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VOL. 20, NO. 2 JUNE 1999 ISSN 0276
SMALL GEOTHERMAL
POWER PROJECTS
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GEO-HEAT CENTER QUARTERLY BULLETINISSN 0276-1084
A Quarterly Progress and Development Report
on the Direct Utilization of Geothermal Resources
CONTENTS
Small Geothermal Power Plants:
Design, Performance and Economics
Ronald DiPippo
Small Geothermal Power Project
Examples
John W. Lund and Tonya Toni Boyd
Opportunities for Small Geothermal
Power ProjectsLaura Vimmerstedt
Geothermal Small Power Generation
Opportunites in the Leeward Islands
of the Caribbean Sea
Gerald W. Huttrer
Geothermal PipelineProgress and Development Update
Geothermal progress Monitor
Page
1
9
27
30
34
PUBLISHED BY
GEO-HEAT CENTEROregon Institute of Technology
3201 Campus DriveKlamath Falls, OR 97601
Phone: 541-8851750Email: [email protected]
All articles for the Bulletin are solicited. If you wish tocontribute a paper, please contact the editor at the above
address.
EDITOR
John W. LundTypesetting/Layout - Donna GibsonGraphics - Tonya Toni Boyd
WEBSITE http://www.oit.edu/~geoheat
FUNDING
The Bulletin is provided compliments of the Geo-Heat
Center. This material was prepared with the support ofthe U.S. Department of Energy (DOE Grant No. FG01-99-EE35098). However, any opinions, findings,
conclusions, or recommendations expressed herein arethose of the author(s) and do not necessarily reflect the
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Cover Photos: Top Photograph - Fang, Thailand,
300 kWe ORMAT Energy Converter modular
unit, Electric Generation Authority of Thailand
(EGAT) (photograph by ORMAT Inc., Sparks,
NV--used with permission); and Bottom Photo-
graph - Blue Lagoon at Svartsengi, Iceland com-
bined thermal and electric power plant (16.4 MWe
total), The Sudurnes Regional Heating Corpora-
tion (photograph by Haukur Snorrason, Reykjavik,
Iceland--used with permission).
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GHC BULLETIN, JUNE 1999 1
SMALL GEOTHERMAL POWER PLANTS:
DESIGN, PERFORMANCE AND ECONOMICS
Ronald DiPippo, Ph.D.
Mechanical Engineering Department
University of Massachusetts Dartmouth
North Dartmouth, Massachusetts 02747
A BRIEF HISTORY OF GEOTHERMAL POWER
GENERATION
Ninety-five years ago, in the Tuscany village of
Larderello, electricity first flowed from geothermal energy
when Prince Piero Ginori Conti powered a 3/4-horsepower
reciprocating engine to drive a small generator. The Prince
was thereby able to light a few bulbs in his boric acid factory
situated amid the boron-rich geothermal steam field. He up-
graded the power system to 20 kW in 1905 [1].
Commercial delivery of geothermally-generated elec-
tric power occurred in 1914 when a 250 kW unit at Larderello
provided electricity to the nearby cities of Volterra and
Pomarance. Prior to being destroyed in 1944 during WorldWar II, Larderello had a total power capacity of 136,800 kW,
an annual generation greater than 900 GWh, and an average
annual capacity factor of more than 75 percent. The plants
were rebuilt after the war and extensive development of the
steam field began. Today, there are over 740 MW installed at
Larderello and the other nearby geothermal fields in the
Tuscany region of Italy. Many of the power plants are in the
15-25 MW range, qualifying them as small power plants.
New Zealand was the first country to operate a com-
mercial geothermal power plant using a liquid-dominated, hot-
water type reservoir (as contrasted with the steam-type at
Larderello). This took place at Wairakei in 1958. The United
States became the third country to use geothermal energy to
generate electricity in 1960 when the Pacific Gas & Electric
Company (PG&E) inaugurated an 11 MW Geysers Unit 1.
This small plant later earned the designation as a Mechanical
Engineering Historical Landmark. The U.S. has become the
largest generator of geothermal electricity with an installed
capacity of 2850 MW [2,3]. A summary of the state of world-
wide installed geothermal electric generating capacity is given
in Table 1 [4].
INTRODUCTORY REMARKS
The rest of this article will cover the basic geothermal
energy conversion systems with regard to their design, ther-modynamic performance, and economics. It draws heavily
on a recent encyclopedic contribution by the author to the
Second Edition of the McGraw-Hill Standard Handbook of
Powerplant Engineering [5]; the interested reader is referred
to this source for more details than can fit in this introductory
article. Although much of the contents of this article are gen-
erally applicable to geothermal powerplants of any size, the
specific characteristics of small plants will be of particular
interest.
Small power plants have played an important role in the
development of geothermal energy. Since it is not practical
to transmit high-temperature steam over long distances by
pipeline owing to heat losses, most geothermal plants are built
close to the resource. Given the required minimum spacing
of wells to avoid interference (typically 200-300 m) and the
usual capacity of a single geothermal well of 4-10 MW (with
some rare, spectacular exceptions), geothermal powerplants
tend to be in the 20-60 MW range, even those associated with
large reservoirs. Much smaller plants, in the range of 500-
3000 kW, are common with binary-type plants.
Table 1Summary of Worldwide Installed Geothermal Power
Capacity (as of 1998)
Country
United States
Philippines
Mexico
Italy
Indonesia
Japan
New Zealand
Costa Rica
El Salvador
Nicaragua
Iceland
KenyaChina
Turkey
Portugal (Azores)
Russia
Ethiopia
France (Guadeloupe)
Argentina
Australia
ThailandTotal
MW
2850
1848
743
742
589.5
530
364
120
105
70
50.6
4528.78
21
16
11
8.5
4
0.7
0.4
0.38147.78
No. Units
203
64
26
na
15
18
na
4
5
2
13
313
1
5
1
2
1
1
1
1
MW/Unit
14.0
28.9
28.6
39.3
29.4
30
21
35
3.9
152.2
21
3.2
11
4.2
4
0.7
0.4
0.3
Plant Types1
DS,1F,2F,B,H
1F,2F,H
1F,2F,H
DS,2F,H
DS,1F
DS,1F,2F
1F,2F,H
1F
1F,2F
1F
1F,2F,H
1F1F,2F,B
1F
1F,H
1F
H
2F
B
B
B
1DS=Dry Steam, 1F=Single Flash, 2F=Double Flash, B=Binary, H=HybridNote: A unit is defined as a turbine-driven generator. Data from Ref. [4] and various other sources.
DIRECT-STEAM PLANTS
Direct-Steam plants are used at vapor-dominated (or drysteam) reservoirs. Dry, saturated or slightly superheated steam
is produced from wells. The steam carries noncondensable
gases of variable concentration and composition. Steam from
several wells is transmitted by pipeline to the powerhouse
where it is used directly in turbines of the impulse/reaction
type. Between each wellhead and the plant one finds in-line
centrifugal cyclone separators situated near the wellhead to
remove particulates such as dust and rock bits, drain pots (traps)
along the pipelines to remove condensation which forms dur-
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ing transmission, and a final moisture remover at the entrance
to the powerhouse.
Figure 1 is a simplified flow diagram for a Direct-Steam
plant. A Nomenclature List at the end of the article identifies
the items in this and the ensuing flow diagrams [5]. A con-
densing plant is shown as typical of an installation in the United
States. In some countries, back-pressure, exhausting-to-atmo-
sphere operation is possible in accordance with local environ-
mental standards. Because of noncondensable gases (NCG)
found in geothermal steam (typically 2-10% by wt. of steam,but sometimes higher), the gas extraction system is a critical
plant component. Usually, 2-stage steam ejectors with inter-
and after-condensers are used, but in some cases vacuum pumps
or turbocompressors are required.
Figure 1. Simplified flow diagram for a direct-steam geo-
thermal power plant (5).
A surface-type condenser is shown but direct-contact
condensers are often used. The former is preferred whenever
the NCG stream must be treated or processed before release to
the atmosphere, e.g., whenever emissions limits for hydrogen
sulfide would be exceeded. In such cases, an elaborate chemi-
cal plant must be installed to remove the hydrogen sulfide.
Most units at The Geysers in northern California use Stretford
(or similar) systems for this purpose, yielding elemental sulfur
as a by-product. Such an elaborate system would not be eco-
nomically justified at a very small plant.A water-cooled condenser is shown. Since the steam
condensate is not recirculated to a boiler as in a conventional
powerplant, it is available for cooling tower makeup. In fact,
an excess of condensate (typically, 10-20% by wt. of the steam)
is available and is usually injected back into the reservoir.
Long-term production can deplete the reservoir and novel ways
are being developed to increase the amount of fluid being re-
turned to the reservoir [6,7]. The use of air-cooled condensers
would allow for 100% return but so far have been uneconomic.
Mechanical induced-draft cooling towers, either counterflow
or crossflow, are mostly used for wet cooling systems, but natu-
ral-draft towers are used at some plants.
Recent practice, particularly in Italy, has seen nominalpowerplant ratings of 20 or 60 MW per unit, the smaller units
being of modular design for rapid installation. Flexible design
allows the basic unit to be adapted to a fairly wide range of
actual steam conditions.
Table 2 lists major the equipment typically used in the
four basic types of geothermal powerplants [5,8].
Basic
Binary
Yes
Yes
No
Yes
No
No
No
Yes
Poss.
No
Yes
Yes
No
YesNo
Yes
Yes
Yes
Yes
No
No
No
Poss.
Poss.
Double
Flash
No (Poss.)
Yes
Yes
No
Yes
Yes
Yes
Yes
Poss.
Yes
No
Yes
Yes
NoYes
Yes
Yes
Yes
Yes (No)
Yes
Poss.
Poss.
Yes
No
Single
Flash
No (Poss.)
Yes
Yes
No
Yes
Yes
No
Yes
Poss.
Yes
No
Yes (No)
Yes
NoNo
Yes
Yes (No)
Yes (No)
No (Poss)
Yes
Poss.
Poss.
Yes (No)
No
Dry
Steam
No
Yes
Yes
Yes
Yes
No
No
No
No
Yes
No
Yes (No)
Yes
NoNo
Yes
Yes (No)
Yes (No)
No
Yes
Poss.
Poss.
Yes (No)
No
Equipment
Steam and/or Brine Supply:Downhole pumps
Wellhead valves & controls
Silencers
Sand/particulate remover
Steam piping
Steam cyclone separators
Flash vessels
Brine piping
Brine booster pumps
Final moisture separator
Heat Exchangers:
Evaporators
Condensers
Turbine-Generator & Controls:
Steam turbine
Organic vaopr turbineDual-admission turbine
Control system
Plant Pumps:
Condensate
Cooling water circulation
Brine injectionNoncondensable Gas Removal System:
Steam-jet ejectors
Compressors
Vacuum pumps
Cooling Towers:
Wet type
Dry type
Notes: Yes=generally used, No=generally not used, Poss.=possibly used under certain circumstances.
Type of Energy Conversion System
Table 2
Major Equipment Items for Geothermal Powre Plants
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GHC BULLETIN, JUNE 1999 3
DOUBLE-FLASH PLANTS
About 20-25% more power can be generated from the
same geofluid mass flow rate by using Double-Flash technol-
ogy. The secondary, low-pressure steam produced by throt-
tling the separated liquid to a lower pressure is sent either to a
separate low-pressure turbine or to an appropriate stage of the
main turbine (i.e., a dual-pressure, dual-admission turbine). The
principles of operation of the Double-Flash plant are similar to
those for the Single-Flash plant. The Double-Flash plant is,
however, more expensive owing to the extra equipment asso-
ciated with the flash vessel(s), the piping system for the low-pressure steam, additional control valves, and the more elabo-
rate or extra turbine. Figure 3 is a simplified flow diagram for
a Double-Flash plant [5]. An equipment list is given inTable
2.
Figure 3. Simplified flow diagram for a double-flash geo-
thermal powerplant [5].
BINARY PLANTS
In a Binary plant, the thermal energy of the geofluid is
transferred via a heat exchanger to a secondary working fluid
for use in a fairly conventional Rankine cycle. The geofluid
itself does not contact the moving parts of the power plant,
thus minimizing, if not eliminating, the adverse effects of ero-
sion. Binary plants may be advantageous under certain condi-
tions such as low geofluid temperatures, say, less than about
150 C (300 F), or geofluids with high dissolved gases or high
corrosion or scaling potential. The latter problems are usually
exacerbated when the geothermal liquid flashes to vapor as
typically occurs in a self-flowing production well. Downwell
pumps located below the flash level can prevent flashing by
raising the pressure above the saturation pressure for the fluid
temperature [14]. Most binary plants operate on pumped wells
and the geofluid remains in the liquid phase throughout the
FLASH-STEAM PLANTS
Dry steam reservoirs are rare, the only known major fields
being Larderello and The Geysers. The most common type of
geothermal reservoir is liquid-dominated. For artesian-flow-
ing wells, the produced fluid is a two-phase mixture of liquid
and vapor [9]. The quality of the mixture (i.e., the weight per-
centage of steam) is a function of the reservoir fluid condi-
tions, the well dimensions, and the wellhead pressure which is
controlled by a wellhead valve or orifice plate. Typical well-
head qualities may range from 10 to over 50 %.Although some experimental machines have been tested
which can receive the total two-phase flow and generate power
[10-12], the conventional approach is to separate the phases
and use only the vapor to drive a steam turbine. Since the
wellhead pressure is fairly low, typically 0.5-1.0 MPa (75-150
lbf/in2, abs), the liquid and vapor phases differ significantly in
density (rf/r
g=175-350), allowing effective separation by cen-
trifugal action. Highly efficient cyclone separators yield steam
qualities ranging as high as 99.99 % [13].
The liquid from the separator may be injected, used for
its thermal energy via heat exchangers for a variety of direct-
heat applications, or flashed to a lower pressure by means of
control valve or orifice plate, thereby generating additionalsteam for use in a low-pressure turbine. Plants in which only
primary high-pressure steam is used are called Single-Flash
plants; plants using both high- and low-pressure flash steam
are called Double-Flash plants.
SINGLE-FLASH PLANTS
A simplified flow diagram of a Single-Flash plant is
shown in Figure 2 [5].
Figure 2. Simplified flow diagram for a single-flash geo-
thermal power plant (5).
The two-phase flow from the well(s) is directed hori-
zontally and tangentially into a vertical cylindrical pressure
vessel, the cyclone separator. The liquid tends to flowcircumferentially along the inner wall surface while the vapor
moves to the top where it is removed by means of a vertical
standpipe. The design shown is called a bottom-outlet separa-
tor and is extremely simple, having no moving parts. Baffles
and guide vanes are sometimes used to improve the segrega-
tion of the two phases. A ball check valve provides insurance
against a slug of liquid entering the steam line during an upset.
The steam transmission lines are essentially the same as in the
case of dry steam plants and are usually fitted with traps.
The balance of the plant is also nearly identical to the
dry steam plant, the main difference being the much greater
amount of liquid that must be handled. Comparing 55 MW
plants, a typical Single-Flash plant produces about 630 kg/s
(5x106 lbm/h) of waste liquid, whereas a Direct-Steam plant
produces only 20 kg/s (0.16x106 lbm/h), a ratio of over 30 to
1. If all of the waste liquid is injected, a Single-Flash plant
would return to the reservoir about 85 % of the produced mass;
this should be compared with only 15% for a Direct-Steam
plant. The major equipment items for a typical Single-Flashplant are given in Table 2.
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4 GHC BULLETIN, JUNE 1999
Figure 4. Simplified flow diagram for a basic binary geo-
thermal powerplant [5].
Binary plants are particularly well suited to modular
power packages in the range 1-3 MW per unit. Standardized,
skid-mounted units can be factory-built, tested, assembled and
shipped to a site for rapid field installation. A number of units
can then be connected at the site to match the power potential
of the resource. Table 2 contains the major equipment items
for a Basic Binary plant.
If a mixture is selected as the working fluid, (e.g.,isobutane and isopentane, or water and ammonia), then the
evaporation and condensation processes will occur at variable
temperature. This characteristic allows a closer match between
the brine and the working fluid (evaporation), and the cooling
water and the working fluid (condensation), giving higher heat
exchanger efficiencies and better overall system efficiencies
[16,17]. Furthermore, if the turbine exhaust carries significant
superheat, a heat recuperator may be utilized to preheat the
working fluid [18]. Both of these features are the basis for the
Kalina version of the geothermal binary plant [19], shown sche-
COMBINED OR HYBRID PLANTS
Since geothermal fluids are found with a wide range of
physical and chemical properties (e.g., temperature, pressure,noncondensable gases, dissolved solids, pH, scaling and cor-
rosion potential), a variety of energy conversion systems have
been developed to suit any particular set of conditions. The
basic systems described in the earlier sections can be com-
bined to achieve more effective systems for particular applica-
tions. Thus, the following hybrid or combined plants can be
designed:
Direct-Steam/Binary Plants [5]
Single-Flash/Binary Plants [5]
Integrated Single- and Double-Flash Plants [20,21]
Hybrid Fossil-Geothermal Systems [22-24].
Properly designed combined or hybrid systems achieve
a synergistic advantage by having a higher overall efficiency
compared with using the two systems or fuels (in the case of
the fossil-geothermal plants) in separate state-of-the-art plants.
The intricacies of the design of these systems are beyond the
scope of this introductory paper and the reader is referred to
the references cited above.
POWERPLANT PERFORMANCE
The modern approach to measuring the performance of
energy systems is to use the Second Law of thermodynamics
as the basis for assessment. The concept of available work or
energy has been widely used for this purpose [25]. Geother-
mal powerplants are an excellent illustration of the application
of the Second Law (or utilization) efficiency, hu
. Since geo-
thermal plants do not operate on a cycle but instead as a series
of processes, the cycle thermal efficiency, hth, for conventional
plants does not apply [9, 26].
The one instance where the cycle thermal efficiency, hth,
can be meaningfully applied to geothermal powerplants is the
case of Binary plants. Even in this case, however, the thermal
efficiency must be used solely to assess the closed cycle in-
plant, from production wells through the heat exchangers to
the injection wells.
It is an interesting historical note that the first commer-
cial geothermal powerplants at Larderello were, in fact, binary-
type plants [15]. The geothermal steam was used to evaporate
clean water to run steam turbines because the materials avail-
able at that time did not allow the corrosive steam to be used
directly in the turbines.
A flow diagram for a typical Basic Binary plant is given
in Figure 4 [5]. The power cycle consists of a preheater, anevaporator, a set of control valves, a turbine-generator set, a
condenser and a feedpump. Either water or air may be used
for cooling depending on site conditions. If wet cooling is
used, an independent source of make-up water must be found
since geosteam condensate is not available as it was in the case
of Direct- or Flash-Steam plants. Owing to chemical impuri-
ties the waste brine is not generally suitable for cooling tower
make-up. There is a wide range of candidate working fluids
for the closed power cycle. In making the selection, the de-
signer tries to achieve a good thermodynamic match to the
particular characteristics of the geofluid, especially the geofluid
temperature. Hydrocarbons such as isobutane, isopentane and
propane are good candidate working fluids as are certain re-frigerants. The optimal fluid will give a high utilization effi-
ciency together with safe and economical operation.
matically in Figure 5 [5]. A 12 MW pilot plant of this type
has been designed and is planned for installation at Steamboat
Springs in Nevada.
Figure 5. Simplified flow diagram for a Kalina binary geo-
thermal powerplant [5].
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GHC BULLETIN, JUNE 1999 5
Plant
Location
Start-up year
Type
Rating, MW
Output power, MW-net
Geofluid flow rate, kg/sResource temperature, CTurbine:inlet pressure, kPa: primary
secondary
inlet temperature, C: primary
secondary
mass flow/turbine, kg/s: primary
secondary
exhaust pressure, mm Hg
last stage blade height, mm
speed, rpm Condenser:type
heat duty, MWt
CW flow, kg/s
NCG system:steam-jet ejectorstages
steam flow, kg/s
compressor
stages
power, MW
vacuum pump Plant performance:SGC-net, kg/MWh
hu
, %: gross
Net
Valle Secolo, Unit 2
Larderello, Italy
1992
Direct steam
57
52.2
111.1204
550.3
200-210
111.1
59.94
na
3,000
DC
245
2,785
no
yes
2
1.4
no
7,666
62.9
57.6
Miravalles, Unit I
Guanacaste, Costa Rica
1994
Single flash
55
52
759.5230
600.0
159
114.0
93.73
584
3,600
DC
243
4,234
yes
2
4.06
yes
4
0.4
no
52,572
31.2
29.5
BeowaweBeowawe, Nevada
1985
Double flash
16.7
16.0
157.5215
421.4
93.1
146
99
22.3
12.2
33.02
635
3,600
DC
71.8
1,474
yes
1
na
no
yes
35,437
48.7
46.7
Table 3
Design Conditions for Selected Geothermal Steam Plants (after [5])
The utilization efficiency, hu, measures how well a plant
converts the exergy (or available work) of the resource into
useful output. For a geothermal plant, it is a found as follows:
where is the net electric power delivered to the grid, is therequired total geofluid mass flow rate, and e is the specific
energy of the geofluid under reservoir conditions. The latter
is given by:
The specific enthalpy, h, and entropy, s, are evaluated
at reservoir conditions,P1and T
1, and at the so-called dead
state,P0and T
0. The latter correspond to the local ambient
conditions at the plant site. In practice, the design wet-bulb
temperature may be used for T0
(in absolute degrees) when a
wet cooling system is used; the design dry-bulb temperature
may be used when an air-cooled condenser is used.
The major design specifications and actual performancevalues for selected powerplants of the Direct-Steam, Single-
and Double-Flash types are given in Table 3; similar data are
e = h(P1
- T1) - h(P
0- T
0) - T
0[s(P
1- T
1) - s(P
0- T
0)].
given in Table 4 for selected small Binary powerplants. The
specific geofluid consumption, SGC, is given as one measure
of performance. One will observe a dramatic increase in this
parameter (i.e., a decrease in performance) when comparing
Binary plants with geothermal steam plants, particularly Di-
rect-Steam plants. It can be seen that Direct-Steam plants op-
erate at quite impressive efficiencies based on exergy, typically
between 50-70 %. Each utilization efficiency given in Tables
3 and 4 was computed using the appropriate site-specific dead-
state temperature.The contemporary use of small modular binary units is
exemplified by the SIGC plant [27,28]. Several small units,
2.7 MWn, are clustered together receiving geofluid from sev-
eral wells through a manifold and generate a total of 33 MWn.
The small sacrifice in efficiency of the modular-sized units,
istics of the wells are known.
The influence of resource temperature and power rating
on plant costs for small-size Binary units are summarized in
Table 6[30]. Capital costs (per kW) vary inversely with tem-
perature and rating; annual O&M costs increase with rating but
are independent of fluid temperature (over the range studied).
These costs are favorable when compared to other renewable
energy sources, and are absolutely favorable for remote loca-tions where electricity is usually generated by diesel engines.
HP:
X
&
&
=
h
:
&
volving the secondary working fluid and not the overall op-
eration involving the flow of the geofluid from the production
wells, through the plant, and ultimately to the fluid disposal
system.
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ECONOMICS OF GEOTHERMAL POWERThe costs associated with building and operating a geo-
thermal powerplant vary widely and depend on such factors
- Resource type (steam or hot water)
- Resource temperature
- Reservoir productivity
- Powerplant size (rating)
- Powerplant type (single-flash, binary, etc.)
- Environmental regulations
- Cost of capital
- Cost of labor.
The first three factors influence the number of wells thatmust be drilled for a given plant capacity. Using typical costs
and power potential for production wells, a single well can
cost $100-400/kW. The next three items determine the capital
cost of the energy conversion system; whereas, the last two
affect the cost of running the plant (i.e., debt service, and op-
erations and maintenance [O & M]).
Table 5 gives capital costs for a variety of plants in the
United States (29). Note that all values are in as spent dol-
lars for the year quoted. Furthermore, the figures for the Di-
Table 4
Design Conditions for Selected Geothermal Binary Plants (after [5])
Plant
Location
Start-up year
Type
No. of units
Rating, MW
Output power, MW-net
Net power/unit, MW
Geofluid flow rate, kg/s
Resource temperature, CDownwell pumps
Working fluid
Evaporator(s):
No. per unit
type
heat duty,MWt
geofluid temperature, C:
inlet
outlet Turbine:type
inlet temperature, C
pressure, kPa: inlet
outlet
mass flow/turbine, kg/s
speed, rpm Condenser(s):No. per unit
type
heat duty, MWt
coolant
coolant temperature, C: inlet
outlet
Plant performance:
SGC-net, kg/MWh
hu, %: gross
net
hth, %: gross
net
Second Imperial Geothermal Co.
Heber, CA
1993
dual-pressure
12
40
32
2.7
999.0
168yes
isopentane, C5H
12
2
shell & tube
413.2 (e)
168
71 (e)
axial flow
na
na
na
na
1,800
2
shell & tube
269.2
water
20.0
28.1
85,049
44.5
35.6
14.0
13.2
Mammoth-Pacific, Unit I
Mammoth, CA
1985
basic
2
10
7
3.5
220.5
169yes
isobutane, C4H
10
6
shell & tube
86.75
169
66-88
radial inflow
138
3,379
variable
92.0
11,050
11
finned tube
79.72
air
variable
variable
113,399
32.4
22.7
11.5
8.1
Amedee
Wendel, CA
1988
basic
2
2
1.6
0.8
205.1
103yes
R-114, C2Cl
2F4
1
shell & tube
28.72
104
71
axial flow
83
993
276
100.8
3,600
1
evaporative
na
water
21.1
na
462,669
17.4
13.9
7.0
5.6
rect Steam plants (all at The Geyers) do not include field de-velopment costs but cover only the powerplant. The other fig-
ures (all estimated) include both field and plant costs.
Table 5
Capital Cost for U.S. Geothermal Plants (after [5]) Type/Plant Name
Direct Steam
PG&E Geysers:
Unit 1
Unit 8
Unit 13
NCPA-1Single Flash
Blundell
Steamboat Hills
Double Flash
Desert Peak
Beowawe
Heber
Dixie Valley
Brady Hot Springs
Binary
Empire
Stillwater
SIGC
Year
1960
1972
1980
1983
1984
1988
1985
1985
1985
1988
1992
1987
1989
1993
Power, MWn
11
53
133
110
20
12
9
16
47
66
24
3
12
33
Cost, $/kW
174
109
414
780
3000 (e)
2500 (e)
2000 (e)
1900 (e)
2340 (e)
2100 (e)
2700 (e)
4000 (e)
3085 (e)
3030 (e)
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Table 6
Capital and O&M Costs for Small Binary Geothermal
Plants (1993 $) [5]
Net Power, kW
100
200
500
1,000
Resource Temperature, C
100 120 140
Capital Cost, $/kW
2,535 2,210 2,015
2,340 2,040 1,860
2,145 1,870 1,705
1,950 1,700 1,550
Total O&M Cost
$/year
19,100
24,650
30,405
44,000
SUMMARY AND OUTLOOK
Extensive research and development over the last two
decades has resulted in an impressive array of commercially
available technologies to harness a wide range of geothermal
resources. Off-the-shelf power systems of the Direct-Steam,
Flash-Steam or Binary types can be ordered for use with low-
to-high temperature resources of the vapor- or liquid-domi-
nated variety, with any level of noncondensable gas or dis-
solved solids. If new plants are to be built, however, they must
demonstrate an economic advantage over alternative systems.
The economics are governed by site-specific and time-specific
factors. For example, in the United States in the late 1990s, it
has been difficult for any energy source to compete with natu-ral-gas-fired plants, particularly combined steam-and-gas-tur-
bine cycles.
The effects of deregulation on the electric industry have
also had a negative impact on geothermal plants. No longer
endowed with favorable power purchase agreements, geother-
mal plant must now compete openly with other energy sys-
tems. Interestingly, privatization in many other countries, par-
ticularly those lacking in indigenous fossil fuels, has actually
enhanced the attractiveness of geothermal plants which often
turn out to be the lowest cost option among new electric power
plants.
Since geothermal projects are heavily loaded with up-
front costs for exploration, reservoir characterization, and drill-ing, all of which carry a measure of risk for investors, research
directed at improving the technology in these areas is appro-
priate. Also, better methods of monitoring and predicting res-
ervoir behavior, both prior to and during exploitation would
allow more systematic and reliable development strategies to
maximize energy extraction over the long term.
In countries with long histories of operating geothermal
plants (such as Italy, the U. S. and New Zealand), geothermal
re-powering projects are replacing older, less efficient units or
units that no longer match the resources (due to long-term res-
ervoir changes) with modern, high-efficiency, flexible systems.
In many countries, both large and small, which are endowed
with abundant geothermal resources, there is good potential
for strong growth in geothermal power capacity. Of particular
interest are Indonesia, the Philippines, Mexico, Japan, Italy,
Kenya, and countries in Central America including Costa Rica,
El Salvador, Guatemala and Nicaragua. In the United States,
further development of its abundant geothermal resources will
depend strongly on the prices of competing conventional fu-
els.
Geothermal is now a proven alternative energy source
for electric power generation. Because of its economic com-
petitiveness in many situations, the operational reliability of
the plants, and its environmentally friendly nature, geothermal
energy will continue to serve those countries endowed with
this natural energy resource.
REFERENCES
[1] ENEL, 1993. The History of Larderello, Public Rela-
tions and Comm. Dept., Rome.
[2] DiPippo, R., 1980. Geothermal Energy as a Source of
Electricity: A Worldwide Survey of the Design and
Operation of Geothermal Power Plants, USDOE/
RA/28320-1, US Gov. Printing Office, Washington.
[3] DiPippo, R., 1995. Geothermal Power Plants in the
United States: A Survey and Update for 1990-
1994, Geothermal Resources Council BULLETIN,
24: pp. 141-152.
[4] Wright, P. M., 1998. A Look Around the World,
Geothermal Resources Council BULLETIN, 27: pp.154-155.
[5] Geothermal Power Systems, R. DiPippo. Sect. 8.2 in
Standard Handbook of Powerplant Engineering,
2nd ed., T. C. Elliott, K. Chen and R C.
Swanekamp, eds., pp. 8.27 - 8.60, McGraw-Hill,
Inc., New York, 1998.
[6] Voge, E.; Koenig, B.; Smith, J. L. B.; Enedy, S.; Beall,
J. J.; Adams, M. C. and J. Haizlip, 1994. Initial
Findings of the Geysers Unit 18 Cooperative Injec-
tion Project, Geothermal Resources Council
TRANSACTIONS, 18: pp. 353-357.
[7] Cappetti, G. and G. Stefani, 1994. Strategies for Sus-
taining Production at Larderello, Geothermal
Resources Council TRANSACTIONS, 18: pp. 625-
629.
[8] DiPippo, R. and P. Ellis, 1990. Geothermal Power
Cycle Selection Guidelines, EPRI Geothermal In-
formation Series, Part 2, Palo Alto, CA.
[9] DiPippo, R., 1987. Geothermal Power Generation from
Liquid-Dominated Resources, Geothermal Science
and Technology, 1: pp. 63-124.
[10] Cerini, D. J. and J. Record, 1983. Rotary Separator
Turbine Performance and Endurance Test Results,
Proc. Seventh Annual Geoth. Conf. and Workshop,
EPRI Rep. AP-3271, pp. 5-75 - 5-86, Palo Alto,
CA.
[11] Gonzales Rubio, J. L. and F. Illescas, 1981. Test of
Total Flow Helical Screw Expander at Cerro Prieto,
Mexico, Geothermal Resources Council TRANS-
ACTIONS, 5: pp. 425-427, 1981.
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8 GHC BULLETIN, JUNE 1999
[12] Austin, A. L. and A. W. Lundberg, 1978. The LLL
Geothermal Energy Program: A Status Report on
the Development of the Total Flow Concept,
Lawrence Livermore Laboratory Rep . UCRL-
50046-77, Livermore, CA.
[13] Lazalde-Crabtree, H., 1984. Design Approach of
Steam-Water Separators and Steam Dryers for Geo-
thermal Applications, Geothermal Resources
Council BULLETIN, 13: No. 8, pp. 11-20.
[14] Frost, J.,Introduction to Geothermal Lineshaft Produc-
tion Pumps, Johnston Pump Co., Pomona, CA.
[15] Anon, 1981. Electrical Energy from the Volterra
Soffioni,Power, 47: No. 15, p. 531.
[16] Demuth, O. J., 1981. Analyses of Mixed Hydro-
carbon Binary Thermodynamic Cycles for Mod-
erate Temperature Geothermal Resources, INEL
Rep. EGG-GTH-5753, Idaho Falls, ID.
[17] Bliem, C. J., 1983. Preliminary Performance Esti-mates and Value Analyses for Binary Geothermal
Power Plants Using Ammonia-Water Mixtures as
Working Fluids, INEL Rep. EGG-GTH-6477,
Idaho Falls, ID.
[18] Demuth, O. J. and R. J. Kochan, 1981. Analyses of
Mixed Hydrocarbon Binary Thermodynamic
Cycles for Moderate Temperature Geothermal Res-
sources Using Regeneration Techniques, INEL
Rep. EGG-GTH-5710, Idaho Falls, ID.
[19] Leibowitz, H. M. and D. W. Markus, 1990. Economic
Performance of Geothermal Power Plants Using theKalina Cycle Technique, Geothermal Resources
Council TRANSACTIONS, 14 (Part II): pp. 1037-
042.
[20] DiPippo, R., 1987. Ahuachapan Geothermal Power
Plant, El Salvador, Proc. Fourth Annual Geoth.
Conf. and Workshop, EPRI Rep. TC-80-907, pp.
7-7 - 7-12, Palo Alto, CA, 1980.
[21] Jimenez Gibson, J., 1987. Operation of the Five
Units of Cerro Prieto I Geothermal Power Plant,
Proc. Ninth Annual Geoth. and Secon IIE-EPRI
Geoth. Conf. and Workshop, Vol. 2, English Vers.,
EPRI Rep. AP-4259SR, pp. 7-1 - 7-9, Palo Alto,
CA.
[22] DiPippo, R.; Khalifa, H. E.; Correia, R. J. and J. Kestin,
1979. Fossil Superheating in Geothermal Steam
Power Plants, Geothermal Energy Magazine, 7:
No. 1, pp. 17-23.
[23] Khalifa, H.E.; DiPippo, R. and J. Kestin, 1978. Geo-
thermal Preheating in Fossil-Fired Steam Power
Plants, Proc. 13th Intersociety Energy Conversion
Engineering Conf., 2: pp. 1068-1073.
[24] Habel, R., 1991. Honey Lake Power Facility, Lassen
County, Geothermal Hot Line, 20: No. 1, p. 19.
[25] Moran, M.J., 1989. Availability Analysis: A Guide to
Efficient Energy Use, Corrected edition, ASMEPress, New York.
[26] DiPippo, R. and D. F. Marcille, 1984. Exergy Analy-
sis of Geothermal Power Plants, Geothermal Re-
sources Council TRANSACTIONS, 8: pp. 47-52.
[27] Ram, H. and Y. Yahalom, 1988. Commercially Suc-
cessful Large Binary Applications, Geothermal
Resources Council BULLETIN, 17: No. 3, pp. 3-7.
[28] Anon., 1993. New Geothermal Facility Exceeds Pro-
duction Expectations, Geothermal Resources
Council BULLETIN, 22: pp. 281-282.
[29] Schochet, D. N. and J. E. Mock, 1994. How the De-
partment of Energy Loan Guarantee Program Paved
the Way for the Growth of the Geothermal Indust-
ries, Geothermal Resources Council TRANSAC-
TIONS, 18: pp. 61-65.
[30] Entingh, D. J.; Easwaran, E. and L. McLarty, 1994.
Small Geothermal Electric Systems for Remote
Powering, Geothermal Resources Council TRANS-
ACTIONS, 18: pp. 39-46.
NOMENCLATURE FOR PLANT FLOW DIAGRAMS(Figs. 1, 2, 3, 4, 5)
BCV - ball check valve C - condenser
CP - condensate pump CS - cyclone separator
CSV - control and stop valves CT - cooling tower
CW - cooling water CWP - cooling water pump
E - evaporator F - flasher
FF - final filter IP - injection pump
IW - injection wells M - make-up water
MR - mositure remover P - well pump
PH - preheater PW - production wells
R - recuperator S - silencer
SE/C - steam ejector/condenser SH - superheater
SP - steam piping SR - sand remover
T/G - turbine/generator TV - throttle valveWP - water piping WV - wellhead valves
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SMALL GEOTHERMAL POWER
PROJECT EXAMPLES
John W. Lund
Tonya Toni Boyd
Geo-Heat Center
WHAT ARE SMALL GEOTHERMAL POWERPROJECTS?
According to Vimmerstedt (1998 - and this Bulletin),
small geothermal power projects are less than 5 MWe. Oth-
ers (Entingh, et al., 1994a and b, and Pritchett 1998a) refer to
a range of 100 to 1000 kWe as small. In this article, we
will use the 5 MWe definition as small.
Small power projects, often called village power and
sometimes as off-grid power, can serve rural people in de-
veloping countries; since, this market may be best served by
many small generating units, rather than fewer larger ones.
For examples, at 50 watts per household for lighting, 1 MWe
could serve 20,000 households (Cabraal, et al., 1996). Entingh,
et al., (1994a) estimates that the demand for electric capacityper person at off-gird sites will range from 0.2 kW in less-
developed areas to 1.0 kW or higher in developed areas. Thus,
a 100-kWe plant could serve 100 to 500 people, and a 1,000-
kWe plant would serve 1,000 to 5,000 people. However, one
of the main problems with small geothermal power projects is
that they are unlikely to obtain financing due to high cost per
installed kW and low rate of return; thus, these remote projects
often must be subsidized by the government to encourage lo-
cal economic development.
Alternative power at remote locations, which is usually
provided by diesel generations, can be much more expensive
per kWh than geothermal, as the fuel transportation costs are
high. For example at Fang, Thailand, a 300-kWe geothermalbinary plant supplies power from 6.3 to 8.6 cents/kWh, com-
pared to the alternative of diesel generators at 22 to 25 cents/
kWh (Schochet, 1998).
Small geothermal power units are already common,
though not always in remote applications. They are some-
times used within larger geothermal developments, either be-
cause they are cost effective, because they fit with incremen-
tal development plans, or because they were installed early in
a sites development.
According to Vimmerstedt (1998):
Small geothermal units are used in larger
developments for several reasons. First, a
modular approach can be less expensive
overall because of shipping and handling costs.
Second, small modules increase reliability and
improve flexibility when adapting to changing
well and system performance. Third, a small,
remote well is sometimes located so far from
other wells that a power plant sized to the re-
mote well costs less than transmission pipes
for the fluid [to a larger centralized plant].
Well spacing must take reservoir character-istics into consideration, and so can not be
optimized for power plant size alone.
Small units are also found at larger sites
where they were used during early phases
of site development. Placing a small plant
at the site of a larger anticipated develop-
ment supplies electricity during develop-
ment of the field [and can provide a return
on investment sooner. Also, if the initial
electricity demand at the site is low, then
the small-scale plant can be fully utilized
until a larger one is justified. When thereis a problem in resource development, a
smaller plant can utilize resource confir-
mation holes, or shallow, less expensive
wells]. Small systems at large sites have
advantages over remote ones in that the
financing is often secured for the entire
project. The resource is confirmed for
that project, operation and maintenance
infrastructures are readily available, a grid
either exists or is constructed for the large
project, and sufficient base load is avail-
able.
A critical distinction between the applica-
tion of small geothermal plants within a lar-
ger site and application in a remote area
is the load-following ability of small geo-
thermal systems. Although geothermal
plants can follow loads, this ability is limit-
ed and cost of a reduced-load factor is
high because much of the cost of the geo-
thermal power plant is capital cost. Re-
mote areas and small grids generally have
low base loads, so the contrast between
achievable capacity factors (low cost per
kWh) for large versus small grid applica-
tions is major.
TECHNOLOGY FOR SMALL GEOTHERMAL
POWER SYSTESM
Vimmerstedt (1998) reports:
The most likely technology choices for
small geothermal power plants are flash
steam and binary cycle. Dry steam systems
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10 GHC BULLETIN, JUNE 1999
are unlikely to be used in small geothermal
plants because dry steam resources are
thought to be rare.
The advantages of flash steam systems in
small applications include the relative
simplicity and low cost of the plant. In
contrast to binary plants, they require no
secondary working fluid. However, whenthe geothermal fluid is flashed to steam,
the solids that precipitate can foul
equipment, and pose health, safety and
disposal problems. If steam contains
hydrogen sulfide or other contaminants, it
poses an air quality problem when released
directly to the atmosphere. Treating non-
condensable gases in the condensing
design adds complexity, maintenance, and
disposal requirements (Forsha and Nichols,
1997). Flash systems are most often used
where higher temperatures (above 300oF -
150o
C) are available; although, a low-pressure turbine design for lower-tempera-
ture flash plants (230oF - 110oC) has been
proposed (Forsha, 1994) and feasibility of
lower-temperature flash plants have been
studied (Pritchett, 1998b).
The advantage of binary technology is that, in small-
size ranges, modular binary units are readily available, and
they can operate at lower temperatures (below 300oF - 150oC
and down to around 180oF - 82oC). One of the early experi-
mental binary plants, Paratunka on the Kamchatka Peninsula
of Siberia, operated at 178oF (81oC). Because the geothermalfluid can be contained in a separate loop, precipitation and
environmental effects of the geothermal fluid can be controlled.
Conversely, secondary working fluids may be hazardous and
difficult to supply. Other disadvantages of binary designs are
the higher capital cost and greater complexity of plants (Forsha
and Nichols, 1997).
The choice between flash steam and binary designs for
small geothermal plants will be site specific, and will depend
on resource temperature, chemical composition of the geother-
mal fluid and maintenance preferences.
ADVANTAGES OF SMALL GEOTHERMAL BINARY
POWER PLANTS
Entingh, et al., (1994a) gives some of the reasons why
small geothermal binary plants can be successful in off-grid
or village power situations.
1. The plants are very transportable. For 100 to 300
kWe plants, the entire plant, including the cooling
system, can be built on a single skid that fits in a
standard trans-ocean container.
2. Binary power plants can accommodate a wide range
of geothermal reservoir temperatures, 212 to 300oF
(100 to 150oC). Above 300oF (150oC) flashed- steam
plants usually prove less expensive than
binary plants.
3. The demand for electric capacity per person at off-
grid sites will range from 0.2 kWe to 1.0 kWe.
4. The design of the power plants and their interac-tions with the wells includes provisions for hand-
ling fluctuating loads, including low-instantaneous
loads ranging from 0 to 25 percent of the installed
capacity.
5. Power plant designs emphasize a high degree of
computer-based automation, including self starting.
Only semi-skilled labor is needed to monitor plant
operation, on a part-time basis. Complete unatten-
ded operation might also be possible, with plant
performance monitored and controlled remotely
through a satellite link.
6. The system releases no greenhouse gases to the
atmosphere. There may be very small leakages of
the binary-cycle working fluids, but these do not
contain chlorine or fluorine and are non-greenhouse
gases.
7. All wells could be drilled by truck-mounted rigs,
either heavy-duty water-well rigs or light-duty oil/
gas-well rigs. At very remote sites, both drilling rig
and power system equipment can be transported by
helicopter.
8. Injection well costs can be relatively low. For smallsystems, because the geothermal flow rates are
relatively small, rarely will there be a need to inject
the fluid back into the production reservoir. Any
shallow aquifer not used for drinking water could
be used for reinjection. If the fluids are clean
enough to be disposed of on the surface, then the
disposal costs can be quite low.
9. Field piping costs are low. All wellheads are
located near the power plant module. Inexpensive
plastic or carbon steel pipe is used to connect wells.
10. Geothermal direct-heat applications can be attached
to these electric systems inexpensively. Applica-
tions needing temperatures not higher than 150oF
(65oC) might be attached (cascaded) in series to the
power-plant fluid outlet line.
11. Critical backup need is estimated to range from one
to five percent of the installed geothermal capacity.
The very high availability factors for geothermal
systems, on the order of 98 percent, substantially
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GHC BULLETIN, JUNE 1999 11
reduce the cost of special features needed to ensure
that power is always available. Small critical loads
such as medical refrigeration or pumps for drinking
water could be supported against brief unscheduled
outages by a diesel engine or by small amounts of
battery storage.
COSTS OF SMALL GEOTHERMAL POWER PLANTS
Ultimately, the costs of small geothermal power plants
will determine their potential market. Reported costs for smallplants are rare. Those that do are located at large fields and are
in the $0.05 to $0.07/kWh range, for units in the 1 to 5 MWe
range (GRC, 1998).
Entingh, Easwaran, and McLarty (1994a and 1994b)
developed a model called GT-SMALL for small, binary geo-
thermal systems in the 100 to 1000-kWe size range. They
evaluated reservoir temperatures of 212 - 284oF (100 - 140oC),
production well depth of 656 - 3,281 ft (200 - 1,000 m), and
injection well depth of 656 - 1,640 ft (200 - 500 m). Technical
costs at the busbar for this evaluation ranged from $0.047 to
$0.346/kWh. An example is shown below for a system cost of
$0.105/kWh.
Technical Resource Temperature 248oF (120oC)
System Net Capacity 300 kWe
Number of Wells 2
Capacity Factor 0.8
Plant Life 30 years
Rate of Return
on Investment 12%/yr
kWh/yr produced 2.10 million
Capital Costs Exploration $200,000
Wells 325,000
Field 94,000Power Plant 659,000
TOTAL $1,278,000
Plant cost/installed kW $2,200
Annual capital recovery cost $158,650
O&M Costs Field $32,000
Plant 26,000
Backup System 5,000
TOTAL/yr $63,000
For the range of project sizes investigated, the capital
costs represented about 55 to 80% of the cost of electricity
generation, and operation and maintenance costs represented
about 30 to 45% (Entingh, 1991). The accuracy of GT-SMALL
is difficult to evaluate given the scarcity of remote applica-
tions of small systems. The $0.05 to $0.07/kWh prices re-
ported in the GRC database are comparable to the modeled
cost estimates at the 1 MWe size.
EXAMPLES OF SMALL GEOTHERMAL POWER
PLANTS
The generating potential of a geothermal resource can
be estimated from the temperature and flow rate as shown in
Figure 1 (Nichols, 1986). This figure gives the net power out-
put which accounts for the parasitic loads such as due to the
condenser and feed pump power requirements. Single modu-
lar units can handle flow rates up to 1000 gpm (63 l/s), with
multiple units required to accommodate greater flow rates and
produce proportionately larger output power. The output powerfrom two-phase water-steam or steam alone is much greater
than the curves shown for liquid in Figure 1. Temperatures
above 350oF (175oC) can also be accommodated with high ef-
ficiencies by making minor modifications to the modular units.
However, it should be pointed out that the conversion effi-
ciency is quite low at the lower temperature and therefore, the
cost of power becomes higher. Reservoir temperature is the
physical factor to which overall project costs are most sensi-
tive. A schematic of the binary cycle (Rankine cycle) is shown
in Figure 2 (Nichols, 1986).
Figure 1. Potential power generation of a geothermal re-
source (Nichols, 1986).
Figure 2. Schematic of the binary cycle (Rankine cycle)
(Nichols, 1986).
Additional details of binary plant efficiency and operat-
ing characteristics can be found in Ryan (1982, 1983 and 1984).
There are approximately 50 geothermal power plants in
the world at or below 5 MWe, including some bottoming cycle
plants associated with large plants. Some of these are described
in more detail in the following section.
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1. Amedee Geothermal Venture binary plant (Fig. 3),
located in northern California near Susanville was
placed in operation in 1988. The plant consists of
two units of one MWe each with a total net output of
1.5 MWe. The resource temperature is 219oF (104oC),
and well depth of 850 ft (260 m) with a maximum
flow rate of 3,200 gpm (205 l/s). The plant uses R-
114 working fluid and cooling ponds for makeup
water. The units were designed by Barber-Nichols
Engineering Company of Arvada, Colorado. Theyhave an availability is 90% and the system is remotely
monitored by telephone line.
Geothermal fluids from two wells are used to operate
the plant, and surface discharge is used to dispose of
the spent fluid. This is possible because the geother-
mal fluids have a very low salinity and a composition
the same as area hot spring water.
Figure 3. Amedee Geothermal Venture 2-MWe binary
plant.
2. Wineagle Developers binary plant (Fig. 4), also lo-
cated in northern California near Susanville was
placed in operation in 1985. The plant consists of
two binary units of total gross capacity of 750 kWe
and a net output of 600 kWe. A 1,300-ft (400-m)
deep well is pumped to produce 1000 gpm (63 l/s) of
230oF (110oC) water. The spent fluid at 1,000 ppm
total dissolved solids, is disposed on the surface. It
has an availability of 98%, a gross efficiency of 8.5%and a capacity factor of 109%. The units were de-
signed by Barber Nichols Engineering Company of
Arvada, Colorado and the installed cost was about
$2,100/kWe (Nichols, 1986).
Figure 4. Wineagel Developers 750-kWe binary plant.
The plant is completely automated. The entire plant,
including the well pump, is controlled by either mod-
ule. By pushing one button on the module controlpanel, the plant will start, synchronize to the power
line and continue operation. If the power line goes
down, the module and the downhole pump immedi-
ately shut down, since no power is available for its
operation. When the power line is re-energized, the
modules restart the downhole pump, then bring them-
selves on line. The two, identical power plant mod-
ules are mounted on 10-ft by 40-ft (3-m x 12-m) con-
crete slabs. Each unit is self-contained and includes
the heat exchanger, a turbine generator and controls
(Fig. 5). The fans on top of the units are evaporative
condensers.
3. TADs Enterprises binary plants units No. 1 and
No. 2, located at Wabuska, Nevada, were placed in
operation in 1984 and 1987 respectively (Fig. 6). They
are rated at 750 kWe and 800 kWe, and are supplied
heat from two geothermal wells at 220oF (104oC),
pumped at 850 and 950 gpm (54 and 60 l/s) respec-
tively. They use water cooled condensers fed from a
cooling pond. The operation is automatic and un-
manned, with maintenance only as required. The units
were manufactured and supplied by ORMAT Inter-
national, Inc. of Sparks, Nevada.
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Figure 5. Schematic of one of the Wineagle modular units (Nichols, 1986).
Figure 6. TADs unit No. 1 - 750-kWe modular binary
power plant unit.
The units originally used Freon 114 as the working
fluid. From 1985 to 1990, there were minor mainte-
nance outages, and very cold weather in 1990, during
a power trip caused freezing in the condenser and
pumps. The plant was repaired and operated until
1996, when the unavailability of Freon 114 caused a
shutdown from 1996 to 98. It was then converted to
Iso-Pentane and reconditioned in 1998. Commercial
operation was re-established in 1998. As it turns out,
the Iso-Pentane working fluid does not mix with
water; thus, water leakage is not a problem as it was
with Freon 114. Gene Culver (1987) of the Geo-
Heat Center conducted an evaluation of unit No. 1
while it was still using Freon 114. He found that the
parasitic load (well pump, feed pump circulation wa-
ter pump and other loads) amounted to 241.6 kWe
and the net thermal efficiency ranged from 6.5% to
9.4%, depending on the cooling water temperature(which varied from 65 to 55oF - 18 to 13 oC).
4. Empire Geothermal Project binary plant, San
Emidio desert near Empire, Nevada, was placed in
operation by OESI in 1987 (later called OESI/
AMOR). The plant consists of four one-MWe mod-
ules, supplied by ORMAT International, Inc. of
Sparks, Nevada (Fig. 7). The units use water-cooled
condensers with a spray pond. The rated net output
is 3.6 MWe, and the units produced from 15 to 7.5
GWh annually through 1996. Two production wells
at 278oF (137oC) were initially used. By 1989, injec-
tion into the reservoir started to cool the wells and by
1996, the wells were only producing 237 and 253 oF
(114 and 123oC) respectively, with energy output sig-
nificantly reduced. In 1994, Integrated Ingredients
dedicated their new onion and garlic processing plant
and used a well at 266oF (130oC) pumping up to 900
gpm (57 l/s) from the same reservoir. They founded
the local community of Grunion due to the large
number of employees on site (Lund and Lienau, 1994).
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Figure 7. OESI/AMOR II binary plant near Empire,
Nevada.
The resource was acquired by Empire L.P. in 1996.
The cooler production wells were then shut-in andadditional geothermal fluid supplied at 306oF (152oC)
from a new well. A three-cell cooling tower was also
added which resulted in the net output increasing to
3.85 MWe in 1998. The power plant is, thus, operat-
ing above design capacity, and produced almost 18
GWh in 1997. The onion/garlic dehydration plant is
still operating at full capacity using the same re-
source.
5. Cove Fort Geothermal No. 1, Sulphurdale, Utah, wascommissioned in 1985 with a steam turbine added in
1988. This 4.8-MWe power plant is comprised of
four ORMAT Energy Converter (OEC) modular units
and one back-pressure steam turbine. The OEC units
operate on condensing steam from the exhaust of the
back pressure steam turbine. The four modular bi-
nary units, with a capacity of 0.8 MWe each or 3.2
MWe total, are housed in a single building which also
contains the computer unit controls (Fig. 8) (GRC,
1985). The binary units operate on dry steam from
two production wells producing from 1,200 feet (365
m). The combined production from both wells is in
excess of 100 tons per hour. The geothermal steam is
at 280oF ( 138oC) and the units are water cooled. The
field and plant were developed by Mother Earth In-dustries and the city of Provo Municipal Utility is the
power purchaser. Real-time system and operating data
are received by the city of Provos main control cen-
ter, facilitating remote performance monitoring and
service diagnosing.
Figure 8. Cove Fort Geothermal No. 1 - 4.8-MWe com-
bined power plant.
6. Soda Lake Geothermal Power Plant No. 1, Fallon,
Nevada, commenced generating power in 1988. Thisis a 3.6-MWe binary power plant comprising three
ORMAT OECs modular units (Fig. 9). The power
plant operates on a liquid dominated resource at 370oF
(188oC). The power plant was designed and built on
a turnkey basis by ORMAT, is owned by Constella-
tion Developments, Inc. (CDI) and ORMAT Energy
Systems, Inc. (OESI), and is operated by OESI, with
power sold to Sierra Pacific Power Company SPPC.
The geothermal field was developed by Chevron Re-
sources. The units are water cooled and produce a
net generated power of 2.75 MWe (Krieger, 1989).
Two hundred tons of geothermal fluid per hour are
delivered to the plant. The plant output voltage is
43.8 kV.
Figure 9. Soda Lake 3.6-MWe binary power plant No. 1.
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7. Fang Geothermal binary power plant, located near
Egat, Thailand, was commissioned in 1989. This is a
single-module 300-kWe plant that has a water cooled
condenser with once-through flow (Fig. 10 - after
Ramingwong and Lertsrimongkol, 1995). The net
power output varies with the season from 150 to 250
kWe (175 kWe average). This is a multipurposeproject which in addition to electricity production, the
geothermal fluid also provides hot water for refrig-
eration (cold storage), crop drying and a spa. The
artesian well provides approximately 130 gpm (8.3 l/
s) of 241oF (116o) water. The well requires chemical
cleaning to remove scale about every two weeks. Plant
availability of 94% and the estimated power cost is
from 6.3 to 8.6 cents/kWh. This is very competitive
with diesel generated electricity which runs 22 to 25
cents/kWh . Plant was supplied by ORMAT
International, Inc. of Sparks, Nevada.
8. Nagqu Geothermal binary plant, Tibet, Peoples
Republic of China, was installed and commissioned
in 1993. This plant is an air-cooled module rated at
1.3 MWe, with a gross output of 1.0 MWe, which
was funded by UNDP. Geothermal fluid is supplied
from two wells at 230oF (110oC) with a fluid flow of
1,100 gpm (69 l/s). The plant is located at 14,850
feet (4,526 m) elevation, and thus the air-cooled con-
denser had to be sized and especially adapted for the
thin air at the site which doubled the size of the con-
denser compared to a similar plant at sea level
Figure 10. Pictorial diagram of Fang, Thailand 300-kW binary power plant.
(Cuellar, et al., 1991). In addition, the long overland
transportation of the equipment from the port of ar-
rival in China also called for special design of the
equipment packaging for over land transport. Elec-
trical and control equipment had to be especially de-
signed to withstand the rigorous environmental con-
ditions at the site. The plant was provided by ORMATInternational, Inc (Fig. 11).
Figure 11. Nagqu 1.0-MWe power plant in Tibet at 14,850
ft. (4,526 m) elevation.
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The power plant initially operated for 6,400 hours,
and then was shutdown due to failure of the down-
hole pumps. The cable failed after 15 days of opera-
tion and the seals after seven months of operation.
The wells were then operated without pumps and ex-
perienced severe scaling. The downhole pumps were
replaced and the plant recommissioned in August of
1998. It is currently operating satisfactorily.
This is the only completely stand-alone, off-grid geo-thermal power project in operation. The town of
Nagque, which is a political, cultural, economic and
traffic center of the North Tibet Plateau, has a popu-
lation of about 20,000. Prior to 1993, there were 10
diesel generators with a total nominal capacity of 1.68
MWe supply electricity to the area. This capacity
could only satisfy the lighting needs of the local or-
ganizations and some inhabitants, lasting only 4 to 5
hours every night due to high production cost. The
others had to light their houses with candles or but-
tered lamps. This shortage seriously restricted the
further development of the local economy. The geo-
thermal plant, estimated to provide a net power of840 kWe, will assist the local economic development
(Cuellar, et al., 1991).
A two MWe power plant is report at Langiu (Yangyi
?) is reported installed in Tibet near the Yangbaijain
geothermal field in Tibet (Wang, 1998).
9. Eastern China experimental binary plants. Rec-
ognizing the importance of geothermal energy as an
alternative new and renewable energy source, experi-
mental geothermal power stations were set up in east-
ern China from 1970 to 1982 (Cai, 1982 and Wang,
et al., 1995). These plants are summarized in the
table below. It became clear that the capacity of all
the experimental geothermal power stations was too
small and the efficiency too low due to the low tem-
perature of the thermal water for power generation.
At present, only Dengwu and Huitang are still in op-
eration (part time), and the remaining were shut down
in the early 1990s.
Plant Name Province Date Commissioned Type Capacity Water Temp.
Dengwu No. 1 Guangdong 1970 FS 86 kW 196oF (91oC)
No. 2 Guangdong 1977 B 200 kW 196oF (91oC)
No. 3 Guangdong 1982 FS ? 196oF (91oC)
Huailai Hebei 1971 B 200 kW 185oF (85oC)
Wentang Jiangxi 1971 B 50 kW 153oF (67oC)
Huitang Hunan 1975 FS 300 kW 198oF (92oC)
Yingkou Liaoning 1977 B 100 kW 167oF (75oC)
Zhaoyuan Shandong 1981 FS 200 kW 196oF (91oC)
B = binary (isobutane, ethyl chloride, normal butane or freon-11), FS = flash steam
10. Tu Chang binary power plant, Taiwan, connected
to the grid in 1987. This is a 300 kWe, water cooled
ORMAT OEC that uses a liquid dominated resource
at 266oF (130oC) (Fig. 12). The project is owned and
operated by the Industrial Technology Research In-
stitute and the power is sold to the Taiwan Power
Company. It has a CO2
recovery system, as the non-
condensable gases are two percent by weight. The
project, including the 1,640-foot (500-m) deep well,
cost $2 million and the power is sold at four cents/kWh.
Figure 12. Tu Chang 300-kWe binary power plant,
Taiwan.
11. Tarawera binary plants, Kawerau, New Zealand,
were commissioned in late 1989 and officially opened
in early 1990 after a record short construction time of
15 months (Tilson, et al., 1990). The two ORMAT
energy convertors (OEC) (Fig. 13) receive waste wa-
ter from Kawerau 21 flash plant at about 342 oF
(172oC) and 116 psi (8 bar) (Freeston, 1991). Heat
rejection from the plant is by a forced draft air con-
denser situated above the OEC units. Each unit has a
gross output of 1.3 MWe; a total of 2.6 MWe, of which
about 13% is used by auxiliaries, pumps, fans, etc.,
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giving approximately 2.2 MWe available for the Bay
of Plenty Power Board (BOP) grid. The monitoring
system allows unattended operation that ensures that
unscheduled outages can be quickly reported. The
plant performance is also monitored by the manufac-
turers in Israel, who provide weekly reports directly
to the BOP offices in Whakatane. Tilson, et al., (1990)
reported no deposition in the heat exchangers and,
with little maintenance required, load factors for the
first six months of operation were over 90%, with96.6% availability. The unit average output was about
1,800 MWh per month for the initial operation. The
OECs utilize separated geothermal water which pre-
viously ran into the Tarawera River. The installation
of the OECs, thereby, contributes to environmental
conservation by reducing pollution.
Figure 13. Tarawera 1.25-MWe binary unit at Kawerau,
New Zealand.
12. TG2 binary power plant, Kawerau, New Zealand,
was installed and linked to the grid in 1993. This 3.5-
MWe gross output ORMAT OEC module uses 342oF
(172oC) geothermal brine at 325 tons/hr (Fig. 14). The
air-cooled unit also utilizes separated geothermal fluid
which previously ran into the Tarawera River. The
power plant is owned and operated by Bay of Plenty
Electric Power Board.
13. Kirishima International Hotel back pressure unit,
Beppu, Kyushu, Japan, was installed in 1983. Theunit is 100-kWe non-condensing flash unit (Fig. 15).
A condensing- type turbine was considered, and even
though the gross output would be about 240 kWe with
the same steam flow, and the increase in the net out-
put would be only 50 kWe because of the increase in
the parasitic loads (Ohkubo and Esaki, 1995). In ad-
dition, the simplicity of maintenance was also a rea-
son to selected the non-condensing unit. Steam
Figure 14. Diagram of TG2 3.5-MWe binary unit at
Kawerau, New Zealand.
from two wells, runs through a separator, providing
an inlet temperature of 260oF (127oC) at 36 psi (2.45
bar) at 6 tons/hour. Hot water from the separator is
used for outdoor bathing, space heating and cooling,
hot water supply, heating of a sauna bath and for two
indoor baths.
Figure 15. Kirishima International Hotel 100-kWe back
pressure unit and separator.
The electricity from the unit is used for the base load
in the hotel such as sewage water treatment, lighting
in the hallway and lounge, kitchen refrigerators, and
provides 30 to 60% of the hotel load according to the
season and time of day. Whenever the hotel load ex-
ceeds the capacity of the unit, the hotel receives power
from the grid. The unit was furnished by Fuji
Electric Co., Ltd. of Japan.
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14. Kokonoe Kanko Hotel condensing f lash unit,
Kokonoe, Kyushu, Japan, was installed in 1998. This
is the most recent installation of a small-scale geo-
thermal power plant in Japan (Esaki, 1998). The con-
densing unit with a geared turbine (about 8,000 rpm)
is installed on the premises of this resort hotel, and
when the hotel load is below the unit capacity, which
it is most of the time, they sell power to Kyushu Elec-
tric Power Company. The installed capacity is 2,000
kWe, with major parastic loads of 356 kWe (hot wellpump, vacuum pump for gas extraction, cooling tower
fan and auxiliary cooling water pump) or about 17%
of the gross output giving a net output of 1,644 kWe.
The reason for the high parasitic load is that a vacuum
pump (164 kWe), not a set of steam jet ejectors, is
employed for gas extraction to reduce noise during
the operation because the plant is located adjacent to
a campsite of the hotel.
The steam temperature and pressure at the turbine inlet
is 271oF (133oC) at 44 psi (3.0 bar). The turbine
exhaust pressure is 3.1 psi (0.21 bar). The steam flow
supplied from two small production wells is 23 tons/h with 2.0% by weight of non-condensable gas. The
unit was supplied by Fuji Electric Co. Ltd. of Japan.
15. Hachijojima Island condensing flash unit, 400 km
south of Tokyo, was complete in early 1999.
Hachijojima is a remote island with power supplied
from several diesel power plants. The unit has a gross
output of 3,300 kWe and parasitic load of 9% of the
gross output with the non-condensable gas abatement
system in operation, and 7% with the abatement sys-
tem shut down (Esaki, 1998). It is expected that the
fuel transportation cost will be drastically reduced
once the plant has been in operation. The plant, sup-
plied by Fuji Electric Co. Ltd., cost about $10 million
or $3,000 per installed kWe, and electricity will be
supplied for about 20 cents/kWh.
The steam temperature and pressure at the turbine inlet
is 338oF (170oC) at 118 psi (8.2 bar). The flow rate is
30 tons/h with 1.56% by weight of non-condensable
gas. The plant is equipped with a hydrogen sulfide
abatement system to comply with the regulation of
the Tokyo Metropolitan Government which prescribes
the concentration of 0.1 ppm, in this case at the cool-
ing tower cell.
16. The Bouillante geothermal flash condensing power
plant, Guadeloupe, was placed in operation in 1986.
The plant site is at Cocagne on the western coast of
the isle of Basse Terre, some 1,600 feet (500 m) south
of the center of Bouillante and some 9 miles (15 km)
from the Soufriere volcano. The operation of the
power-plant is mainly automatic and the electric out-
put will meet 6% of the Guadeloupe electric power
demand at a cost lower than that obtained with diesel
generators. Numerous modernization and improve-
ments were undertaken in 1995 and 1996 (Correia, et
al., 1998). Three automated controllers monitor plant
activity and manage all operation. The plant, locatedwithin a residential district, was designed so as not to
produce noise greater than the ambient noise of the
city.
Geothermal wells on the island produced tempera-
tures of 446 to 482oF ( 230 to 250oC) at depths of
2,000 to 8,200 ft. (600 to 2,500 m) with a steam to
water mixture of 20 to 80% (Jaud and Lamethe, 1985).
A study was made of the various means to produce
electric power, and binary cycles were rejected due
to silica deposits on the heat exchange surface, thus a
condensing turbine was selected. The plant was then
supplied with a water-vapor mixture which is near400oF (200oC) at the surface with an output of ap-
proximately 150 tons/hour. Two saturated steam
flows were used at 87 and 14.5 psi (6 and 1 bar). The
high pressure steam from the separator is conveyed
to the turbine and the separated geothermal water at
about 320oF (160oC) is sent to a flash vessel to pro-
duce low-pressure steam. The exhaust steam is then
condensed by cooling seawater in a direct-contact
condenser with a barometric pipe. The residual geo-
thermal water at 212o (100oC) is mixed with the wa-
ter coming from the condenser and is discharged to
the sea (Fig. 16). Approximately 30 tons per hour of
steam are produced by the high-pressure separator and
12 tons per hour of steam is produced by the low-
pressure separator.
During operation, the turbine is mainly supplied with
two high- and low-pressure steam flows. However,
it can operate with only the high pressure steam flow;
thus, enabling repair and maintenance operations to
be carried out on the flash vessel without having to
stop power production completely. The gross output
is 5.0 MWe and the net output of the unit is 4.2 MWe,
which is enough power for the cities on the west coast
of the island of Basse-Terre. Plant availability dur-ing late 1997 and early 1998 averaged 95% (Correia,
et al.,1998).
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Figure 16. Diagram of the Bouillante geothermal power plant.
17. CGPV flash steam plant, Pico Vermelho, island of
San Miguel, Azores, Portugal, was installed in 1980
(Fig. 17). The reservoir temperature was as high as
400oF (200oC) at a depth around 1,600 feet (500 m).
The Mitsubishi back-pressure steam turbine, using a
single-flash system with a rated capacity of 3 MWe,
never produced more than 0.8 MWe, due to the in-sufficient supply of steam from the small diameter
PVI well (depth 2,660 feet - 811 m) (Ponte, 1998). In
the first years after plant start-up, the production of
CGPV was variable; however, stable production fig-
ures have been achieve only since about 1993. The
main operation difficulty has been calcium carbonate
scaling, which requires that well PV1 be cleaned out
every month. Annual production varied from 4 to 5
GWh during 1994 to 1997. Availability average is
about 95% and the load factor average about 70%.
18. CGRG (phase A), binary plant, island of San
Miguel, Azores, Portugal, was installed in 1994. Theunits consist of two dual ORMAT turbo-generators
of 2.5 MWe each, with auxiliaries, transformers,
switch gear, emergency diesel generators, fire fight-
ing system and a connection line to the grid. The
organic Rankine cycle uses normal pentane as the
working fluid. Two wells, CL-1 and CL-2, for the
project are about 400oF (200oC) at 5,000 feet (1,500
m). The larger well, CL-2, delivers 152 tons/hour at
a wellhead pressure of 116 psi (8 bar) with a steam
flow of 39 tons/hour. Until the middle of 1994, the
Figure 17. Pico Vermelho 3-MWe flash steam plant,
Azores.
net power output was maintained near 4.8 MWe
(Ponte, 1998). However, well production rates and
plant output began to decline, indicating that wellbore
scaling was restricting flow in both wells. Therefore,
the wells were cleaned out in early 1995, using a drill-
ing rig. With both wells back in production, the plant
was operated at a net output near 4.4 MWe. Well
production decline in mid-1995 required a new clean
out; thus, after this operation, a scale inhibitor system
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was installed and put in continuous operation in both
wells. In 1997, the output was 42.3 GWh, the avail-
ability factor was 99.5% and the load
factor 96.5%.
The actual installed geothermal power production
meets 20% of San Miguel Islands electricity demand,
which represents 50% of the Azorean total demand.
The CGRG plant is presently being expanded (Phase
B) with the installation of additional capacity of two-4 MWe ORMAT binary plants (Fig. 18). With the
addition of Phase B, it is expected that nearly 45% of
the electricity demand of San Miguel will
be met.
Figure 18. CGRG binary plant, Phase B (2x4 MWe), San
Miguel, Azores.
19. Mulka Station and Birdsville power plants, Aus-
tralia. The first successful geothermal power plant in
Australia, a Mulka cattle station, was put into opera-
tion in 1986. This unit is a 20-kWe binary cycle and
flash steam, 415 V, II phase unit located in South
Australia. A 150-kWe, binary plant has been con-
structed at Birdsville, Queensland. This power plant
uses 210oF (99oC) water from the towns well. This
well, flowing for 75 years, produces about 6,800 gpm
(30 l/s) at a shut-in pressure of 176 psi (1,213 kPa)
from a depth of about 3,900 feet (1,200 m). The cycle
efficiency is only 5% and parasitic losses reduce this
to 4%. The energy demand for the town varies from
60 to 150 kWe. The geothermal power alone suffices
when demand is low, but peaking with diesel power
is needed when the demand increases. The system
has been operating since 1992 and has achieved a ser-
vice factor of about 50% (Burns, et al., 1995).
20. Back pressure turbine, Bjarnarflag, Namafjall, Ice-
land, was installed in 1969. Based on exploration in
northern Iceland, a field temperature of 482 to 500oF
(250 to 260oC) was utilized to provide power to the
area through the Laxa Power Works, to gain experi-
ence in geothermal power generation, and to reduce
the use of imported and expensive fuel in their diesel
plants (Fig. 19). In order to minimize the construc-
tion time, a second-hand 2.5-MWe BTU back-pres-
sure industrial turbine-alternator set was purchasedin England (Ragnars, 1970). The design and erec-
tion of the power plant were carried out in seven
months.
The turbine itself was of simple design, with one Curtis
wheel and only two rows of blades on the rotor. It
runs on geothermal steam at 130 psi (9 bar) at the
inlet valve, a steam rate of 35 to 37 lbs/kWh (16 to 17
kg/kWh), with a back pressure of 0.7 psi (0.05 bar).
The rating is 3.4 MWe. The installed cost at the time
(1970) was $50/kW and the power generated at 0.45
to 0.55 cents/kWh delivered to the network. The
field also supplies steam to the Kisilidjan diatomiteplant, located adjacent to the site. The total electrical
production of the Bjarnarflag power plant in 1993 was
8.9 GWh.
Figure 19