Modeling the Hydraulic Fracture Stimulation performed for Reservoir Permeability Enhancement at the Grimsel Test Site, Switzerland

Abstract

In-situ hydraulic fracturing has been performed on the decameter scale in the Deep Underground rock Laboratory (DUG Lab) at the Grimsel Test Site (GTS) in Switzerland in order to measure the minimum principal stress magnitude and orientation. Conducted tests were performed in a number of boreholes, with 3–4 packer intervals in each borehole subjected to repeated injection. During each test, fluid injection pressure, injection flow rate and microseismic events were recorded amongst others. Fully coupled 3D simulations have been performed with the LLNL's GEOS simulation framework. The methods applied in the simulation of the experiments address physical processes such as rock deformation/stress, LEFM fracture mechanics, fluid flow in the fracture and matrix, and the generation of micro-seismic events. This allows to estimate the distance of fracture penetration during the injection phase and correlate the simulated injection pressure with experimental data during injection, as well as post shut-in. Additionally, the extent of the fracture resulting from simulations of fracture propagation and microseismic events are compared with the spatial distribution of the microseismic events recorded in the experiment.

Full text

PROCEEDINGS, 42nd Workshop on Geothermal Reservoir Engineering
Stanford University, Stanford, California, February 13-15, 2017
SGP-TR-212
1
Modeling the Hydraulic Fracture Stimulation performed for Reservoir Permeability
Enhancement at the Grimsel Test Site, Switzerland
D. Vogler, R.R. Settgast, C.S. Sherman, V.S. Gischig, R. Jalali, J.A. Doetsch, B. Valley, K.F. Evans, F. Amann and M.O.
Saar
ETH Zurich, Zurich, Switzerland.
davogler@ethz.ch
Keywords: EGS, Hydraulic Fracturing, Microseismicity, Reservoir Stimulation, Numerical Modeling
ABSTRACT
In-situ hydraulic fracturing has been performed on the decameter scale in the Deep Underground rock Laboratory (DUG Lab) at the
Grimsel Test Site (GTS) in Switzerland in order to measure the minimum principal stress magnitude and orientation. Conducted tests
were performed in a number of boreholes, with 3–4 packer intervals in each borehole subjected to repeated injection. During each test,
fluid injection pressure, injection flow rate and microseismic events were recorded amongst others. Fully coupled 3D simulations have
been performed with the LLNL’s GEOS simulation framework. The methods applied in the simulation of the experiments address
physical processes such as rock deformation/stress, LEFM fracture mechanics, fluid flow in the fracture and matrix, and the generation
of micro-seismic events. This allows to estimate the distance of fracture penetration during the injection phase and correlate the
simulated injection pressure with experimental data during injection, as well as post shut-in. Additionally, the extent of the fracture
resulting from simulations of fracture propagation and microseismic events are compared with the spatial distribution of the
microseismic events recorded in the experiment.
1. INTRODUCTION
Oil, gas and geothermal reservoirs rely on sufficiently high reservoir permeability to achieve target production rates. However,
Enhanced Geothermal Systems (EGS) have the potential for providing sustainable energy production from geothermal heat sources at
great depths, even though the formation originally has a low permeability and has little water in place (Tester et al. 2006). The
permeability is increased through hydraulic stimulation treatments in which large fluid volumes are injected. Such high-pressure fluid
injections can drive tensile hydraulic fractures into the target formation (Economides et al. 2000, McClure & Horne 2014a,b, Detournay
2016) and also result in the activation in shear of pre-existing, critically stressed fractures or fault zones (hydro-shearing) (Evans et al.
1999, Evans 2005a). Hydraulic fracturing and hydro-shearing can thereby be used to achieve the fracture permeabilities required to
obtain sufficiently high fluid circulation and corresponding heat extraction (Evans 2005a , Evans et al. 2005b, Gischig & Wiemer 2013,
Guo et al. 2016, Vogler et al. 2016b). Both mechanisms commonly generate microseismicity, which constitutes an essential tool for
mapping the migration of pressure and flow within the rock mass during reservoir creation (e.g. Niitsuma et al, 1999, Wolhart et al.
2006, Kim 2013, Deichmann et al. 2014, McClure & Horne 2014b). When large fluid volumes are injected, significant earthquakes may
be induced, which can lead to the termination of reservoir operations (Kim 2013, Kraft & Deichmann 2014). Within the context of this
paper, microseismic signals observed during minifrac stress measurements can indicate the dimension and propagation direction of the
induced hydraulic fractures, which can be used to determine the direction of the minimum principal stress.
This study focuses on numerical simulations of hydraulic fracture propagation and attendant microseismicity during minifrac stress tests
conducted in the Deep Underground Geothermal Laboratory (DUG Lab) at the Grimsel Test Site, Switzerland (Gischig et al. 2017).
Simulations of hydraulic fracture dimensions, as indicated by the propagation of discrete fractures and the occurrence of microseismic
events, are scrutinized with respect to the in-situ datasets.
Figure 1: Location of the Deep Underground rock Laboratory at the Grimsel Test Site (GTS) in the Swiss Alps.

Vogler, Settgast, Sherman, Gischig, Jalali, Doetsch, Valley, Evans, Amann and Saar
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METHODS
An experiment is underway at the Grimsel Test Site (GTS), in the Swiss Alps (Figure 1, Gischig et al. (2017)) that is intended to
advance our understanding of the fundamental processes activated when stimulating Enhanced Geothermal Systems (EGS). The GTS is
operated by the Swiss National Cooperative for the Disposal of Radioactive Waste (Nagra) as a centre for underground research and
development. The GTS is located in the granitic formations of the Aar Massif, about 1730 meters above sea-level and 450 meters
beneath the Juchlistock (ground surface). The total tunnel length in the laboratory is about 1 km and the total length of cored boreholes
is above 5 km. The experiments conducted at the GTS aim to advance; (i) quantitative capabilities to model stimulation and reservoir
operation, (ii) process understanding and validation in underground lab experiments, and (iii) develop a petrothermal (i.e., EGS) Pilot
and Demonstration (P&D) project.
As part of the initial rock mass characterization, a number of small-scale hydraulic fractures (mini-fracs) were initiated and propagated
in order to measure the in-situ minimum principal stress magnitude and orientation. Three to four packed-off intervals in three boreholes
(Figure 2a) were each subjected to fluid injection until breakdown and fracture propagation were observed. During testing, the
experimental rock volume was geophysically monitored (Figures 2b and d). The present study focuses on the injection cycles of mini-
fracs performed at 18 m (SB3-18) and 8 m depth (SB3-8) along sub-horizontal borehole SB3. At these borehole locations, three fracture
reopening injection cycles (injection cycles 2-4) were performed after an initial breakdown cycle (injection cycle 1). The fluid volumes
injected during cycles 1-4 into intervals SB3-18 and SB3-8 were 0.5, 1.6, 2.5, 3.3 litres (7.9 litres total) and 1.1, 1.8, 3.3, 4.2 litres (10.4
litres total) respectively. An example for a breakdown cycle and subsequent refrac cycles for borehole SB3 at 8 m depth is given in
Figure 3. During one injection cycle, the fracture propagates until fluid injection is stopped and the wellbore is shut-in to determine the
pressure decline curve. The wellbore is then opened and part of the injected fluid is recovered.
The GTS is excavated in Granite and Granodiorite and has hosted numerous diverse studies relevant to the current project. Mechanical
and hydraulic properties not determined during the present experiments were obtained from previous studies (Keusen et al. 1989, Pahl et
al. 1989, Konietzky 1995). The principal stress magnitudes in the borehole derived from over-coring measurements conducted in the
current program were estimated to be σ1 = 17.3, σ2 = 9.7 and σ3 = 8.3 MPa (Figure 2c, Gischig et al. 2017). It is noteworthy, that σ3 is
roughly parallel to borehole SB3.
Figure 2: GTS - a) Borehole locations; b) Monitoring of fault zones; c) Main fault zones and principal stress orientations; d)
Tunnel view.

Vogler, Settgast, Sherman, Gischig, Jalali, Doetsch, Valley, Evans, Amann and Saar
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The numerical simulator GEOS, developed at Lawrence Livermore National Laboratory (Settgast et al. 2014, 2016), is used to simulate
the injection phases. GEOS is a massively parallel multi-physics framework, which incorporates capabilities to model hydraulic
fracturing (Settgast et al. 2012, 2014, Fu et al. 2015, Settgast et al. 2016); seismic events (Sherman et al. 2016); fracture shearing
(Annavarapu et al. 2015); thermal drawdown (Fu et al. 2016); matrix flow and heat transport (Guo et al. 2016); flow in rough fractures
(Vogler et al. 2016a); geochemical transport and reaction (Walsh et al. 2012, 2013); and simulations of immiscible fluid flow (Walsh &
Carroll 2013). The numerical solver employed in this study offers fully coupled hydro-mechanics (HM) and implicit time stepping.
Solid body deformation is modeled with a finite element method and fluid flow in fractures and the matrix is modeled with a finite
volume method. Fracture propagation employs an energy-based fracture mechanics concept, fluid flow in the fracture is based on
lubrication theory and fluid leak-off uses Carter’s leak-off method. In this study, the fracture is initiated with a notch in the location of
the packer interval. A detailed explanation of the GEOS framework can be found in Settgast et al. (Settgast et al. 2016).
Modeling of microseismic events in GEOS can be performed with a full mechanical treatment or with a point-source approximation
(Sherman et al. 2016). In this study, the point-source approximation is used. Joint sets are characterized by statistical distributions of
location, dimension, orientation and material properties, and are mapped onto the finite element mesh. During the simulation, the stress
state and fluid pressure are evaluated to determine local failure according to a Coulomb friction model. If an element fails, shear slip,
dilation and the moment tensor of microseismic events are computed. Pressure loss between the pump setup in the GTS tunnel and the
fracture are computed with an analytical wellbore solver, which incorporates frictional losses based on borehole dimensions, fluid entry
into the fracture and near wellbore effects (such as fracture tortuosity near the wellbore). The wellbore solver is coupled to the fracture
at the fracture entry. The flow rates injected into the reservoir during the experiment are applied to the head of the wellbore solver.
Figure 3: SB3-8. Example of injection cycles with fluid flow rate and pressure response in borehole SB3 at 8m depth.

Vogler, Settgast, Sherman, Gischig, Jalali, Doetsch, Valley, Evans, Amann and Saar
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RESULTS AND DISCUSSION
This section compares the results of the minifrac tests and numerical simulations, with a special emphasis on dimensions of the
propagated fractures, the location and number of induced microseismic events, and the wellhead pressure response to the injected flow
rates.
Simulation results for the fracture aperture field and pore pressure in and around the propagating fracture before shut-in are shown for
four injection cycles (Figure 4). As σ3 is roughly parallel to borehole SB3, Figure 4 shows fracture propagation is in a plane normal to
the wellbore. The microseismic cloud recorded in the experiments, however, is not perfectly normal to the current best estimate of the
minimal principal stress orientation, an observation which will be further discussed at the end of this section. The corresponding
dimensions of the fracture after the four injection cycles are shown in Figures 5a-b. Here, fracture growth increases from about 4 m after
the breakdown cycle, to 7.5 m (SB3-18, 7.9 litres injected) and 8.3 m (SB3-8, 10.4 litres injected) after the last injection cycle.
Simulations of the pressure response at the wellhead during injection cycle 4 (SB3-8) are compared to the experiment in Figure 6. The
rapid pressure decline after shut-in was only captured by employing the wellbore solver in the simulations. Without accounting for
wellbore effects (mostly consisting of fracture entry losses), the simulated pressure decrease after shut-in was about 20% of the decrease
computed by incorporating pressure losses between the pump setup and the fracture. As the intact rock at the GTS has a low porosity
and permeability, fluid pressure only slowly diffuses away from the fracture and the fracture closes slowly. Optical televiewer data and
other geophysical observations in SB3 suggest that the rock mass around the test interval probably contains a significant number of
discontinuities at various scales. Additionally, the Granodiorite at the GTS can display strong foliation. These factors could conceivably
influence the pressure response during injection, the fracture propagation direction and pressure diffusion after shut-in, and thus need to
be further investigated. For example, smaller, unmapped fractures or flaws in the vicinity of the propagating fracture could cause the
fluid to diffuse away from the fracture faster. The observed foliation of the rock mass in the GTS could influence the direction of
fracture propagation as fracture toughness is likely to be anisotropic, although it is clear that the microseismic structures do not lie in the
plane of the foliation (Gischig et al, 2017).
Experimental and simulation results for the microseismic activity around the propagating fracture in SB3-18 are shown in Figure 7.
Here, the microseismic activity is viewed normal to the propagating fracture plane (i.e. horizontal view from the north). While the
boundaries of the microseismic activity in the field experiment is more irregular, both experiment and simulation predict hydraulic
fracture dimensions of around 7 m diameter after the last injection cycle. Triggered seismicity is more evenly distributed across all
injection cycles in the simulations, the experimental data showing fewer seismic events during the first injection cycles. The propagation
of simulated microseismic activity with the evolving fracture fluid pressure field around the fracture is shown in the snapshots of Figure
8. It should be noted that each snapshot shows the microseismic events that occur between the beginning of the respective injection
cycle and the start of the next cycle, since a few events in the experiment occurred during shut-in. For injection cycle 4, Figure 8.4
shows pore pressure and seismic events up to the start of injection in the next packer interval (SB3-13), which occurred a few hours
after the last injection cycle in SB3-18. This longer time period after injection cycle 4 causes an apparent smearing of the pressure front
when compared to cycles 1-3.
As noted earlier, it proved difficult to reproduce the pressure decrease that occurred after shut-in. In the simulations, this was modeled
with a number of effects in and near the wellbore, among which entrance losses at the fracture were most significant. However, further
study of the system behavior after shut-in is required. Heterogeneity and anisotropy of the rock mass are likely to influence the
geometry of the induced fracture and the pressure history during the tests. Geophysical observations indicate heterogeneous
distributions of rock properties around borehole SB3 (e.g., strength and/or elastic modulus variations due to pre-existing discontinuities
in the rock mass), and it is known the rock is anisotropic. This might contribute to the discrepancy between the plane of the induced
microseismicity and the current best estimate of the minimum principal stress orientation. It is planned to include the effect of
heterogeneity and anisotropy in future simulations of on-going experiments at the GTS site which entail fault stimulation and hydraulic
fracturing with larger injected volumes.

Vogler, Settgast, Sherman, Gischig, Jalali, Doetsch, Valley, Evans, Amann and Saar
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Figure 4: SB3-8 before shut-in during injection cycles 1-4 (left to right). The frames at top show the distributions of fracture
aperture, a, minimum principal σx and flow rate vectors prevailing immediately before shut-in. The frames at bottom
show the corresponding distributions of fluid pressure and flow rate vectors at the fracture-rock interface. The wellbore,
going from the left of the Figure to the fracture center, is shown as a dotted line in all plots. A sketch illustrating the
perspective view of the rock mass (blue and green) and fracture (red) is shown at the bottom.
Figure 5: Simulated fracture dimensions: a) Fracture volume vs total injected volume in SB3-18; b) Fracture dimensions vs total
injected volume in East-West (EW) and Z-direction.

Vogler, Settgast, Sherman, Gischig, Jalali, Doetsch, Valley, Evans, Amann and Saar
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Figure 6: SB3-8. Injection flow rate and resulting pressure at wellbore head during injection cycle 4 for experiment and
simulation.
Figure 7: SB3-18. Microseismic activity in simulations (left) and experiments (right) viewed normal to the fracture (horizontal
view from the north). Microseismic events are colored according to the injection cycles 1-4.

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Figure 8: SB3-18. Snapshots of simulated microseismic activity and the fluid pressure distribution around the propagating
fracture (fracture is not explicitly shown) at the end of the four injection cycles (i.e. immediately before the start of the
subsequent injection cycle). Only one octant is shown, as illustrated by the sketch of the fracture region (red) within the
rock mass (blue, green and magenta) shown at the bottom. The simulated microseismic events are colored according to
the injection cycles 1-4.
CONCLUSIONS
Numerical simulations were made of hydraulic fracture stress tests conducted in the Deep Geothermal Underground Laboratory (DUG
Lab) at the Grimsel Test Site, Switzerland. The simulations sought to reproduce the pressure response, hydraulic fracture dimensions
and microseismic event distributions observed during the tests.
Model simulations for fracture dimensions yield a fracture diameter of roughly 7.5 m (SB3-18) and 8.3 m (SB3-8), which is in good
agreement with fracture dimensions estimated from microseismic event distributions observed during the experiment. Microseismic
events in the experiments predominantly occurred during the refracturing cycles, while seismic activity in the numerical simulations was
more evenly distributed across all injection cycles. The pressure response during fracture propagation is captured in the numerical
model, where an analytical wellbore solver is needed to reproduce post shut-in behavior. Microseismic events observed during the
experiments defined planar structures that were not oriented perpendicular to the estimated orientation of the minimum stress, as would
be expected were they to define classical hydrofractures. Whether this reflects structural control of the microseismic plane (i.e.
activation in shear of a preexisting structure), local deviation of the minimum stress orientation from that estimated or both is currently
uncertain. Simulation of the effect of the injections in a medium with pre-existing structures and foliation will be examined in future
work.
The simulations reported in this paper can serve as a baseline for more complex models that will be applied to modeling on-going field
experiments which entail fault stimulation and hydraulic fracturing with larger injected volumes.

Vogler, Settgast, Sherman, Gischig, Jalali, Doetsch, Valley, Evans, Amann and Saar
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ACKNOWLEDGEMENTS
The authors want to thank the NAGRA and the Grimsel Test Site, Switzerland. Funding by the Swiss Competence Center for Energy
Research (SCCER) is gratefully acknowledged.
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