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IEA-GIA ANNEX III TASK B

Technology crossover between

Engineering Geothermal System (EGS) and hydrothermal technology

By

Roy Baria1, Joerg Baumgaertner2, Dimitra Teza2 & Ezra Zemach3

(1MIL-TECH UK Ltd, 2BESTEC GmbH, 3Ormat Nevada Inc.)

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Content List: Pages

1. Introduction: Purpose of this report 1 -2

2. Natural conditions and critical parameters

2A. Shearing Mechanism for enhancing in-situ permeability

2B. Joint orientation and distribution

2C. Stress regime

2D. In-situ fluid

2E. Stimulation flow rate

2F. Geological faults at depth

3. Methodology and technology to improve reservoir performance

3A. Infrastructure items which may need evaluation and rectification before

stimulation is carried out.

3Aa. Casing

3Ab. Casing cement

3Ac. Well-head tree

3Ad. Measuring instrumentation

3Ae. Mud pool or water storage reservoir

3Af. Allocation of safety zone during stimulation

3Ag. Health & safety aspect during the stimulation

3B. Diagnostic tools to help characterise hydraulic stimulation & the reservoir

3Ba. Access to hydraulic data

3Bb. Down-hole measurement during stimulation

3Bc. Tracer tests

3Bd. Pressure response in adjacent wells

3Be. Microseismic monitoring in real time

3Bf. Public relations and strong motion seismic sensors

3Bg. Daily reports on stimulation and activities associated with it

3C. Hydraulic stimulation of reservoirs

3Ca In-situ characterisation of background permeability/leak off

3Caa. Slug Test

3Cab. Production Test

3Cac Low flow rate injection test

3Cb Main hydraulic stimulation to create an EGS reservoir

3Cba A pre-stimulation test (MINI FRAC)

3Cbb Main stimulation of a well

3Cc Reinjection test to evaluate the main stimulation

4. Evaluation of how stimulation affected performance

4A . Stages increase in the circulation flow rate for circulation

4B. Increasing the energy output from the stimulated system

4C. Likely problems with reservoir characteristics and possible solutions

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4Ca. Reduction of near wellbore impedance

4Cb. Reduction of the reservoir impedance

5. Lessons learned to facilitate successful cross-over of technology between

hydrothermal & EGS.

5A. Crossover of technology from EGS to hydrothermal

5Aa. Desert Peak site (ORMAT)

5Aaa. Initial proposal to the US DoE (DP 23-1)

5Aab. Revised proposal to the US DoE (DP 27-15)

5Ab. Hydraulic stimulation of DP 27-15

5Ac. Brady Hot Spring site (ORMAT)

5B. Crossover of technology from hydrothermal to EGS

5Ba Geochemistry

5Bb. Downhole submersible pumps

5Bc. High temperature well head & pressure control equipment

5Bd. Steam & binary power plants

5Be. Tracer testing

5Bf. Production logging

6. Observations & conclusions

7. Acknowledgement

8. References

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1. Introduction : Purpose of this report

Geothermal resources are associated with regions of earth where the temperature is high at

shallower depth, and thus the most desirable, but these resources are concentrated in regions

of active or geologically young volcanoes. Large quantities of heat that are economically

extract-able 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). Such “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 uppermost, solid part of the underlying

denser, hotter layer (the mantle).

In a hydrothermal system, fluid migrates from the surface via faults and other permeable

conduits to a specific depth determined by the local geology and are stored as hot fluid

reservoir. Traditionally, these stored hot fluid zones are identified by surface expressions,

geological settings, geophysical surveys, drilling wells or a combination of these methods.

Boreholes are drilled in to the permeable zones of the hydrothermal systems to extract the hot

fluid. Cold fluid is re-injected into known local faults some distance away in expectation that

the cold fluid will be reheated and finds its way back to the known reservoir and thus form a

part of the recharge of the hydrothermal system.

During the exploration of a hydrothermal system, a number of wells are drilled to identify the

best permeable and hot zones. Not all of these wells are productive and therefore the random

selection of the position of the wells can be a great financial burden on the project. Some of

these dry wells (non-commercial wells) are used for reinjection but not always successful.

The purpose of this report is to see if the knowhow gained from the development of

Engineered Geothermal System (EGS) could be applied to hydrothermal system to improve

the overall production of fluid from other wells and thus the economics of a hydrothermal

system.

The concept of EGS was developed with the understanding that there is a significant

proportion of the upper crust which is hot but is not permeability enough to drain fluid from

the surface and store it as hot fluid reservoir at depth, similar to that of hydrothermal

reservoir. A concept was developed whereby an artificial permeability was created 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 M C, 1975) and consisted

of drilling in to a flank of a caldera 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 J D, 1976;

Parker R. J, 1989) and many other sites in the world. The project at the Rosemanowes site

was at a shallower depth (2000m depth) and was specifically designed to understand the

physics of the process of creating enhanced permeability in igneous rock. It became soon

clear that the shearing of natural fractures was the main mechanism for enhancing

permeability and that understanding geo-mechanic of the site was a key to the success of this

technology.

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Similarly, after some years of the development of EGS technology, it became apparent that

some of the geological and other aspects that play a key role in the development of a

hydrothermal system can also be transposed on the development of 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 to delivering high flow rate for a

sustained period.

This report discussed basic principles involved and technology crossover between

hydrothermal and EGS systems.

2. Natural conditions and critical parameters

Engineered Geothermal System (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 the European project was built (Abe et al., 1999; Baria et al., 1992, 1995;

Baumgaertner et al., 1996, 1998). This research has been superseded by two commercially

funded projects at Landau and Insheim in Germany (Dimi & Joerg References) which uses

the knowhow form both EGS and hydrothermal projects to create 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. One of the major overriding factors is the in-situ stress, both magnitude

and direction. Geo-mechanics plays an important part and even the configuration of the

injection and production well is strongly influenced by it. Some of the natural conditions

which need to be understood and play an important part are as follows:

2A. 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 the in-situ permeability was hydrofracking and the use of propant to keep the

newly created fractures open. By early 1980’s research at various sites (Pine R.J. and

Batchelor A.S., 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 principal stresses of the local stress field 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 only marginally affects the magnitude of 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 the permeability. The

shearing mechanism allows frictional slippage to occur before jacking and therefore there

will be a component of shearing ahead of any “jacked” zone (Baria R. et al., 1985; Baria R. &

Green A.S.P., 1990).

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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 progress in the shearing process during an enhancement of permeability

(stimulation) can be tracked using a microcosmic system and then the process can be

evaluated using the microseismic/tracer data.

2B. Joint orientation and distribution

The distribution of joints with depth and their azimuth is very 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 in natural convection. At the Soultz site it was observed that

the hydrothermalised joints/fault played an important part and was the main hydraulic

connections between the wells and the reservoir.

2C. Stress regime

The stress regime (Haimson B., 1978; Rummel F., 1986; Batchelor et al., 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

with the maximum principle stress direction.

Therefore, it is essential to have a critical evaluation of the stress regime at the site of

operation. This includes orientation and gradient of the magnitudes with depth. Stress

evaluation can be carried out using various methods or a combination of them. Some of these

methods are a) hydro fracture stress measurement using hydraulic straddle packers at various

depths in the well to get gradient and orientation, b) evaluation of drilling breakouts c) taking

core samples and evaluating it in a laboratory, d) using background natural earthquakes to

construct fault planes and thus stress values. One method which is most reliable for

determining the stress field with depth is the hydro fracture 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 up, joints in other directions will start to fail as well until the pressure reaches the

minimum earth’s stress when a classical tensile failure will occur. If the maximum in-situ

stress is in the horizontal direction than the injected fluid will migrate ~22.5° from the

maximum stress direction because this is the least resistance to 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 principle stress was

the overburden stress (Batchelor A.S. and Pearson C.M., 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, the reservoir grew

downwards. Similarly it was observed that in an isotropic geological environment (in welded

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Tuff) where there were relatively very few joints, the reservoir followed the line of least

resistance - i.e. opening occurred against 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 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.

Observation on the influence of reservoir growth direction related to the in-situ stress:

i. Normal faulting regime (vertical stress is the minimum): reservoir development in the

horizontal to upwards direction (300 system at Rosemanowes; Batchelor A S 1977,

Cornwall; Swedish project ??, François Cornet ??; Geodynamics ??, Cooper Basin,

Australia).

ii. Strike-slip regime (vertical stress is the intermediate stress): reservoir development in

the horizontal to downwards direction (Rosemanowes, Baria R et al 1985)

iii. Operating reservoir close or above the minimum stress regime: high fluid losses,

continuous reservoir growth and increases induced seismicity (Parker R H 1989)

2D. 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 of the direction of growth of the reservoir. For example, if fresh water is used

during the stimulation and the in-situ fluid is brine, 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.

2E. 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 flowing connections.

Any fracture with a residual aperture greater than molecular size will transmit pressure and

permit flow, even at very low rates, provided it is part of an open and connected flowpath.

Increased pressure causes the joint to widen by the elastic compression of the adjacent block,

the rigid body motion of the 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 a rock with a low intrinsic permeability of the matrix (10-21 m2, 10-3 micro Darcy), joints

form the only detectable flow paths. Field measurements by Black J.H., 1979 show that field

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.

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It is essential to have a minimum of three stepped flow rates during hydraulic stimulation

(creation of an EGS reservoir and preferable 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 normally to the minimum principal stress

and widens 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.

2F. Geology & geological faults at depth

Geology is a key parameter in the development of a hydrothermal system and in particular

the geology associated with the permeable faults and structures associated with either

underground fluid storage or transport. Identifying the required geology and delineating its

characteristic at depth are important for the development of hydrothermal ssystem.

Predominantly hydrothermal fields are in sedimentary/volcanic environment.

For a conventional EGS development, the geology is predominantly in an igneous rock

environment where joint characteristics play an important part for the development of

permeability. During the early days of the development of the EGS technology (1980’s),

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 (References ??).

Presently, the term ‘EGS’ now 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 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 method is used to drill a second well (injection

well) some distance away 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 (www.geox-gmbh.de/en). The EGS

reservoir has been producing for around five years with no indication of reduction in the flow

rate, or thermal drawdown. The data from the project is not widely circulated due to the

commercial nature of the project.

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To a large extent, the radiogenic nature of the granite determines the temperature at depth and

thus the exploitation depth. Granite with high radiogenic material is hotter than one with

lower radiogenic material.

3. Methodology and technology to improve reservoir performance

Observations and experience show that the depth drilled in hydrothermal systems is

significantly shallower than that for EGS systems. The completion of the well and basic

geological and geo-mechanic information obtained in hydrothermal systems is relatively

limited. Basically this is due to the site being sold on to new owners a number of times and

therefore the details and specifications are lost. Additionally, hydrothermal exploitation is a

commercial operation and to make it commercially viable, sometimes, materials and other

operations are carried out with very limited budget and long term reliability may not be a

primary goal. Therefore, the basic infrastructure associated with dry or unproductive wells

proposed for stimulations needs to be assessed and brought up to an acceptable standard, if

necessary. 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), a

maximum flow rate of around 2,500 gpm ( ~150 l/s ) and a volume of around 190,000 US

barrels (30,000 m3) (check these figures).

3A. Infrastructure items which may need evaluation and rectification before stimulation

is carried out are as follows:

3Aa. Casing.

It is imperative to assess that 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 casing may

have corrosion, hole in the casing, collapsed section in the casing and may even be partially

filled up with debris.

I. It is imperative to examine existing records for this information on its integrity

and specification

II. Run a sinker bar to assess how deep is the well is open to

III. Run a calliper log to check the diameter of the casing.

IV. 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.

3Ab. Casing cement.

It is imperative to assess that the cementing of the casing is in a good condition to be able to

be pressurised for stimulation. If the well has been abandoned for a long period, the

cementing may have deteriorated.

I. It is imperative to examine existing records for this information

II. Run a cement bond log.

III. 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

high sensitive flow impeller that can measure flows of around 0.1 l/s

3Ac. Well-head tree

High pressure well heads are relative expensive and therefore in a hydrothermal system the

cost is kept down by using ones with relatively low operating pressure. Typically this is

around 900 psi (~6 MPa). It will be necessary to change the well head to bring it to a high

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pressure rating but this also depends on the pressure rating of the casing. During stimulation

it is preferred to have two well heads, one mounted above the other. The upper wellhead is

used for connection of injection pipe work. Lower well head is for emergency in case the

upper wellhead does not function or something is trapped within the well head. The well head

assembly has to be anchored soundly to the platform using tie bars so it does not vibrate or

move up if there is a failure of the cement.

3Ad. Measuring instrumentation

The following instrumentation needs to be mounted and tested before the injection test and

maintained during the injection period.

I. Pressure gauge needs to be mounted on the well head to measure the injection

pressure. Preferably two, in case of a failure. The pressure rating of the pressure

gauge should be higher than that of the well head, preferably by around 2,000 psi.

Wireless sensors are preferable as this reduces accidental damage to the cable or cold

tubing which relays the data from the sensor to a data acquisition room.

II. Appropriate flow meter needs to be installed in the injection pipe line, taking in to

consideration that it may be necessary to flow back the hot in-situ fluid to the surface

to either relive the reservoir pressure or carry out a production flow test after the

stimulation.

3Ae. Mud pool or water storage reservoir

Adequate storage of water resource is necessary (10,000 m3) if high flow rate injection is

necessary. Alternatively, a small mud pool (~600 m3) is constructed and the pool is

replenished to cope with the injection flow by a water supply pipe.

3Af. Allocation of safety zone during stimulation

It is a good practice to cordon off area of potential high risk with wooden stakes and bright

coloured ribbons. This is normally deployed around the high pressure pumps and well heads.

Only nominated people are allowed in the cordon off area such as pump operators and

geophysical logging. All staff operating in this zone has to be kitted out with appropriate

safety gear and to make sure that appropriate communication radios are provided to report

any dangerous situation that may arise.

3Ag. Health & safety aspect during the stimulation

A staff meeting has to be organised before any hydraulic tests are carried out to make sure

that they are aware of the danger and the cordoned off zone. Chain of responsibility is

defined and appropriate measures are put in place in case there is an accident. A trained staff

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 when

they leave the site. A dedicated phone is put in place to contact emergency service in case of

any accident.

3B. Diagnostic tools to help characterise hydraulic stimulation & 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 and reasons

for using them. It is important to stress that the majority of the data (hydraulic & seismic)

should be made available immediately 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.

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3Ba. Access to hydraulic data

Hydraulic data from the injection wellhead may consist of the well head 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 without

stopping or crashing the system. There should a display of these data on a large screen in real

time so that the injection history can be viewed at a glance to help make faster decision.

Additionally, well head 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

get some idea of the interaction of the injected flow with the reservoir.

3Bb. Down-hole measurement during stimulation

In it very important to know what is the exact pressure in the main exit flow, the flow

distribution as a function of the flow injected and the temperature variations in the open-hole

during stimulation, particularly if the 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 specific

exit zone may change 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 find out define the

operating pressure during the circulation.

In a conventional hydrothermal system, it is normal to just take the well head pressure as the

main pressure measuring point. The actual pressure at the zone being stimulated in the well is

estimated from the well head pressure. Additionally, it 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 and thus increases 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 a sensitive

pressure, flow and temperature transducers, is parked just inside the casing shoe. A recording

of the changes in the 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

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 needs a winch with appropriate

logging cable, a riser assembly with associated gear, a data acquisition system and an

experienced logging engineer.

3Bc. Tracer tests

The use of tracers is extensively used in hydrothermal and EGS systems to characterise the

flow paths and flow distribution. The use of the tracers depends on 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 drilled. It is useful to put a long

resident tracer at the beginning of the stimulation. The tracer is pushed forward in to

the formation and to a large extent defines how far the flow has migrated to from the

injection well. During the drilling of the second well, drilling fluid samples are taken

regularly and analysed for the injected tracer in the first well. This is a good indicator

of how far the injected fluid has migrated to and at what depth are these flow

connections associated with the stimulation of the first well.

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During the initial circulation test between the two wells, a short resident tracer is

injected in the injection well and samples at regular intervals are taken form the

production well. The time taken 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 quick return means an

existence of preferential flow path (short circuit) which can lead to the cooling of the

system. Too long a breakthrough may indicated that the hydraulic connection between

the injection and the production well is poor 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 system 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 than there is a good probability of the

development of a preferential flow path. Remedial measure can be taken to seal this

path or divert the flow though 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 the 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.

3Bd. 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 injections

flow/pressure 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 the pressure migration, in particularly the

direction it takes and how far it has reached. Monitoring the well head pressure in adjacent

well is another method of getting some idea of the pressure migration. It is relatively cheap

and very helpful to support the data observed from seismicity.

3Be. Microseismic monitoring in real time

Microseismic monitoring during reservoir creating and subsequent circulation has become

one of the most important diagnostic methods for understanding and characterising a

reservoir. It is relies on the fact that in an anisotropic stress regime, it is easier to shear a

critically aligned joint at a pressure significantly below that of tensile failure. The seismic

energy radiated from shear is significantly more efficient and well defined. This makes it

easier to detect and locate the source of 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 in to what happening during stimulation and

helps him to control the flow and length of the stimulation. Additionally, seismic data is also

used for targeting the second well in an EGS system and therefore precise locations are

essential to help locate the 2nd well in the correct position.

In a hydrothermal system, the generation and migration of seismicity during stimulation

indicate that the reservoir is being stimulated and the direction of migration will indicate the

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direction the injected flow/pressure is taking. This is one of the methods for determining the

stimulated reservoir size and the direction of the growth.

Some of the basic rules for establishing an adequate microseismic system are defined below

for guidance:

I. Number of seismic sensors

Six seismic stations are regarded as minimum configuration which gives a possibility of one

station breaking down and still able to maintain the seismic monitoring with some degree of

confidence. The layout of geometry used for seismic stations is important in terms of the

systematic errors caused by poor geometry and also being able to relay the data back to the

main observation/processing room.

II. Type of sensors

It important to select seismic sensor which have as low a noise figure as possible, large

inherent output, broad bandwidth (2-500 Hz), low output impedance and very reliable. It is

preferable to have the sensors deployed in shallow boreholes to improve the signal to noise

ratio on order to detect very small events.

III. Velocity model.

It is very important to obtain a good in-situ velocity model of the in-situ 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 record the arrival time or using explosive on the surface at each

seismic station and a sensor deployed at the bottom of the stimulation well.

IV. Automatic Location Algorithm.

A number of commercial software or academically based software is available to carry out

this task. It is important that a basic research on the provider and the user to see if it what one

wants.

V. 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 are source parameters

(length of fault failed, stress drop across the fault, seismic every released etc) and fault plane

solution (strike of the failed joint).

3Bf. Public relations and strong motion seismic sensors

It is imperative to establish a good relation with the regional authority and the local residents.

It is essential to explain to them 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 few strong motion seismic sensors in appropriate places to register ground acceleration

and the dominant frequency. This is to address any structural damage issues to local

properties in case a very large induced event occurs. A guide line is available for IEA/GIA

website & publications (http://iea-gia.org/wp-content/uploads/2014/01/Protocol-for-Induced-

Seismicity-EGS_GIA-Doc-25Feb09-ed9Mar10.pdf)

14

3Bg. 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 included belief 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 activates being carried out. It is also a good way keeping

daily operational log which can be accesses in the future for reference.

3C 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 anything up to 3 months after the

drilling is completed. Before a stimulation can take place, a number of hydraulic tests will

need to carry out to characterise the in-situ permeability, flow exits from the well and

pressures at depth.

3Ca 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 be made on the

requirement of the water for these tests.

3Caa. 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 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 eg 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 30m 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 around 10 l/s until the

height of the water level has increased by around 15 to 20m. 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 25m and 35m 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 2-5m3.

15

3Cab. Production Test

An explanation to carry out a production test falls outside the brief of this report but it was

felt that a mention should be made and its importance pointed out.

A 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 to design the pilot plant in such a way that scaling

and corrosion can be minimized. However, it is unlikely that a sufficient amount of fluid

could be produced by the natural permeability at 5-6km depth.

A well can be put on production by using a buoyancy effect 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 100-150m. Depending on the outcome of the slug test, it is

probable that the well could produce something like 1m3/hr. Additionally, a down-hole

pressure gauge, gas sampling (or gas trap) at the wellhead and a surface flowmeter 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 have some water

storage facility to store the in-situ water which may vary from fresh water to brine, depending

on the geological setting. A storage facility of around 450m3 will be required at the surface if

one produces three wellbore full of in-situ fluid from a 4000m deep well with 8.5” nominal

diameter.

3Cac. Low flow rate injection test

The main objective of the low rate injection test is to determine the hydraulic properties of

the un-stimulated 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

injections are carried in sequence for around 8-10 hrs and shut-in for 12-14 hrs after each

step. 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

these tests (for 3 tests).

3Cb. Main hydraulic stimulation to create an EGS reservoir

The objective of the 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 all

wellhead sensors, seismic system, down-hole PTF tool, injection pump etc are working

satisfactorily prior to the main stimulation test. A pre-stimulation test will also show if

evaluations (injection pressure) derived from previous tests were correct. After the

stimulation, a post-fracturing injection test is carried out to quantify the efficiency of the

stimulation.

3Cba 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 1996; Bruel 1997; Deb, R. & Jenny, P. 2015) of the creation of an EGS

reservoir and evaluate its properties. There are a number of numerical geo-mechanic models

16

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 in to consideration that the models assume ideal conditions and 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. 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.

3Cbb. A pre-stimulation test (MINI FRAC)

This test consists of injecting something like 400-600m3 of fluid at a constant flow rate of

around 5-7 l/s. One can use either fresh water or saturated brine. Saturated brine can be very

useful in helping stimulation near the bottom of the well but this will 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.

3Cbc Main stimulation of the a 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 step of injected flow rate 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 system 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 28,000m3 to 31,000m3 depending on the flow and the injection

period.

3Cc Reinjection test to evaluate the main stimulation

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, 12 hrs. 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 7,200m3.

4. Evaluation how stimulation affects reservoir performance

To assess the quality of the stimulation will depend on it’s application to some degree. In a

traditional EGS system 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, this type of stimulation could be used for enhancing the

permeability of dry well so that it can be connected to the main reservoir and thus turning a

non-commercial well to a commercial well. It is very important to make sure that the

17

proposed dry well is oriented in the right direction to the main reservoir using the geo-

mechanical data.

4A. Staged increase in the circulation flow rate for circulation

Once a hydraulic link between either the two wells has been established, a small-scale

circulation loop between the wells will need to be established. In a traditional EGS system,

separation of wells are in the range of 600m and a good hydraulic link between the wells

would show a breakthrough time for a tracer of around 4 to 6 days. The storage of injected

fluid in the reservoir may increase to accommodate 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 (~5days) and an estimated 20%

of the injected volume before the breakthrough occurs could be stored in the reservoir, 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

2600m3 will be required to initiate a circulation test. Taking a worst scenario of losing 10%

in the formation via leak off, this will bring the figure up to 3,600m3 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. But if the above low flow rate circulation test shows that the total impedance for

circulation was above 0.3 MPa/l/s (or another estimated from an economic model) then

further treatments might be needed to improve this. Data from previous hydraulic tests will

need to 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 chapter 4c.

4B. Increasing the energy output from the stimulated system

The above 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 well bore 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 to fast to 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 monitoring 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.

18

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 sort circuit. Ideally, the breakthrough time should remain similar but the modal volume

should increase indicating that the injected water is accessing much larger volume of the rock

mass.

4C. 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 hydraulic tests show that there is a restriction near the wellbore then proposal in chapter

4Ca ought to be implemented. If the restriction is deeper in the reservoir then proposal in

chapter 4Cb will need to be implemented. The problem of 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 etc.

4Ca. 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 a 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 sigma max direction. This will mean reaching injection

pressure above that of the sigma mean value at 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 2000m3 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.

It is very 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.

4Cb. 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 proposed method

to improve this could 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 over pressure to shear joints is 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 relatively a new and very efficient

technique but needs to be implemented in conjunction with a real time microseismic

monitoring to guide it through. Total volume of water used is estimated to be around

9000m3.

Alternative methods are to inject in one well at a time with much higher flow rate (>50 l/s) or

the use of viscous fluid (~700 - 1000 cp) and mobilise propant into the formation to improve

the flow impedance. This technique is widely used by hydrocarbon industry but is relative

19

expensive and the higher temperature in a geothermal environment may make the viscous

fluid to breakdown earlier than planned thus causing the screen out at the bottom of the well.

5. Lessons learned to facilitate successful cross-over of technology between

hydrothermal & EGS

A hydrothermal method is the most efficient way of extracting energy from the earth’s crust

but unfortunately it is not always accessible in the major part of the earth’s land mass.

Additionally, areas with a potential for hydrothermal system may also have possibility of

generating larger natural earthquakes and this could become a problem if these systems are

located closer to highly density populated areas. On the other hand EGS type of systems can

be engineered in significantly larger part of the land mass and thus make it more widely

available. Unfortunately this technology is still in its infancy and therefor relative expensive

and significantly more experience needs to be built up. It is essential that a technological

crossover takes place between hydrothermal and EGS systems which in a long term will

benefit both.

An example is give below (5A) using the successful implementation of EGS knows to a

hydrothermal system at Desert Peak plant (ORMAT Technologies) near Reno in Nevada. In

particularly, the geo-mechanics/microseismic aspects to reservoir development and

underground fluid transportation are of extreme benefit to the future development of

hydrothermal systems.

One of the objectives of this report is to show that there are some unsuccessful procedures

and practice used in the past, both in hydrothermal & EGS, which are not reported because of

the embarrassment or poor decisions but it is felt these needs to made public because one

learns by mistakes and if these are not reported than there is good probability of it to be

repeated again.

Similarly, there are well established working practices in hydrothermal technology which are

of great benefit to the development of EGS technology (Chapter 5B)

5A Crossover of technology from EGS to hydrothermal

Geo-mechanics plays an important part in the fluid flow in a jointed matrix geological

formation. This was explained in the chapter 2C. A project was funded by the US DoE in

conjunction with ORMAT technologies to test this hypothesis and to see if this observed

behaviour in the development of EGS can be implemented in a known hydrothermal field.

5Aa. Desert Peak site, Reno in Nevada, USA (ORMAT)

The site selected to carry out the experiment was the Desert Peak Geothermal Field (DPGF)

of western Nevada and operated by Ormat Nevada Inc (Faulds et al 2003; Figure 1) and the

enlarged view of the site is shown in Figure 2.

An initial industry-DOE cost-shared project was started to evaluate the technical feasibility of

developing an EGS power generation project on the eastern side of the Desert Peak

geothermal field (Ann Robertson-Tait et al 2004 & 2006). An existing well (DP 23-1) was

the focus of much of the Phase I investigation, including re-interpretation of lithology,

acquisition and analysis of a well bore imaging log, and conducting and analysing a step-rate

injection test. In addition, numerical modelling has been undertaken to estimate heat recovery

and make generation forecasts for various stimulated volumes and well configurations.

20

Figure 1. Map of Desert Peak Geothermal Field, Nevada, USA; faults from Faulds et al (2003).

Figure 2. Enlarged Map of Desert Peak Geothermal Field showing the well layout & SHmax direction

SHmax = N27°E (ORMAT & GeothermEx, 2006)

21

The target formations for hydraulic stimulation in well DP23-1 lay below an unstable phyllite

which bottoms 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

(lutz et al, 2009: Figure 3). This granodiorite unit extends from 2,140 m (7,020 feet) to TD

(2,939 m or 9,641 feet) in DP23-1 and is likely to have considerable lateral extent. A well

bore image log obtained over a significant portion of the open hole has been 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 magnitudes of the principal

stresses. These analyses 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, have been used to identify the most prospective interval for stimulation.

Future plans for Phase II include undertaking a "minifrac," re-completing the well in

preparation for hydraulic stimulation, and planning, conducting, monitoring and evaluating a

massive hydraulic stimulation.

5Aaa. 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 it’s suitability. At the request of ORMAT, a review of the

proposed plan was carried out by the EGS consulting company (MIL-TECH/BESTEC) in

2007 and it became apparent that the well selected for stimulation (DP23-1) was not in the

right place in relationship with other commercial wells (injection & 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 (Fig 2) while the proposed well (DP23-1) 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 in parallel to the direction to the existing hydrothermal

reservoir and it is unlikely that the new stimulation will pay any part in the production of

additional energy for the existing reservoir (Need Reference???).

Figure 3. South-North geologic cross-section through Desert Peak Geothermal Field; from Lutz et al (2009).

22

5Aab. 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 the well and subsequent testing indicated that

27-15 was a non-productive well. The geological evaluation showed that there was clay at the

depth of the existing hydrothermal reservoir. Clay is impermeable material and therefore the

well 27-15 was discarded as a useful well.

Following the conclusion of the review on the effectiveness of using DP 23-1 for enhancing

recovery from the existing hydrothermal field, a second review was carried out on the Desert

Peak in 2007 by Ormat staff & their consultants (MIL-TECH/BESTEC) to select an

appropriate well for applying the EGS technology to a hydrothermal field (Zemach et al

2009) . A number of meetings were held at the ORMAT’s site in Reno to interact with the

scientist/engineers involved and to convey the EGS technology and explain reasons for the

selection of the well 27-15 for testing the crossover of technology (Baria & Teza, 2008). The

well 27-15 is 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/DP scientific team and MIL-

TECH/BESTEC (M & B), the view of the Ormat/DP scientific team was that 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 to characterising the flow exits in the well to assess the quality of the

well regardless of the geology and not to rely on traditional decision making process which is

based entirely 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 well bore surface.

The recommendation of the review panel was to use DP 27-15 as a test well to do stimulation

instead of DP 23-1.

5Ab. Hydraulic stimulation of DP 27-15

The well DP 27-15 well is located on the margins of the operating geothermal field at Desert

Peak around 500m NNE of the two injection wells 21-2 & 22-22. A low flow injection test

had identified the likely zones that will respond to stimulations. The plan was to hydraulically

stimulate 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), (Ethan Chabora et al 2012).

An integrated study of fluid flow, fracturing, stress and rock mechanics, silicified rhyolite

tuffs and metamorphosed mudstones were hydraulically and chemically stimulated in Desert

Peak well 27-15 as part of an Enhanced Geothermal System (EGS) project.

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 high injectivity in a system (Davatzes et al 2009; Hickman et al 2010). The

experiment showed that the injectivity increased only marginally and this was not a good

method of improving the injectivity of a well. A possible explanation for not attaining higher

23

injectivity could be that the impedance near wellbore caused an appreciable pressure drop

and therefore made it difficult to transmit the required pressure in to the formation to cause

shear and thus improve the injectivity. This assessment is also supported by the lack of

induced seismicity over this long injection test.

The operation was halted on the advice of ORMAT’s consultants (MIL-TECH & BESTEC)

and the stimulation strategy and equipment was 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 promote fluid pressure transfer to greater distances from the borehole, resulting in an

additional 4-fold increase in injectivity.

Induced microseismicity started within few hours of injection and locations of micro

earthquakes demonstrated growth of the stimulated volume between well 27-15 and active

geothermal wells (21-2 & 22-22) located approximately ~500m to the SSW (figure 3). The

migration of the seismicity from the injection well 25-15 towards 21-2 7 22-22 clearly

demonstrates a dominant effect of maximum horizontal stress on a stimulation and the fluid

migration path as proposed by Ormat’s consultants and observed at the European EGS

project at Soultz (France) and the Rosemanowes project in the UK. The seismic array has

been augmented and a final phase of high flow rate stimulation. Tracer tests also confirmed

that the injected fluid had migrated from 27-15 to wells from _400m to 1,800m (0.25 to 1.25

miles) to SSW. Additionally it was observed that the pressure in the injection well 21-2 had

increased and the flow output of the overall system had gone up, giving additional power of

around 2MWe.

Figure3. Map-view of MEQ events in Desert Peak target area with S

Hmax indicated.

Tracer test 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 74-21. This suggests that much of the tracer was still

residing in the formation and continuing to be flushed from 27-15 towards 74-21. The higher

concentrations of fluorescein observed during the high flow rate stimulation as compared to

24

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 (called 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 (Ethan et al 2012; figure 4) project to advance the

commercial viability of EGS in Ormat’s existing geothermal fields and have demonstrated:

• 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 test showed that the injectivity was improving slightly and then

stabilised (0.63 gpm/psi) at an injection pressure of 52 Bar (750 psi) as the rock near the

injection well 27-15 was being cooled.

Figure 4: Summary of the stimulations at Desert Peak

5Ac. Brady Hot Spring site (ORMAT) ????

Brady Hot spring is adjacent to the Desert Peak site and therefore the assumptions are that the

stress regime will be very similar.

25

5B. Crossover of technology from hydrothermal to EGS

Hydrothermal systems for producing heat & power have existed for over a hundred years

(Larderello, Italy~1904) and a considerable experience have been gained which is filtered in

to the development of EGS. Some of the cross over is described below:

5Ba Geochemistry:

Fluids in hydrothermal systems can be very aggressive and extensive work has been done to

deal with these problems.

One of the techniques used is to stop the minerals from precipitating by keeping the

circulating fluid under pressure, stabilising the pH and reinjection at an appropriate

temperature to keep the minerals in solution. This has been adapted to EGS systems where

there are aggressive in-situ fluids and needed to be kept in solution.

Another technique is to inject inhibitors using dousing pumps and thus stop the minerals form

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 re-injecting it into the formation. This is

found not 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.

Significant proportion of hydrothermal plants has a high concentration of chlorides and this

would damage the casing/pumps etc over a long period. One of the solutions to overcome this

is by injecting corrosion inhibitors. EGS systems have adopted this method to help reduce

corrosion in the casing.

5Bb. Downhole submersible pumps

Many of the hydrothermal fields use downhole submersible pumps to enhance recovery from

the production well. This has been adopted in EGS systems to enhance the recovery from the

formation but the pumps (impellors) may be deployed at depth in excess of 400m.

5Bc. High temperature well head & pressure control equipment

Temperature of the production fluid in hydrothermal fields can reach fairly high (200º C plus)

and equipment has been developed to cope with both the aggressivity of the fluid and high

temperatures. This equipment has also been adapted for the application for EGS as well.

5Bd. Steam & binary power plants.

Both steam and binary power plants were developed for converting hot fluids into power and

this has been adopted by hydrothermal industry. The binary plant is more suitable for EGS

systems and this has been adopted for generating power.

5Be. 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 find the breakthrough time and the modal volume.

26

Breakthrough time is normally used to assess how quickly the injected fluid travels the

reservoir and reached the production well. This is an indicator of the development of

preferential flow paths and the life of the system.

Model 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.

5Bf. Production logging

Production logging consists of charactering specific properties of the well as a function of

depth using a wireline cable and truck. These properties are obtained during an injection in to

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. One suspects that the 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 250ºC). EGS

have also adopted the technology but have increase the specifications in terms of accuracy,

resolution and the depth of operation to ~5000m depth.

6. Observations & conclusions:

1. Technology from hydrothermal & EGS technology are interchangeable on many

aspects and should be encouraged.

2. In hydrothermal systems, the operating pressure is relatively low and therefore

everything is selected for lower pressure operation to minimise the cost of the well. It

very important that all the equipment, casing etc is evaluated for high pressure

operation and rectified before stimulation takes place in a hydrothermal well.

3. Understanding of geo-mechanics and its application is beneficial to the development

of hydrothermal fields & EGS plants.

4. Determining the stress field (both magnitude gradient & direction) is essential.

5. Drilling new wells or developing a hydrothermal system has to take the geo-

mechanics in to consideration as the direction of fluid flow is very strongly influenced

by the in-situ stresses.

6. Characterisation of joints in terms of spacing & orientation is important

7. Obtaining the basic undisturbed characteristic of the well in terms of temperature,

flow profile and geology after the well is completed is essential.

8. Initial basic hydraulic characterisation of a new 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. It is important to assess that the wellhead, casing, cement and the well is suitable for

stimulation. Anticipated well head pressure & flow rate can be up to 10 MPa (~1500

psi) and 100l/s (~1600 gpm)

10. A microseismic monitoring system with good area coverage, broad band sensitive

sensors and well defined velocity model is necessary. The system should be able to

acquire online data and produce the locations in real time.

11. Hydraulic and microseismic data should be available in real time to reservoir engineer

to make a decision to continue or stop the stimulation

12. It is also useful to carry out tracer study to see a breakthrough in adjacent wells and

monitor surface pressure response at wellhead.

27

7 Acknowledgement:

This report was supported by IEA/GIA committee and Ormat technologies, Nevada USA.

The Desert Peak EGS project is supported by the U.S. Department of Energy, Assistant

Secretary for Energy Efficiency and Renewable Energy, under a cooperative agreement with

Golden Field Offices, DE-FC36-02ID14406 for EGS field projects.

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31

Appendix A: Details of well DP23-1

Basic Data from Well DP23-1Well DP23-1 was completed in May 1979 with a 13-3/8-inch production casing from the surface to 90S m (2,9S0 feet). Below this is a 12-1!4-inch open hole to 1,613 m (5,292 feet), an S-1!2-inch open hole to 2,445 m (S,022 feet) and a 7-7/S-inch open hole to TO (2,931 m or 9,641 feet), Circulation losses occurred while drilling between 2,533 and 2,5S6 m (8,310 and S,485 feet) and losses continued to 2,809 m (9,215 feet). Below this depth, the drilling fluid was changed from mud to aerated water, and it is not possible to discern if or where any fluid losses occurred in this lower interval. During drilling and after completion, various attempts were made to flow test the well, sometimes with air or nitrogen assist. During testing in November 1979, the well bridged off below the 13-3!S-inch casing shoe, In December 19S4, a 9-5!S-inch liner was hung and cemented from S10 to 1,309 m (2,65S to 4,293 feet) to cover the bridging zone, The depth for the bottom of this liner was chosen on the basis of temperature (the well reaches 400'F [204'C] at 4,300 feet [1,311 mj; see Figure 2), There were no returns of drilling fluids while cleaning out bridges down to 4,60S feet (1,406 m), After setting and cementing the 9-5!S-inch liner, the bottom of the hole was cleaned out with full returns to 2,755 m (9,040 feet), and with about 95% returns below that depth, A step-out from the known productive area at Desert Peak, well DP23-1 was unable to sustain flow at commercial rates and pressures, Several flow tests were made before installing the 9-5/S-inch liner; during the November 1979 test, the well flowed unassisted, After the work over was completed, a brief injection test was conducted, While injecting at 5 barrels per minute (bpm), the wellhead pressure varied between 100 and 150 psig, The following day, the injection rate was increased to 20 bpm and the corresponding wellhead pressure was about 600 psig, A temperature survey was collected during the first injection period and is included in Figure 2 (the blue survey),

???????

Should the stimulation result in the creation of a large enough reservoir, a second and perhaps

a third well would be drilled and stimulated, and the system would be tested for several

months to determine its capacity. In Phase III, a .2-5 MW stand-alone binary power plant

would be designed and constructed at Desert Peak East, and in Phase IV, the power would be

either sold to a utility customer or used to supply the parasitic power needs of the existing

Desert Peak hydrothermal power plant.

In an open system like that experienced so far at Soultz, an HDR reservoir module will probably consist of three

wells, one injector bounded by two producers (see Gerard et al., 1997, Fig. 1C). The two production wells will

contain downhole pumps to assist production. The three wells are likely to be aligned approximately parallel to

the direction of the maximum horizontal stress