June 1999 Geo-Heat Center Quarterly Bulletin

8/8/2019 June 1999 Geo-Heat Center Quarterly Bulletin

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VOL. 20, NO. 2 JUNE 1999 ISSN 0276

SMALL GEOTHERMAL

POWER PROJECTS
http://bull20-2.pdf/http://bull20-2.pdf/http://bull20-2.pdf/


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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

view of USDOE.

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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).
http://geoheat.oit.edu/bulletin/bull20-2/art1.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art1.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art1.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art2.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art2.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art2.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art3.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art3.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art3.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art4.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art4.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art4.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art4.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art5.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art5.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art5.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art1.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art2.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art3.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art4.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art5.pdfmailto:geoheat.oit.edumailto:geoheat.oit.eduhttp://www.oit.edu/~geoheathttp://geoheat.oit.edu/bulletin/bull20-2/cover.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/cover.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/cover.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/cover.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/cover.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/cover.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/cover.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/cover.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/cover.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/cover.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/cover.pdfhttp://www.oit.edu/~geoheatmailto:geoheat.oit.eduhttp://geoheat.oit.edu/bulletin/bull20-2/cover.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art5.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art4.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art3.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art2.pdfhttp://geoheat.oit.edu/bulletin/bull20-2/art1.pdf


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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-


4/36

2 GHC BULLETIN, JUNE 1999

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


5/36


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.


6/36


Figure 4. Simplified flow diagram for a basic binary geo-


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-



7/36


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.


8/36


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)


9/36


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.


10/36


[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


11/36


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


12/36


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


13/36


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.


14/36


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.


15/36


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).


16/36


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.


18/36


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.,


19/36


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


22/36


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

Documents

June 1999 Geo-Heat Center Quarterly Bulletin