Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
Unalaska Geothermal Electrical Power Generation Analysis-Final Report 1984
THE UNALASKA GEOTHERMAL EXPLORATION PROJECT ELECTRICAL POWER GENERATION ANALYSIS =FINAL REPORT Prepared By: Republic Geothermal,Inc. For: The Alaska Power Authority April 1984 UNA 008 c.2 DATE ISSUED TO HIGHSMITH:==42-225 PRINTEDINU.SA. DATE ISSUED TO TABLE OF CONTENTS Page Executive Summary .2.2 2 2 ww ew we ee ww ee we we we tw ew ws 1 Introduction..2 2 2 2 ww wwe we ee ww ee ee ew eee 2 Power Conversion Options.ee 3 Power Conversion Process Description....1...2.2 2 ee ee eevee 5 Flash Steam Process Description .......+s+ee-re | Binary Process Description..........26200e6-.8 rr 8 Hybrid Process Description.......ee we se ee ee 8 Total Flow Process Description......."oe .cee ew VW Power Plant Constructors..2...2 2 ee ew ww ee ee we ww we ee 13 Load Forecasts.2.2.1 6 2 we we ww we ew we ww we ee we re |) Unit Sizing and Scheduling.....we eeeeeee 21 Geothermal Power Development Technical Characteristics........4..29 Geothermal Power Development Cost Comparisons .........46+s80e08-39 Positive and Negative Aspects of each Type of Power Plant Considered...45 Power Conversion Process Recommendation .........6506-e0.60e6-e0042028 47 Binary System Development Costs ..1...2.2.2 wwe ww ee we we 48 Conclusions ..2...1 ew ee we tw we wt tt wh ww et tt te tt 57 13 14 15 LIST OF FIGURES Page Single-Flash Steam Process -Schematic Flow Diagram.......6 Double-Flash Steam Process -Schematic Flow Diagram.......7 Binary Process -Schematic Flow Diagram..........2.246-.9 Hybrid Process -Schematic Flow Diagram..........2.2.6.10 Total Flow Process -Schematic Flow Diagram...........12 No-Bottomfish Development Case -Average and Maximum Power Demands as Estimated by Acres American,Inc.......226srrr 7 Low-Bottomfish Catch Case -Average and Maximum Power Demands as Estimated by Acres American,Inc...2.2.2.6 ee ew ew we we ew we we eww 18 No-Bottomfish Development Case -Electrical SystemLoadDemands..2...1 2-5 ww we we ww we wee wt wh we ww 19 Low-Bottomfish Catch Case -Electrical System | Load Demands........2.2.a 20 No-Bottomfish Development Case -Power GenerationDevelopmentSchedule...2...6 0 ee we ew we we ew we we ww 23 No-Bottomfish Development Case -Power Generation During Normal Operation -All Units Available.........24 No-Bottomfish Development Case -Power Generation During Emergency Operation -Largest Unit Down and Second Largest Unit Trapped.......2.2 2 ee wees 25 Low-Bottomfish Catch Case -Power Generation Development Schedule...1...6 ee we we we ee ww we ew ee 26 Low-Bottomfish Catch Case -Power Generation During Normal Operation -All Units Available .........27 Low-Bottomfish Catch Case -Power Generation During Emergency Operation -Largest Unit Down and Second Largest Unit Trapped ..........24-242420046-s 28 11 List of Fiqures (continued) Fiqure 16 VW 18 19 20 21 22 23 ii Page Potential Net Power Generation of Average Production Well When Using Single-Flash Steam Cycle.........2.2..33 Potential Net Power Generation of Average Production Well When Using Double-Flash Steam Cycle............34 Potential Net Power Generation of Average ProductionWellWhenUsingBinaryCycle...1...1.1 5 ee we ew wwe 35 'Potential Net Power Generation of Average ProductionWellWhenUsingHybridCycle...2...1 2 ew ew ew we we ww 36 Potential Net Power Generation of Average Production Well When Using Total Flow Cycle.........42....37 Geothermal Power Plant -Total Installed Cost*vs Power Plant Unit Size...1 1 we ew we et we we tt tw te tw we 42 Geothermal Power Plant -Installed Cost Per kw vs Power Plant Unit Size Based on Continental USA Construction.....43 Geothermal Power Plant -Installed Cost Per kw vs Power Plant Unit Size Based on Unalaska Construction..........44 IST OF TABLES Page No-Bottomf ish Development Case -Geothermal Power Development Technical Matrix...1...2.2.2 2 eee eee 30 Low-Bottomfish Catch Case -Geothermal Power Development Technical Matrix....2.0...26605 eee eee 31 No-Bottomfish Development Case -Geothermal Power Development Capital Costs Matrix.....2...2 ew eee 40 Low-Bottomfish Development Case -Geothermal PowerDevelopmentCapitalCostsMatrix........5622eeee 4] No-Bottomfish Development Case -Unalaska 10 MW Gross (6.7 MW Net)Binary Power Plant Development-Costs.......49 Low-Bottomfish Catch Case Unalaska 30 MW Gross (20 MW Net)Binary Power Plant Development Costs - All Wells Drilled in First Phase of Power Development.....50 Low-Bottomfish Catch Case -Unalaska 30 MW Gross (20 MW Net)Binary Power Plant Development Costs - Wells Drilled as Needed in Each Phase of PowerPlantDevelopment...2.7.2.2 wwe we ew ewe th we ew te 51 No-Bottomfish Development Case -Unalaska 10 MW Gross (6.7 MW Net)Binary Power Plant -Combined Plant and Field Annual Operation and Maintenance Costs .......52 Low-Bottomfish Catch Case -Unalaska 30 MW Gross (20 MW Net)Binary Power Plant -Combined Plant and Field Annual Operation and Maintenance Costs .......53 iv EXECUTIVE SUMMARY The objective of this study was to determine the most cost-effective powercycleforutilizingtheMakushinVolcanogeothermalresourcetogenerate electricity for the towns of Unalaska and Dutch Harbor.It is anticipated that the geothermal power plant would be intertied with a planned conventional power plant consisting of four 2.5 MW diesel-generators whose commercial operation is due to begin in 1987.Upon its completion in late 1988,the geothermal power plant would primarily fulfi11 base-load electrical power demand while the diesel-generators would provide peak-load electrical power and emergency power at times when the geothermal power plant would be partially or completely unavailable. This study compares the technical,environmental,and economic adequacy offive"state-of-the-art”geothermal power conversion processes.Options con- sidered are single-and double-flash steam cycles,binary cycle,hybrid cycle, and total flow cycle. The power plant designs considered were limited to those capable of beingunitizedinpre-assembled and pre-tested modules so as to.facilitate transpor- tation,erection,and start-up.The size and number of units were determined by an evaluation of commercially available units and by an analysis of the electrical load demands as estimated by Acres American,Inc.for APA.As requested by APA,both "no-bottomfish demand"and "low-bottomfish catch"cases were considered. Because of the uncertainties in the electrical load forecasts it 1s recom- mended heretn that the geothermal power plant be developed in phases that aretimedtothegrowthindemand.The first phase of development should consist of two identical 5 MW gross binary units capable of generating a total of 6.7 MW net of electrical power.This plan satisfies the estimated demand for the no-bottom fishing case past the year 2000. Should bottom fishing take place and electrical load demand increase in accordance with the "low-bottomfish"projections,then a second and third phase would be added to become commercial in early 1993 and 2000 respectively.Each of these two phases would comprise two 5 MW gross binary units identical to those installed in Phase I. The binary cycle was selected because 1t is the most economical process in the small unit size considered,it is efficient,it does not incur the risk of freezing during winter months operation and it can be installed quickly,thus adding scheduling flexibility. INTRODUCTION The city of Unalaska,a community in the Aleution Island region of south- western Alaska is expanding and modernizing the electric power systems in the towns of Dutch Harbor and Unalaska.As part of this electrification program, a larger electrical distribution system is being built,an old power house is being refurbished and the installation of four 2.5 MW diesel-generator units is being planned. Acres American Inc.has been requested by the Alaska Power Authority (APA) to prepare an economic study to determine how to supplement the electricity produced by the diesel-generating system as the system demand grows and thus, minimize reliance on high cost diesel-fired power generation.Because the state of Alaska is attempting to utilize indigenous energy sources located close to population centers,one of the options being considered is the use of geothermal energy. A significant geothermal resource was discovered in 1983 as a result of the Unalaska geothermal exploration project conducted by Republic GeothermalInc.for the APA.A small diameter resource confirmation well,Makushin ST-1, was drilled in the flank of the Makushin Volcano which is.located within 12 miles of the towns of Unalaska and Dutch Harbor.A short test of the well yielded fluid from that flowed from a three-inch orifice at 47,000 lb/hr with a 16 percent steam flash.Analyses of samples collected during the flow test indicate that the reservoir contains a sodium-chloride type water with a total dissolved solids (TDS)content of approximately 6,000 ppm by weight and that the preflash carbon dioxide content is 217 ppm.At these low concentrations, the dissolved solids and gases are not expectedto pose any problems in theconversioncycles. While more testing is necessary to further characterize and delineate the resource,theoretical calculations predict that a full-scale production well would yield approximately 900,000 lb/hr at a pressure of 57 psia both of which parameters are more than adequate for commercialization. The study that is described below establishes the best means of generating electricity from the Makushin resource,presents a power generation develop- ment scenario based on estimated load forecasts and estimates the cost of commercializing geothermal power on Unalaska.The report addresses all of the tasks listed in the "scope of work"section of Amendment No.6 to Contract CC-08-2334 as modified by the letter dated February 2,1984 from the APA. POWER CONVERSION OPTIONS The conversion of hydrothermal energy from Makushin-type liquid-dominated geothermal resource into electric power can be accomplished by the following processes: 1.Flash Steam In the flash steam process,steam is produced from the geothermal fluid by reducing the pressure of the fluid below the saturated liquid pressure.The steam is then used to directly power a turbine, which in turn drives an electric generator. 2.Binary In the binary process,a low boiling point fluid,such as freon or isobutane,1s passed through a heat exchanger where it is vaporized by proximity to the geothermal brine.The superheated vapor is then used to power a turbine,which in turn drives an electric generator... "te 3.Hybrid In the hybrid process,part of the geothermal fluid is flashed into steam which is used to drive a steam turbine-generator.The residual Fluid is then used to vaporize a low boiling point fluid through a heat exchanger.The superheated vapor produced is then used to powerasecondturbine-generator.-- 4.Total Flow In the total flow process,all of the geothermal fluid is expanded through a mechanical device which converts both thermal and kinetic energy of the well fluid into shaft work (torque).This shaft work is then used to drive an electric generator. Numerous commercial power plants using the flash steam process are in operation and several more are under construction in various locations throughout the world.Notable examples of successful geothermal flash steam plants include installations in the Imperial Valley of the United States,New Zealand,Mexico,Japan,The Philippines,and Iceland.It is safe to say that the flash steam process 4s proven. One 10 MW geothermal binary plant is presently operating successfully in the Imperial Valley and a number of others are under construction in the United States.While the binary process has not been widely used to date in geothermal applications,the organic fluid Rankine cycle has been used extensively over the years in petrochemical and waste heat recovery plants. The binary process is,therefore,considered to be technologically proven,at least in units in the 0.5 to 5.0 MW size range. aeThere are no operating geothermal power plants using the hybrid cycle atthepresenttime,however,Republic Geothermal,Inc.1s planning to build one soon in the Imperial Valley.The hybrid process is simply the combination of two proven processes (flash steam and binary)for greater conversion effici- ency and it is,therefore,considered to be proven as well. The total flow process,which was developed specifically for geothermalapplication,comes in technically different options which are in various stages of development.The two best known are the Sprankle helical screw expander and the Biphase rotary separator turbine.The Sprankle expander has been tested extensively on a smal]scale,and may be ready for commerciali- zation.A full-scale version of the Biphase turbine has been tested successfully in Utah for the last few months and is definately ready for commercialization.The Biphase turbine does not involve significant technical risks and is considered to be state-of-the-art. Only state-of-the-art processes are being considered for the commercial development of the Unalaska Island resource. rm POWER CONVERSION PROCESS DESCRIPTIONS Flash Steam Process Description Both single and double flash steam options have been considered in this study. 1.Single Flash Steam Process Two-phase geothermal fluid produced by the wells 4s piped to a steam separator where the steam is separated from the geothermal water. The steam ts then piped from the separator to a steam turbine- generator where it is expanded to produce electrical power.The exhaust steam from the turbine is then ducted to an extended-surface,air-cooled heat exchanger where its ts condensed by rejecting heat to the atmosphere.Noncondensable gases are removed from the condenser by a combination of steam jet ejectors and liquid-ring vacuum pumps. Condensate pumps transfer the warm water from the condenser to an injection surge tank.* The residual geothermal water flows from the separator into the injection surge tank where it 1s mixed with the condensate from the steam cycle.The water is then pumped out of the surge tank and injected back into the ground. Figure 1 1s a schematic flow diagram of the single flash steam process. Double Flash Steam Process Two-phase geothermal fluid produced by the wells is piped to a steam separator where the high-pressure steam is separated from the geothermal water.The geothermal water then flows to a flash tank where low-pressure steam is generated by reducing the pressure. High-and low-pressure steam from the separator and the flash tank is piped to a dual inlet steam turbine-generator where it is expanded to produce electrical power.The exhaust steam from the turbine is ducted to an extended-surface,air-cooled heat exchanger where it is condensed by rejecting heat to the atmosphere.Noncondensable gases are removed from the condenser by a combination of steam jet ejectors and liquid-ring vacuum pumps.Condensate pumps transfer the warm water from the condenser to an injection surge tank. The residual geothermal water is transferred out of the flash tank into the injection surge tank where it is mixed with the condensate from the steam cycle.The water is then pumped out of the surge tank and injected back into the ground by the injection pumps. Figure 2 ts a schematic flow diagram of the double flash steam process. ora FIGURE 1 SINGLE FLASH STEAM PROCESS SCHEMATIC FLOW DIAGRAM os PRODUCTION WELLS RESIDUAL HOT WATER > - INJECTION SURGE TANK STEAM TO ATMOSPHERE NON-CONDENSIBLE GASES>EVACUATION SYSTEM STEAM SEPARATOR A STEAM}(TURBINE-GENERATOR (% <q- INJECTION PUMPS AIR COOLED CONDENSER ' CONDENSATE PUMPS -e 7 hoon) INJECTION WELLS RCL E1485 FIGURE 2 DOUBLE FLASH STEAM PROCESS SCHEMATIC FLOW DIAGRAM LOW PRESSURE STEAM HIGH PRESSURE STEAM STEAM SEPARATOR "- >HOT WATER TRANSFER PUMPS -S PRODUCTION WELLS fantTO ATMOSPHERE FLASH TANK U INJECTION .SURGE RESIDUAL WATER TANK NON-CONDENSIBLE GASES EVACUATION SYSTEM A STEAM(TURBINE-GENERATOR Y,AIR COOLED CONDENSER UU ' CONDENSATE PUMPS -eyINJECTION PUMPS. haeeorar) INJECTION WELLS RCI E1406 Binary Process Description Two-phase geothermal fluid produced by wells is piped to a steam separatorwherethesteamisseparatedfromthegeothermalwater. The steam and water are piped separately from the separator to a series of shell-and-tube-heat exchangers.The water preheats and evaporates the binary fluid,which can be a hydrocarbon such as isobutane or a fluocarbon such as freon R-114.The steam superheats the binary fluid vapor.The superheated fluid vapor ts then ptped to a binary turbine-generator where it is expanded to produce electric power. The exhaust vapor from the turbine is then ducted to an extended-surface, air-cooled:heat exchanger where it is condensed by rejecting heat to the atmosphere.Condensate pumps transfer the binary fluid condensate from the condenser back to the binary fluid heat exchangers where the cycle is repeated. Cooled geothermal water and steam condensate flow from the binary fluidheatexchangersintoaninjectionsurgetank.The water ts then pumped out ofthesurgetankandinjectedbackintotheground.* Figure 3 ts a schematic flow diagram of the binary process. Hybrid Process Description Two-phase geothermal fluid produced by the wells is piped to a steam separator where the steam 1s separated from the geothermal water. The steam is piped from the separator to a steam turbine-generator whereitsisexpandedtoproduceelectricpower.The exhaust steam from the turbine is directed to an extended-surface,air-cooled heat exchanger where it is condensed by rejecting héat to the atmosphere.Noncondensable gases are removed from the condenser by a combination of steam jet ejectors and liquid- ring vacuum pumps.Condensate pumps transfer the warm water from the condenser to an injection surge tank. The residual geothermal water flows from the separator to a serie of shell-and-tube heat exchangers where it preheats,evaporates,and superheats the binary fluid,which can be a hydrocarbon such as isobutane or a fluocarbon such as freon R-114.The superheated binary fluid vapor is piped to a binary turbine-generator where it is expanded to produce electric power. The exhaust vapor from the binary turbine is ducted to a second extended- surface,air-cooled heat exchanger where it is condensed by rejecting heat to the atmosphere.The binary fluid condensate is then transferred by the con- densate pumps from the binary fluid condenser back to the binary fluid heat exchangers where the cycle is repeated. Cooled geothermal water flows from the binary fluid heat exchangers into the injection surge tank and mixes with the condensate from the steam cycle. The water is then pumped out of the surge tank and injected back into the ground. Figure 4 1s a schematic flow diagram of the hybrid process.| 8 teeFIGURE 3 BINARY PROCESS | SCHEMATIC FLOW DIAGRAM STEAM CONDENSATE STEAM | od > STEAM . .' < BINARY FLUID BINARY FLUID BINARY FLUIDSEPARATORSUPERHEATEREVAPORATORPREHEATER --p>t BINARY FLUID =x TURBINE-GENERATOR £ |5 AM">HOTWATER CONDENSATE BINARY FLUID PUMPS CONDENSER RESIDUAL WATER INJECTION SURGE t .TANK G <q INJECTION PUMPS x. PRODUCTION WELLS Loony : INJECTION WELLS RCL E1487 OTFIGURE 4 HYBRID PROCESS SCHEMATIC FLOW DIAGRAM PRODUCTION WELLS STEAM STEAM TURBINE-GENERATOR TO ATMOSPHERE MON Cee OLEee>Es EVACUATIONTEMSTEAM->SEPARATOR S BINARY FLUID _BINARY FLUID jr HOT WATER >.| EVAPORATOR-PREHEATER EVAPORATOR.AIR COOLED CONDENSER STEAM CONDENSATE BINARY FLUID |INJECTION TURBINE-GENERATOR SURGE 'AN*PUMPS >TANK N RESIDUAL WATER | .\AMN"'>)INJECTION BINARY FLUID PUMPS BINARY FLUID CONDENSATE AIR COOLED CONDENSER PUMPS Loy haemany INJECTION WELLS AGL E1408 Total Flow Process Description Two-phase geothermal fluid produced by the wells ts piped to a steamseparatorwherethesteamisseparatedfromthegeothermalwater. The steam is piped from the separator to the high-pressure inlet of a steam-turbine generator.The separated geothermal water is piped to a two- phase nozzle which converts the thermal and pressure energy of the expanded liquid and gas mixture to high efficiency fluid kinetic energy.The two-phase jet is directed tangentially on the inner surface of the rotary separator where steam and water are separated by centrifugal forces.A liquid turbine rotor mounted into the rotary separator converts the kinetic energy of the liquid to shaft power.The turbine shaft is connected to one end of the double-ended electric generator. The resulting low-pressure steam from the rotary separator is piped to thelow-pressure inlet of the steam turbine-generator where it is expanded together with the high-pressure steam to produce electric power.The exhaust steam from the turbine is then ducted to an extended-surface,-air-cooled heat exchanger where it is condensed by rejecting heat to the atmosphere.Non- condensable gases are removed from the condenser by a combination of steam jet ejectors and liquid-ring vacuum pumps.Condensate pumps transfer the warm water from the condenser to an injection surge tank. The residual geothermal water from the rotary separator flows into the injection surge tank where it is mixed with the condensate from the steam cycle.The water is then pumped out of the surge tank and injected back into the ground._ :. Figure 5 is a schematic flow diagram of the total flow process using a Biphase rotary separator., While the Sprankle helical screw expander may be a viable candidate machine for conversion of geothermal energy by the total flow process,it is not considered in this study due to lack of available test data and to the large physical size required to produce significant power output. However,should it be used,the geothermal fluid produced by the wells would be piped directly to the positive-displacement device which operates by direct expansion of the two-phase fluid meshing rotors.The fluid entering through a nozzle control valve into a high-pressure pocket is expanded through a pocket that elongates continually as the rotors revolve all the way down to the exhaust port. ll FIGURE 5 TOTAL FLOW PROCESS SCHEMATIC FLOW DIAGRAM HIGH PRESSURE STEAM TO ATMOSPHERE STEAM LOW PRESSURE STEAM SEPARATOR NON-CONDENSIBLE->>GASES ROTARY evenSEPARATOR TURBINE A HOT WATER |bn TWO-PHASE STEAM NOZZLE Lt TURBINE-GENERATORre (maamummanememeee ad A AIR COOLED CONDENSER RESIDUAL RATES|INJECTION SURGE <q | «CONDENSATE INJECTION PUMPS PUMPS i, PRODUCTION WELLS - INJECTION WELLS OGL E14e9 weerinPOWER PLANT CONSTRUCTORS Geothermal power plants can be designed,engineered,and constructed by Engineering-Construction (E&C)companies or by Equipment Manufacturing Companies. 1.Engineer ing-Construction Typically,E&C companies do not manufacture,but they do specify,select,and purchase the equipment which is integrated into the overall power plant design.Because of their large and diversified staff,E&C companies can select the optimum cycle for the resource as well as optimize and engineer any selected power cycle.While they do not warrant individual pieces of equipment used to construct the plant,they will ensure that the equipment manufacturers do so andwillguaranteetheoverallplantperformanceandworkmanship. The following is a short list of E&C companies having geothermal power plant experience. te a.Large E&C Firms: Bechtel Power Corporation 12400 E.Imperial Highway Norwalk,CA 90650 Phone:(213)864-6011 Contact:Joseph A.Falcon Fiuor Engineers and Constructors,Inc. 3333 Michelson Drive Irvine,CA 92730 Phone:(714)975-6839 Contact:Jake Easton III The Ralph M.Parsons Co. 100 West Walnut St. Pasadena,CA 91124 Phone:(213)440-2000 Contact:Roy E.Gaunt Gibbs and H1i11,Inc. 226 W.Brokaw Road San Jose,CA 95110 Phone:(408)280-7091 Contact:Larry R.Krumiand Morrison-Knudsen Co.,Inc. P.0.Box 7808 Boise,ID 83729 Phone:(208)386-5000 Contact:Frank G.Turpin 13 b.Small E&C Firms: The Ben Holt Co. 201 South Lake Ave. Pasadena,CA 91101 Phone:(213)684-2541 Contact:Clement B.Giles Ultrasystems,Inc. 2400 Michelson Drive Irvine,CA 92715 Phone:(714)752-7500 Contact:Phillip J.Stevens Equipment Manufacturers Typically Equipment Manufacturers,generally turbine-generator and/or heat exchanger manufacturers,prepackage power module assemblies incorporating their own equipment into the overall power 'plant design.Because most equipment manufacturers specialize in one segment of the industry,they can only offer one type of power cycle which may or may not be optimum for the resource.The following is a short list of equipment manufacturing companies that design,engineer, and butld geothermal power plants: a.Equipment Manufacturers for Flash Steam Plants General Electric Company 1100 Western Ave. Lynn,MA 01910 Phone:(617)594-4146©Contact:Howard C.Spears Fuji Electric Company,Ltd./Nissho Iwai American Corp. Broadway Plaza,Suite 1900 700 South Flower St. Los Angeles,CA 90017 Phone:(213)688-0671 Contact:Mikio (Michael)Ikukawa Mitsubishi International Corp. 555 South Flower St. Los Angetes,CA 90071 Phone:(213)977-3767 Contact:Sam Miyamoto Toshiba International Corp. 465 California St.,Suite 430 San Francisco,CA 94104 Phone:(415)434-2340 Contact:Htsashi Ohtsuka 14 erEquipment Manufacturers for Binary and Hybrid Plants Ormat Systems Inc. 168 Sendra Ave. Arcadia,CA 91006 Phone:(213)445-4202 Contact:H.Ram Mechanical Technology Inc.968 Albany-Shaker Road Latham,NY 12110 Phone:(518)785-2400 Contact:Thomas E.Williams Barber-Nichols Engineering 6325 West 55th Avenue Arvada,CO 80002 Phone:(303)4213-8111 Contact:Kenneth Nichols "te Equipment Manufacturers for Total Flow Plants Biphase Energy Systems 2800 Airport Ave. Santa Monica,CA 90405 Phone:(213)391-0691 Contact:Donald J.Cerini Hydrothermal Power Co.,Ltd. P.0.Box 2794 Mission Viejo,CA 92690 Phone:(714)837-3081 Contact:Roger Spankle 15 QAD_FORECASTS _- The electrical load forecasts for Unalaska and Dutch Harbor have recentlybeendevelopedaspartofareconnatssancestudyfortheAlaskaPowerAuthority by Acres American Inc.As requested by the Alaska Power Authority,only the "No-Bottomfish Development"case and the "Low-Bottomfish Catch*case are being considered in this study.Figures 6 and 7 show the average and maximum power demand estimated by Acres American Inc.for these two cases. The average power demand,which 1s calculated by dividing the annual energy use by 8760 hours,is less than 30 percent of the maximum power demand, indicating possible large seasonal and/or daily demand variations.Discussion with Mr.Jeff Currier of Unalaska Public Utility to clarify this matter seems to disprove this interpretation of the data.While the calculated average power demand appears to be representative of the expected base load demand for the electrical system,he does expect this base load demand to be less than approximately 60 percent of maximum power demand. In the absence of load duration curves showing daily and seasonal variations in estimated load demand,it is therefore assumed that the electrical system base load demand is the average load demand estimated by Acres and that it 4s 60 percent of the system peak load demand.Figures 8 and 9 show both base load and peak load demands assumed for the two cases under study. 16 "LTELECTRICALPOWERDEMAND-MWFIGURE 6 NO BOTTOMFISH DEVELOPMENT CASE AVERAGE AND MAXIMUM POWER DEMANDS AS ESTIMATED BY ACRES AMERICAN INC. Ta 4b 4 MAXIMUM POWER DEMAND 12/- ne 10 9 Loe aL EL af- | ' al | . af ) 2h li- 0 t i l {I i i i j j i i |j i i 1 984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 YEARS AGI E1630 8TELECTRICALPOWERDEMAND-MWFIGURE 7 LOW BOTTOM FISH CATCH CASE AVERAGE AND MAXIMUM POWER DEMANDS AS ESTIMATED BY ACRES AMERICAN INC. 1986 1988 1990 1992 1994 1996 1998 2000 2002,--s 2004 YEARS AGI E1639 61ELECTRICALPOWERDEMAND-MWFIGURE8 NO BOTTOMFISH DEVELOPMENT CASE ELECTRICAL SYSTEM LOAD DEMANDS 4- 8 12- lif 10 9 l 8i- 7 PEAK LOAD DEMAND 6 ) . 51.: ; a BASE LOAD DEMAND4|cossesenntsetneacAnAS RISA EAS IK 2 1k 0 {];||tf 7 4 4 !}4 ||!a 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 YEARS AGI E1834 02ELECTRICALPOWERDEMAND-MWFIGURE 9 'LOW BOTTOMFISH CATCH CASE ELECTRICAL SYSTEM LOAD DEMANDS Ph i Pa SN DO RN SL ON DON EN DN DN SON DS GO A I NN DO DOO 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 YEARS AGI €1633 UNIT SIZING AND SCHEDULING It is anticipated that a geothermal power plant would be intertied with a planned conventional power plant to supply the electrical power needs of Unalaska and Dutch Harbor.The conventional power plant will consist of four 2.5 MW diesel generators and is scheduled to begin commercial operation in early 1987.To allow for orderly planning of financing,field development, and power plant/transmission line engineering and construction,the geothermal power plant would be scheduled to begin commercial operation in January 1989. Upon completion,the geothermal power plant would primarily provide base load power while the diesel generators would provide peak load and emergency power should the geothermal power plant be partially or totally disabled. Due to the remoteness of the geothermal construction site,the difficult site access and the need for high reliability,the geothermal power plant would be unitized.The size,number and phasing schedule of the geothermal units for each of the power conversion processes studied are determined as follows: 1.Unit Sizing . * Economical size of the units is determined by an evaluation of commercially available units.To minimize field erection and start-up operations,only units that can be completely or partially shop-assembled and tested in modules are considered.Modules are sized to be truck-transportable on both main throughfares and unpaved gravel roads.a 2.Determination of number of units and commercial operation schedule. The Number of units required to meet power demand forecasts and the commercial operation schedule for these units are determined by superimposing the net generating capacity of all units over the estimated power demands.During "normal operation",which is when all installed units are available for power generation,the net generating capacity of the geothermal units will always be kept above the electrical system base load demand.During "emergency operation", which is when the largest instailed unit is down for maintenance and the second largest installed unit is down on emergency trip,the net generating capacity of all remaining units will always be kept above the electrical system peak load demand. In order to meet the electrical system load demands estimated up to the year 2000 for both the "No-Bottomfish Development"and "Low-Bottomfish Catch" cases,a geothermal power plant using any one of the five different power conversion cycles studied could be used to meet the criteria described above. 21 1. No-Bottomfish Development Case. a.Single or double flash steam cycles. One 5 MW net unit to be commercial in January 1989 and one 5 MWnetunittobecommercialinJanuary2000. Binary cycle. Two 3.35 MW net units to be commercial in January 1989. Hybrid cycle. Three 3.35 MW net (1 steam and two binary)units to becommercialtnJanuary1989. Total flow cycle. One 5 MW net unit to be commercial in January 1989 and one 5 MWnetunittobecommercialinJanuary2000.- 2. Low-Bottomfish Catch Case. a.Single or double flash steam cycles. Two 5 MW net units to be commercial in January 1989,one 5 MWnetunittobecommercialinJanuary1993,and one 5 MW net unittobecommercialinJanuary1998.-. Binary cycle. ; Two 3.35 MW net units to be commercial in January 1989,two 3.35 MW net units to be commercial in January 1993,and two 3.35 MW net units to be commercial in January 2000. Hybrid cycle. Three 3.35 MW net (1 steam and two binary)units to be commercial in January 1989 and three 3.35 MW net units to be commercial in January 1997. Total flow cycle. Two 5 MW net units to be commercial in January 1989,two 5 MW net units to be commercial in January 1993,and two 5 MW net units to be commercial in January 1998. Figures 10 through 15 show the power generation development schedule,the power generation during normal operation,and the power generation during emergency operation for both the "no bottomfish development"and "low bottom- fish catch”cases for an electrical power system with a geothermal power plant using a binary cycle. 22 FIGURE 10 NO BOTTOMFISH DEVELOPMENT CASE POWER GENERATION DEVELOPMENT SCHEDULE 3.35 MW NET BINARY UNIT-e|2.5 MW DIESEL-GENERATOR { }ELECTRICALPOWERGENERATION&ELECTRICALPOWERDEMAND-MWae0= ;Se ss 1985 1987 1989 1981 1983 1995 1997 1999 2001 2003 2005 2007 . YEARS AGI E3529 ,23 ca FIGURE 12 NO BOTTOMFISH DEVELOPMENT CASE POWER GENERATION-EMERGENCY OPERATION LARGEST UNIT DOWN AND 7 SECOND LARGEST UNIT TRIPPED 3.35 MW NET BINARY UNIT e DISABLED UNIT 25 MW DIESEL-GENERATOR ome©oe©ome6em6gp6oe6oe6oeELECTRICALPOWERGENERATION&ELECTRICALPOWERDEMAND-MWoe,0.od 1985 1987 1989 1991 1993 1995 1987 1999 2001 2003 2005 2007 YEARS AGI £1527 25 FIGURE 13 LOW BOTTOMFISH CATCH CASE POWER GENERATION DEVELOPMENT SCHEDULE alaaa3.35 MW NET BINARY UNIT 2.5 MW DIESEL-GENERATOR ELECTRICALPOWERGENERATION&ELECTRICALPOWERDEMAND-MW- 1985 1987 1989 1991 1993 1995 1997 1989 2001 2003 2005 2007 . YEARS 26 RGI E1531 oe He ARR PEAK LOAD DEMAND: GEOTHERMAL POWER DEVELOPMENT TECHNICAL CHARACTERISITICS The technical characteristics of each geothermal power development altern- ative considered for both the "No-Bottomfish Demand"and Low-Bottomfish Catch" cases are shown on Tables 1 and 2.Each power development alternative includes both the power plant and the associated field development.The basis used in developing the power development technical matrices is defined below: 1.The electrical power generation capacity of each alternate power plant is determined by matching economically sized units to the power load demands estimated beyond the year 2000 for the electrical system, as described in the previous section "Unit Sizing and Scheduling." Due to the low average dry-bulb temperature of the air on Unalaska Island,a direct dry cooling system is incorporated into all altern- ative cycles.Ina dry cooling system the heat to be rejected from the power cycle is transferred through the walls of an air-cooled heat exchanger directly to the ambient air stream.Use of this system allows for 100 percent geothermal fluid reinjection and elim- inates the need for an outside source of water. Customarily a power plant is designed for a constant output that can be assured year-around,as determined by the capacity of the heat rejection system at reasonable worst-case conditions.Alternatively, a power plant can be designed to allow for a power output that wil} vary as the capacity of the waste heat rejection system is affected by ambient conditions.This variable output concept is termed "floating"power.-° The thermodynamic properties.of steam are not compatible with the variable output mode creating excessive in costs and efficiencies. Therefore,all steam flash alternatives are designed for a constant output mode based on a 50°F dry-bulb ambient temperature. The thermodynamic properties of organic hydrocarbons or fluocarbons do allow turbines to operate over a wide range of back pressure with only minor reductions of peak efficiencies;therefore,all binary alternatives have been designed for a floating output mode based on an average 30°F dry bulb ambient temperature. As described in the "Unit Sizing and Scheduling”section,each power plant unit is comprised of completely or partially shop-assembled and tested modules.This modular approach facilitates field erection and start-up as well as transportation.It has been assumed that modules would be barged from the mainland to Driftwood Bay where they would be unloaded and trucked to the construction site. 29 OfPower Plant Gross Power Generation Capacity Power Plant Net Power Generation Capacity Power Plant Heat Rejection Type Power Plant Uesign Aubient Temperature Power Plant Construction Type Shop Assembly Field Construction Transportation Power Plant Operation Number of Power Generation Units Largest Module Weight of Heaviest Module Maxine tet Power Generation Potential of Average Production Well Minimum Geothermal Fluid Flow Required per Net kw of Power Generation Mininum Total Geothermal Fluid Flow Required andCorrespanding Wellhead Pressure Mininum Number of Production Wells Required Nuuber of Production Wells Provided Average Flow per Production Well Production Wellhead Pressure Production Wellhead Temperature Percent Reinjection Minimum Nuwber of Injection Wells Required Number of Injection Wells Provided Average Flow per Injection Wel) Injection Wellhead Pressure Injection Wellhead Temperature Waste Oischarge to Atnwsphere Expected Reliability Expected Substainable Capacity Factor TABLE } NO-BOTTOMFISH DEVELOPMENT CASE GEOTHERMAL POWER DEVELOPHEN MATRIX Single Flash Steam Plant 11.2 MW 10 MW Dry Cooling 50°F Modular Max imum Minimum Barge &Truck Constant Output 2 Turb ine-Generator Sets 130,000 Ib 4.35 MW 206.9 1b/br 2,069,000 1b/hr at 57 psta 2.3 3 690,000 1b/br 75 psta 308°F 100% 1.15 2 1,035,000 1b/hr Atmospheric 260°F 476 1b/hr Noncondensable Gases High 65% Doubte FlashSteamPlant 11.5 MW 10 MW Dry Cooling 50°F ° Modular Max imum Mintmum Barge &Truck Constant Output 2 Turbine-Generator:Sets 145,000 1b 5.5 MW 163.6 Ib/hr 1,636,000 1b/hr at 57 psia 1.82 2 815,000 1b/br 65 psia 298°F 100% 91 1 1,636,000 1b/hr Atmospheric 200°F 376 lb/hr Noncondensable Gases High 85% Binary Plant 10 MW 6.7 MW Dry Cooling 30°F Modular Max {mum Minimum Barge &Truck Floating Output 2 .:Heat Exchangers 120,000 1b 6.1 MW 143.4 Ib/hr 961,000 tb/br at 59 psia 1.1 2 365,000 Ib/hr 96 psia 325°F 100% 53 1 961,000 1b/hr Atmospheric 170°F 221 1b/hr NoncondensableGases High 85% Hybrid Plant 14 AW 10 MW Dry Cooling 50°F (steam unit)30°F (binary units) Modular Max imum Minimum Barge &Truck Floating Output 3. (1 steam +2 binary) Heat Exchangers and Steam Turbine- Generator Sets 120,000 1b 6.75 Mw 133.3 Ib/hr 1,333,000 tb/hr at 57 psia 1.48 2 665,000 Ib/hr 77 psta 309°F 100% 1,333,000 Ib/hr Atmosphertc 170°F 307 lb/hr Noncondensable Gases High 85% Total Flow Plant 11.5 MW 10 MW Dry Cooling 50°F Modular Maximum Minimum Barge &Truck Constant Output 2 Turbine-Generator Sets 233,000 Ib 5.8 Mul 155.2 Ib/hr 1,552,000 Ib/hr at 57 psta 1.72 2 775,000 1b/br 68 psla 301°F 100% 1,552,000 1b/hr Atmospheric 200°F 357 1b/br Noncondensable Gases High 85% TePower Plant Gross Power Generation Capacity Power Plant Net Power Generation Capacity Power Plant Heat Rejection Type Power Plant Design Ambient Temperature Power Piant Construction Type Shop Asseubly Field Construction Transportation Power Plant Operation Number of Power Generation Units Largest Module Weight of Heaviest Module Maxiaum Net Power Generation Potential of Average Production Well Minimum Geothermal Fluid Flow Required per Net kw of Power Generation Minimum Total Geothermal Fluid Flow Required and Corresponding Wellhead Pressure Minimum Nuwber of Production Wells Required Number of Production Wells Provided Average Fluw per Production Wel} Production Wellhead Pressure Production Weljhead Temperature Percent Reinjection Mininum Number of Injection Wells Required Number of Injection Wells Provided Average Flow per Injection Well Injection Wellhead Pressure Injection Wellhead Temperature Waste Discharge to Atmosphere Expected Reliability Expected Sustainable Capacity Factor LOW-BOTTOMFISI]CATCH CASE TABLE @ GEOTHERMAL POWER DEVELOPMENT TECIINCIAL MATRIX Single Flash Steam Plant 22.4 Mu 20 MW Dry Cooling 50°F Modular Maximum Minimum Barge &Truck Constant Output 4 Turbine-Generator Sets 130,000 1b 4.35 MW 206.9 Ib/hr 4,138,000 1b/hr at 57 psta 4.6 5 +1 standby 825,000 1b/hr 64 psia 297°F 100% 2.3 3 +1 standby 1,379,000 1b/hr Atmospheric 260°F 952 Ib/hr Noncondensable Gases High B5% Double Flash Steam Plant 23 MW 20 MW Dry Cooling 50°F Modular Maximum Min inum Barge &Truck Constant Output 4 Turbine-GeneratorSetsrors 145,000 tb 5.5 MW 163.6 lb/hr 3,272,000 Ib/hr at 57 psia 3.64 4 +1 standby 815,000 1b/hr 65 psta 298°F 100% 1.82 2 +1 standby 1,636,000 1b/hr Atmospheric 200°F 752 Vb/hr Noncondensable Gases High 85% Binary Plant 30 MW 20 MW Dry Cooling 30°F Modular Maximum Minimum Barge &Truck Floating Output 6 Heat Exchangers 120,000 1b 6.1 MW 143.4 Vb/hr 2,883,000 Ib/hrat59psfa 3.3 4 +1 standby 595,000 1b/hr 82 psta 314°F 100% 1.6 2 +1 standby 1,442,000 1b/hr Atmosphertc 170°F 663 Ib/hr Noncondensable Gases High 85% Hybrid Plant 28 MW 20 HW Dry Cooling 50°F (steam unit)30°F (binary unit) Modular Maximum Minimum Barge &Truck Floating Output 6(2 steam +4 binary) Heat Exchangers and Steam Turbine- Generator Sets 120,000 1b 6.75 MW 133.3 Ib/hr 2,666,000 Ib/hr at 57 psia 2.96 3 +1 standby 890,000 Ib/hr 58 psia 291°F 100% 1.48 2 +1 standby 1,333,000 Ib/hr Atmospheric 170°F 614 Vb/hr Noncondensable Gases High 85% Total Flow Plant 23 MW 20 MW Dry Cooling 50°F Modular Maximum Minimum Barge &Truck Constant Output 4 Turbine-Generator Sets 213,000 1b 5.8 MW 155.2 Ib/hr 3,104,000 1b/hr at 57 psia 3.45 4 +1 standby 775,000 1b/hr 68 psia 301°F 100% 1.72 2 +1 standby 1,552,000 1b/tir Atmospheric 200°F 714 1b/hr Noncondensable Gases High 85% 10. The maximum net power generation potential of an average productionwell,the minimum geothermal fluid flow required per net kw of power generation,the minimum total geothermal fluid flow required and the minimum number of production wells required are derived from curves shown in Figures 16 through 20 where the wellhead pressure vs flow rate curve for a commercial well with 13-3/8 inch casing is cross- plotted with electricity generation curve for the various power cycles studied.To stay within safe operating conditions,the well flow and wellhead pressure have been limited to 900,000 1Ib/hr and 57 psia respectively. The average flow per production well,the production wellhead pres-sure and the production wellhead temperature are derived from the number of operating production wells provided.No-bottomfish development case power development does not include any dedicated spare production well as it cannot be economically justified. However,the "low-bottomfish catch®case power development does include one dedicated spare production well. The number of injection wells required is based on the assumptionthatoneinjectionwellwillbeabletodisposeof1,800,000 lb/hr of cooled geothermal fluid at atmospheric wellhead pressure. The average flow per injection well is derived from the number of operating injection wells provided. No-bottomfish development case power development does not include any dedicated spare injection well as it cannot be justified economically.However,the "low-bottomfish catch"case power development does include one dedicated spare injec- tion well. Waste discharge to atmospheric assumes total removal of the non- condensable gases contained in the geothermal fluid.Analysis of gas samples collected during the Makushin ST-1 test indicate,that very low initial concentrations of noncondensable gases (approximately -023 percent by weight)can be expected.The gases are predominantly C05(94%),plus Ho(5%),with traces of HoS,NH3,Ho,Ar, CH4,and He.They should therefore,not pose any problems in the conversion cycles and can be directly discharged to atmosphere. The composition of liquids produced from the Makushin Resource is given in the Unalaska Geothermal Exploration Project Phase II Final Report.The geothermal fluid,averaging approximately 6,000 ppm total dissolved solids (TDS),is not expected to be corrosive or to pose any scaling problems,thus allowing for use of standard con- struction materials.Because of the benign nature of the fluid, filtration is not expected to be required prior to reinjection of the spent fluid. 32 €€WELLHEADPRESSURE-PSIA120 100 40 20 FIGURE 16 POTENTIAL NET POWER GENERATION OF AVERAGE PRODUCTION WELL WHEN USING SINGLE FLASH STEAM CYCLE MAXIMUMFLOW100 200 300 400 500 600 700 800 WELL FLOW -1000 LBS/HR POTENTIALNETPOWERGENERATION-MW> AG!E1660 veFIGURE 17 POTENTIAL NET POWER GENERATION OF AVERAGE PRODUCTION WELL , WHEN USING DOUBLE FLASH STEAM CYCLE 120 }--16 100 j- 80 -WELLHEADPRESSURE-PSIARP 40 we {CodPOTENTIALNETPOWERGENERATION-MWMAXIMUMFLOW20}-é !{|!I |!!|| 100 200 300 400 500 600 700 800 900 WELL FLOW-1000 LBS/HA =o AGIE1661 GEWELLHEADPRESSURE-PSIA120 100 40 20 FIGURE 18 POTENTIAL NET POWER GENERATION OF AVERAGE PRODUCTION WELL WHEN USING BINARY CYCLE yeoo”MAXIMUMFLOW100 200 300 400 500 600 WELL FLOW -1000 LBS/HR 700 POTENTIALNETPOWERGENERATION-MW.RGUE 1669 9EWELLHEADPRESSURE-PSIAFIGURE 19 POTENTIAL NET POWER GENERATION OF AVERAGE PRODUCTION WELL WHEN USING HYBRID CYCLE 120 = 100 } 60 t- 40|-ace 0 l>POTENTIALNETPOWERGENERATION-MWMAXIMUMFLOW20;--- l L | 100 200 300 400 500 600 700 800 900 WELL FLOW-1000 LBS/HR o> AGI E 1668 LEWELLHEADPRESSURE-PSIAFIGURE 20 POTENTIAL NET POWER GENERATION OF AVERAGE PRODUCTION WELL WHEN USING TOTAL FLOW CYCLE 4 8 ; 100 F- i 5 -z 2 80 14 E cc iu = = as ao fr60}-"I = eo Q -pee5?== Ve =]140i-Ve i -j]2 <4\u =Sy?s -ACK 5 a -°F =be .5 2 201-=-i1 i l !l l !_ 100 200 300 400 500 600 700 800 900 WELL FLOW-1000 LBS/HR AGIE 1662 11.All alternative power plants on Makushin Volcano are assumed to be enclosed and include the following three main prefabricated buildings: a. . Db ° A power building;housing the power generation equipment. A control building;housing the control room,switch gear,and Jaboratory. A maintenance butlding;housing the maintenance shop,the ware- house for storage of spare parts,and the living quarters for the crew. 38 ca GEOTHERMAL POWER DEVELOPMENT COST COMPARISONS The capital costs required to develop geothermal power using each of thealternativeprocessesconsideredforboth"No-Bottomfish Demand"and "Low- Bottomfish Catch"cases are shown on Tables 3 and 4.Each power development alternative includes power plant costs and associated major field development costs.Costs for infrastructure items,such as road and transmission line, are not included as they are identical for all alternatives.All costs are in 1983 dollars and do not include escalation and interest during construction. Power plant costs are limited to the costs of the power generation units and are broken down as follows: 1.Power plant engineering and fabrication costs which include engineering,shop fabrication and testing of power modules, prefabrication of auxiliary systems and transportation to Driftwood Bay. 2.Power plant constructton costs which include transportation fromDriftwoodBaytojobsite,construction camp,construction labor,and construction management.Construction costs at the Unalaska site are estimated to be four times the construction costs at a site in the continental United States. Associated field development costs are limited to the following major items:. 1.Production well costs which include drilling,completion,and short testing of all production wells to be provided to supply the geo- thermal fluid flow required by the power plant. 2.Injection well costs which include drilling,completion,and shorttestingofallinjectionwellstobeprovidedtodisposeofthe residual geothermal fluid flow from the power plant. 3.Production pipeline costs which include engineering and construction of insulated pipeline between production wells and power plant. 4.Injection pipeline costs which include engineering and construction of noninsulated pipeline between power plant and injection wells. Costs include injection pumps as required. Figures 21,22,and 23 were developed to show the total installed cost and the installed cost per kw of a geothermal power plant,using each alternative process considered,based on power generation unit size.To illustrate the impact of the high construction costs estimated for the Island of Unalaska,we have shown both the installed costs at a hypothetical site in the "lower 48" United States and the costs at the site on Unalaska Island. It ts notable that the cost per installed kw of geothermal power decreases substantially as the power generation unit size increases,particularly for flash steam plants. 39 OvTABLE 3 NO-BOTTOMFISH DEVELOPMENT CASE GEOTHERMAL POWER DEVELOPMENT CAPITAL COSTS MATRIX ALL COSTS IN THOUSANDS OF 1983 DOLLARS Single Flash Double Flash Total Flow Steam Plant Steam Plant Binary Plant Hybrid Plant Plant Power Plant Net Generating Capacity 10 MW 10 MW 6.7 MW 10 MW 10 MW Number of Power Generation Units 2 2 2 3 2 Power Plant Engineering and Fabrication Costs 14,820 17,000 8,590 14,520 18,720 Power Plant Construction Costs 21,800 24,800 ,11,440 20,080 27,200 Subtotal Installed Power Plant Costs |36,620;41,800 20,030 34,600 45,920 Number of Production Wells Provided 3 ,2 2 2 2 Number of Injection Wells Provided 2 ]J 1:] Production Well Costs "8,151 6,099 6,099 6,099 6,099 Injection Well Costs 3,200 1,600 1,600 1,600 1,600 Production Pipeline Costs 1,445 963 |963 963 963 Injection Pipeline Costs 900 680.453 453 680 Subtotal Field Development Costs 13,696 -9,342.9,115 9,115 9,342 Total Geothermal Power Development Costs 50,316 51,142 29,145 43,715 55,262 Cost Per MW of Net Power Generated 5,031.6 5,114.2 4,350 4,371.5 5,526.2 TvTABLE 4 LOW-BOTTOMFISH DEVELOPMENT CASE GEOTHERMAL POWER DEVELOPMENT CAPITAL COSTS MATRIX ALL COSTS IN THOUSANDS OF 1983 DOLLARS Single Flash Double Flash Total Flow Steam Plant Steam Plant Binary Plant Hybrid Plant Plant Power Plant Net Generating Capacity 20 MW 20 MW 20 MW 20 MW 20 MW Number of Power Generation Units 4 4 6 6 4 Power Plant Engineering and Fabrication Costs 28,160 32,300 25,770 29,040 37,440 Power Plant Construction Costs 41,420 47,120 34,320 40,160 54,400 Subtotal Installed Power Plant Costs 69,580 -79,420 60,090 69,200 91,840 Number of Production Wells Provided 6 5 5 4 5 Number of Injection Wells Provided .|3 3 3 3 Production Well Costs 14,907 12,555 12,555 10,503 12,555 Injection Well Costs 6,400 4,800 4,800 4,800 4,800 Production Pipeline Costs 2,701 2,25),2,251 1,801 2,251 Injection Pipeline Costs .2,718 2,038 -1,359 _1,359 2,038 Subtotal Field Development Costs 26,726 21,644 20,965 18,463 21,644 Total Geothermal Power Development Costs 96,306 101,064 81,055 87,663 113,484 Cost Per MW of Net Power Generated 4,815.3 5,053.2 4,052.8 4,383.2 5,675.2 cyFIGURE 21 GEOTHERMAL POWER PLANT. TOTAL INSTALLED COST vs.POWER PLANT UNIT SIZE 130 fF amram smererrm SINGLE FLASH STEAM CYCLE 120|--a -DOUBLE FLASH STEAM CYCLE 2 z meee eee TOTAL FLOW CYCLE .-LSe110$7 taeaeceescocnnccesensBINARYCYCLEao<mea<tr 100 HYBRID CYCLE -a 22 a)TOTALINSTALLEDCOSTINMILLIONSOFDOLLARSCONTINENTALUSACONSTRUCTION5 10 15 20 25 30 35 40 45 50 POWER PLANT UNIT SIZE -MW NET AGIE 1565 FIGURE 22 GEOTHERMAL POWER PLANT INSTALLED COST PER KW vs. POWER PLANT UNIT SIZE BASED ON CONTINENTAL USA CONSTRUCTION 2600}-4 -\SINGLE FLASH STEAM CYCLE \m=-DOUBLE FLASH STEAM CYCLE 2400 Yeenee -TOTAL FLOW CYCLE =\eenccecousencccees BINART CYCLE HYBRID CYCLE © 2200 -=\ =2000 - = Ps 1 med fp 3oS 1800 = a re ol md - < _ "” =1600 1400 1200 N ee °See _ "N "™-_ ,ee ,Seae™.La1000-mo ood reeewn800--. !a a a l - 5 10 15 20 25 30 35 40 45 50 POWER PLANT UNIT SIZE -MW NET 43 RGIE 1564 INSTALLEDCOST-$/KWFIGURE23GEOTHERMALPOWER PLANT INSTALLED COST PER KW vs. POWER PLANT UNIT SIZEBASEDONUNALASKACONSTRUCTION 4600 4400 4200 4000 3800 3608 3400 3200 3000 2800 2600 2400 2200 2000 1800 1600 1400 1200 \SINGLE FLASH STEAM CYCLE \---DOUBLE FLASH STEAM CYCLE or TOTAL FLOW CYCLE \snccccscecccececes BINARY CYCLE 1 |-.HYBRID CYCLE ,eeee Tes Oe ewe eae oe ae, i,t l !!L _ 5 10 15 20 25 30 35 40 45 50 POWER PLANT UNIT SIZE -MW NET 44 RGIE 1563 POSITIVE AND NEGATIVE ASPECTS OF EACH TYPE OF OWER PLANT CONSIDERED Single Flash Steam Plant a.Positive Aspects 4.Uses proven and reliable process to generate electrical power. 41.Simple plant with few components. 441.Easily operated and maintained. b.Negative Aspects 4.Requires more geothermal fluid flow and therefore morewellsthanallotheralternativeplantsduetoavery low brine utilization factor. - "44.Requires careful monitoring during winter months operation to prevent freezing of steam condensate. 411.Not cost competitive in the small unit size contemplated. Double Flash Steam Plant a.Positive Aspects - 4.Uses proven and reliable process to generate electricalpower.; 41.Simple plants with few components. 444.Eastly operated and maintained. b.Negative Aspects 4.Requires careful monitoring during winter months operation to prevent freezing of steam condensate. 44.Not cost competitive in the small unit size contemplated. Binary Plant a.Positive Aspects 4.High brine utilization factor. 41.Does not run the risk of freezing during winter months operation due to the low freezing point of the working fluid. 45 111.Lowest cost in the smal?unit size contemplated. iv.Can be easily modularized. b.Negative Aspects ) 4.Uses less proven process than flash steam process. 41.Some working fluids may pose potential fire or environ- mental hazards if they should leak to the atmosphere. 411.Requires a large number of components increasing theoperationandmaintenancecosts. Hybrid Power Plant a.Positive Aspects i.Highest brine utilization factor. t 14.Combines the advantages of both steam flash and binary processes. b.Negative Aspects 1.To be efficient and economical,must be developed in aminimumof10MWincrementswhichprovidesforlargeexcesscapacityupfront. 41.Combines the disadvantages of both flash steam and binary processes. Total Flow Plant a. Posttive Aspects 1.High brine utilization factor. b.Negative Aspects 4.Uses the least proven of all studied processes. 41.Requires careful monitoring during winter months operation to prevent freezing of steam condensate. 411.Not cost competitive in the small unit size contemplated. 46 POWER CONVERSION PROCESS RECOMMENDATION Considering the positive and negative aspects of each cycle considered as discussed previously,the binary cycle is recommended as the best power con- version process to generate electricity from the Makushin resource for the following reasons: 1.It is the most economical process for the small estimated base load demand (5 to 20 MW)of the electrical system. 2.It is an efficient power conversion process requiring relativelysmallfielddevelopmenttosupportthepowerplant. 3.While it has not been as widely used as the flash steam process,itiseasilydevelopedinsmallunitsthus,adding reliability to the overall plant. 4.It can be fabricated in small,shop assembled and tested modules thatcanbeeasilytransportedandinstalled. 5.It can be easily automated to require minimal operating supervision. 6.It does not incur a risk of freezing during winter months operation. 7.It can be installed quickly,adding scheduling flexibility if power demand increases faster than expected. 47 BINARY SYSTEM DEVELOPMENT COSTS The economic feasibility of developing the Makushin geothermal resourceforelectricalpowergenerationwillbeassessedbyACRESAmerican,Inc.as requested by the Alaska Power Authority.To permit this assessment,RepublicGeathermal,Inc.has prepared the following tables showing the capital cost estimate and the operation and maintenance cost estimate for the 10 MW and the 30 MW scenario.All cost estimates are based on the use of the recommendedbinarycycleforpowergeneration. 1.Table 5 -Capital cost estimate for the development of a 10 MW gross(6.7.MW net)geothermal power plant. 2.Table 6 -Capital cost estimate for the development of a 30 MW gross(20 MW net)geothermal power plant with al]the wells drilled during the first phase of plant development. 3.Table 7 Capital cost estimate for the development of a 30 MW gross(20 MW net)geothermal power plant with the wells drilled as neededineachphaseofplantdevelopment. 4.Table 8 -Operation and maintenance cost estimate for a 10 MW gross(6.7 MW net)geothermal plant development. 5.Table 9 -Operation and maintenance cost estimate for a 30 MW gross(20 MW net)geothermal plant development. An analysis of the costs of drilling all wells required for the 30 MW gross power plant upon construction of the initial phase,instead of drilling the wells as each increment is constructed shows the following: If all wells are drilled in the initial phase of development (as shown on Table 6),the total development costs are $202,316,000.This requires atotalcapacityinvestmentof$101,158,000 having a 1983 present valkueof $45,984,000 if discounted back at a factor of 10.5%per year. If the wells are drilled as each increment is constructed (as shown on Table 7),the total development costs are $220,334,000.This requires a total equity investment of $110,172,000 having a 1983 present value of $46,201,000 if discounted back at a factor or 10.5%per year. Assuming that the amortization of the debt starts upon completion of each phase of construction,a high penalty would be patd if all wells are drilled up front,as the debt service will be substantially higher.Based on this, and because of the uncertainties in electrical demand growth,it is recom- mended that the wells be drilled as each increment is developed,thus minimizing the risks to the existing consumer base. 48 aeraTABLE 5 NO-BOTTOMFISHING DEVELOPMENT CASE UNALASKA 10 MW GROSS (6.7 MW'NET)BINARY POWER PLANT DEVELOPMENT COSTS IN THOUSANDS OF DOLLARS Field Development Costs (1983) Production Wells (2) Injection Well (1) Well Testing Direct Operation &Maintenance Home Office Start-Up Subtotal Field Costs Power Plant Costs (1983) Power Plant Eng.&Const. Production Pipeline Injection Pipeline Spare Parts Consulting &Coordination Start-Up Insurance Subtotal Power Plant Costs Other Costs (1983) Road Construction Transmission Line Subtotal Other Costs TOTAL COSTS (1983) Escalation TOTAL ESCALATED COSTS Interest Expenses TOTAL DEVELOPMENT COSTS Equity Debt TOTAL USE OF FUNDS Total 1985 1986 1987 1988 Costs 3,747 2,352 0 0 6,099 1,600 0 0 0 1,600 521 236 0 0 157 513 526 426 734 2,199 475 600 400 525 2,000 0 0 0 210 210 6,856 3,714 826 1,469 12,865 0 2,504 10,516 7,010 20,030 0 0 963 0 963 0 0 0 453 453 0 0 0 200 200 162 200 200 238 800 0 0 0 400 400 0 0 130 130 260 162 2,704 11,809 8,431 23,106 0 5,146 0 0 5,146 0 0 0 6,405 6,405 0 5,146 0 6,405 11,551 7,018 11,564 12,635 16,305 47,522 1,017 2,602 3,927 6,564 14,110 8,035 14,166 16,562 22,869 61,632 259 978 2,018 3,399 6,654 8,294 15,144 18,580 26,268 68,286 4,147 7,572 9,290 13,134 34,143 4,147 7,572 9,290 13,134 34,143 8,294 15.144 18,580 26,268 68,286 osField Development Costs (1983) Production Wells (5) Injection Wells (3) Well Testing Direct Operation &Maint. Howe Of fice Start-Up Subtotal Field Costs Power Plant Costs (1983) Power Plant Eng.&Const. Production Pipeline Injection Pipeline Spare Parts Consutting &Coordination Start-Up Insurance Subtotal Power Plant Costs Other Costs (1983) Road Construction Transmission Line Subtotal Other Costs TOTAL COSTS (1983) Escalation TOTAL ESCALATED COSTS Interest Expenses TOTAL DEVELOPMENT COSTS Equity Debt TOTAL USE OF FUNDS LOW-BOTTOMFISH CATCH CASE UNALASKA 30 MW GROSS (20 MW NET)BINARY POWER PLANT DEVELOPMENT COSTS IN THOUSANDS OF DOLLARS TABLE 6 ALL WELLS ORILLED IN FIRST PHASE OF POWER PLANT DEVELOPMENT Total Costs Total Costs Total Costs Total Costs 1985 1986 1987 1988 =First Phase 1991 1992 Second Phase 1998 1999 Third Phase Alt Phases 3,747 4,404 4,404 0 12,555 0 0 0 0 0 0 12,555 1,600 1,600 1,600 0 4,800 0 0 0 0 0 0 4,800 52)354 354 0 1,229 0 0 0 0 0 0 1,229 513 526 526 734 2,299 426 734 1,160 426 734 1,160 4,619 475 600 600 525 2,200 400 525 925 400 525 925 4,050 0 0 0 210 210 0 150 150 0 100 100 460 6,856 7,484 7,484 1,469 23,293 826 1,409 2,235 826 =1,359 2,185 27,713 0 2,504 10,516 7,010 20,030 10,015 10,015 20,030 10,015 10,015 20,030 60,0900.0 963 0 963 963 0 963 325 0 325 2,251 0 0 0 453 453 0 453 "453 0 453 453 1,359 0 0 0 200 200 0 200 200 0 200 200 600 162 200 200 238 800 200 200 400 200 200 400 *1,600000-400 400 0 200 200 0 150 150 750 0 0 130 130 260 |0 130 130 Oo -130 130 §20 162 2,704 11,809 68,431 '23,106 11,178 11,198 22,376 10,540 11,148 21,688 67,170 Fy O 5,146 0 0 5,146 0 0 0 0 0 0 5,146006,405 6,405 0 0 0 0 0 0 6,405 OQ 5,146 O 6,405 11,551 0 0 0 0 0 0 112,551 7,018 15,334 19,293 16,305 57 ,950 12,004 12,607 24,611 11,366 12,507 28 873 106 434 1,017 3,451 5,997 6,564 17,029 8,621 10,570 19,191 19,993 24,416 44,409 80 ,629 8,035 18,785 25,290 22,869 74,979 20,625 23,177 43,802 31,359 36,923 68 282 187 ,063 259 «#+1,125 2,598 4,295 8,277 655 2,091 2,746 997 3,233 4,230 15,253 8,294 19,910 27,888 27,164 83,256 21,280 25,268 46,548 32,356 40,156 75,512 202,316 4,147 9,955 13,944 13,582 41,628 10,640 12,634 23,274 16,178 20,078 36,256 101,1584,147 9,955 13,944 13,582 41,628 10,640 12,634 23,274 16,178 20,078 36,256 101,158 8,294 19,910 27,888 27,164 83,256 21,280 25,268 46,548 32,356 40,156 72,512 202,316 sTSField Development Costs (1983) Production Wells (5) Injection Wells (3) Well Testing Direct Operation &Maint. Home Of fice Start-Up Subtotal Field Costs Power Plant Costs (1983) Power Plant Eng.&Const. Production Pipeline Injection Pipeline Spare Parts Consulting &Coordination Start-Up Insurance Subtotal Power Plant Costs Other Costs (1983) Road Construction Transmission Line Subtotal Other Costs TOTAL COSTS (1983) Escalation TOTAL ESCALATED COSTS Interest Expenses TOTAL DEVELOPMENT COSTS Equity Debt TOTAL USE OF FUNDS 'TABLE 7 LOW-BOTTOMFISH CATCH CASEUNALASKA30MHGROSS(20 MW NET)BINARY POWER PLANT DEVELOPMENT COSTS IN THOUSANDS OF DOLLARS WELLS DRILLED AS NEEDED IN EACH PHASE OF POWER PLANT DEVELOPMENT Tota)Costs Total Costs :Total Costs Total Costs 1985 1986 1987 1988 =First Phase 1991 1992.Second Phase 1998 1999 Third Phase All Phases 3,747 2,352 0 0 6,099 5,799 0 5,799 3,747 0 3,747 15,645 1,600 0 .0 0 1,600 1,600 0 1,600 1,600 0 1,600 4,800 52)236 0 0 757 354 0 354 236 0 236 1,347 513 §26 426 734 2,199 §26 734 1,260 526 734 1,260 4,719 475 600 400 §25 2,000 600 §25 1,125 600 525 1,125 4,250 0 0 0 210 210 0 .180 150 0 100 100 460 6,856 3,714 826 1,469 12,865 8,879 1,409 10,288 6,709 1,359 8 ,068 31,221 . i 0 2,504 10,516 7,010 20,030 10,015 10,015 20,030 10,015 10,015 20,030 60,090 0 963 0 963 963 963 325 0 325 2,251 0 0 0 453 453 0 453 453 0 453 453 1,359 0 0 0 200 200°0 200 200 0 200 200.600 162 200 200 238 800 200 200 400 200 200 400 1,600 0 0 0 400 400 0 200 200 0 150 150 750 0 0 130 130 +260 0 130 130 0 130 130 520 162 «2,704 11,809 8,431 23,106 11,178 11,198 22,376 10,540 11,148 21,688 67,170 4 O 5,146 0 0 5,146 0 0 0 0 0 0 5,146 0 0 0 6,405 6,405 0 0 0 0 0 0 6,405 O 5,146 O 6,405 11,551 0 0 0 0 0 0 17,55) 7,018 11,564 12,635 16,305 47 ,522 20,057 12,607 32,664 17,249 12,507 29,756 109,942 1,017 2,602 3,927 6,564 14,110 14,405 10,570 24,975 30,342 24,416 54,758 93,843 8,035 14,166 16,562 22,869 61,632 34,462 23,177 57,639 47,591 36,923 84,514 203,785 .259 978 2,018 3,399 6,654 1,096 2,999 4,095 1,513 4,297 5,810 16,559 8,294 15,144 18,580 26,268 68 286 35,558 26,176 61,734 49,104 41,220 90,324 220,344 4,147 7,572 9,290 13,134 34,143 17,779 13,088 30 ,867 24,552 20,610 45,162 410,172 4,147 7,572 9,290 13,134 34,143 17,779 13,088 30,867 24,552 20,610 45,162 110,172 8,294 41,220 90,324 220,34415,144 18.580 26,268 68,286 35,558 26,176 61,734 49,104 TABLE 8 NO-BOTTOMFISHING DEVELOPMENT CASE UNALASKA 10 MW GROSS (6.7 MW NET)BINARY POWER PLANT COMBINED PLANT AND FIELD ANNUAL OPERATION AND MAINTENANCE COSTS (Thousands of 1983 Dollars) Administration 85 Operation and Maintenance Labor 580 Contract Maintenance 350 Well Reconditioning 75 Outside Consulting 150 Power Plant Insurance 100 Miscellaneous -__460 TOTAL ANNUAL COST -1,800 52 TABLE 9 LOW-BOTTOMFISH CATCH CASE UNALASKA 30 iW GROSS (20 MW NET)BINARY POWER PLANT COMBINED PLANT AND FIELD ANNUAL OPERATION AND MAINTENANCE COSTS (Thousands of 1983 Dollars) Administration Operating and Maintenance Labor Contract Maintenance Well Reconditioning Outside Consulting.* Power Plant Insurance Miscellaneous TOTAL ANNUAL COST 53 170 790 650 225 150 300 550 2,835 Capital Costs Capital cost estimates show the field development costs,power plantconstructioncosts,and other necessary costs in 1983 dollars for each alternative.Addition of these costs gives a total development cost in 1983 dollars.To this total,escalation and interest during construction are added to give a total capital cost required for thedevelopmentofeachalternative. 1.Field Development Costs The field development costs include production well drilling andcompletion,injection well drilling and completion,well testing necessary to prove productivity and injectivity,direct field operation and maintenance during development,home office sup- port and services,and field operation and maintenance during power plant start-up. Ten MW gross field development includes two production wells and one injection well.This provides for aimost a full spare pro- duction well when the plant is operated at full capacity and ensures adequate power generation in the unlikely event of the catastrophic failure of a production well.The injection well provides approximately 40 percent more capacity than necessary to reinject the total fluid required to run the power plant at full capacity.In the very unlikely event of a catastrophic failure,it is assumed that temporary disposal of the spent brine on the ground would be permissible. Thirty MW gross field development includes five production wells and three injection wells,which provides for one spare produc- tion well and one spare injection well. Power Plant Costs Power plant costs include engineering and construction of the binary units,engineering and construction of the production pipeline,engineering and construction of the injection pipe- line,spare parts,consulting services and coordination support, start-up including operator training,and fire and casualty insurance during construction. 10 MW gross power plant construction is assumed to take place during spring and summer months (April to October)of the first year of construction and continuously from April to end of con- struction of second year of construction. First phase of 30 MW gross power plant construction (20 MW gross)is assumed to take place as described above.Second and third phases will take place continuously,starting in April of the first year until completion at the end of the second year. 54 Power plant engineering and construction costs are based ona turnkey type proposal offered-by the Ben Holt Co.for a binary plant similar to one being built in the Sierra Nevada of California.Construction costs are multiplied by a factor of four to reflect the high construction cost expected on Unalaska. Construction field costs include manual labor,nonmanual labor,indirect field costs and construction management. Other Costs Other costs include the construction of a road from Oriftwood Bay to the power plant site and the construction of a 34.5 kv transmission line from the power plant site to a substation in Dutch Harbor. The road construction estimate is based on a Dames and Moore study prepared for Republic Geothermal,Inc.and Alaska Power Authority in February 1,1983.It includes existing road grading,repair and gravel surfacing;new road construction including culverts and major.canyon crossing;and mobilization and demobilization.To ensure that the road is ready to receive major equipment as it ts unloaded from the barge,road construc- tion is scheduled for the summer months of the year prior to actual field construction of the first 10 MW gross power plant. The transmission line estimate is based on burial of the cable approximately 30"underground from the power plant site to Broad Bay and then going underwater to Dutch Harbor.The estimate includes a substation to be located in Dutch Harbor that will tie the power plant to the distribution system.It also includes a 30 percent contingency to account for the uncertain- ties about the underwater portion of the line which has to be buried in the ocean floor. Escalation Escalation is based on an annual inflation rate of seven percent. Interest Expenses Interest expenses represent the interest to be paid during construction based in a debt to equity ration of one and on an interest rate of 12 percent per year. 35 Operation and Maintenance Costs Operation and maintenance (0&M)costs estimates show the total annual cost in 1983 dollars to operate and maintain the overall geothermal development. O&costs assume that operation and maintenance labor as well as administration personnel are shared by both power plant and field. 0&costs do not include any royalty payment on the resource utilized during commercial operation or any taxes on the power plant or field. 56 CONCLUSIONS On the strength of this study,the following conclusions can be drawn: 1.The Makushin geothermal resource can be utilized to generate elec-trical power for the towns of Unalaska and Dutch Harbor. 2.Due to its high development costs,geothermal power ts best suited to meet baseload demand of the electrical system. 3.The binary cycle is the preferred power conversion process to generate electricity from the Makushtn geothermal resource. 4.A 10 MW gross (6.7 MW net)geothermal power development would satisfy the electrical load demand estimated by Acres American,Inc.for the "no-bottomfishing"case past the year 2000.Preferred development would consist of two identical 5 MW gross binary units together with two production and one injection wells. 5.A 10 MW gross geothermal power development could be commercial byJanuary1989andwouldcostatotalof$68,286,000. 6.A 30 MW gross (20 MW net)geothermal power development would satisfytheelectricalloaddemandestimatedbyAcres,America,Inc.for the "low-bottomfish catch"case past the year 2000.It 14s recommended that such a power plant be developed in three phases timed to the growth in demand.The first phase of development would consist of two identical 5 MW gross binary units together.with two production and one injection wells and would become commercial in January 1989. The second phase of development would consist of duplicating the initial phase and would become commercial in January 1993.The third phase of development would consist of two additional binary units identical to the units provided in phases 1 and 2 together with oneproductionandoneinjectionwellsandwouldstartcommercialopera-.tion in January 2000. 7.A 30 MW gross geothermal power development as outlined above would cost a total of $220,344,000. 57