The seismo-hydro-mechanical behaviour during deep geothermal reservoir stimulations : open questions tackled in a decameter-scale in-situ stimulation experiment

The major points of both reviewers were 1) the combination of a review and an original experiment part in one manuscript and 2) the timing of writing the second part of the paper versus the timing of the test. Both reviewers provided suggestions how to proceed with these two issues. Reviewer 1 suggests splitting the paper in a review paper and an experimental paper, with the latter providing much more detail on the experimental design. Reviewer 2 suggests to substantially shorten the second part by providing much less detail and more higher-level information.


Introduction
The necessity to produce carbon dioxide neutral electricity, ideally as baseload power (i.e., 24 h a day, year-round) and the increased aversion to nuclear power generation have motivated global efforts to optimize methods for extracting deep geothermal energy for electricity production.However, currently, geothermal power production is limited to distinct geological conditions, where fluid flow rates in geothermal reservoirs carry sufficient heat (Saar, 2011) and/or pressure for economic power generation (Randolph and Saar, 2011a;Breede et al., 2013;Adams et al., 2015).It is widely agreed that the earth's crust holds substantially more geothermal re-Published by Copernicus Publications on behalf of the European Geosciences Union.
F. Amann et al.: The seismo-hydromechanical behavior during deep geothermal reservoir stimulations sources than are presently being exploited (e.g., Tester et al., 2006).However, standard water-or brine-based geothermal power generation requires persistently high reservoir permeabilities of at least 10 −16 m 2 (Manning and Ingebritsen, 1999) and ideally temperatures of over about 170 • C (e.g., Evans, 2014;Saar, 2017), as otherwise the process is not economic.Wells have to be drilled to at least 5 to 6 km depth into crystalline hard rock to reach formation temperatures of approximately 170-200 • C in regions with standard geothermal gradients of about 30 • C km −1 , although such temperatures are often reached at shallower depth if there is a low thermal conductivity sedimentary cover.Presently, rotary drilling to such depths is uneconomic on a routine basis.Moreover, at this depth permeability is often much less than 10 −16 m 2 (e.g., Manning and Ingebritsen, 1999;Saar and Manga, 2004;Achtziger-Zupančič et al., 2017), so that permeability has to be artificially enhanced to permit circulation of fluids to advectively extract the heat energy economically.Such systems are referred to as enhanced or engineered geothermal systems (EGSs), originally termed hot dry rock (HDR) systems (Brown et al., 2012).EGSs virtually always require hydraulic stimulation to enhance the permeability to such a degree that economic geothermal power generation becomes possible.However, the goal of controlling the permeability enhancement process has not yet been achieved in a sustained way, despite attempts since the 1970s (Evans, 2014).Additionally, induced seismicity, which almost invariably accompanies hydraulic stimulation because of high fluid injection pressure, can be problematic inasmuch as it may reach felt or even damaging intensities (e.g., Giardini, 2009).
In this contribution, we focus on how a subsurface heat exchanger may be constructed between boreholes at depth within low-permeability rock to form EGS, where a fluid, typically water or brine, may then be circulated more easily than before.The artificially enhanced permeability needs to be high enough to reach flow rates that are commercially relevant for power production, depending on the subsurface working fluid.Larger permeability enhancements are required for water or brine than for CO 2 , as the latter can utilize lower temperatures and lower permeabilities for economic geothermal power generation, due to its higher energy conversion efficiency (Brown, 2000;Pruess, 2006Pruess, , 2007;;Randolph and Saar, 2011a, b;Adams et al., 2014Adams et al., , 2015;;Garapati et al., 2015;Buscheck et al., 2016).Moreover, fluid flow should occur within a large number of permeable fracture pathways that sweep a large surface area of the rock, thereby providing longevity to the system and avoiding early thermal breakthrough, such as occurred at the Rosemanowes Project (Parker, 1999) and the Hijiori Project (Tenma et al., 2008).The construction of such systems (i.e., an artificial reservoir with sufficient permeability for energy extraction) is one of the key research challenges for unlocking the large potential of deep geothermal energy.The creation of a subsurface heat exchanger between the boreholes in the low-permeability rock mass typically involves hydraulic stimulation, i.e., fluid injections, during which the pore pressure is raised in the rock mass, leading to the enhancements of permeability of natural fractures and faults and perhaps the creation of new fractures.
Hydraulic stimulation is inevitably accompanied by induced seismicity (e.g., Zoback and Harjes, 1997;Evans et al., 2005a;Davies et al., 2013;Bao and Eaton, 2016) because the slip triggered by the elevated pore pressure arising from injections may be sufficiently rapid to generate seismic waves.In shale gas-and EGS-related stimulations, clouds of small induced (micro-)seismic events are important monitoring tools for delineating the location, where rock mass volume is undergoing stimulation (e.g., Wolhart et al., 2006).Unfortunately, seismic events induced by the stimulation injections may be large enough to be felt by local populations and even to cause infrastructure damage (e.g., in Basel, 2006;Giardini, 2009).In the past few years, induced seismicity has been recognized as a significant challenge to the widespread deployment of EGS technology.From a reservoir engineering perspective, EGS faces two competing but related issues: (1) rock mass permeability must be significantly enhanced by several orders of magnitude within a sufficiently large volume to enable sustainable heat extraction over many years (i.e., 20-30 years) while (2) keeping the associated induced seismicity below a hazardous level (Evans et al., 2014).Designing reservoir stimulation practices that optimize permeability creation and minimize induced seismicity requires a greatly improved understanding of the seismo-hydromechanical (SHM) response of the target rock mass volume.Seismo-hydromechanical processes relevant for stimulation involve (1) hydromechanically coupled (HM-coupled) fluid flow and pressure propagation, (2) transient pressure-and permanent slip-dependent permeability changes, (3) fracture formation and interaction with preexisting structures, (4) rock mass deformation around the stimulated volume due to fault slip, failure processes and poroelastic effects, and (5) the transition from aseismic to seismic slip.
In 2017, a decameter-scale, in situ, stimulation and circulation (ISC) experiment was conducted at the Grimsel Test Site (GTS), Switzerland, with the objective of improving our understanding of the aforementioned HM-coupled processes in a moderately fractured crystalline rock mass.The ISC experiment activities aim to support the development of EGS technology by (1) advancing the understanding of fundamental processes that occur within the rock mass in response to relatively large-volume fluid injections at high pressures, (2) improving the ability to estimate and model induced seismic hazard and risk, (3) assessing the potential of different injection protocols to keep seismic event magnitudes below an acceptable threshold, (4) developing novel monitoring and imaging techniques for pressure, temperature, stress, strain and displacement as well as geophysical methods such as ground-penetrating radar (GPR) and passive and active seismics, and (5) generating a high-quality benchmark dataset that facilitates the development and validation of numerical modeling tools.
This paper presents a literature review that highlights key research gaps concerning hydraulic reservoir stimulation and discusses which of the aforementioned research questions can be addressed in our decameter underground stimulation experiment.We then provide an overview of the ISC project that describes the geological site conditions, the different project phases and the monitoring program.
2 Literature review

Stimulation by hydraulic shearing
The concept of mining heat from hot, low-permeability rock at great depth was first proposed at Los Alamos National Labs in the 1970s and was called hot dry rock system (Brown et al., 2012).They initially envisioned creating a reservoir by applying oil and gas reservoir hydro-fracture technology to build a heat exchanger between two boreholes.Subsequent field tests have demonstrated that hydraulic stimulation injections are effective in enhancing the permeability of a rock mass by several orders of magnitude by producing irreversible fracture opening, whilst also increasing the connectivity of the fracture network (Kaieda et al., 2005;Evans et al., 2005b;Häring et al., 2008).Two different "end-member" mechanisms commonly appear in discussions of permeability creation processes through hydraulic injections: (1) hydraulic fracturing as the initiation and propagation of new tensile fractures and (2) hydraulic shearing, i.e., the reactivation of existing discontinuities in shear with associated irreversible dilation that is often referred to as the self-propping mechanism.Hydraulic shearing is of particular relevance for EGS as it has been shown that slip along fractures can generate a permeability increase by up to 2-3 orders of magnitude (Jupe et al., 1992;Evans et al., 2005a;Häring et al., 2008).If the rock mass in the reservoir is stressed to a critical level (e.g., Byerlee, 1978), then a relatively small reduction in effective normal stress would be sufficient to cause shearing along preexisting discontinuities that are optimally oriented for failure (Hubbert and Rubey, 1959;Raleigh et al., 1976;Zoback and Harjes, 1997;Evans et al., 1999;Evans, 2005).Thus, shearing and the associated permeability enhancement can occur at large distances from the injection point, even though the causal pressure increases may be low (Evans et al., 1999;Saar and Manga, 2003;Husen et al., 2007).In contrast, hydraulic fracture initiation and propagation (i.e., the original concept of EGS to connect two boreholes) requires high pressures exceeding the minimum principal stress to propagate hydro-fractures away from the wellbore.The high pressure in the fracture may interact with natural fractures and stimulate them, leading to leak-off (i.e., the extent of hydro-fractures is influenced by pressure losses and the existence of preexisting fractures).Therefore, hydraulic frac-turing is often only considered relevant in the near field of a wellbore, where it improves the linkage between the borehole and the natural fracture system.Rutledge et al. (2004) showed that shear activation of existing fractures and creation of new fractures can occur concomitantly, dependent on the in situ stress conditions, injection pressure, initial fracture transmissivity, fracture network connectivity and fracture orientation (e.g., McClure and Horne, 2014).Regardless of which process is dominant, the direction of reservoir growth, and therefore the geometry of the stimulated volume, depends to a considerable degree on the in situ stress gradient, stress orientation and the natural fracture network.
Pressurized fractures may open due to a reversible, compliant response to pressure (Rutqvist, 1995;Rutqvist and Stephansson, 2003;Evans and Meier, 1995) or due to largely irreversible shear dilation (Lee and Cho, 2002;Rahman et al., 2002).As a consequence of the coupling between pressure, fracture compliance and permanent fracture aperture changes, the pressure field does not propagate through the reservoir as a linear diffusive field, but rather as a pressure front (Murphy et al., 2004).The fracture normal and shear dilation that occurs in response to elevated fluid pressure thus has a major influence on the magnitude and profile of the propagating pressure perturbation in the rock mass during hydraulic stimulations (Evans et al., 1999;Hummel and Müller, 2009).As a consequence, fracture compliance and normal or shear dilation characteristics have an impact on the size and geometry of the reservoir created during hydraulic stimulation.
Although the aforementioned processes are conceptually well understood, the quantification and detailed understanding required for designing stimulations and truly engineering geothermal reservoirs are insufficient.There remains considerable uncertainty as to how the above processes interact and what rock mass characteristics and injection metrics control the dominant mechanisms (Evans et al., 2005a;Jung, 2013).Thermo-hydromechanically coupled numerical models have become widely used for analyzing relevant aspects of reservoir stimulation in retrospective (e.g., Baujard and Bruel, 2006;Rutqvist and Oldenburg, 2008;Baisch et al., 2010;Gischig and Wiemer, 2013) or as prospective tools for predicting reservoir behavior or alternative stimulation strategies (e.g., McClure and Horne, 2011;Zang et al., 2013;Gischig et al., 2014;McClure, 2015;Yoon et al., 2014).The fact that such numerical models must be parameterized from sparse quantitative field-scale data is a major limitation of all those studies.In the following we present an overview of the experimental observations of hydromechanical coupling that are relevant to the parameterization of numerical models.These stem from reservoir-scale (i.e., hectometer) stimulation operations, such as in EGS demonstration projects or oil and gas reservoirs, intermediate-scale (i.e., decameter)  The paucity of high-quality data on the stimulation process from reservoir-scale projects is largely a result of the considerable depth of typical geothermal resources (e.g., several kilometers), which prohibits the observation of hydromechanical processes from instrumentation installed within the reservoir.In the geothermal domain, such projects constitute expensive experiments and thus are relatively few in number, whereas, in the oil and gas domain, where hydro-fracture operations are frequent and routine, the data tend to be proprietary.Nevertheless, some notable datasets have been acquired for deep brine injection projects (Ake et al., 2005;Block et al., 2015), deep scientific drilling projects such as the German KTB project (Zoback and Harjes, 1997;Emmermann and Lauterjung, 1997;Jost et al., 1998;Baisch and Harjes, 2003), and hydraulic fracturing for oil and gas production enhancement (Warpinski, 2009;Das and Zoback, 2011;Dusseault et al., 2011;Pettitt et al., 2011;Vermylen and Zoback, 2011;Boroumand and Eaton, 2012;van der Baan et al., 2013;Bao and Eaton, 2016) and during the stimulation of deep geothermal boreholes (Parker, 1989;Jupe et al., 1992;Cornet and Scotti, 1993;Tezuka and Niitsuma, 2000;Asanuma et al., 2005;Evans et al., 2005a;Häring et al., 2008;Brown et al., 2012;Baisch et al., 2015).Welldocumented hydraulic stimulation datasets generally include microseismic observations as well as injection pressures and flow rates and, occasionally, tilt monitoring (Evans, 1983;Warpinski and Teufel, 1997).Although much information can be gained from these datasets, including imaging of microseismic structures (Niitsuma et al., 1999;Maxwell, 2014), energy balance between injected fluids and seismic energy release (Boroumand and Eaton 2012;Zoback et al., 2012;Warpinski, 2013), and source mechanisms (Jupe et al., 1992;Deichmann and Ernst, 2009;Warpinski and Du, 2010;Horálek et al., 2010), the constraints placed on the processes are insufficient to resolve details of the hydromechanical processes that underpin permeability enhancement, flow-path linkage, channeling or the interaction with natural fractures.Many of these processes possibly also depend on rock type.For instance, case studies analyzed by Evans et al. (2012) support the notion that injection into sedimentary rock tends to be less seismogenic than in crystalline rock.Moreover, it is likely that a significant part of the permeability creation processes take place in an aseismic manner (Cornet et al., 1997;Evans, 1998;Guglielmi et al., 2015b;Zoback et al., 2012), implying that seismic monitoring may only illuminate parts of the stimulated rock volume.In many deep hydraulic stimulation projects the rock mass is only accessed by one or at most a few boreholes, and the structural and geological models of the reservoir are not well defined.In general, the displacements on fractures arising from the injection can only be directly measured where they intersect the boreholes, and deformation occurring within the rock mass is poorly resolved.
Despite limitations in reservoir characterization and monitoring, significant insights into the stimulation process can be gleaned from the experience from the EGS projects that have been conducted to date.Two examples in crystalline rock are studies of stimulation-induced fault slip and changes in flow conditions in the fracture network associated with the permeability creation processes at the Soultz-sous-forêt (Cornet et al., 1997;Evans et al., 2005b) and the Basel EGS projects (Häring et al., 2008).At both sites, it has been shown that permeability in the near-wellbore region increased by 2-3 orders of magnitude.At Basel, a single initially impermeable fracture has been shown to take at least 41 % of the flow during the 30 L s −1 injection stage (Evans and Sikaneta, 2013), whereas at Soultz-sous-forêt, the stimulation of the 3.5 km deep reservoir served to enhance the injectivity of a number of naturally permeable fractures (Evans et al., 2005b).These fractures tended to be optimally oriented for fault slip, as also found elsewhere by Barton et al. (1995Barton et al. ( , 1998) ) and Hickman et al. (1998).At Soultz-sous-forêt, it was possible to estimate stimulation-induced slip and the normal opening of fractures that cut the borehole by comparing pre-and post-stimulation acoustic televiewer logs (Cornet et al., 1997;Evans, 2005).Shearing of fractures was also proposed as the predominant mechanism of permeability enhancement in granite at the Fjällbacka site in Sweden, by Jupe et al. (1992), based upon focal mechanism analysis.The above observations provide evidence of a link between shearing and permeability changes.
An additional, important lesson from deep stimulation projects is that the stress conditions in reservoirs may be strongly heterogeneous and that this influences the flow field (e.g., Hickman et al., 2000).For instance, profiles of horizontal stress orientation defined by wellbore failure observations commonly show significant fluctuations whose amplitude varies systematically with scale (Shamir and Zoback, 1992;Valley and Evans, 2009;Blake and Davatzes, 2011), even though that may have an average trend consistent with the tectonic stress field.Strong deviations may occur in the vicinity of faults, indicating past fault slip and complex fault zone architecture (Valley and Evans, 2010;Hickman et al., 2000).Similarly, the hydromechanical properties of faults depend on the fault architecture, which itself depends on lithology and the damage history accumulated over geological time (Caine et al., 1996;Faulkner and Rutter, 2008;Guglielmi et al., 2008;Faulkner et al., 2010;Jeanne et al., 2012).Within a fault zone, permeability and compliance contrasts can vary by several orders of magnitude (Guglielmi et al., 2008), thus complicating the predictability of hydromechanical responses to stimulations.In some EGS projects, it was observed that the hydraulic communication between injection and production boreholes may be unsatisfactory for efficient exchange of heat, either because of high flow impedance, such as in granite rock at Ogachi, Japan, (Kaieda et al., 2005), or because of flow channeling, as inferred from early thermal drawdown in granitic rock at Rosemanowes, UK (Nicol and Robinson, 1990) and in granodiorite at Hijiori, Japan (Tenma et al., 2008).

Laboratory-scale experiments
On the laboratory scale, considerable effort has been devoted to experiments that address the role of effective stress changes in normal fracture opening and closure, shear dilatancy and related permeability changes (Goodman, 1974;Bandis et al., 1983;Yeo et al., 1998;Esaki et al., 1999;Gentier et al., 2000;Olsson and Barton, 2001;Samuelson et al., 2009).These experiments have demonstrated that the relationships between fluid pressure change, fracture opening and flow within rough natural fractures are strongly nonlinear.Even though significant progress has been made on defining permeability changes during normal opening and shear slip on the laboratory scale, the nonlinear relationships between fracture opening, changes in effective normal stress, shearing and the resulting permeability are not yet well constrained (Esaki et al., 1991;Olsson and Barton, 2001;Vogler et al., 2015).One common approach is to represent the fracture as two parallel plates whose separation, the hydraulic aperture, gives the same flow rate per unit pressure gradient as would apply for the natural fracture.For parallel plates and laminar flow, the flow rate per unit pressure gradient is proportional to the cube of hydraulic aperture.However, for rough-walled fractures, the hydraulic aperture, a h , is generally only a fraction of the mean mechanical aperture, a m (i.e., the mean separation of two surfaces), the fraction tending to decrease with smaller apertures, although the precise relationship is difficult to derive from fracture geometry alone (Esaki et al., 1999;Olsson and Barton, 2001;Vogler et al., 2015).With larger mechanical apertures, limited evidence suggests that an incremental form of the cubic law might hold such that changes in mechanical aperture give rise to equal changes in hydraulic aperture, at least for normal loading (e.g., Schrauf and Evans, 1986;Evans et al., 1992;Chen et al., 2000).For shear-induced dilation, an additional complication arises from channel clogging due to gouge production (e.g., Lee and Cho, 2002).Particle transport through fluid flow (Candela et al., 2014) and mineralogy (Fang et al., 2017) may additionally influence permeability changes in a complex manner.Deviations from the cubic law also occur when flow becomes non-laminar, which tends to occur at high flow velocities (Kohl et al., 1997) or at feed points in boreholes (e.g., Hogarth et al., 2013;Houben, 2015).
Dilatancy associated with shearing is often expressed in terms of a dilation angle, which is a property describing the relationship between mean mechanical aperture and slip.Dilation angle depends on the fracture surface characteristics, the effective normal stress and the amount of slip.The dependence of dilation on effective normal stress is particularly important within the stimulation context, the dilation angle tending to decrease at higher effective normal stress, in large part because shorter wavelength asperities are sheared off (Evans et al., 1999).Thus, shearing-induced dilation is likely to be more effective at low effective normal stress, such as in the near field of the injection where fluid pressures are relatively high.Clearly, insights from laboratory experiments into the relationships describing fracture dilation and permeability changes are important for understanding field observations in EGS reservoirs (e.g., Robinson and Brown, 1990;Elsworth et al., 2016;Fang et al., 2018) and also for parameterizing numerical models.

Intermediate-scale experiments
In situ experiments on the intermediate scale (i.e., decameter scale) serve as a vital bridge between laboratory and reservoir scales.As such, they can contribute to an improved understanding of reservoir behavior during stimulation and enable upscaling of hydromechanical information obtained from laboratory experiments (Jung, 1989;Martin et al., 1990;Rutqvist, 1995;Schweisinger et al., 2007;Cornet et al., 2003;Murdoch et al., 2004;Cappa et al., 2006;Derode et al., 2013;Guglielmi et al., 2014Guglielmi et al., , 2015a, b), b).Much experience has been gained from stress testing using the hydraulic methods of hydro-fracturing (HF), hydraulic testing of preexisting fractures (HTPF) (Haimson and Cornet, 2003) and hydrojacking (Evans and Meier, 1995;Rutqvist and Stephansson, 1996).Hydraulic tests have been commonly used to quantify pressure-sensitive permeability changes (Louis et al., 1977) and normal stiffness in natural fractures or faults (Rutqvist, 1995).Evans and Wyatt (1984) estimated the closure of a fracture zone from observed surface deformations induced by drilling-related drainage of fluid pressure within the structure.Similarly, Gale (1975), Jung (1989), Martin et al. (1990), Guglielmi et al. (2006) and Schweisinger et al. (2009) used borehole caliper sondes to monitor changes in fracture aperture and pressure during hydraulic jacking tests.The resulting displacements and the flow and pressure responses allowed relationships between mechanical and hydraulic aperture changes to be established and helped to constrain the fracture/fault normal compliance on larger scales.
Irreversible permeability increases arising from slipinduced dilation of natural fractures are particularly relevant for the stimulation of EGS and hydrocarbon reservoirs.To study the phenomenon in situ, Guglielmi et al. (2014) developed a novel double packer system (Step-Rate Injection Method for Fracture In-Situ Properties, SIMFIP) that allows the simultaneous measurement of pressure, flow rates and three-dimensional relative displacements occurring across a fracture isolated within the interval in response to injection.The device was successful in reactivating a fault zone in a limestone formation in southeast France (Derode et al., 2013;Guglielmi, et al., 2015a, b).Pressure, injection rate and 3-D displacements in the SIMFIP interval were measured, together with microseismic activity, tilt and fluid pressure in the vicinity of the injection borehole.The dataset is unique and provided quantitative insights into the relationships bewww.solid-earth.net/9/115/2018/Solid Earth, 9, 115-137, 2018 tween (i) fault dislocation including shear and permeability changes, (ii) fault normal compliance and static friction, and (iii) slip velocities and magnitudes and their relation to aseismic and seismic slip.Recently, a similar experiment was conducted in a series of interacting complex fault zones in shale (Guglielmi et al., 2015a, b).Distributed pore pressure and strain sensors across the faults allowed the evolution of the pressurized and slipped areas to be constrained, which was not previously possible.Such experiments provide a useful methodology for advancing our understanding of the hydromechanically coupled processes in complex faults.

Stimulation by hydraulic fracturing
Experience gained from large-scale stimulation of EGS reservoirs in crystalline rock suggests that hydraulic shearing is the dominant mechanism for permeability creation, at least several tens of meters distance from the injection point (e.g.Evans, 2014).However, the initiation and propagation of hydraulic fractures may be an important mechanism in the near field of the wellbore to connect the wellbore to the preexisting fracture network in the reservoir (Cornet and Jones, 1994).Considerable effort has been devoted to understanding the initiation and propagation of hydraulic fractures on both the laboratory and intermediate field scale.

Laboratory-scale hydraulic fracturing experiments
Many well-controlled, small-scale laboratory experiments on hydro-fracture are documented in the literature (Jaeger, 1963;Zoback et al., 1977;Warpinski et al., 1982;Bruno and Nakagawa 1991;Johnson and Cleary 1991;Song et al., 2001;Jeffrey and Bunger, 2007;Bunger et al., 2011).For such experiments, samples of various shapes (e.g., hollow cylinders and perforated prisms) are loaded along their boundaries and the internal fluid pressure is increased until a hydraulic fracture initiates and propagates.For some tests, transparent materials like polymethyl methacrylate (PMMA) were used to image fracture growth.Some experimental setups include multimaterial "sandwiches" to study the effect of stress contrast on hydraulic fracture containment (Jeffrey and Bunger, 2007;Warpinski et al., 1982).Others study the interaction of propagating hydro-fractures with preexisting fractures (Zoback et al., 1977;Meng, 2011;Hampton et al., 2015) or rock textures (Ishida, 2001;Chitrala et al., 2010), the impact of injection fluids with different viscosities (Bennour et al., 2015) or the role of stress anisotropy (Doe and Boyce, 1989) on the geometry and orientation of generated fractures or the interaction between multiple fractures (Bunger et al., 2011).These laboratory studies provide important results relevant for EGS.For instance, in the common situation where a family of natural fractures in not normal to the minimum principal stress, injections with high-viscosity fluids (viscositydominated regime) may help maintain tensile fracture prop-agation normal to the minimum principal stress despite the presence of cross-cutting fractures (Zoback et al., 1977), whereas low-viscosity fluids (toughness-dominated regime) such as water will promote leak-off into the cross-cutting natural fractures, whose permeability may be increased by shear (Rutledge et al., 2004).This leak-off will tend to limit hydrofracture propagation.Laboratory studies also give insights into the influence of shear stress shadow and transfer on hydraulic fracture growth (Bunger et al., 2011).Laboratory tests have also been essential for providing well-controlled fracture initiation and propagation datasets to benchmark hydraulic fracture simulation codes (Bunger et al., 2007).

Intermediate-scale hydraulic fracturing experiments
Intermediate-scale experiments have been performed to study the initiation and propagation of hydraulic fractures.Typically, they are conducted from boreholes drilled from excavations to facilitate dense near-field instrumentation and secure good experimental control.An early example is the series of experiments that took place at the Nevada Test Site in soft, bedded volcanic tuff with high porosity and high permeability (Warpinski, 1985;Warren and Smith, 1985).The pressure, flow and fracture aperture were monitored during the experiments, and the fractures were mined back at the end of the experiments.The mine-back revealed that stress contrasts were the predominant influence on hydraulic fracture containment and that the fractures consisted of multiple fracture strands and thus differed significantly from simple shapes assumed in theoretical studies.This complexity of the fracture shape impacts the flow and pressure distribution within the propagating hydraulic fractures.Another notable series of in situ tests on hydraulic fracture propagation within the context of coal-seam mining and block cave mine preconditioning have been performed by the hydraulic fracture group of CSIRO (Chacón et al., 2004;Jeffrey et al., 1993Jeffrey et al., , 1992Jeffrey et al., , 2009;;Jeffrey and Settari, 1995;van As et al., 2004;van As andJeffrey, 2002, 2000).The block cave mining experiments were performed in hard rock media and thus are more relevant to EGS.Those conducted in the quartz monzonite porphyries at the Northparkes mine in Australia are probably the most detailed and densely instrumented tests executed to date and included tiltmeter monitoring, a microseismic network and pore pressure sensors as well as detailed rock mass and stress characterization (Jeffrey et al., 2009).Hydro-fractures were formed with water and cross-linked gels, with colored plastic proppants added in order to facilitate their identification once the test volume was mined back.
The mapped trajectories of the hydraulic fractures exhibited complex geometries, sometimes with multiple branching and crossing of joints, veins and shear zones, with and without offset.Subparallel propped sections accounted for 10 to 15 % of the total fracture extent, which microseismic activity indicated was more than 40 m from the injection point.The re-sults demonstrate that the geometry of the fractures is much more complex than typically obtained in small-scale laboratory experiments in a homogeneous material and uniform stress field.The complexity close to the injection point is controlled by the near-well stress perturbation and the interaction with natural fractures and rock mass fabric.Natural fractures also have a strong influence on the propagation of hydraulic fractures.The propagation regime (i.e., viscosity-dominated or toughness-dominated; Detournay, 2016) can be controlled by the injection rate and injected fluid rheology and will have likely a strong influence on the interaction with natural fractures and the final complexity of the hydraulic fractures, although this has not been validated by in situ experiments.Another relevant aspect that has not been investigated with in situ tests is the problem of proppant transport and distribution within the created fractures.Indeed, in the case of hydraulic fractures, the selfpropping mechanism, which results in a permanent aperture increase, is unlikely to be effective, and so proppant placement is necessary for ensuring permanent permeability enhancement.Finally, the nature of the microseismicity generated by hydraulic fracturing is not adequately understood.Moment tensor analyses can offer insight into the nature of the failure in a microseismic event (Warpinski and Du, 2010;Eyre and van der Baan, 2015).For example, they can help resolve whether the seismic radiation is primarily generated by shear on preexisting fractures that are intersected by the propagating fracture, with relatively little energy generated by the advancing mode 1 tip of the hydraulic fracture (Sileny et al., 2009;Horálek et al., 2010;Rutledge et al., 2004).

Rock mass deformation and stress interaction
Injection of fluid into a rock mass invariably leads to the deformation of the surrounding rock mass due to poroelasticity (Biot, 1941) or slip-related stress changes (McClure and Horne, 2014).Numerical studies have suggested that stress interaction between adjacent fractures can have a significant impact on the stimulation results (e.g., Preisig et al., 2015;Gischig and Preisig, 2015).In most reservoir stimulations, the microseismic clouds exhibit an oblate shape, due primarily to the interaction between the strongly anisotropic stress field with the natural fracture population.This tendency to form an oblate ellipsoidal shape instead of a sphere may also be promoted by stress transfer from slipped fractures, which tends to inhibit slip on neighboring fractures (Gischig and Preisig, 2015).Schoenball et al. (2012) and Catalli et al. (2013) have demonstrated that induced earthquakes preferably occur where stress changes generated by preceding nearby earthquakes render the local stress field to be more favorable for slip.Similar effects have been observed for natural earthquakes (Stein, 1999).The effect becomes more important during stimulation as time goes on, especially at the margin of the seismicity cloud.Direct observation of deformation associated with fluid injection has been observed in several intermediate-scale in situ experiments.Evans and Holzhausen (1983) report several case histories of using tiltmeter arrays to observe ground deformation above high-pressure hydraulic fracturing treatments.The results show clear evidence of the self-propping of the induced fractures (van As et al., 2004).Jeffrey et al. (2009) used a tiltmeter array to monitor a hydro-fracturing treatment at the Northparkes mine in Australia.The pattern of tilting indicated that the induced fracture was subhorizontal, which was confirmed by excavating the fracture traces.Evans and Wyatt (1984) modeled strains and tilts occurring around a well during air drilling and found that the deformation was due to the opening of a preexisting fracture zone in response to fluid pressure changes.Derode et al. (2013) observed tilts of 10 −7 -10 −6 radians some meters away from small-volume injections into a fault in limestone.In contrast, Cornet and Deroches (1989) monitored surface tilts with a six-instrument array during injections of up to 400 m 3 of slurries into granite at 750 m depth at the Le Mayet test site in France and report no resolved signal associated with the injections.
Rock mass deformation during stimulation injections necessarily leads to stress changes in the rock mass.Small but nonzero residual stress changes induced by hydraulic fracturing were measured using a stress cell by van As et al. (2004).Stress changes during injections are recognized as playing a potentially important role in determining the pattern of fracture and slip that develops during the injection (e.g., Preisig et al., 2015;Catalli et al., 2013).

Seismic and aseismic slip
A significant fraction of the slip that occurs on fractures within a reservoir undergoing stimulation may be aseismic, depending upon in situ stress and geological conditions.That aseismic slip has occurred is often inferred indirectly from changes in the hydraulic characteristics of a reservoir without attendant microseismicity (Scotti and Cornet, 1994;Evans, 1998).Direct detection of aseismic slip is difficult as it requires relative displacements across fractures to be resolved from borehole or near-field deformation measurements (e.g., Maury, 1994;Cornet et al., 1997;Evans et al., 2005b).For example, Cornet et al. (1997) compared borehole geometry from acoustic televiewer logs run before and after the 1993 stimulation at the Soultz-sous-forêt site and found that 2 cm of slip had apparently occurred across a fracture.The cumulative seismic moment of events in the neighborhood of the fracture was insufficient to explain the observed slip magnitude, thereby suggesting that a large portion of the slip had occurred aseismically.Indeed, almost all fracture zones that were hydraulically active during the stimulation showed evidence of shear and opening-mode dislocations of millimeters to centimeters (Evans et al., 2005b).
The transition from aseismic to seismic slip was directly observed by Guglielmi et al. (2015a) during fluid injection into a well-instrumented fault in limestone in a rock labo-ratory at 280 m depth.Some 70 % of a 20-fold permeability increase occurred during the initial aseismic slip period.The transition to seismic slip coincided with reduced dilation, and the inference is that slip zone area exceeded the pressurized area, suggesting that the events themselves lay outside the pressurized zone.Modeling the observed slip as occurring on a circular fracture with total stress drop gave a radius of 37 m and a moment release of 65 × 10 9 Nm, far larger than the estimated seismic moment release of the order of 1 × 10 6 Nm, again indicating that most slip was aseismic.Guglielmi et al. (2015a) concluded that the aseismic behavior is due to an overall rate-strengthening behavior of the gauge-filled fault and seismicity occurs due to local frictional heterogeneity and rate-softening behavior.These results are consistent with laboratory experiments performed by Marone and Scholz (1988) on fault gauge, which suggest that slip at low effective normal stresses (as anticipated in the near field of a high-pressure injection) and within thick gouge layers tends to be stable (aseismic).
Apart from these observations, aseismic slip has been mostly discussed from the perspectives of semi-analytical or numerical models.Garagash and Germanovic (2012) used a slip-weakening model to show that aseismic slip depends on the stress conditions and injection pressure.Zoback et al. (2012) used McClure's (2012) rate-and-state friction model to show that aseismic slip becomes more prominent for stress states farther from the failure limit.Using the same model, Gischig (2015) demonstrated that slip velocity depends on fault orientation in a given stress field.For nonoptimally oriented faults, aseismic slip becomes more prominent and the seismicity is less pronounced for lower slip velocities and shorter rupture propagation distances.These model results suggest that aseismic slip and low slip velocities may be promoted by avoiding the stimulation of optimally oriented critically stressed faults.Clearly, a more detailed understanding of the conditions that result in aseismic slip may be a basis for less hazardous stimulations.

Induced seismicity
Keeping induced seismicity at levels that are not damaging or disturbing to the population continues to be a major objective for EGS (Giardini, 2009;Bachmann et al., 2011;Majer et al., 2012;Evans et al., 2012) and other underground engineering projects (oil and gas extraction, liquid waste disposal, gas and CO 2 storage).Man-made earthquakes are not a new phenomenon (Healy et al., 1968;McGarr, 1976;Pine et al., 1987;Nicholson and Wesson, 1951;Gupta, 1992).However, the occurrence of several well-reported felt events near major population centers has served to focus attention on the problem (Giardini, 2009;Ellsworth, 2013;Davies et al., 2013;Huw et al., 2014;Bao and Eaton, 2016).Some even led to infrastructure damage, such as following the Mw5.7 event in Oklahoma, USA (Keranen et al., 2013), or the suspension of the projects (e.g., the geothermal projects at Basel (Häring et al., 2008) andSt. Gallen (Edwards et al., 2015) in Switzerland).As a consequence, a substantial research effort has been initiated to understand the processes that underlie induced seismicity.Examples are the numerous studies that have been performed using the high-quality seismic dataset collected during the Basel EGS experiment.Kraft and Deichmann (2014) and Deichmann et al. (2014) analyzed waveforms of the seismicity to determine reliable source locations.Terekawa et al. ( 2012) used an extended catalogue of the focal mechanism solutions of Deichmann and Ernst (2009) to estimate the stress field at Basel and to infer the pore pressure increase required to trigger the events.Goertz-Allmann et al. ( 2011) determined stress drop for the Basel seismicity and found higher stress drops at the margin of the seismic cloud than close to the injection borehole.A similar dependency for Gutenberg-Richter b values was found by Bachmann et al. (2012) -lower b values tended to occur at the margin of the seismicity cloud and at later injection times.
There are numerous analyses of induced seismicity at other EGS sites.Pearson (1981) and Phillips et al. (1997) analyzed microseismicity generated during the stimulation of the 2930 m deep "large Phase 1" and the 3460 m deep Phase 2 reservoirs, respectively, at the Fenton Hill EGS site, New Mexico.Batchelor et al. (1983) summarize microseismicity observed during the stimulation injections into the Phase 2a and 2b reservoirs at Rosemanowes in Cornwall, UK.Tezuka and Niitsuma (2000) examined clusters of microseismic events generated during the stimulation of the 2200 m deep reservoir at the Hijiori EGS site in Japan.Baisch et al. (2006Baisch et al. ( , 2009Baisch et al. ( , 2015) ) analyzed data from different stages of the stimulation of the Habanero EGS reservoir in the Cooper Basin, Australia.Calò et al. (2011) used microseismicity generated during the stimulation of the 5 km deep EGS reservoir at Soultz-sous-forêt to perform timelapse P-wave tomography to infer pore pressure migration during injection.Various authors also explored the vast induced seismicity dataset of > 500 000 events recorded since the 1960s at the Geysers geothermal site, where recently also an EGS demonstration stimulation has been performed (Garcia et al., 2012;Jeanne et al., 2014).The observed seismicity was partly related to injections (Jeanne et al., 2015) and thermoelastic stress changes (Rutqvist and Oldenburg, 2008).Here, local variability in the stress field (Martínez-Garzón et al., 2013) and volumetric source components (Martínez-Garzón et al., 2017) were inferred from detailed analysis of injection-induced seismicity.
Another major focus of induced seismicity research has been the development of hazard assessment tools for injection-related seismicity.The primary goal of these efforts is to develop a dynamic, probabilistic and data-driven traffic light system that can provide real-time hazard estimates during injections (Karvounis et al., 2014;Király-Proag et al., 2016), as opposed to the traditional, static traffic light system (Bommer et al., 2006).Bachmann et al. (2011) 2013) developed several statistical models and tested them in a pseudo-prospective manner using the Basel seismicity dataset.More complex models including physical considerations and stochastic processes (so-called hybrid models) were developed to include information on the reservoir behavior and from the spatiotemporal evolution of seismicity (Goertz-Allmann and Wiemer, 2013;Gischig and Wiemer, 2013;Kiràly et al., 2018).Mignan et al. (2015) evaluated reported insurance claims arising from the Basel induced seismicity in order to infer procedures for evaluating risk based on induced seismic hazard estimates.
The Gutenberg-Richter b value, which describes the reduction in the frequency of the occurrence of events with increasing earthquake magnitude, plays a key role in induced seismic hazard analysis.Schorlemmer et al. (2005) examined the b values of earthquakes in different stress regimes and found that lower values correlated with areas of higher differential stress.Similar trends have been reported for induced seismicity (Bachmann et al., 2012) but also in tectonic earthquakes (Tormann et al., 2014(Tormann et al., , 2015;;Spada et al., 2013) and laboratory experiments (Amitrano, 2012;Goebel et al., 2012).Thus, it was hypothesized that b values are related to local stress conditions (Scholz, 2015), or -in the context of induced earthquakes -to a combination of pressure and stress conditions.Considering standard scaling laws between magnitudes and earthquake source dimensions (i.e., slip and slipped area), it has to be expected that seismicity with high b values may have an indirect but strong impact on permeability enhancement (Gischig et al., 2014).However, these observations have so far only been qualitatively established, as the absolute stress state within the rock volume that hosts the seismicity whose b value is estimated has not been quantitatively determined.
Whilst the hazard associated with induced seismicity is clearly an important factor for reservoir engineering, it should not be forgotten that the shearing of fractures and fracture zones, which is the source of the seismicity, is a key process in the irreversible permeability enhancement that is the objective of the stimulation injections.Furthermore, precise mapping of the 3-D distribution of events provides an indication of the direction of fluid pressure propagation and hence the geometry (i.e., size, shape, degree of anisotropy) of the distribution of permeability enhancement -information that is vital for drilling a subsequent well (Niitsuma et al., 1999).Managing induced seismic hazard also requires considering the design of reservoir attributes such as size, system impedance and heat exchanger properties that control system longevity (e.g., Gischig et al., 2014).Currently, few case studies consider both seismicity and the related changes that occurred in the reservoir (e.g., Evans et al., 2005a), and relatively few studies even report both permeability changes or well injectivity (e.g., Häring et al., 2008;Evans et al., 2005b;Kaieda et al., 2005;Petty et al., 2013).More work is needed to quantitatively link the spatial, temporal or magnitude distribution of seismicity with the thermo-hydraulic-mechanical properties of the rock mass under stimulation conditions.We believe controlled experiments on the intermediate (in situ test site) scale supported by laboratory-scale experiments could be key in making progress towards this end.

Open research questions in hydraulic stimulation research
Research on reservoir stimulation for deep geothermal energy exploitation has been largely performed through laboratory observations, large-scale projects and numerical models.
Observations of full-scale reservoir stimulations have yielded important observations.However, the difficulty in observing the processes occurring within the reservoir under stimulation conditions severely limits the understanding of the permeability creation processes in a way that aids future stimulation design.
Laboratory experiments are attractive because they are controllable and readily repeatable, but they suffer from two main limitations.(1) Upscaling results to the field scale is affected by large uncertainties (Gale, 1993).Although there is evidence that the roughness of fresh fracture surfaces obeys well-defined scaling over many orders of magnitude (Power and Tullis, 1991;Schmittbuhl et al., 1995), complications arise in upscaling the aperture distribution and hence permeability of two semi-mated rough surfaces due to the effects of damage and wear of the asperities during shearing and gouge formation (Amitrano and Schmittbuhl, 2002;Vogler et al., 2016).(2) Laboratory tests are typically performed on single fractures in relatively homogeneous materials and uniform stress conditions, which makes upscaling to structures with multiple fractures such as fracture zones challenging.Similarly, hydraulic fracture propagation behavior is usually studied with homogeneous rock samples under uniform stress, and this can lead to an oversimplistic fracture flow and/or hydraulic fracture propagation behavior.In an EGS reservoir, for example, the stress may be heterogeneous on the meter to decameter scale (Evans et al., 1999;Valley and Evans, 2009;Blake and Davatzes, 2011) and the rock mass may contain various heterogeneities such as stiffness contrasts, fractures or faults (Ziegler et al., 2015).
Because of the large uncertainties in upscaling, many numerical studies make direct (i.e., not upscaled) use of laboratory results to parameterize HM-coupled models for EGS because so few field-scale relationships are available (e.g., Rutqvist, 2011;McClure, 2012;Gischig et al., 2014).This impacts the reliability of the numerical simulation studies because the descriptions of the processes and the input parameter values may be inappropriate for the scale of the simulation.
Clearly there is a need for field-scale hydraulic stimulation experiments that bridge the various scales and are performed with the target rock mass equipped with a comprehensive monitoring system to capture details of the processes.Re-  Guglielmi et al., 2008Guglielmi et al., , 2014Guglielmi et al., , 2015a, b;, b;Jeffrey et al., 2009).The hydro-shearing experiments by Guglielmi et al. (2008) have all been in sedimentary rock types at shallow depth.No such densely instrumented experiments have been performed in fractured and faulted crystalline basement rocks faults, the target rocks for most EGS, where a variety of complex fault architectures and stress-fracture system configurations need to be investigated.The In situ Stimulation and Circulation (ISC) experiment addresses these research gaps, with a focus on the following research questions (RQs).
-RQ1: What is the relationship between pressure, effective stress, fracture aperture, slip, permeability and storativity (i.e., the hydromechanically coupled response of fractures)?
-RQ2: How does the transient pressure field propagate in the reservoir during stimulation?
-RQ3: How does the rock mass deform as a result of rock mass pressurization, fracture opening and/or slip?
-RQ4: How does stress transfer inhibit or promote permeability enhancement and seismicity along neighboring fractures?
-RQ5: Can we quantify the transition between aseismic and seismic slip and the friction models (such as rateand-state friction) describing slip evolution and induced seismicity?
-RQ6: How do hydraulic fractures interact with preexisting fractures and faults and how can the interaction be controlled?
-RQ7: How does induced seismicity evolve along faults and fractures of different orientation?
-RQ8: How does induced seismicity along stimulated faults compare to induced seismicity along newly created hydraulic fractures?
-RQ9: Can we quantify the link between spatial, temporal and magnitude distribution of induced seismicity and HM-coupled properties of fractures and faults?
3 The ISC experiment The objective of the ISC experiment was to find answers to the abovementioned research questions by (1) stimulating a naturally fractured crystalline rock volume on the decameter scale that is exceptionally well characterized in terms of its structural, geomechanical and hydraulic conditions and (2) providing a dense network of sensors within the test volume so as to establish a 3-D dataset at high spatial resolution that will yield detailed insight into geomechanical processes associated with induced micro-earthquakes, fracture shearing, permeability creation and fluid circulation.The experiment was planned and prepared during 2015 and 2016 and executed during two series of experiments in February and May 2017.Here we give a general overview of the experiment site, the main concepts and the design of the experiment, without detailing results; these are to be published in future work.

The in situ rock laboratory
The ISC experiment was performed at the GTS, near the Grimsel Pass in the Swiss Alps (Fig. 1a).The GTS is owned by the National Cooperative for the Disposal of Radioactive Waste (NAGRA) and was developed to host in situ experiments relevant to nuclear waste repository research.The facility consists of a complex of tunnels at a mean depth of 480 m that penetrate crystalline rock with well-documented structures.The rock type is considered representative of the Alpine crystalline basement that is a main target for EGS.
The test site for the ISC experiment is located in the southern part of the GTS (marked in blue in Fig. 1b) between a tunnel that is called AU tunnel in the west and one that is called the VE tunnel in the east.The rock at the GTS consists of Grimsel granodiorite and Central Aar granite.Both show an alpine foliation that strikes northeast and dips steeply at ∼ 77 • towards the southeast.The moderately fractured rock mass is intersected by ductile and brittle shear zones, as well as brittle fractures and metabasic dykes.Within the ductile shear zones, numerous fractures that are commonly partially filled with gouge are present.

Experimental phases
The ISC experiment was divided into three phases (Fig. 2).The first phase (2015-2016) was a pre-stimulation phase that aims to characterizing the rock volume in terms of geological and structural conditions, the local stress state (Gischig et al., 2018), hydraulic and thermal properties, and fracture connectivity, all of which are essential for the design of the experiment and the interpretation of experimental results.In addition, during the pre-stimulation phase, a monitoring system was established that allows capturing the seismohydromechanical response at high spatial and temporal resolution.The second phase (February-May 2017) -the main hydro-shearing and hydro-fracturing experiment -was concerned with enhancing the permeability of the rock mass with high-pressure fluid injections.A third and final phase (June-December 2017), the post-stimulation phase, was dedicated to characterize the rock mass in great detail after stimulation  to quantify changes in permeability, fracture connectivity and heat exchanger properties.

Pre-stimulation phase -rock mass characterization and instrumentation
Boreholes, rock mass characterization and geological model The governing aspects for designing the instrumentation of the decameter-scale ISC experiment were (1) a detailed understanding of the geological settings in three dimensions During the pre-stimulation phase a series of 15 cored boreholes with a length of between 18 and 50 m and diameters of between 86 and 146 mm were drilled within or at about the experimental volume (Fig. 3).Three boreholes were ded- icated to stress measurements (SBH), two to the stimulation injections (INJ), four to geophysical characterization and monitoring (GEO), three to strain and temperature measurements (FBS), and another three to pore pressure, strain and temperature measurements (PRP).The boreholes were characterized in terms of geologic structures, hydraulic properties and inter-borehole connectivity.Various geological (i.e., core logging), geophysical (i.e., optical televiewer logs, resistivity logs, full-wave sonic logs, GPR surveys and active seismic measurements between the injection boreholes) and singlehole and cross-hole hydraulic methods (i.e., packer tests such as pressure-pulse, constant-rate and constant head injection tests, oscillating pumping tests, and tracer tests using various solutes, DNA-encoded nanoparticles and heat) were used.In addition to borehole-based characterization methods, the experimental rock volume was characterized using detailed tunnel maps, reflection GPR from the tunnel walls and active seismic data acquisition between the AU and VE tunnels (Fig. 1b).The trajectories of the subsequent boreholes were chosen based on these preliminary geological and hydraulic data and simplified numerical HM-coupled models (i.e., using 3DEC; Itasca 2014) for stimulation scenarios that provided an estimate of the deformation field and pore pressure propagation along geological structures.
The joint interpretation of all geophysical, geological and hydrogeological observations was used to constrain a 3-D structural model of the experimental volume (Krietsch et al., 2017, Fig. 4).The 3-D model illustrates the intersection of the shear zones within the experimental volume.Two major metabasic dykes (S3.1 and S3.2) up to 1 m thick with a spacing of 2 m crosscut the volume in an east-west direction.These metabasic dykes form the boundary of a zone with a high fracture density and partly open fractures, which together with the dykes define the S3 shear zone.The majority of brittle fractures within and outside the S3 shear zone are oriented parallel to the boundaries of the sheared metabasic dykes, which strike east-west in the test volume.Very few fractures penetrate into the dykes.

Rock mass instrumentation
In addition to a detailed characterization of the test volume for the design and interpretation of the in situ experiment, a dense sensor network was required to collect the necessary data at a sufficient spatial resolution that were needed to address the previously mentioned research questions (RQ1-9).This includes pore pressure monitoring, strain and tilt, and microseismic monitoring.Instrumentation design was also governed by the types of hydraulic injection treatments that were performed in the ISC experiment, i.e., hydraulic shearing (pressurization and reactivation of natural fractures and faults) and hydraulic fracturing (i.e., initiation and propagation of new fractures).

Pore pressure, deformations and temperature
To address questions related to hydromechanics (RQ1), pressure propagation (RQ2), and interaction between preexisting and hydraulic fractures (RQ6), four pressure monitoring boreholes (three PRP boreholes and SBH15.004;Fig. 3) were instrumented at points where they cut relevant structures.The boreholes were drilled approximately normal to the strike of the main geological features (S1 and S3 shear zones).They were completed with cement and resin-grouted packer systems with fixed open pressure monitoring intervals that record the pressure within fracture zones or fault zones.Pressure was also recorded in the INJ borehole that was not used for stimulation (Fig. 3) with a straddle packer system similar to the one used for high-pressure fluid injections.The PRP boreholes were also equipped with prestressed distributed fibre optics (FO) cables for strain and temperature measurements.Strain recordings give information on the hydromechanical response to pressurization across preexisting fractures (RQ1) and help to detect propagation of new fractures during hydro-fracturing experiments (RQ6).Distributed temperature measurements were used during preand post-stimulation thermal tracer tests.
To address research questions related to rock mass deformations (RQ3-6), three boreholes (FBS16.001-3 in Fig. 3) were equipped with both distributed and fiber Bragg grating (FBG) strain-sensing optical fibers that were grouted in place.One borehole (FBS16.001) is approximately normal to the strike of the main geological features and intersects both the S3 and S1 fault zones.Another borehole is parallel to the strike of the S3.1 fault and intersects the S1.1 fault (FBS16.002),and one is parallel to the S1.2 faults and intersects the S3 fault zone (FBS16.003).The FBG sensors record axial strain across borehole sections that span potentially active fractures or the "intact" rock mass.Distributed strainsensing optical fibers allow a dense spatial coverage and thus are more likely to observe the propagation and opening of a hydraulic fracture.
The borehole strain monitoring system was complemented with an array of three biaxial tiltmeters installed on the margins of the test volume along the VE tunnel near the S3 fault zone (Fig. 3).The tilt sensors were mounted in shallow holes drilled into the tunnel floor and record horizontal tilt.Together, the tilt measurements and the longitudinal strain in the FO boreholes were capable of describing the deformation field around the stimulated rock volume and allowed constraining the characteristics of the stimulated fault zones (i.e., dimension, dislocation direction and magnitude).

Microseismicity
Questions related to induced seismicity (RQ5, 7, 8) were tackled using a microseismic monitoring system, which consists of a sensor network with 14 piezosensors affixed to the tunnel walls and 8 sensors that were pressed pneumatically against the borehole wall in the geophysical monitoring boreholes (GEO16.001-4,Figs. 3 and 5).The uncalibrated piezosensors were complemented with calibrated accelerometers (as done by Kwiatek et al., 2011) at five locations on the tunnel surface to enable the calculation of absolute magnitudes.A real-time event detection gave provisional event hypocenters.
The sensor network was also used to record periodic active seismic experiments.Highly reproducible sources (i.e., piezoelectric pulse sources in boreholes and hammers installed at the tunnel walls with predefined constant fall height; Fig. 5) were triggered roughly every 10 min during the stimulation experiments with the goal of recording systematic changes in the waveform characteristics that allow inferring changes in seismic velocity, attenuation and scattering properties.Such measurements can give additional constraints on 3-D pressure propagation and deformation characteristics (RQ1-4, 9).

Stimulation phase
The stimulation experiments were performed in two experiment sequences.(1) In February 2017, six hydraulic shearing experiments were performed including high-pressure water injection into existing faults or fracture zones so as to reduce effective normal stress and trigger shearing.(2) In May 2017, six hydraulic fracturing experiments were conducted with high-pressure injection into fracture-free borehole intervals so as to initiate and propagate hydraulic fractures.
Two 146 mm diameter, downwardly inclined boreholes (INJ 1 and INJ 2 in Fig. 3) were dedicated to the injections from packer-isolated intervals.For the stimulation operations, water or gel was injected into a 1-2 m interval in one borehole, and the second borehole was used to additionally monitor the fluid pressure response.The maximum injected volume for the stimulation at each interval was limited to about 1000 L. This value was determined as part of a pre-experiment hazard and risk study (Gischig et al., 2016) and was found to be acceptable regarding the estimated likelihood of inducing seismic events that could be felt in the tunnels, as well as the disturbance to ongoing experiments elsewhere in the GTS.We used standardized injection protocols for HS and HF (i.e., we did not test different injection strategies) so that the variability in the rock mass response arises from differences in local hydromechanical conditions as well as geological settings and not from different injection strategies.

Hydro-shearing experiments
The stimulation injections targeted natural fracture zones in the rock volume.Each interval stimulation consisted of four cycles (Fig. 6).The objective of the first cycle was to measure initial transmissivity and jacking pressure and break down the interval.Initially (Cycle 1), pressure was increased in small steps until breakdown occurred, as evidenced by a disproportionate increase in flow rate.This first cycle allowed quantifying the initial injectivity.After venting, the test was repeated with refined pressure steps (Cycle 2) in a narrow range to identify the jacking pressure.After Cycle 2 the interval was shut in to capture the pressure decline curve before the interval was vented.The purpose of the third cycle was to increase the extent of the stimulation away from the injection interval.For this purpose, a step-rate injection test with four or more steps was utilized.The interval was then shut in and the pressure decline was monitored for 40 min before initiating venting for 30 min.The purpose of the fourth cycle was to determine post-stimulation interval transmissivity and jacking pressure for comparison with pre-stimulation www.solid-earth.net/9/115/2018/Solid Earth, 9, 115-137, 2018  values.Thus, a step-pressure test was conducted, initially taking small pressure steps to define the low-pressure Darcy trend, with the deviation from it defining the jacking pressure.Following this cycle, the interval was shut in for 10 min before venting.An important aspect for the quantification of irreversible changes in the reservoir was to run acoustic televiewer logs across each interval before and after the stimulation to attempt to resolve any dislocation that may occur across the fractures in the interval.

Hydraulic fracturing experiment
The protocol for hydraulic fracturing tests in borehole intervals without natural fractures is shown in Fig. 7.Each interval stimulation consisted of three cycles.First, the packed interval was tested with a pulse for integrity.The objective of the first cycle was to break down the formation (i.e., to initiate a hydraulic fracture) using low flow rates (i.e., around 5 L min −1 injections for 60 s).The second cycle aimed to propagate the hydraulic fracture away from the wellbore and connect to the preexisting fracture network using progressively increasing flow rates (up to 100 L min −1 ).The purpose of the third cycle was to quantify the final injectivity and jacking pressure using a pressure

Post-stimulation phase
In the last experiment phase, the changes to the hydrology and rock mass properties that occurred because of each of the two stimulation phases (i.e., the hydraulic shearing and hydraulic fracturing phases) were investigated.Accordingly, after each phase, a characterization program was performed.
The hydraulic properties of the rock mass were determined using single-hole and cross-hole hydraulic methods similar to those methods used during the pre-stimulation phase.In addition, single-hole, cross-hole and cross-tunnel active seismic and GPR measurements were conducted.

Summary and conclusion
The review of scientific research results showed that carefully analyzed data from large-scale experiments (i.e., EGS projects) and laboratory-scale experiments provide a fundamental understanding of processes that underpin permeability creation and induced seismicity in EGS.The results from large-scale experiments suffer from accessibility and resolution, which does not permit us to resolve the details of seismo-hydromechanically coupled processes associated with the stimulation process.Laboratory-scale experiments provide a fundamentally improved understanding of these processes but suffer from scalability and test conditions that may lead to oversimplistic fracture flow and/or hydraulic fracture propagation behavior that is not representative of a heterogeneous reservoir.Intermediate-scale experiments can serve to bridge the gap between the laboratory and the large scale and may enable the upscaling of results gained from small-scale experiments.However, only few intermediatescale hydro-shearing and hydro-fracturing experiments have recently been performed in a densely instrumented rock mass and no such measurements have been performed on faults in crystalline basement rocks.
We have provided here an overview of the intermediatescale hydro-shearing and hydro-fracturing experiment (i.e., ISC experiment) that was executed in 2017 in the naturally fractured and faulted crystalline rock mass at the Grimsel Test Site (Switzerland).It was designed to fill some of the key research gaps and thus contribute to a better understanding of seismo-hydromechanical processes associated with the creation of enhanced geothermal systems.As this contribution is only meant to provide a literature review and an overview of our ISC experiment at the Grimsel Test Site, several other publications will provide more detailed descriptions and analyses of this intermediate-scale hydro-shearing and hydro-fracturing experiment.

Figure 1 .
Figure 1.(a) GTS is located in the Swiss Alps in the central part of Switzerland.(b) The ISC experiment is implemented in the southern part of the GTS in a low fracture-density granitic rock.

Figure 2 .
Figure 2. The three test phases of the ISC experiments with listings of the main activities during each phase.
(e.g., fracture and fault orientation and intersections, fracture density) (2) the in situ state of stress, (3) the pre-stimulation hydraulic conditions, including the flow field, preferential fluid flow-path ways and transmissivities, (4) the borehole sections used for stimulation, (5) the type of hydraulic injection (i.e., hydraulic shearing or hydraulic fracturing), and (6) anticipated quantities and spatial distributions of strain, tilt and pressure within the rock volume during stimulation.

Figure 3 .
Figure 3.The 15 boreholes drilled for the ISC experiment (view steeply inclined towards the southeast).

Figure 4 .
Figure 4. Three-dimensional model showing the boreholes drilled towards the rock volume for the in situ stimulation experiment; S1-(red) and S3-(green) oriented shear zones as well as the dextral shear sense at the S3 shear zones indicated by the black arrows.

128F.
Figure 5. Outline of seismic monitoring network including hammer sources and borehole piezo sources for active seismic surveys.
step injection similar to the pressure step injection considered for Cycle 4 in the fault slip experiments.Both pure water and a gel (i.e., a xanthan-water-salt mixture with 0.025 weight percent of xanthan and 0.1 weight percent of salt with a viscosity between 35 and 40 cP) were used for fracture propagation.The two injection fluids allowed investigating two different propagation regimes (i.e., toughness-dominated and viscosity-

Figure 7 .
Figure 7. Injection protocol for hydro-fracturing experiments.The blue solid curve denotes flow-rate-controlled injection and the red solid curve pressure-controlled injection.