong blocks of rock. These bulking induced fractures are favored through high-rate injection, and they are thought to be the primary source of microseismic emissions, whereas the zone into which sand is transported, the propped aperture, and the number of near-wellbore propped natural fractures are favored by injection of a highly viscous fluid. Remote displacement measure‐ ments (i.e. tilt measurements) cannot distinguish amongst individual fractures, only suitable local instrumentation and a mine-back test can give confidence in the actual geometry and disposition of the dilated or propped regions.

Thus, the motivation for the O&G industry is to optimize HF treatment in tight reservoirs by calibrating design software and hydraulic fracturing propagation monitoring techniques, that is to relate the geophysical observables from fracture initiation and propagation, particularly in the case of microseismic monitoring, and to better understand the development of hydraulic fractures in tight and low permeability naturally fractured lithologies. These objectives can be achieved by performing experiments in deep mines, in which the rock properties are similar to the O&G lithological context because of their stiff, fractured, low permeability characteristics.

**3. Review of injection practices and their effect on the rock mass** 

and that the fracture has propagated beyond the near-wellbore region.

Hydraulic Fracturing Mine Back Trials — Design Rationale and Project Status

cave mining

cave mining

tight shale

http://dx.doi.org/10.5772/56260

tight shale

100 101 10<sup>2</sup> 103 10<sup>4</sup> 10<sup>5</sup>

enhanced geothermal

enhanced geothermal

Injection rate [l/min]

plot of injection volume and injection durations vs. maximum injection rate.

<sup>100</sup> <sup>101</sup> <sup>10</sup><sup>2</sup> <sup>103</sup> <sup>10</sup><sup>4</sup> <sup>10</sup><sup>5</sup> 1 min.

**Figure 3.** A broad spectrum of injection practices with specific injection metrics for each industry; related objectives

A different situation is encountered in deep geothermal projects with high rate, long duration injections performed in long open-hole sections for reservoir stimulation. The injection metrics are one to two orders of magnitude higher than for cave pre-conditioning cases and extensive monitoring is used to understand fracture activation and propagation, permeability enhance‐ ment and fluid penetration [13, 14]. The predominant mechanisms stem from natural fracture system activation [15] leading to fracture self-propping by shear displacement, causing permanent permeability increases. Critically stressed fractures, oriented optimally to the deviatoric stress field for shear failure are the most prone to activation (see Fig. 2), and slip is

are demonstrated by this cross plot of injection volume and injection durations vs. maximum injection rate.

Injection rate [l/min]

(e.g., joints)unless the later makes an sharp angle with the growing hydraulic fracture path.

stimulated volume, fracture extent...).

stress measurement

stress measurement

10−4

1/2 hour 1 hour 3 hours

accompanied by microseismicity.

Injection duration [min]

1 day

1 week 20 days

10−2

100

Injection volume [m3

]

10<sup>2</sup>

10<sup>4</sup>

10<sup>6</sup>

The generic term "hydraulic injection" covers a spectrum of practices with distinct objectives. With the contribution of Itasca, we conducted a literature survey to capture current injection practices in three sectors: mining, deep geothermal and O&G. A case study database, including 14 mining cases, 46 deep geothermal cases, and 4 O&G cases (to be expanded), includes information on the geomechanics context (stress state, rock strength,...), the injection metrics (flow rate, pressure record, injection volume and duration,...), the monitoring program and the measured or observed effect on the rock masses (main activated mechanisms,

Fig. 3 illustrates the breadth of injection practices. At the low end of the spectrum, we included some metrics from the ISRM suggested method for hydraulic fracturing stress measurements [12] where a short interval is injected at a very low rate (2 – 3 l/min) for a short time (1 – 3 min). The mechanism in this case is borehole wall failure in tension, captured by the breakdown pressure in the pressure record followed by a limited extension of the hydraulic fracture and its closure after well shut-in (instantaneous shut-in pressure, ISIP) which is used as an indicator of the σhmin magnitude, assuming that the borehole is vertical

883

Figure 3. A broad spectrum of injection practices with specific injection metrics for each industry; related objectives are demonstrated by this cross

An up-scaled version of the stress measurement method is used in cave mining operations to pre-condition the rock for improved caveability or fragmentation. A short packed interval is injected to initiate and propagate fractures, and rates, duration and volumes are about two to three orders of magnitude larger than for stress measurements. This propagates fractures typically several tens of meters from the borehole and injections are repeated to generate a zone of fractured rock. Observed fractures typically grow perpendicular to the minimum principal stress and their trajectory is relatively little influenced by natural features

A different situation is encountered in deep geothermal projects with high rate, long duration injections performed in long openhole sections for reservoir stimulation. The injection metrics are one to two orders of magnitude higher than for cave preconditioning cases and extensive monitoring is used to understand fracture activation and propagation, permeability enhancement and fluid penetration [13] [14]. The predominant mechanisms stem from natural fracture system activation [15] leading to fracture self-propping by shear displacement, causing permanent permeability increases. Critically stressed fractures, oriented optimally to the deviatoric stress field for shear failure are the most prone to activation (see Fig. 2), and slip is accompanied by microseismicity.

At the upper end, shale gas well practices involve high rate injection at a number of sites along the well; injections that are carefully sequenced at each stage with massive injection (up to 3000 m3 per site) of fluids of different viscosity at elevated rates (typical rates

 Insights into the role of variable injection metrics on rock mass response is gained in Fig. 4 where the maximum pressure reached during an injection is plotted against the local estimate of the minimum principal stress magnitude as well as the predominantly activated mechanism (Mode I opening fracture propagation vs. shear re-activation). The dominant activated mechanisms on this

of 12 m3/min are reported) to optimize proppant penetration and the generation of shear dilated zone volume.

**Figure 2.** The sand zone and the dilated zone (the stimulated volume).
