Post on 06-Feb-2018
transcript
Technology crossover between Engineered Geothermal System (EGS) and hydrothermal technology
Roy Baria Joerg Baumgaertner
Dimitra Teza John Akerley
2015
Disclaimer
IEA Geothermal do not warrant the validity of any information or the
views and findings expressed by the authors in this report. Neither IEA
Geothermal (IEA-GIA) nor IEA shall be held liable, in any way, for use
of, or reliance on, any information contained in this report.
Roy Baria1; Joerg Baumgaertner2; Dimitra Teza2; John Akerley3, 2015 Technology crossover between Engineered Geothermal System (EGS) and hydrothermal technology.
1 MIL-TECH UK Ltd and EGS Energy Ltd
2 BESTEC GmbH
3 Ormat Nevada Inc.
i
Contents
1. Introduction: purpose of this report .......................................................................................................... 1
2. Natural conditions and critical parameters ........................................................................................... 2
2.1 Shearing mechanism for enhancing in-situ permeability ...................................................................... 2
2.2 Joint orientation and distribution .................................................................................................................... 3
2.3 Stress regime ......................................................................................................................................................... 3
2.4 In-situ fluid ............................................................................................................................................................... 4
2.5 Stimulation flow rate ............................................................................................................................................ 4
2.6 Geology and geological faults at depth ...................................................................................................... 5
3. Methodology and technology to improve reservoir performance................................................ 6
3.1 Infrastructure may need rectification before a hydraulic stimulation is carried out ..................... 6
3.1.1 Casing......................................................................................................................................................... 6
3.1.2 Casing cement ........................................................................................................................................ 6
3.1.3 Wellhead tree ........................................................................................................................................... 7
3.1.4 Measuring instrumentation .................................................................................................................. 7
3.1.5 Mud pit or water storage reservoir.................................................................................................... 7
3.1.6 Allocation of safety zone during stimulation .................................................................................. 7
3.1.7 Health and safety aspect during the stimulation .......................................................................... 7
3.2 Diagnostic tools to help characterise hydraulic stimulation and the reservoir .............................. 8
3.2.1 Access to hydraulic data ...................................................................................................................... 8
3.2.2 Down-hole measurement during stimulation ............................................................................... 8
3.2.3 Tracer tests ............................................................................................................................................... 9
3.2.4 Pressure response in adjacent wells .............................................................................................. 9
3.2.5 Microseismic monitoring in real time .............................................................................................. 10
3.2.5.1 Number of seismic sensors ............................................................................................ 10
3.2.5.2 Type of sensors .................................................................................................................. 10
3.2.5.3 Velocity model .................................................................................................................... 10
3.2.5.4 Automatic location algorithm ......................................................................................... 10
3.2.5.5 Additional information from seismic data ................................................................... 11
3.2.6 Public relations and strong motion seismic sensors .................................................................. 11
3.2.7 Daily reports on stimulation and activities associated with it.................................................. 11
3.3 Hydraulic stimulation of EGS reservoirs ...................................................................................................... 11
3.3.1 In-situ characterisation of background permeability/leak off .................................................. 11
3.3.1.1 Slug test ................................................................................................................................. 11
3.3.1.2 Production test.................................................................................................................... 12
3.3.1.3 Low flow rate injection test ............................................................................................. 12
ii
3.3.2 Main hydraulic stimulation to create an EGS reservoir ............................................................ 13
3.3.2.1 Numerical modelling of an EGS reservoir ................................................................. 13
3.3.2.2 A pre-stimulation test (MINI FRAC) .................................................................................. 13
3.3.2.3 Main stimulation of the well ............................................................................................ 13
3.3.3 Reinjection test to evaluate the main stimulation ...................................................................... 14
4. Evaluation how stimulation affects reservoir performance............................................................. 14
4.1 Staged increase in flow rate for circulation ............................................................................................... 14
4.2 Increasing the energy output from the stimulated system .................................................................. 15
4.3 Likely problems with reservoir characteristics and possible solutions............................................ 15
4.3.1 Reduction of near wellbore impedance ........................................................................................ 15
4.3.2 Reduction of the reservoir impedance .......................................................................................... 16
5. Lessons learned to facilitate successful cross-over of technology between hydrothermal and EGS ........................................................................................................................................................... 16
5.1 Crossover of technology from EGS to hydrothermal ............................................................................. 16
5.1.1 Desert Peak site, in Nevada, USA (ORMAT) ................................................................................ 17
5.1.1.1 Initial proposal to US DOE (DP 23-1) ............................................................................ 18
5.1.1.2 Revised proposal to US DOE (DP 27-15) ................................................................... 19
5.1.2 Hydraulic stimulation of DP 27-15 ................................................................................................... 20
5.2 Crossover of technology from hydrothermal to EGS ............................................................................ 22
5.2.1 Geochemistry ......................................................................................................................................... 22
5.2.2 Downhole submersible pumps........................................................................................................ 23
5.2.3 High temperature wellhead and pressure control equipment ............................................. 23
5.2.4 Steam and binary power plants ...................................................................................................... 23
5.2.5 Tracer testing ......................................................................................................................................... 23
5.2.6 Production logging .............................................................................................................................. 23
6. Observations and conclusions ................................................................................................................ 24
7. Acknowledgement ...................................................................................................................................... 24
8. References.................................................................................................................................................... 25
Appendix 1 – Protocol for Induced Seismicity Associated with EGS .................................................... 29
Figures
Figure 1. Map of DPGF, Nevada, USA; faults from Faulds et al. (2003). ............................................................ 18
Figure 2. South-North geologic cross-section through DPGF; from Lutz et al. (2009). ................................ 18
Figure 3. Enlarged Map of DPGF showing the well layout and SHmax direction. ......................................... 19
Figure 4. Map-view of MEQ events in Desert Peak target area with SHmax indicated. .............................. 21
Figure 5. Summary of the stimulations at Desert Peak. .......................................................................................... 22
1
1. Introduction: purpose of this report
This report has been prepared to capture the experiences of the authors in permeability
stimulation associated with Engineered Geothermal System (EGS) creation. Some of the
experience gleaned may be of assistance in a conventional hydrothermal system setting. In the
report there is a short case study from the Desert Peak Geothermal Field (DPGF) in Nevada and
a substantial reference list at the end of the report. IEA Geothermal invited the report to be
prepared in September 2012 and has paid a small proportion of the costs involved. Ormat
Technologies Inc. have also paid some of the costs involved. Please refer to the disclaimer
because the reader must be aware that the report is the view of the authors and not that of IEA
Geothermal (IEA-GIA). IEA Geothermal trust you find the report of interest and enjoy the read.
The most desirable geothermal resources are associated with regions of the earth where
temperatures are high at shallower depth with these resources concentrated in regions of active
or geologically young volcanoes. Large quantities of heat that are economically extractable tend
to be concentrated in places where hot or even molten rock (magma) exists at relatively shallow
depths in the Earth’s outermost layer (the crust). These “hot” zones generally are near the
boundaries of the continental plates that form the Earth’s lithosphere, which is composed of the
Earth’s crust and the mantle; the uppermost solid part of the underlying denser, hotter layer.
To a large extent, the radiogenic nature of the underlying granite determines the temperature at
depth and thus the potential exploitation depth. Granite with high radiogenic material is hotter
than one with lower radiogenic content.
In a hydrothermal system meteoric water migrates from the surface via faults and other permeable
conduits to depth, picking up heat and dissolved minerals determined by the local geology, which
is stored in a hot fluid reservoir. Traditionally, these stored hot fluid zones are identified by surface
expressions, geological settings, geophysical surveys, drilled wells or a combination of these
methods. Boreholes are drilled into the permeable zones of the hydrothermal systems to extract
the hot fluid. Once the heat is extracted, cold fluid is reinjected into known local faults some
distance away in expectation that the cold fluid will be reheated finding its way back to the known
reservoir and thus form a part of the recharge of the hydrothermal system.
During exploration of hydrothermal systems, wells are drilled to identify the best permeable and
hot zones. Not all of these wells are productive and some of these dry wells (non-commercial
wells) may be used for reinjection.
The concept of EGS was developed with the understanding that there is a significant proportion
of the upper crust which is hot but not permeable enough to drain fluid from the surface and store
this as hot reservoir fluid at depth as occurs in hydrothermal reservoirs. A concept was developed
whereby artificial permeability was created or a permeable fault was identified at great depth to
allow the fluid to circulate through this system and extract the stored geothermal energy. The
original concept was developed at Los Alamos (Smith, 1975) and consisted of drilling into a flank
of a caldera at Fenton Hill, New Mexico, to access high temperature and then enhance
permeability by injecting fluid under high pressure.
The concept was replicated at the Rosemanowes site in Cornwall, UK (Garnish, 1976; Parker, 1989)
and at other sites in the world. The project at the Rosemanowes site was at a shallower depth
(2000 m depth) and was specifically designed to understand the physics of the process of
2
creating enhanced permeability in igneous rock. Apparently, the shearing of natural fractures was
the main mechanism for enhancing permeability and that understanding the geomechanics of
the site was a key to the success of this technology.
Similarly, after some years of EGS technology development, it became apparent that some of the
geological and other aspects that play a key role in a hydrothermal system can also be
transposed to an EGS system to enhance its performance and thus the economics. For example,
large faults at great depth in igneous rocks were found to be highly permeable and capable of
delivering relatively high flow rates for a sustained period (Baumgaertner et al., 2013).
This report discusses basic principles involved and technology crossover between hydrothermal
and EGS systems. One purpose is to see if the know how gained from the development of EGS
could be applied to hydrothermal systems to improve the overall production of fluid from other
wells and thus the economics of hydrothermal systems.
2. Natural conditions and critical parameters
EGS is a relatively new technology with tremendous potential for providing heat and power, as
well as helping to address the issue of reduction of CO2 in the environment. The technology is
complex and it has taken some time for a series of research projects globally to understand the
physical processes involved, develop supporting technologies such as high temperature
instrumentation, numerical models, etc. and to validate the concept. The most advanced and near
commercial scale EGS project until recently was the European EGS project at Soultz-sous-Forêts,
north of Strasbourg in France. Knowledge gained from over 30 years of research carried out at
other EGS projects formed the basis upon which this project was built (Abe et al., 1999;
Kappelmeyer and Jung, 1987; Baria et al., 1992, 1995; Baumgaertner et al., 1996, 1998). This
research has been succeeded by two commercially funded projects at Landau and Insheim in
Germany (Baumgaertner et al., 2007; Baumgaertner and Lerch, 2013) which use the knowhow
from both EGS and hydrothermal projects to create a sustainable geothermal project.
Anyone with experience of natural materials like rocks knows that there are always
imponderables that have not been really understood and indeed cannot at present be dealt with
in a fully satisfactory manner. Furthermore, geology always has a habit of presenting us with new
problems. Determination of the in-situ stress profile with depth is crucial, and major overriding
factors include the in-situ stress magnitude and direction. Geomechanics plays an important part
and even the configuration of injection and production wells is strongly influenced by this.
Some of the conditions which need to be understood and play an important part are discussed
in the sections that follow.
2.1 Shearing mechanism for enhancing in-situ permeability
Enhancement of permeability is one of the key factors in this technology, and the mechanism
used for this is important to understand. Up until 1980, the key mechanism put forward for
enhancing in-situ permeability was hydrofracking and the use of proppant to keep the newly
created fractures open. By early 1980s research at various sites (Pine and Batchelor, 1984)
confirmed that the creation of new hydraulic fractures in igneous rocks was not the dominant
process but that the shearing of natural joints, favourably aligned with the local principal stresses,
was a more important mechanism. These joints fail in shear because the fluid injection reduces
the normal stress across them, but at the same time this only marginally affects the magnitude of
3
the shear stress. The residual increase in the joint aperture (permeability) is caused by
displacement of the joint which is resting on the roughness of the asperities. This is a permanent
residual increase in permeability. The shearing mechanism allows frictional slippage to occur
before jacking (increase joint aperture) and therefore there will be a component of shearing
ahead of any “jacked” zone (Baria et al., 1985; Baria and Green, 1989).
One of the most significant outcomes of the various international research projects to date has
been this realisation that shearing on existing joints constitutes the main mechanism of reservoir
growth. This has led to a basic change in our vision of an EGS reservoir. It has led to a departure
from the conventional oil field reservoir development concepts and techniques towards a new
technology related to the uniqueness of any jointed rock mass subjected to a particular
anisotropic stress regime.
Additionally, the shearing process of natural joints may generate microseismic events, and this
can be used to monitor the progress of the development of an EGS reservoir (size and direction)
and the enhancement of permeability. Microseismic data can also be used subsequently to
characterise the joint failure properties using source parameter calculations. The use of tracers
and hydraulic data in conjunction with the microseismic data is a common method to assess the
enhanced reservoir characteristics.
2.2 Joint orientation and distribution
The distribution of joints with depth and their azimuth and inclination are critical. The orientation
of the joints in relationship to the stress field will determine to a large extent the pressure required
to stimulate the rock mass. It has been found that in a Graben setting, not only the natural joints
but also hydrothermalised faults or swarms of joints play a dominant part, as these form zones for
flows of in-situ brine under natural convection. At the Soultz site it was observed that the
hydrothermalised joints/fault played an important part and was the main hydraulic connection
between the wells and the reservoir.
2.3 Stress regime
The local stress regime (Haimson, 1978; Rummel, 1986; Batchelor, 1983) is another factor that is
critical for the creation of an EGS reservoir. The direction in which the reservoir will grow is
dependent predominantly on the orientation of the joints and their relationship relative to the
maximum principal stress direction.
Therefore, it is essential to have a critical evaluation of the stress regime at the site of operation.
This includes the magnitude, orientation and gradient of the stress with depth. Stress evaluation
can be carried out using various methods or a combination of them. Some of these methods are
a) hydrofracture stress measurement using straddle packers at various depths in the well to get
gradient and orientation, b) evaluation of borehole breakouts and drilling-induced fractures, c)
taking core samples and evaluating them in a laboratory, and d) using background natural
earthquakes to construct fault planes and thus determine stress values. The method which is
most reliable for determining the stress field with depth is the hydrofracture stress measurement
but it is the most expensive.
Both observations and numerical modelling have shown that the joints which are aligned
favourably (~22 degrees) with the maximum stress direction will shear first. As the pressure builds,
joints in other directions will start to fail as well until the pressure reaches the minimum earth’s
4
stress when a classical tensile failure will occur. If the maximum in-situ stress is in the horizontal
direction then the injected fluid will migrate ~22.5° from the maximum stress direction because
this is the least resistance for flow using shear mechanism.
In-situ stress has a strong influence on the direction of the growth of the artificially created EGS
reservoir. Examples in shallower EGS systems where the minimum principal stress was the
overburden stress, normal faulting regime (Batchelor and Pearson, 1979), it was observed that the
reservoir grew in a near horizontal direction. A number of other EGS reservoirs created in a stress
regime where the vertical stress was the intermediate stress, strike slip regime, the reservoir grew
downwards. Similarly, it was observed that in an isotropic geological environment (in welded tuff)
where there were relatively very few joints, the reservoir followed the line of least resistance, i.e.,
opening occurred against the minimum in-situ stress (GHEE project in Japan, Takahashi et al.,
1987). The stress field is one of the key factors controlling not just the creation of the reservoir
but also subsequent operations and heat extraction. For example, during a circulation period, if
a reservoir has to be operated using injection pressure near or above the minimum in-situ stress
in order to additionally dilate the fracture apertures to increase the fluid flow across the wells,
there is a good probability that runaway growth of the stimulated rock volume will occur, leading
to an undesirable increase in water losses and additional seismicity.
Examples of these behaviours are discussed below.
1. Observation on the influence of reservoir growth direction related to the in-situ stress:
Normal faulting regime (vertical stress is the minimum): reservoir development is in the horizontal to upwards direction (300 m system at Rosemanowes, Cornwall, UK: Batchelor, 1977; Fjallbacka Hot Dry Rocks Project, Sweden: Jupe et al. (1992), Le Mayet de Montagne Project: Cornet (1987); Falkenberg Project, Bavaria, Germany: Kappelmeyer and Jung (1987). Cooper Basin HDR Project, Australia: Soma et al. (2004).
2. Strike-slip regime (vertical stress is the intermediate stress): reservoir development in the horizontal to downwards direction (Rosemanowes, Baria et al., (1985)).
3. Operating reservoir close or above the minimum stress regime: high fluid losses, continuous reservoir growth and increases induced seismicity (Parker, 1989).
2.4 In-situ fluid
The in-situ fluid also plays a role in the creation of a reservoir (Gerard et al., 1997). The fluid’s
density and pressure are critical when the minimum stress is closer to the hydrostatic pressure at
reservoir creation depth, as the resulting change in the density can influence formation and
growth direction of the reservoir. For example, if fresh water (lower density) is used during the
stimulation and the in-situ fluid is brine (higher density), then there is likely to be an upwards
migration of the injected fresh water due to the critical stress state, almost certainly influencing
the direction of growth of the reservoir.
2.5 Stimulation flow rate
Water injection flow rates for classical EGS systems in tightly confined, low permeability rocks
(< 10 microdarcy, 10-17 m2) are designed to produce a network of flow connections. Any fracture
with a residual aperture greater than sub microns will transmit pressure and permit flow, even at
very low rates, provided it is part of an open and connected flow path. Increased pressure causes
the joint to widen by the elastic compression of the adjacent block, the rigid body motion of the
5
blocks surrounding the zone and by any dilation caused by shear movements. Witherspoon and
Wang (1980) have shown that the permeability of a rock joint is a function of the cube of aperture
width. This is derived from the Couette flow relationship for laminar flow between parallel plates
(see for example: Hopkirk et al., 1981).
In rocks with low intrinsic permeability of the matrix (10-21 m2, 10-3 microdarcy), joints form the only
detectable flow paths. Field measurements by Black (1979) show that permeability lies mostly
within the range 10-17-10-16 m2 (10-100 microdarcy), implying naturally occurring effective joint
apertures of 5-35 microns at around 1 m spacing. The 1 m spacing value has been based on
surface observations and borehole logging. Doubling the joint width results in an eight-fold
reduction in a pressure gradient along the joint. The stimulation process has to widen the existing
joints and thus permit pressures to be applied to regions remote from the well.
It is essential to have a minimum of three stepped flow rates during hydraulic stimulation (creation
of an EGS reservoir and preferably four if possible). The first flow rate is determined for a pressure
which is just above that required for shearing to take place at the reservoir depth followed by a
number of increased flow rates. Highest injection flow rate is determined by the expected
circulation flow. A rule of thumb is that the highest stimulation flow should be around twice the
expected flow rate for circulation.
If, right at the beginning, a rapid high flow rate injection (> 100 kg/s) is carried out, this will open
preferentially oriented joints approximately normal to the minimum principal stress and widen
joints to balance the head loss. Permeation at right angles will occur into connected members of
other families of natural joints, but the penetration of these will be small compared with the axial
extent of the reservoir. The converse situation occurs when a low flow of water, at less than joint
opening pressures, permeates in all directions along open joints in random directions.
2.6 Geology and geological faults at depth
Geology is a key parameter in the development of a hydrothermal system and in particular the
geology associated with permeable faults and structures associated with either underground
fluid storage or transport. Identifying the geology and delineating its characteristics at depth are
important for the development of a hydrothermal system. Hydrothermal fields are predominantly
in sedimentary/volcanic environments.
For a conventional EGS development, the geology is predominantly an igneous rock environment
where joint characteristics play an important part for the development of permeability. During the
early days of the development of EGS technology (1980s), there was a belief that as one gets
deeper in the igneous rock massif, the joint spacing increases, in-situ permeability decreases,
rock matrix porosity decreases and therefore the presence of faults at greater depth was most
unlikely. This has not been the case, and the data from various deep wells show the presence of
permeable faults with inexhaustible flow of in-situ fluid.
Presently, the term ‘EGS’ also encompasses the exploitation of fluid filled faults at depth with
favourable orientation within the prevailing stress field (e. g., Barton et al., 1995; Finkbeiner et al.,
1997). Experience and knowledge to date indicate that some large faults that are approximately
aligned in the maximum horizontal stress direction at depth are likely to be open and are able to
deliver large flow rates of hot fluid for power generation (e. g., Barton et al., 1997). A production
well is drilled orthogonally to intersect a large fault at depth that is striking in the direction of
6
maximum horizontal stress. Significant flow rates might be immediately achievable. If not, then
stimulations may be necessary to enhance the flow rate by decreasing the flow impedance. A
similar procedure is followed for the drilling of a second well (injection well), some distance away
(~800 m) and offset from the first fault. In planning such a strategy, it is important to recognise that
stimulation of either or both wells may be necessary to reduce the natural hydraulic impedance.
EGS projects based on this model have already been commercialised at Landau and Insheim in
Germany (Schindler et al., 2010; Teza et al., 2011). These EGS reservoirs have been producing for
around five years with no indication of reduction in the flow rate or thermal drawdown. The data
from the projects are not widely circulated due to their commercial nature.
3. Methodology and technology to improve reservoir performance
Observations and experience show that the drilled depth to access hydrothermal systems is often
significantly shallower than for EGS systems. The completion of the well and basic geological and
geomechanical information obtained in hydrothermal systems is often limited and the basic
infrastructure associated with dry or unproductive wells proposed for stimulations needs to be
assessed and possibly brought up to an acceptable standard.
A rough upper limit of operating parameters used as a reference for carrying out a stimulation in
shallow hydrothermal fields would be around 1,500 psi (~10 MPa) at the well head, a maximum
flow rate of around 2,500 gpm (~150 l/s) and a volume of around 190,000 US barrels (30,000 m3).
3.1 Infrastructure may need rectification before a hydraulic stimulation is carried out
Recommended evaluation is as follows.
3.1.1 Casing
It is imperative to assess that the casing is in good condition for it to be able to be pressurised
for hydraulic stimulation. If the well has been abandoned for a long period, the casing may have
corrosion, may have holes, collapsed sections, or may even be partially filled with debris. The
following steps are recommended:
1. Examine available records for information on casing integrity and specification.
2. Run a sinker bar to assess the accessible depth of the well.
3. Run a calliper log to check the diameter of the casing and assess if the casing can withstand hydraulic stimulation.
4. Run a low flow rate injection test in the well with flow logs to identify any leaks/holes in the casing. Use high sensitive flow impeller that can measure flows of around 0.1 l/s.
3.1.2 Casing cement
It is imperative to assess that the cementing of the casing is in a good condition for it to be able
to be pressurised for stimulation. If the well has been abandoned for a long period, the cementing
may have deteriorated. The following steps are recommended:
1. Examine existing records for cementing-related information.
2. Run a cement bond log.
7
3. Run a low flow rate injection and examine the annulus near the well head for leaks and identify any flow leaving just below the casing with flow logs. Use a sensitive flow impeller that can measure flows of around 0.1 l/s.
3.1.3 Wellhead tree
High pressure wellheads are relatively expensive and therefore in hydrothermal systems the cost
is kept down by using wellheads with relatively low operating pressure/specifications. Typically
this is around 900 psi (~6 MPa). For hydraulic stimulation the wellhead must be replaced to bring
it to a high pressure rating, but this has to be done in conjunction with the known pressure rating
of the casing. During a stimulation it is advisable to have two wellheads, one mounted above the
other. The upper wellhead is used for connecting injection pipe work. The lower wellhead is for
emergency in case the upper wellhead does not function or something is trapped within the
wellhead.
3.1.4 Measuring instrumentation
The following instrumentation mounted and tested before the injection test and maintained
during the injection period is recommended:
1. Pressure gauges need to be mounted on the wellhead to measure the injection pressure. Preferably two, in case of a failure. The pressure rating of the gauges should be higher than that of the wellhead, preferably by around 2,000 psi. Wireless sensors are preferable as this reduces accidental damage to the cable which relays the data from the sensor to data acquisition equipment.
2. Appropriate flow meters need to be installed in the injection pipe line, taking into consideration that it may be necessary to flow back the hot in-situ fluid to the surface to either relieve the reservoir pressure or carry out a production flow test after the stimulation.
3.1.5 Mud pit or water storage reservoir
Adequate storage of water is necessary (10,000 m3) for high flow rate injection. Alternatively, a
small mud pit (~600 m3) can be constructed and replenished sufficiently fast by a water supply to
cope with the injection flow rate.
3.1.6 Allocation of safety zone during stimulation
It is a good practice to cordon off areas of potential high risk with wooden stakes and bright
coloured ribbons. This is normally deployed around the high pressure pumps and well heads.
Only authorized people are allowed in the cordoned off area, such as pump operators and
geophysical loggers. All staff operating in this zone have to be kitted out with safety gear and
equipped with communication radios to report any dangerous situations that may arise.
3.1.7 Health and safety aspect during the stimulation
A staff meeting has to be organised before any hydraulic tests are carried out to make sure that
all participants are aware of the health and safety aspects and the cordoned off zone. Chain of
command is defined and appropriate measures are put in place in case there is an accident.
Trained personnel who can administer first aid must be on site. All accidents, however small, must
be recorded in the accident book. All staff entering the stimulation area must sign in and sign out
8
when they leave the site. A dedicated phone is put in place to contact emergency service in case
of any accident.
3.2 Diagnostic tools to help characterise hydraulic stimulation and the reservoir
During stimulation, various diagnostic techniques are used to help to understand and
characterise the stimulated reservoir. Some of these techniques are listed below along with
reasons for using them. It is important to stress that the majority of the data (hydraulic and seismic)
should be made available immediately (i.e., real time) in order to help in the decision making
during the stimulation, such as, whether to continue stimulation with the same flow rate, change
the flow rate or stop the stimulation.
3.2.1 Access to hydraulic data
Hydraulic data from the injection wellhead should consist of wellhead pressure, injection flow
rate, the annulus pressure and downhole pressure (a pressure tool parked just inside the casing).
All the above digitised data should be available for evaluation and plotting with real time display
so that the injection history can be viewed at a glance to help make informed decisions by a
nominated person which is normally a reservoir engineer. Additionally, wellhead pressure data
from other adjacent wells should also be available in order to assess if the injected flow is
interacting with reservoir pressure near these wells and to get some idea of the interaction of the
injected flow with the reservoir.
3.2.2 Down-hole measurement during stimulation
It is very important to know the exact pressure in the main exit flow, the percentage of flow
distribution as a function of the flow injected and the temperature variations in the open-hole
during stimulation, particularly if a well is deep. Depending on the in-situ stress regime and the
far field connectivity of the flow exits from the well, the flow proportion from a specific exit zone
may change during a hydraulic stimulation from being dominant to being a minor flow zone. It is
important to know the change in the distribution of the flow exits as this may help to define the
operating pressure during the circulation.
In a conventional hydrothermal system, it is normal to just take the wellhead pressure as the main
pressure measuring point. The actual pressure at the zone being stimulated in the well is
estimated from the wellhead pressure. Additionally, it is also common practise to use tubing
mounted inside the casing to carry out stimulation. This tubing can be significantly smaller in
diameter than the casing, increasing the friction losses during injection, and thus gives a poor
measure of the pressure exerted on the formation at depth.
During stimulation in an EGS system, a production logging tool consisting of sensitive pressure,
flow and temperature transducers, is parked just inside the casing shoe. A recording of the
changes in these parameters with depth is logged at each injected flow rate by running the tool
to the bottom and then bringing it back inside the casing shoe. This gives a measure of the
changes that might occur in the formation during stimulation at the specific flow rate.
The use of a production logging tool during stimulation requires a winch with appropriate logging
cable, a riser assembly with associated gear, a data acquisition system and an experienced
production logging engineer.
9
3.2.3 Tracer tests
Tracers are used in hydrothermal and EGS systems to characterise flow paths and flow
distribution. The use of the tracers depends on the specific stage of the development of a
reservoir.
• After the drilling of the first well, stimulation is carried out to develop the reservoir and also to assess where the second well should be drilled. It is useful to put a long resident tracer (e. g., naphthalene disulfonate) at the beginning of the stimulation. The tracer is pushed forward into the formation and to a large extent defines how far the injected fluid has migrated from the injection well. During the drilling of the second well, drilling fluid samples are taken regularly and analysed for detection of injected tracer from the first well. This is a good indicator of how far the injected fluid has migrated and the depth of flow connections associated with stimulation of the first well.
• During the initial circulation test between the two wells, a short resident tracer (e.g., naphthalene disulfonate) is injected in the injection well and samples at regular intervals are taken from the production well. The time between when the tracer was injected and recovered from the production well is called a breakthrough time and is an indicator of the quality of the direct flow paths in the reservoir. A very short resident time (quick return) means an existence of preferential flow path(s) (short circuit) which may lead to a rapid cooling of the system. Too long a breakthrough time may indicate that the hydraulic connection between the injection and the production well may suffer from higher impedance and thus high parasitic losses. In this case additional hydraulic stimulation of the system may be necessary.
• During a circulating test it is useful to carry out tracer tests periodically using short resident tracers to forecast a possible development of a preferential flow path. Breakthrough period is plotted against operating months. If the breakthrough period shortens rapidly as a function of time then there is a good probability of the development of a preferential flow path. Remedial measures can be taken to seal this path or divert the flow through other paths.
• Another characteristic of the tracer is called “modal volume”, which is an envelope of the recovery of the bulk of the injected tracer. The concentration of the tracer per unit volume recovered is measured and plotted as a function of time. A larger modal volume indicates that a larger reservoir/rock volume has been accessed and conversely, a smaller modal volume indicates that not enough rock volume has been accessed and therefore there is a potential of the system cooling down earlier than anticipated.
3.2.4 Pressure response in adjacent wells
The way the pressure migrates during stimulation is very important to get some idea on the
growth of the reservoir and also if the design of the stimulation using the selected injection
flows/pressures is appropriate. In a relatively open hydrothermal system, occasionally it may be
difficult to reach shearing pressure and therefore there is less chance of seismicity occurring
during stimulation. This makes it difficult to assess pressure migration, particularly the direction it
takes and how far it has reached. Monitoring the wellhead pressure in adjacent wells is another
method of getting some idea of the pressure migration. It is relatively inexpensive to support the
acquisition of hydraulic data from adjacent wells compared say to the design and installation of a
microseismic system.
10
3.2.5 Microseismic monitoring in real time
Microseismic monitoring during reservoir creation and subsequent circulation has become one
of the most important diagnostic methods for understanding and characterising a reservoir. It
relies on the fact that in an anisotropic stress regime, a critically aligned joint shears at a pressure
significantly below that of tensile failure. The seismic energy radiated from shearing of joints is
significantly efficient and well defined. This makes it easier to detect and locate the dislocation
of joints caused by the increase of pressure in the joint at that specific place. Automatic detection
and location of these events in real time gives the reservoir engineer an insight into what is
happening during stimulation and helps him to control the flow and the period of the stimulation.
Additionally, seismic data are also used for targeting the second well in an EGS system, and
therefore precise locations are essential to help target the second well.
In an EGS system, the generation and migration of seismicity during a stimulation indicates that
the reservoir is being stimulated and the direction of migration indicates where the injected
flow/pressure from the injection zone in the well is heading for. This is one of the methods for
determining the stimulated reservoir size and the direction of growth.
Some of the basic rules for establishing an adequate microseismic system are explained below
for guidance.
3.2.5.1 Number of seismic sensors
Six seismic stations are regarded as a minimum configuration which gives the possibility of one
station breaking down and still being able to maintain the seismic monitoring with some degree
of confidence. The geometrical layout used for seismic stations is important in terms of reducing
the systematic errors caused by poor geometry and also being able to relay the data back to the
main observation/processing location.
3.2.5.2 Type of sensors
It is important to select seismic sensors which have as low a noise figure as possible, large
inherent output, broad bandwidth (2-500 Hz), low output impedance and reliability. It is preferable
to have sensors deployed in shallow boreholes in order to improve the signal to noise ratio so
that very small events are detected.
3.2.5.3 Velocity model
It is very important to obtain a good in-situ velocity model of the rock mass in order to locate the
seismic events with good precision. This can be carried out using an explosive at the bottom of
a well and recording the arrival time or using explosive on the surface at each seismic station and
a sensor deployed at the bottom of the stimulation well.
3.2.5.4 Automatic location algorithm
Commercial software or academically-based software is available to carry out this task. It is
important to evaluate the provider and the user to see which one is suitable for the task.
11
3.2.5.5 Additional information from seismic data
Automatic location of the induced seismic event is the first priority of a seismic system but
additional properties of the failed fault can also be determined. These include source parameters
(length of fault failed, stress drop across the fault, seismic energy released, etc.) and fault plane
solution (strike of the failed joint).
3.2.6 Public relations and strong motion seismic sensors
It is imperative to establish good relations with the regional authority and the local residents. It is
essential to explain in non-technical terms what is being proposed and how it will affect them.
This needs to be done prior to the proposed stimulation and not afterwards. It is very important
to install a few strong motion seismic sensors in appropriate places to register ground
acceleration and the dominant frequency. This is to address any structural damage issues in case
a very large induced event occurs. A guideline is available from the IEA-GIA website and the
document has been appended as Appendix 1.
3.2.7 Daily reports on stimulation and activities associated with it
It is a good practice to prepare a daily report which documents the actual activity of the previous
day and the planned activity for the current day. This includes brief injection history, seismicity
generated, operational activity log, any specific difficulties and future requirements so that they
can be in place when needed. These reports can be distributed to interested parties to inform
them of activities as they are being carried out. It is also a good daily operational log which can
be accessed for future reference.
3.3 Hydraulic stimulation of EGS reservoirs
In a virgin environment, once a deep well is completed, geophysical logs will be carried out to
quantify the temperature profile, joint network data, in-situ stress profile, sonic log etc. In a high
temperature environment the well may need to be circulated and cooled before these logs can
be carried out, except for a temperature log. The only useful temperature information obtained
during drilling or just after drilling, is the bottom hole temperature, as a temperature profile will be
affected by the cooling caused by the drilling of the well. The temperature to reach the natural
equilibrium may take up to three months after the drilling is completed. Before a stimulation can
take place, a number of hydraulic tests should be carried out to characterise the in-situ
permeability, flow exits from the well and pressures at depth.
3.3.1 In-situ characterisation of background permeability/leak off
Following the assessment of the in-situ conditions from geophysical logs, small scale injection
tests will be required to assess undisturbed hydraulic properties of the open section of the well.
The quantity of water and the pressure required will depend on the state of existing flowing joints
and tightness of the formation. Estimation will need to be made on of the water requirements for
these tests.
3.3.1.1 Slug test
A slug test is normally conducted to obtain initial information about the hydraulic properties of the
undisturbed rock mass at depth after the completion of the well. By definition, a slug test is the
12
response of a well-aquifer system to an instantaneous change of the water level, i.e., a response
to an impulse in flow. This impulse excitation can be achieved by the sudden withdrawal of a
weighted float or by the rapid injection of a small volume of water.
It is normally easier to inject fresh water from a water line. The water level in the well has to be
around 30 m or deeper to allow the filling of the well. A sensitive down-hole pressure transducer
is deployed below the water level. The well is filled at about 10 l/s until the height of the water
level has increased by 15 to 20 m. After the injection, the pressure decay in the well is monitored
until it reaches a steady state. Additional tests can be carried out with increasing heights to 25 m
and 35 m to confirm or check if the initial pressure has influence on the response. To meet the
criteria for an impulse excitation it is necessary that the time required to raise the water level is
negligible. These tests are important to assess the initial hydraulic condition of the open-hole
section.
Additionally, the slug test will also give information required to design the subsequent low rate
injection test. The total amount of water used is negligible i. e. in the range of 2-5 m3.
3.3.1.2 Production test
Explanation on how to carry out a production test falls outside the brief of this report but a mention
should be made and its importance pointed out.
Production of formation fluid will yield important information about the p-t conditions in the
environment at depth for the future heat exchanger. Furthermore, the fluid chemistry and the gas
content are important parameters need to assist with the design of the pilot plant in such a way
that scaling and corrosion can be minimized. However, it is unlikely that a sufficient amount of
fluid can be produced by the natural permeability at 5-6 km depth.
A well can be put on production using buoyancy or a down-hole pump. It is preferable to use a
down-hole submersible pump where possible. A submersible pump can be deployed at a depth
of around 100-150 m. Depending on the outcome of the slug test, it is probable that the well could
produce something like 1 m3/hr. Additionally, a down-hole pressure gauge, gas sampling (or gas
trap) at the wellhead and a surface flow meter would add further information on the draw-down
characteristic of the well.
If it is planned to carry out a production test, then it will be necessary to store in-situ water which
may vary from fresh water to brine, depending on the geological setting. A storage facility of
around 450 m3 will be required at the surface if the equivalent of three wellbores of in-situ fluid
from a 4000 m deep well with 8.5” nominal diameter are produced.
3.3.1.3 Low flow rate injection test
The main objective of the low rate injection test is to determine the hydraulic properties of the
unstimulated open-hole section of the well. The derived values will be used as inputs for numeric
models, planning of the stimulation (pressure required for a stimulation), subsequently for the
assessment of the stimulation and identification of predominant flowing zones, using a
temperature or flow log.
Three or four injection tests with flow rates from around 0.2 l/s to 0.6 l/s are carried out. The flow
rate steps are carried out in sequence for around 8-10 hrs and shut-in for 12-14 hrs after each step.
13
Wellhead or (preferably) down-hole pressure (close to the casing shoe) is monitored to get the
actual pressure near the open-hole. Something like 45-50 m3 will be required to carry out these
tests (for 3 tests).
3.3.2 Main hydraulic stimulation to create an EGS reservoir
The objective of a stimulation test is to initiate shearing of joints in order to create the
enhancement of permeability and thus develop a HDR reservoir (sometimes called a heat
exchanger) at the required depth. Normally a pre-stimulation test is carried out to test that
wellhead sensors, the seismic system, down-hole PTS tool, injection pump, etc. are working
satisfactorily prior to the main stimulation test. A pre-stimulation test will also show if evaluation
(injection pressure) derived from previous tests are correct. After the stimulation, a post-fracturing
injection test is carried out to quantify the efficiency of the stimulation.
3.3.2.1 Numerical modelling of an EGS reservoir
Once the in-situ properties are obtained it is possible to make forward modelling (Wills-Richards,
J. et al. 1995 and 1996; Bruel 1997; Deb, R. and Jenny, P. 2015) of the creation of an EGS reservoir
and evaluate its properties. There are a number of numerical geomechanic models available to
scope and design stimulations (Fracsim 3D, Tough 2, (www.altcom.co.uk); AltaStim,
(www.altarockenergy.com); 3DEC, (www.itascacg.com/).
It is important to take into consideration that the models assume ideal conditions and anyone with
experience of natural materials knows that there are always imponderables that have not been
really understood and indeed cannot at present be dealt with in a fully satisfactorily manner.
Furthermore, geology always has a habit of presenting us with new problems. One of the major
overriding factors is the in-situ stress, both magnitude and direction. Geomechanics plays an
important part and even the configuration of the injection and production well is strongly
influenced by this.
3.3.2.2 A pre-stimulation test (MINI FRAC)
This test consists of injecting something like 400-600 m3 of fluid at a constant flow rate of around
5-7 l/s using either fresh water or saturated brine. Saturated brine (due its higher density) can be
useful in helping stimulation near the bottom of the well but this depends on the state of the in-
situ stress. After the pre-stimulation test the wellhead is shut-in to see how the pressure declines.
This will give some indication of the leak off or far field connectivity.
3.3.2.3 Main stimulation of the well
During the main stimulation, fresh water is injected in steps with increasing flow rates. Three to
four flow rate steps are normally used. The flow rate steps may vary depending on the leak off or
whether it is a closed system or an open system. Flow rate steps of around 30, 40, 50 and maybe
70 l/s are not unreasonable. Normally, the selected flow rate step is continued until the wellhead
or down-hole pressure reaches an asymptote showing that the far field leak-off is balanced by
the injected flow. This is feasible in a relatively open system but most observed HDR systems
have poor far field connectivity and therefore the wellhead pressure is likely to continue
increasing. In this case, injection may be carried out at 30 l/s for 24-30 hrs, 40 l/s for 24-30 hrs,
50 l/s for 24-30 hrs and 70 l/s for 3 days. The injected volume may vary between 28,000 m3 to
31,000 m3 depending on the flow and the injection period.
14
3.3.3 Reinjection test to evaluate the main stimulation
Once the reservoir reaches equilibrium, a post-stimulation test is conducted to evaluate the
enhancement in the permeability obtained during the main stimulation of the reservoir. Possible
injection flow rates would be around 7, 30, 40 and 50 l/s for about 12, 12, 24, and 12 hours
respectively. The apparent reduction in the injection pressure compared to the initial injection
pressure required for the same flow rate will give quantitative indication of the improvement in
the permeability of the stimulated rock mass. The total volume of water used for this test could
be around 7,200 m3.
4. Evaluation how stimulation affects reservoir performance
Assessment of the quality of the stimulation will depend to some degree on its application.
In a conventional EGS system based in an igneous rock environment, the stimulation is carried
out to enhance the permeability of the selected rock mass and also to find the target for the
second well to complete the circulation loop.
In a hydrothermal system, the stimulation could be used for enhancing the permeability of a dry
well so that it can be connected to the main reservoir turning a non-commercial well into a
commercial well. It is important to understand the geomechanical stress regime in the well to be
stimulated and the orientation with respect to the main reservoir if benefit is to be achieved from
the stimulation.
4.1 Staged increase in flow rate for circulation
Once a hydraulic link between the two wells has been established, a small-scale circulation loop
between the wells will need to be established. In a conventional EGS system, separation of wells
is in the range of 600 m and a good hydraulic link between the wells would show a breakthrough
time for tracer of around 4 to 6 days. The storage of injected fluid in the reservoir may increase
to accommodate a 20 l/s flow through the system. An assumption is made for the storage or
charging of the reservoir. This is associated with the lag in the production flow because of the
breakthrough time (~5 days) and an estimated 20% of the injected volume being stored in the
reservoir before the breakthrough occurs, either in dilated apertures of the joints or in the rock
matrix.
An initial starting step of 20 l/s is considered reasonable which would suggest that around 2,500
m3 will be required to initiate a circulation test. Taking a worst case scenario of losing 10% in the
formation via leak-off, this will bring the figure up to 3,000 m3 for a three-week circulation test.
Note: A separator, a heat exchanger, a heat load and water storage facility will be required to
implement this test.
This is a critical stage and in principle there should not be any need for further treatment provided
everything works to the plan and the natural conditions in the underground are favourable.
However, if the low flow rate circulation test shows that the total impedance for circulation is
greater than 0.3 MPa/l/s (or another estimated value from an economic model), then further
treatments might be needed. Data from previous hydraulic tests should be examined to see if the
higher impedance (restriction to flow) is near the wellbore or further out in the reservoir. This is
discussed in Section 4.3.
15
4.2 Increasing the energy output from the stimulated system
The circulation using around 20 l/s needs to be maintained for a few weeks. Cold water
(~30-40°C) is injected in the injection well and the recovered hot fluid (150°C or higher) passes
through a separator and then a heat exchanger to dump the heat. By maintaining the circulation,
the injected cold water helps to increase the near wellbore permeability by cooling joints and
thus increasing the aperture between the joints. Additionally, this process also takes place in the
formation between the injection and the production well and helps to increase the flow rate
between the wells.
If necessary, the flow rate through the system can be increased in small steps to recover more
energy output but care has to be taken not to increase the flow rate too quickly otherwise there
is a possibility of a development of a preferential path sometimes referred to as short circuit.
Normally, it is preferable to increase the flow rate in smaller flow steps and to allow the thermal
contraction of the joints to increase the joint aperture and allow larger flow to take place without
causing a short circuit. Microseismic (micro-earthquake (MEQ)) monitoring in real time is important
at this stage to make sure that overpressure does not create another flow path which may divert
the injected flow away from the main reservoir.
Regular tracer tests using short resident tracers (fluorescein) need to be carried out to determine
both the breakthrough time and the modal volume. If the breakthrough time and the modal
volume decrease rapidly between tests then this is an indication of the development of the short
circuit. Ideally, the breakthrough time should remain similar but the modal volume should increase
indicating that the injected water is accessing a much larger volume of the rock mass.
4.3 Likely problems with reservoir characteristics and possible solutions
If the initial circulation or hydraulic tests show that the overall hydraulic impedance is higher than
desired, this is most probably due to either flow exit restriction near the wellbore or in the main
reservoir.
If the restriction is near the wellbore then procedures described in Section 4.3.1 ought to be
implemented. If the restriction is within the reservoir then Section 4.3.2 should be implemented.
High impedance near the wellbore and in the reservoir can also be treated by other methods
such as an injection of proppant or using viscous gel.
4.3.1 Reduction of near wellbore impedance
If the hydraulic test data indicates that there is a need to improve the near wellbore impedance
to reduce the friction associated with turbulent flow in the flowing joints, then a very high flow
rate injection will need to be carried out to mobilise as many joints as possible from critically
aligned to the maximum principal stress direction. This will mean reaching injection pressures
above that of the minimum earth stress at the main flow exit depth. Experience has shown that
injection flows in the range of 75-100 l/s may help in solving this problem, but care must be taken
not to damage the cement at the casing shoe. The flow volume in the range of 2000 m3 should
suffice but this may need to be re-evaluated depending on the available data. Additionally, care
should also be taken not to damage the formation and block the well from breakouts, pieces
falling off the borehole walls, etc.
16
It is helpful to run flow logs before, during and after the hydraulic stimulation to quantify the
changes in the flow paths, identify new flow paths and the distribution of the flows with reference
to the depth of the open hole.
4.3.2 Reduction of the reservoir impedance
If the hydraulic data indicates that there is a need to improve the impedance to flow within the
reservoir due to a possible lack of connectivity between the wells, then a remedy would be to
inject in both wells simultaneously (focussed injection). Flow rates injected in each well will
depend on where the restriction is envisaged. Assuming that the overpressure to shear joints is
in the range of 2-3 MPa and the restriction is the middle of the reservoir, then an injected flow of
between 30 to 50 l/s for up to 24 hrs may be sufficient to improve the connectivity between the
wells. This is a relatively new and very efficient technique but needs to be implemented in
conjunction with real time microseismic monitoring to guide it. The total volume of water used is
estimated to be around 9000 m3.
Alternative methods to reduce a reservoir impedance are to hydraulically stimulate one well at a
time using water at much higher flow rate (>60 l/s) or use viscous fluid (~700-1000 cp) with
proppant. These techniques are widely used by the hydrocarbon industry but are relatively
expensive. Higher temperature in a geothermal environment may cause the viscous fluid to
breakdown earlier than planned thus causing screen out at the bottom of the well.
5. Lessons learned to facilitate successful cross-over of technology between hydrothermal and EGS
The most efficient way of extracting energy from the earth’s crust is through hydrothermal system
technology, but unfortunately hydrothermal resources are accessible only in restricted locations
of the earth’s land mass. On the other hand, EGS systems can potentially be engineered making
them more widely available. EGS technology is in its infancy and relatively expensive. Significantly
more experience is needed to gain confidence in the technology. Technological crossover
between hydrothermal and EGS systems in the long term will benefit both.
An example is given below (Section 5.1) of successful adaptation of EGS to a hydrothermal system
at the Desert Peak plant (Ormat Technologies, Inc. (ORMAT)), Reno, Nevada. In particular, the
geomechanic/microseismic aspects of reservoir development and underground fluid
transportation are likely of benefit to development in other hydrothermal systems.
Similarly, there are well-established working practices in hydrothermal technology which are of
potential benefit to the development of EGS technology (Section 5.2).
5.1 Crossover of technology from EGS to hydrothermal
Geomechanics plays an important part in the fluid flow within a jointed geological formation. This
was explained in the Section 2.3. A project was funded by the US Department of Energy (DOE)
in conjunction with ORMAT to evaluate if methods developed for EGS can be applied to a
hydrothermal system and to observe if it responds hydraulically in a similar fashion. If successful,
the method could be implemented at other hydrothermal fields which might benefit from some
improvement in permeability.
17
5.1.1 Desert Peak site, in Nevada, USA (ORMAT)
The site selected to carry out the experiment was the DPGF, Western Nevada, operated by Ormat
Nevada Inc., a subsidiary of ORMAT, (Faulds et al., 2003). A well layout of the site is shown in
Figure 1.
An initial industry-DOE cost-shared project evaluated the technical feasibility of developing an
EGS power generation project on the eastern side of Desert Peak (Robertson-Tait et al., 2004).
An existing dry well (DP 23-1) was the focus of the Phase I investigation, including re-interpretation
of lithology, acquisition and analysis of a wellbore image log, and conducting and analysing a
step-rate injection test. In addition, numerical modelling had been undertaken to estimate heat
recovery and make generation forecasts for various stimulated volumes and well configurations.
The target formations for hydraulic stimulation in well DP 23-1 lay below an unstable phyllite unit
which bottoms out at about 1,740 m (5,700 feet). The formations beneath this unit include a
section of Jurassic/Triassic metamorphic rocks (of which the phyllite is a part) and an underlying,
younger (Cretaceous?), massive granodiorite that intrudes the older rocks above (Figure 2, Lutz
et al., 2009). This granodiorite unit extends from 2,140 m (7,020 feet) to total depth 2,939 m (or
9,641 feet) in DP 23-1 and is likely to have considerable lateral extent.
A well bore image log obtained over a significant portion of the open hole was analysed in terms
of the distribution and orientation of natural fractures and borehole failure phenomena (tensile
fractures and breakouts). The features analysed from the image log have been used to evaluate
the orientation of the stress field and constrain the magnitude of the principal stress. These permit
an evaluation of the effects of pore pressure increase on pre-existing fractures, and, in
conjunction with lithology, mineralogy, drilling rate and geophysical log data, help to identify the
most prospective interval for stimulation. Future plans for Phase II included undertaking a
"minifrac", re-completing the well in preparation for hydraulic stimulation, and planning,
conducting, monitoring and evaluating a massive hydraulic stimulation.
18
Figure 1. Map of DPGF, Nevada, USA; faults from Faulds et al. (2003).
Figure 2. South-North geologic cross-section through DPGF; from Lutz et al. (2009).
5.1.1.1 Initial proposal to US DOE (DP 23-1)
The initial well selected to test the concept of EGS technology at Desert Peak was DP 23-1, but
there was a concern regarding its suitability. At the request of ORMAT, a review of the proposed
plan was carried out by MIL-TECH/BESTEC (MB) in 2007 and it became apparent that the well
selected for stimulation (DP 23-1) was not in the right place in relationship to other commercial
wells (injection and production wells), and it was unlikely to play any significant part in the
recovery of additional energy. Evaluation showed that all the production and injection wells are
aligned approximately in the direction of the maximum horizontal stress (Figure 3) while the
proposed well (DP 23-1) was orthogonal to the direction of maximum horizontal stress which
implied that if a stimulation was carried out in this well, the reservoir will be created parallel to the
direction to the existing hydrothermal reservoir making it unlikely that the new stimulation will play
any part in the production of additional energy from the existing reservoir.
19
Figure 3. Enlarged Map of DPGF showing the well layout and SHmax direction.
5.1.1.2 Revised proposal to US DOE (DP 27-15)
Geology pays a very important part in deciding where a well needs to be drilled in a hydrothermal
field. Following the drilling of well DP 27-15, subsequent testing indicated that the well was non-
productive. The geological evaluation showed that there was impermeable clay at the depth of
the existing hydrothermal reservoir and well DP 27-15 was non-productive.
Following the review on the effectiveness of using DP 23-1 for enhancing heat recovery from the
existing hydrothermal field, a second review was carried out by ORMAT staff and MB to select an
appropriate well for applying EGS technology (Zemach et al., 2009). A number of meetings were
held at the ORMAT’s site in Reno to interact with the scientists/engineers involved and to convey
the EGS technology and explain reasons for the selection of DP 27-15 for testing EGS technology
(Baria and Teza, 2008). Well DP 27-15is aligned correctly in relation to the maximum horizontal
stress and this was regarded as the most suitable candidate.
During the subsequent review meeting between ORMAT/Desert Peak scientific team and MB,
the view of the ORMAT/Desert Peak scientific team was that DP 27-15 was not suitable for
stimulation because of the clay deposits found near the depth of the reservoir. Consultants from
MB emphasised the importance of carrying out a low flow rate injection test in DP 27-15 and
characterising the flow exits in the well. The intent was to assess the quality of the well regardless
of the geology and not to rely on a traditional decision making process which is based entirely
SHmax = N27°E (ORMAT & GeothermEx, 2006)
20
on the geology. Following the recommendation, a low flow rate test was carried out. The results
of the test showed that there were dominant flow exits within the clay band and at the depth of
the existing hydrothermal reservoir. Therefore one of the lessons learnt was that it is important to
carry out hydraulic testing of the well to characterise the well rather than rely entirely on the
geology. It was felt that the clay band might have just been a veneer near wellbore surface
created by drilling operations (?).
The recommendation of the review panel was to use DP 27-15 as a test well to do the stimulation
instead of DP 23-1.
5.1.2 Hydraulic stimulation of DP 27-15
The well DP 27-15 well is located on the field margins around 500 m NNE of the two injection
wells DP 21-2 and DP 22-22. A low flow injection test had identified the likely zones that will
respond to stimulations. The plan was to hydraulically stimulate DP 27-15 at zones which lie at a
depth from 915 to 1,066 m (3,000 to 3,500 feet) where temperatures range from 180°C to 196°C
(355 to 385°F) (Chabora et al., 2012).
After an integrated study of fluid flow, fracturing, stress and rock mechanics, silicified rhyolite tuffs
and metamorphosed mudstones were hydraulically and chemically stimulated in DP 27-15.
An initial period (~10 days) of shear stimulation was carried out at low fluid pressures (less than
the least horizontal principal stress, SHmin) to assess if this was an effective technique for creating
higher injectivity in a hydrothermal system (Davatzes and Hickman, 2009; Hickman and Davatzes,
2010). The experiment showed that the injectivity increased only marginally and this was not a
good method of improving the injectivity. A possible explanation could be that the impedance
near the wellbore caused an appreciable pressure drop and therefore made it difficult to transmit
the required pressure into the formation to cause shear. This assessment is also supported by
the lack of induced seismicity over this injection test period.
The operation was halted on the advice of ORMAT’s consultants (MB) and the stimulation strategy
and equipment were restructured to increase pressure/flow rate to create the required injectivity.
After a wellbore clean-out, a large-volume hydraulic fracturing operation was carried out at high
pressures (exceeding SHmin) and high injection rates over 23 days to transmit fluid pressure to
greater distances from the borehole, resulting in a 4-fold increase in injectivity.
Induced microseismicity started within a few hours of injection, and locations of MEQs
demonstrated growth of the stimulated volume between well DP 27-15 and active geothermal
wells (DP 21-2 and DP 22-22) located approximately ~500 m to the SSW (Figure 4). The migration
of the seismicity from the injection well DP 27-15 towards DP 21-2 and DP 22-22 clearly
demonstrated a dominant effect of maximum horizontal stress on a stimulation and the fluid
migration path as proposed by ORMAT’s consultants, as also observed at the EGS project at
Soultz (France) and the Rosemanowes project in the UK. The seismic array had been augmented
before the final phase of high flow rate stimulation to monitor seismicity during the hydraulic
stimulation. Tracer tests also confirmed that the injected fluid had migrated from DP 27-15 to wells
from 400 m to 1,800 m (0.25 to 1.25 miles) to the SSW. Additionally it was observed that the
pressure in the injection well DP 21-2 had increased and the flow output of the overall system
had gone up, producing additional power plant output of around 2 MWe.
21
Figure 4. Map-view of MEQ events in Desert Peak target area with SHmax indicated.
Tracer tests were carried out during various stimulation stages (Rose et al., 2009). Results of the
tracer study show relatively large concentrations of the fluorescein tracer – originally injected
during the low flow rate stimulation (called shear stimulation) on September 30, 2010 – appearing
at the production well DP 74-21. This suggests that much of the tracer was still residing in the
formation and continuing to be flushed from DP 27-15 towards DP 74-21. The higher
concentrations of fluorescein observed during the high flow rate stimulation as compared to
those observed during the low flow stimulation phase, indicate that the hydraulic connectivity
between the two wells was significantly enhanced by high flow rate stimulation and that the low
flow rate stimulation (shear stimulation) was ineffective. Moreover, the rapid breakthrough of the
conservative tracer, 1,6-nds, approximately 4 days after injection also supports this conclusion.
Results of testing at the Desert Peak project to advance the commercial viability of EGS in
ORMAT’s existing geothermal fields and have demonstrated (Figure 5, Chabora et al., 2012):
• 175-fold increase in injectivity in the target formation.
• Cost-effective techniques and technologies that are transferrable.
• Adaptive, real-time approach to operations management.
Subsequent circulation tests showed that the injectivity improved slightly and then stabilised (0.63
gpm/psi) at an injection pressure of 52 bar (750 psi) as the rock near the injection well DP 27-15
was being cooled.
22
Figure 5. Summary of the stimulations at Desert Peak.
5.2 Crossover of technology from hydrothermal to EGS
Hydrothermal systems have been used for producing heat and power for over a hundred years
(Larderello, Italy ~1904) and considerable experience has been gained some of which is
applicable to the development of EGS. Some of the crossover is described below.
5.2.1 Geochemistry
Fluids in hydrothermal systems can be aggressive and extensive work has been done to manage
these problems.
One of the techniques used is to stop minerals from precipitating by keeping the circulating fluid
under pressure, stabilising the pH and reinjecting at an appropriate temperature to keep the
minerals in solution. This has been adapted to EGS systems where there are aggressive in-situ
fluids.
Another technique is to inject inhibitors using dosing pumps preventing the minerals from
precipitating. This has also been adopted in EGS systems.
On specific occasions, separators and condensers are incorporated close to power conversion
stage to extract the mineral out of the fluid before reinjecting it into the formation. This is found
not to be necessary in the current EGS systems because the mineralogy of the fluid is not similar
to some of the aggressive fluids found in hydrothermal systems.
23
In some hydrothermal plants corrosion inhibitors are used in some parts of the plant and EGS
systems have adopted this method to help reduce corrosion in the well casing.
5.2.2 Downhole submersible pumps
Some hydrothermal fields use downhole submersible pumps to enhance recovery from the
production wells. This has been adopted in EGS systems to enhance the recovery from the
formation, and the pumps (impellors) may be deployed at depths in excess of 400 m.
5.2.3 High temperature wellhead and pressure control equipment
Temperature of the production fluid in hydrothermal fields can be greater than 200°C and
equipment has been developed to cope with both the chemistry of the fluid and the temperature.
This equipment has been adapted for application to EGS.
5.2.4 Steam and binary power plants
Both steam and binary power plants were developed for converting hot fluids into power and this
has been adopted by the hydrothermal industry. The binary plant is more suitable for EGS
systems and this has been adopted for generating power.
5.2.5 Tracer testing
Various forms of tracers have been used to understand and characterise hydrothermal reservoirs.
These tracers have also been adapted for the application in EGS systems. The two common uses
are to determine the breakthrough time and the modal volume.
Breakthrough time is normally used to assess how quickly the injected fluid travels through the
reservoir to the production well. This is an indicator of preferential flow paths and the life of the
system.
Modal volume gives an indication of the size of the reservoir from which the heat is extracted. In
EGS systems, it can also be used to assess if a system is expanding due to the contraction of the
rock mass from which the heat has been extracted.
5.2.6 Production logging
Production logging consists of characterising specific properties of the well as a function of depth
using a wireline cable and truck. These properties are obtained during injection into a well, while
producing fluid from a well or in a static situation. These properties can be flow (inlet and exit from
the well), temperature and pressure. Production logging originated in the hydrocarbon industry
and it was adopted by hydrothermal industry, but the system had to have significantly higher
temperature specification (up to 250°C). EGS operators have also adopted the technology but
have increased the specifications in terms of accuracy, resolution and the depth of operation to
~5000 m depth.
24
6. Observations and conclusions
The principal findings of this report are listed as follows:
1. Technology from hydrothermal and EGS technology are interchangeable on many aspects.
2. In hydrothermal systems, the operating pressure is relatively low and plant is selected for lower pressure operation. It is important that all the well equipment, casing etc. is evaluated for high pressure operation and rectified before stimulation takes place in a hydrothermal well. Anticipated well head pressures are up to 10 MPa (~1500 psi) and flow rates to 100 l/s (~1600 gpm).
3. Understanding geomechanics and its application is beneficial to the development of hydrothermal fields and EGS reservoirs.
4. Determining the stress field (both magnitude gradient and direction) is essential.
5. Drilling new wells or developing a hydrothermal system has to take the geo-mechanics into consideration as the direction of fluid flow is very strongly influenced by the in-situ stresses.
6. Characterisation of joints in terms of spacing and orientation is very important.
7. Obtaining the basic undisturbed characteristics of the wells in terms of temperature, flow profile and geology after both well types (injection and production) are completed is essential.
8. Initial basic hydraulic characterisation of a new EGS well is essential. This entails injection at flow rate at ~ 5 l/s and carrying out temperature, flow and pressure log in the well.
9. A microseismic monitoring system with good area coverage, broad band sensitive sensors and a well defined velocity model is necessary. The system should acquire online data and produce locations in real time.
10. Hydraulic and microseismic data should be available in real time to enable the reservoir engineer to make a decision to continue or stop the stimulation.
11. It is also useful to carry out tracer studies to observe breakthrough in adjacent wells and monitor their surface pressure responses.
7. Acknowledgement
This report was supported by IEA-GIA and Ormat Technologies, Inc., Nevada, USA. The Desert
Peak EGS project was supported by the US Department of Energy, Assistant Secretary for Energy
Efficiency and Renewable Energy, under a cooperative agreement with the Golden Field Office,
DE-FC36-02ID14406 for EGS field projects. Authors would like to acknowledge the cooperation
and data provided by the Ormat Technologies team in Reno and the associated scientific team.
25
8. References
Abe, H., Niitsuma, H. and Baria, R. (1999). Hot Dry Rock/Hot Wet Rock. Academic Review: Special
Issue, Geothermics, Vol. 28, Nos. 4/5, ISSN 0375-6505, Pergamon Press.
Baria, R., Hearn, K. C. and Batchelor, A. S. (1985). Induced seismicity during the hydraulic
stimulation of the potential Hot Dry Rock geothermal reservoir. Submitted to the Fourth
Conference on Acoustic Emission/Microseismic Activity in Geology Structures and Materials,
Pennsylvania State University, October 22-24, 1985, 26 pp.
Baria, R. and Green, A. S. P. (1989). Microseismic: A Key to Understanding Reservoir Growth. In:
Hot Dry Rock Geothermal Energy, Proceedings Camborne School of Mines International Hot
Dry Rock Conference, Camborne School of Mines Redruth, UK, June 27-30, 1989, Ed. Roy
Baria, Robertson Scientific Publications, London, 1990, ISBN 1-85365-217-2, pp. 363-377.
Baria, R., Baumgaertner, J., Gerard, A., Kappelmeyer, O. (1992). HDR project at Soultz-sous-Forêts.
Geothermal Resources Council Transactions, Vol. 18, pp. 387-394.
Baria, R., Garnish, J., Baumgaertner J., Gerard, A. and Jung, R. (1995). Recent development in the
European HDR research programme at Soultz-sous-Forêts (France). Proceedings of the World
Geothermal Congress, Florence, Italy, International Geothermal Association, ISBN 0-473-
03123-X, Vol. 4, pp. 2631-2637.
Baria, R. and Teza, D. (2008). MIL-TECH UK Ltd, Report to ORMAT on Desert Peak Stimulation
proposal for DP 27-15, March 2008.
Barton, C. A., Zoback, M. D. and Moos, D. (1995). Fluid flow along potentially active faults in
crystalline rock. Geology, 23, pp. 683-683.
Barton, C. A., Hickman, S., Morin, R., Zoback, M. D., Finkbeiner, T., Sass, J. and Benoit, D. (1997).
Fracture permeability and its relationship to in-situ stress in the Dixie Valley, Nevada,
geothermal reservoir. Proceedings 22nd Workshop on Geothermal Reservoir Engineering
Stanford University, Stanford, California, January 27-29.
Batchelor, A. S. (1977). A brief survey of geothermal related studies in the United Kingdom 1977.
In: Proceedings of the 2nd NATO/CCMS Geothermal Conference, Los Alamos, June 22-24,
Section 1.21, pp. 27-29.
Batchelor, A. S. and Pearson, C. M. (1979). Preliminary studies of hot dry rock geothermal
exploitation in south west England. Trans. Inst. Min. Metall., Sec B: Appl. Earth Sci. 88, B51-B56.
Batchelor, A. S. (1983). Hot Dry Rock reservoir stimulation in the UK: an extended summary. In:
Proceedings of the Third International Seminar on the Results of the EC Geothermal Energy
Research, Munich, November 29 - December 1, pp. 681-711.
Baumgaertner, J., Jung R., Gerard A., Baria R. and Garnish, J. (1996). The European HDR Project
at Soultz-sous-Forêts: Stimulation of the second Deep Well and First Circulation Experiments.
Proceedings 21st Workshop of Geothermal Reservoir Engineering, Stanford University,
Stanford, California, SGP-TR-151, pp. 267-274.
26
Baumgaertner, J., Gerard A., Baria R., Jung R., Tran-Viet, T., Gandy, T., Aquilina, L. and Garnish, J.
(1998). Circulating the HDR reservoir at Soultz: maintaining production and injection flow in
complete balance. Proc. 23rd Workshop of Geothermal Reservoir Engineering, Stanford
University, Stanford, California, USA.
Baumgaertner, J., Menzel, H. and Hauffe, P. (2007). The geox GmbH Project in Landau - The First
Geothermal Power Plant Project in Palatinate / Upper Rhine Valley. Abstracts & Papers, First
European Geothermal Review, Geothermal Energy for Power Production, October 29-31,
2007, Mainz, Germany, p. 33.
Baumgaertner, J. and Lerch, C. (2013). Geothermal 2.0: The Insheim Geothermal Power Plant -
The second generation of geothermal power plants in the Upper Rhine Graben. Abstracts &
Papers, Third European Geothermal Review, Geothermal Energy for Power Production, June
24-26, 2013, Mainz, Germany, pp. 9-10.
Baumgaertner, J., Hettkamp, T., Teza, D., Koelbel, T., Mergner, H., Schlagermann, P. and Lerch,
C. (2013). Betriebserfahrungen mit den Geothermiekraftwerken Landau, Insheim und Bruchsal.
bbr 05-2013.
Black, J. H. (1979). Results of multiple borehole pumping tests in low permeability granite. In:
NEA/IAEA, Workshop on Low Permeability Measurements in Largely Impermeable Rock, Paris,
pp. 183-198.
Bruel, D. (1997). Heat exchange modelling using a discrete fracture network model with thermo-
mechanical interaction – evaluation of the thermal performance of the reservoir developed at
Soultz-sous-Forêts in 1996, 3rd Progress Report, JOR3-CT95-0054 European HDR
Geothermal Project, Brussels.
Chabora, E., Zemach, E., Spielman, P., Drakos, P., Hickman, S., Lutz, S., Boyle, K., Falconer, A.,
Robertson-Tait, A., Davatzes, N.C., Rose, P., Majer, E. and Jape, S. (2012). Hydraulic stimulation
of well 27-15, Desert Peak geothermal field, Nevada, USA. Thirty-Seventh Workshop on
Geothermal Reservoir Engineering Stanford University, Stanford, California, January 30 -
February 1, 2012 SGP-TR-194.
Cornet, F. H. (1987). Results from le Mayet de Montagne Project. Geothermics, 16 (4), pp. 355-374.
Davatzes, N. C. and Hickman, S. H. (2009). Fractures, stress, and fluid flow prior to stimulation of
Well 27-15, Desert Peak, Nevada, EGS Project. Proceedings, Thirth-Fourth Workshop on
Geothermal Reservoir Engineering, Stanford University, Stanford, California, February 9-11,
2009, SGP-TR-187.
Deb, R. and Jenny, P. (2015). Numerical Modeling of Flow Induced Shear Failure in Fractured
Reservoirs. Proceedings; Fourteenth Workshop on Geothermal Reservoir Engineering
Stanford University, Stanford, California, January 26-28, 2015.
Faulds, J. E., Garside, L. and Opplinger, G. L. (2003). Structural analysis of the Desert Peak - Brady
Geothermal Fields, northwestern Nevada: Implications for understanding linkages between
northeast-trending structures and geothermal reservoirs in the Humboldt structural zone. GRC
Transactions. 27, Geothermal Resources Council, pp. 859-864.
27
Finkbeiner, T., Barton, C. A. and Zoback, M. D. (1997). Relationships among in-situ stress, fractures
and faults, and fluid flow: Monterey Formation, Santa Maria Basin, California. AAPG Bulletin, 81
(12), pp. 1975-1999.
Garnish, J. D. (1976). Geothermal Energy: The case for Research in the United Kingdom. Energy
Paper No. 9, London, HMSO, 1976, 66 pp.
Gerard, A., Baumgaertner, J. and Baria, R. (1997). An attempt towards a conceptual model derived
from 1993-1996, Hydraulic operations at Soultz. In: Proceedings of NEDO International
Geothermal Symposium, Sendai, pp. 329-341.
Haimson, B. (1978). The hydrofracturing stress measuring method and recent field results. Int. J.
Rock Min. Sci. and Geomech., Abstr. 15, pp. 167-178.
Hickman, S. H. and Davatzes, N. C. (2010). In-situ Stress and Fracture Characterization for Planning
of an EGS Stimulation in the Desert Peak Geothermal Field, Nevada. Proceedings, Thirty-Fifth
Workshop on Geothermal Reservoir Engineering, Stanford University, Stanford, California,
February 1-3, 2010, SGP-TR-188.
Hopkirk, R. J., Sharma, D. and Pralong, P.J. (1981). Coupled convective and conductive heat
transfer in the analysis of Hot Dry Rock geothermal systems. In: Lewis, R. W., Morgan, K.,
Zienkiewicz, O. C. (Eds.), Numerical Methods in Heat Transfer. Wiley, Chichester, UK.
Jupe, R. J., Green, A. S. P. and Wallroth, T. (1992). Induced microseismicity and reservoir growth
at Fjallbacka Hot Dry Rocks Project, Sweden, Int. J. Rock Mech. Min. Sci. Geomech. Abstr., 29,
pp. 343-354.
Kappelmeyer, O. and Jung, R. (1987). HDR Experiments at Falkenberg/Bavaria. In: Garnish, J. (Ed.),
Proceedings of the first EEC/US Workshop on Geothermal Hot Dry Rock Technology, Brussels,
Geothermics Special Issue, Vol. 16, No 4, pp. 375-392.
Lutz, S. J., Moore, J. N., Jones, C. G., Suemnicht, G. and Robertson-Tait, A. (2009). Geological and
structural relationships in the Desert Peak geothermal system, Nevada: Implications for EGS
development. Proceedings, Thirty-Fourth Workshop on Geothermal Reservoir Engineering,
Stanford University, Stanford, California, February 9-11, 2009, SGP-TR-187.
Parker, R. H. (1989). Hot Dry Rock geothermal energy. Phase 2B final report of the Camborne
School of Mines project, Vol. 1 & 2, Pergamon Press, Oxford, UK, ISBN 0-08-037929-X.
Pine, R. J. and Batchelor, A. S. (1984). Downward migration of shearing in jointed rock during
hydraulic injections. Int. J. Rock Mech. Min. Sci., 21 (5), 1984, pp. 249-263.
Robertson-Tait, A., Lutz, S. J., Sheridan, J. and Morris, C. L. (2004). Selection of an interval for
massive hydraulic stimulation in well DP 23-1, Desert Peak East EGS Project, Nevada.
Proceedings, Twenty-Ninth Workshop on Geothermal Reservoir Engineering. Stanford
University, Stanford, California, January 26-28, 2004, SGP-TR-175.
Rose, P., Leecaster, K., Drakos, P. and Robertson-Tait, A. (2009). Tracer Testing at the Desert
Peak EGS Project. GRC Transactions, Vol. 33.
28
Rummel, F. (1986). Stress and tectonics in the upper continental crust. In: Proceedings of the
International Symposium on Rock Stress and Rock Stress Measurements, Stockholm,
September 1-3, pp. 177-186.
Schindler, M., Baumgaertner, J., Gandy, T., Hauffe, P., Hettkamp, T., Menzel, H., Penzkofer, P.,
Teza, D., Tischner, T. and Wahl, G. (2010). Successful Hydraulic Stimulation Techniques for
Electric Power Production in the Upper Rhine Graben, Central Europe. Proceedings World
Geothermal Congress, Bali, Indonesia, 25-29 April 2010.
Smith, M. C. (1975). The Potential for the Production of Power from Geothermal Resources. Los
Alamos Scientific Laboratory Report, LA-UR-73-926.
Soma, N., Asanuma. H., Kaieda H., Tezuka, K., Wyborn, D. and Niitsuma. H. (2004). Twenty-Ninth
Workshop on Geothermal Reservoir Engineering, Stanford University, Stanford, California,
January 26-28, 2004, SGP-TR-175.
Takahashi, H., Shoji, T. and Abe, E. (1987). Recent progress and future of GEEE project at Tohoku
University, Japan. In: Garnish, J. (Ed.), Proceedings of the First EEC/US Workshop on
Geothermal Hot Dry Rock Technology, Brussels, Geothermics Special Issue, Vol. 16, No. 4, pp.
375-392.
Teza, D., Baumgaertner, J., Lerch, C., Gandy, T., Hettkamp, T., Penzkofer, P., Schindler, M. and
Wahl, G. (2011). Developing and circulating a fault system in the crystalline rock for geothermal
power generation in Insheim, Germany. American Geophysical Union, Fall Meeting 2011,
abstract #S44B-03.
Willis-Richards, J., Green, A. S. P. and Jupe, A. (1995). A Comparison of HDR Geothermal Sites.
Proceedings of the World Geothermal Congress, pp. 2601-2605.
Willis-Richards, J., Wanatabe, K. and Takahashi, H. (1996). Progress toward a stochastic rock
mechanics model of engineered geothermal systems. J. of Geoph. Research, 101, B8,
17481-17496.
Witherspoon, P. A. and Wang, J. S. Y. (1980). Validity of the Cubic Law for Flow in a Deformable
Rock Fracture. Tech. Info Rep. 23, Lawrence Berkeley Laboratory, University of California,
Berkeley.
Zemach, E., Drakos, P. and Robertson-Tait, A. (2009). Feasibility Evaluation of an "In-field" EGS
Project at Desert Peak, Nevada. Geothermal Resources Council, GRC Transactions 33, pp.
285-295.
29
Appendix 1 – Protocol for Induced Seismicity Associated with EGS
30
31
32
33
34
35
36
37
38
IEA Geothermal
Executive Secretary
IEA Geothermal
C/ - GNS Science
Wairakei Research Centre
Ph: +64 7 374 8211
E: iea-giasec@gns.cri.nz