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.

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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

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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

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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

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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

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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

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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

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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

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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.

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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

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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.

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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.

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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.

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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.

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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.

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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.

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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

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Appendix 1 – Protocol for Induced Seismicity Associated with EGS

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IEA Geothermal

Executive Secretary

IEA Geothermal

C/ - GNS Science

Wairakei Research Centre

Ph: +64 7 374 8211

E: iea-giasec@gns.cri.nz