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HomeMy WebLinkAboutUnAlaska Geothermal Feasibility Study Final Rep Vol l 6-1987UNA 022 Alaska Power Authority LIBRARY COPY UNALASKA GEOTHERMAL FEASIBILITY STUDY FINAL REPORT VOLUME I June 22, 1987 Dames & Moore UNALASKA GEOTHERMAL FEASIBILITY STUDY FINAL REPORT VOLUME I June 22, 1987 (UNA oO2e Job No. 12023-026-02 UNALASKA GEOTHERMAL FEASIBILITY STUDY Prepared For ALASKA POWER AUTHORITY By Dames & Moore in association with SAI Engineers, Inc. and Mesquite Group, Inc. June 22, 1987 Contract No. 2800020 VOLUME I: TABLE OF CONTENTS MAIN REPORT 1.0 EXECUTIVE SUMMARY... 2. 2 ee cer rcecce veces 1.1 1.2 1.3 1.4 1.5 ah pte aia TC eee ee eee ees STUDY OVERVIEW. ... lilis silesiiisiliieiilis|iiel||teilis SUMMARY OF SIGNIFICANT FINDINGS. atiieriiies isillisiiiielliiailiis Engineering Findings. .......4.2-eee-8 Environmental Findings ... Economic Findings . . . «6 2. see ee ec eee RECOMMENDATIONS ...... . . . oe ORGANIZATION OF THE FEASIBILITY STUDY REPORT |e 2.0 ENGINEERING CONSIDERATIONS . 2... 2.2.2 eee eee 2.1 2.2 2.3 NN oe ue 2.6 GEOTECHNICAL CONSIDERATIONS .....2.2 2 eee 2visi- Welt Site aené Pigent Site 6s 6 6k 8 2.1.2 Foundation Discussion and Recommendations GEOTHERMAL RESOURCE DEVELOPMENT CONSIDERATIONS . 2.2.1 Production Well Location ......2.6-6 2.2.2 Effluent Disposal... ee we ees WELL AND POWER PLANT DESIGN CONSIDERATIONS Sees 2.3.1 Well Design Considerations ....... 2.3.2 Generation Equipment Selection Considerations 2.3.2.1 Total Flow Generating Systems . 22.2 2.3 Single Flash Generating Systems 2.4 Double Flash Generating Systems 2.5 2.6 Small Binary Generating Systems The Hybrid Cycle Plant... 2.3.3 Transmission Line Design and Routing POWER PLANT SITE SELECTION... 2.2 2 ee eo SETE ACCROS OELRCTION ft ce tt te te 2.5.1 Construction Access . . 2... 2 ee ee 2.3 2.3 2.3 2.3 2.3 . . . . . 8 2.5.2 Plant Site Operator and Maintenance Access 2.5.3 Marine Terminal Facilities ....... 2.5.4 Manned Versus Unmanned Operations .... PROJECT DEVELOPMENT LOGISTIC CONSIDERATIONS .. 3.0 ENVIRONMENTAL CONSIDERATIONS ... 2.2.2 eee eee 3.1 3.2 MLF6/C1 GENERAL PERMIT REQUIREMENTS ...... cece 33.1 Federal Permite 6 0 0s we et tl Sak ce || Reem PCIE sn) eo) 9, |) 6)! 6! lll! le! ls lie | lee 3.1.3 Permitting Status and Timing ... oe ENVIRONMENTAL ASPECTS OF CONSTRUCTION ACCESS Sill 16 3.2.1 Driftwood Bay Airstrip .......e.e.. 3.2.2 Driftwood Bay to Sugarloaf Road. .... Medium Size Binary Generating Systems ee oe e wee Ce ed 1 wmMrInItNPwr NS 1 ~ 2-1 2-1 ere 2-4 2-4 2-6 2-10 2-10 2~11 2-12 2-12 2-13 2-14 2-14 2-15 2-15 a~19 2-20 2-20 2-21 2-23 2-24 2-24 PP Pr eere? FwWwwwnrere Www ee uw WWW oe ona 3.9 TABLE OF CONTENTS (continued) ENVIRONMENTAL ASPECTS OF OPERATIONS ACCESS . 3.3.1 Makushin Valley Road Alternative .. 3.3.2 Broad Bay Boat Dock... ENVIRONMENTAL ASPECTS OF TRANSMISSION. LINE ENVIRONMENTAL ASPECTS OF BRINE DISPOSAL. 3.5.1 Surface Disposal . .... ee. 3.5.2 Pipeline to Driftwood Bay . 3.5.3 Injection. ...... 2. POWERPLANT SITE IMPACTS ..... OPERATIONAL IMPACTS ..... CASCADING USES OF GEOTHERMAL EFFLUENT wee lis 3,8,3- Detftweed Bey «5+ 0 0 0s * 0 ee 3.8.2 ‘Broad Bay .: 4. «6 sis n0 2 5 0.0 0 0 0 3.8.3 Other Considerations ......22-. AIR QUALITY |e) ee ee el el ele 4.0 ECONOMIC ANALYSIS... 2.2. ee eee ve cece 4.1 4.2 ee ee Fw 4.5 APPROACH AND ASSUMPTIONS . . 2. 2. 6 ee we we 4.1.1 Economic Assumptions ......e ee oe © © ew ew . 4.1.2 Generation Data and Assumptions - Diesel. 4.1.3 Generation Data and Assumptions - Geothermal. THE ELFIN GENERATION MODEL. .....2 eee 4.2.1 General Overview .... 2.2.2 eee 4.252 Lead Data. . . 7s. 3 6 3 We 8 st 4.2.3 Dispateh Order. 5-0-0. ew ee oe SZ. BOWEN Gukgvt 2 we te he THE ECONOMIC MODEL .... St tetel|'/e || 0! 6 RESULTS AND SENSITIVITY ANALYSIS es. lel 1si| 6! |o 4.4.1 Diesel Price Sensitivity ...... 4.4.2 Load Growth Sensitivity ......-. 4.4.3 Discount Rate Sensitivity ...... 4.4.4 Project Life Sensitivity ...... ECONOMIC CONCLUSIONS AND RECOMMENDATIONS . . 5.0 CONCEPTUAL DESIGN . 2. wis ce ww ewe ee eee el 02 3 www MLF6/C1.1 PROJECT DESCRIPTION. ... . . PROJECT DEVELOPMENT LOGISTICS AND SCHEDULE BARTO VOR BRGIGN 2 nw wh te ewe ee et Deol BULLELNSS iy | ts | 6) bet 01 Jel sll! tor lol, He | ol lle 5.3.2 Major Equipment ......see-s 5.3.2.1 Steam Turbine Generator Set 5.3.2.2 Steam Condenser ...... 5.3.2.3 Condensate Pumps ..... 5.3.2.4 Instrument Air Compressors 3.362:5 Air Déyer.< 2s 5 03 8 8 5.3.2.6 Turbine Drain System ... oe ee ee ww Ww [:*) (cd @ tee ' RR RF OOD WDDIDUM 00 0 10) Ht) to to ole we 1 roar NN + w ' 1 ~ od w EA eta ee een Rr OUWDMANIN UP WH ' ~ w ween wee eee wee SND ADDUWNU We TABLE OF CONTENTS Ceontinued) 3.2 3.2 3.2 5 5 5 5.3.3 Access Roads ... . 5.3.4 Transmission Facilities 5.4 PROJECT CAPITAL COST ESTIMATE Additional Assumptions 5.4.1 5.5 OPERATION AND MAINTENANCE 5.5.1 Operation .... 5.5.2 Maintenance ... 6.0 CONCLUSIONS AND RECOMMENDATIONS TECHNICAL CONSIDERATIONS . . fFwWwnre ECONOMIC CONSIDERATIONS . 6 6 6 6 RECOMMENDATIONS ..... REFERENCES VOLUME II: APPENDICES A, B, C, D APPENDIX A APPENDIX B APPENDIX C APPENDIX D AIR QUALITY ANALYSIS ECONOMIC ANALYSIS DETAILS MLF6/C1.2 ENVIRONMENTAL AND PERMITTING . co . NSIDERATIONS 7 Binary Cycle Generating Units .... -8 Flash Generating Units +9 Geothermal Steam and Water Pipelines GEOTECHNICAL FIELD EXPLORATION AND LABORATORY TESTING GEOTHERMAL DRILLING PROGRAM AND COST ANALYSIS 1.0 EXECUTIVE SUMMARY 1.1 BACKGROUND Utilization of geothermal resources has proven to be an economic source of electric power in many parts of the world. The first major geothermal power Project was developed in Italy near the turn of the century and is still pro- ducing electricity today. Worldwide, over 3,000 megawatts (MW) of geothermal generating capacity have been installed. Certain conditions must exist in order for a geothermal prospect to be viable for development. These include (1) a relatively shallow heat source, (2) a fluid to act as the heat transfer medium, (3) reservoir conditions capable of delivering adequate fluid to the surface, and (4) a market for the energy produced. In Alaska, there are many areas that meet the first three conditions for development. A recent statewide survey identified over 100 surface mani- festations of geothermal resources including hot springs, fumeroles, mud pots, and wells. Over 11 million acres in the state have significant geologic poten- tial for geothermal energy development. However, very few of these resources are within proximity of a potential power market to be an economic energy sourcee The community of Unalaska/Dutch Harbor is one place in Alaska which satis- fies all four of the above-listed conditions, including market proximity to the resource. Located only 13 miles from the Makushin Volcano, the community is the largest city on the Aleutian chain with a 1985 estimated population of 1500. Unalaska is located about 800 miles southwest of Anchorage and is situated on a sheltered bay opening on the Bering Sea. Historically, Unalaska/Dutch Harbor was an important shipping and trading port. During World War II, the area housed a major naval base. Several buildings, including that housing the existing electric generating plant, remain from the wartime development. Presently, the economy is largely dependent on the fishing and crabbing industries. The Alaska Power Authority was established in 1976 to Promote, develop, and advance the general prosperity and economic welfare of its citizens by reducing consumer power costs and otherwise encouraging the long-term economic growth of MLF6/C5 i-i the state, including the development of its natural resources, through the development of power projects (AS 44.83.010). Based on a number of geologic investigations that indicated potential for a significant geothermal resource hear the community of Unalaska/Dutch Harbor, the Alaska Legislature, in 1981, appropriated $5 million to be administered by the Power Authority for a geo- thermal drilling and exploration program at the base of the Makushin Volcano (Figure 1-1). On the basis of a competitive bid procedure, the Power Authority selected a team consisting of Republic Geothermal, Inc. and Dames & Moore to conduct the exploration drilling progran. The exploration program, consisting of three phases, was initiated in 1981 and was concluded in the Spring of 1985. Phase I activities included data review and synthesis; technical planning; determination of land status and per- mitting requirements; acquisition of baseline environmental data; geological, geochemical, and geophysical investigations and mapping; and the drilling of three temperature gradient holes. During Phase Il, a deep exploratory well was drilled and a productive geothermal resource was encountered. Phase III activi- ties included extensive testing of the geothermal resource, the drilling of a fourth temperature gradient hole, and an electrical resistivity survey to delin- eate the extent of the geothermal reservoir. The geothermal exploration program is described in a series of detailed reports produced by Republic and Dames & Moore after each phase of the project and in an Executive Final Report (Republic, 1985). The exploration program confirmed the existence of a highly productive geothermal reservoir at a depth of 1,949 feet, approximately 14 miles west of Unalaska/Dutch Harbor. The water-dominated resource has a bottomhole tempera- ture of 382°F and pressure of 497 psi. Flow tests, reservoir analyses, and wellbore modeling indicate that a commercial-size production well at the site would be capable of producing from 7 to 12 MW of electric power, sufficient to meet the power demand of Unalaska/Dutch Harbor for the foreseeable future. In April 1985, the Power Authority completed a reconnaissance study of energy requirements and alternatives for Unalaska/Dutch Harbor, concluding that a geothermal power system with diesel generators for peaking and backup appeared to be the most economic long-term source of power for the community. Based on MLF6/C5 1-2 ee ~— = DRIFTWOOD BAY > DS ~/ sg NU SSE sot hash Pas, FZ WH y~o ust os UNALASKA BAY- o~ [aS] summeneay SF + DUTCH onan eer YP ER Keen aw UNALASKA w kN vaccey’ UNALASKA ISLAND @® Temperature Gradient Hole ye oO Geothermal Exploratory Well (ST-1) SCALE 1:250 000 5 ° 5 10 15 20 MILES qT ez FIGURE 1-1 5 oO 5 10 15 20 KILOMETERS I = this finding, the Power Authority Board of Directors directed staff to initiate a detailed geothermal feasibility study after obtaining negotiated agreements for access, use of lands, and a long-term geothermal resource lease for the project. Such agreements were negotiated with The Aleut Corporation and the Ounalashka Corporation, and a geothermal feasibility program was initiated in June 1986. The Power Authority initiated the feasibility program by conducting three studies to provide additional data on which to base this feasibility report. These studies included an engineering investigation conducted by the Alaska Division of Geological and Geophysical Surveys (ADNR, 1986), an environmental analysis conducted by the Alaska Department of Fish and Game (Sundberg, 1986), and a load forecast and power market analysis for Unalaska/Dutch Harbor (R.W. Beck, 1987). This report is designed to integrate the data and results of the above studies and the exploration Program to produce a detailed engineering, environmental, and economic feasibility study of developing a geothermal power System to meet the energy needs of Unalaska/Dutch Harbor. 1.2 STUDY OVERVIEW The engineering-economic study of the feasibility of geothermal power pro- duction from the Makushin Volcano involved the synthesis of resource, environ- mental, and engineering considerations within an economic framework. An overview of the study approach is illustrated in Figure 1-2. The resource availability, locational constraints, and reservoir charac- teristics established the initial boundaries of the study. Interpretation of the results of the geothermal exploration Program was provided by the Mesquite Group under a subcontract to Dames & Moore, the prime contractor for this study. Mesquite Group personnel had performed the majority of the exploration program as part of their former employment with Republic Geothermal. Engineering analyses, including evaluation of alternative power cycles, plant locations and configurations, transmission Systems and road alignments, were performed by SAI Engineers. The engineering analysis was performed interactively responding to the constraints of the geothermal resource as well as to environmental and economic factors. Mesquite provided reservoir engi- MLF6/C5 1-3 GEOTHERMAL RESOURCE ANALYSIS & DRILLING COSTS FROM MESQUITE GEOTHERMAL COST AND PERFORMANCE DATA FROM SAI LOAD FORCASTS FROM R.W. BECK DIESEL PERFORMANCE DATA FROM CITY OF UNALASKA ELFIN GENERATION ECONOMIC MODEL: ; CAPITAL, FIXED AND MODEL: DISPATCH BY UNIT BY YEAR rae FIGURE 1-2 OVERALL ECONOMIC ANALYSIS APPROACH NET PRESENT WORTH BY SCENARIO DAMES & MOORE neering and costs associated with the various well drilling scenarios con- sidered. The integration of the project as well as the analysis of the environmental and economic factors was performed by Dames & Moore. The environmental factors significantly influenced facilities design, placement of facilities, alignment of transmission rights-of-way and access roads, and disposal of liquid and gaseous waste products. Dames & Moore's environmental scientists interpreted the data and analysis provided by the ADNR and ADF&G studies (ADNR, 1986 and Sundberg, 1986) and made recommendations which guided SAI's engineering designs on an interactive basis. The economic feasibility analysis included interpretations of the R.W. Beck load study to provide information on generation requirements. Identification of the economically optimal geothermal generation configuration required an interactive analysis involving load requirements and timing, initial engineering cost estimates and comparison with all-diesel generation costs. The economic study utilized a systems generation model to simulate the economic dispatch of generation units over time for alternative geothermal generation capacities. The results of the generation model were passed to an economic model which pro- vided the total life cycle cost of an all-diesel generation system as well as alternative configurations of combined geothermal and full capacity backup diesel systems. The life cycle costs include all new capital investments and operating costs for meeting the generation needs of Unalaska through year 2016. Comparison of the all-diesel system life cycle costs with those of hybrid diesel/geothermal systems provided a test of economic feasibility of geothermal development. 1.3. SUMMARY OF SIGNIFICANT FINDINGS The results of this study indicate that a commercial scale development of the geothermal resources of the Makushin Volcano is technically feasible. Development is also economically feasible under a reasonable set of assumptions regarding future conditions. The project concept proposed presents no unusually restrictive environmental constraints and there should be no serious dif- ficulties in obtaining the required permits. The study team recommends that the MLF6/C5 1-4 Power Authority begin a detailed financial (as opposed to economic) feasibility study and that the permitting process begin as early as possible following a decision to develop. Apart from a site reconnaissance which took place at the beginning of the study, no field work was undertaken. Reliance was placed on the information obtained during the exploration study and the ADNR and ADF&G studies. This lack of field work precluded detailed design of certain key project elements such as bridges, pipeline crossings, and piers. In the absence of such detailed design, an effort was made to select conceptual designs for those elements which, although perhaps not optimal, have a high probability of proving technically feasible. Sufficiently high cost estimates were used for those questionable elements to cover reasonably foreseeable difficulties. Detailed design studies might result in actual project costs significantly lower than those estimated during this study. The main engineering, environmental and economic findings are summarized below. ENGINEERING FINDINGS 1. The preferred facilities locations and road and transmission alignments are shown on Figure 1-3, Project Vicinity Map. 2. Initial production well drilling should take place at the ST-1 test well site used during the exploration study. This effort will be supported by equipment barged to Driftwood Bay and hauled over an extension of the existing road to the lower Fox Canyon Plateau. Helicopter mobilization will be required to support drilling operations because there will be no road access to the production well site. A single 13-3/8 inch production well should provide sufficient energy for power production to 7 MW (net). A second (backup) production well should be completed while equipment is mobilized for the primary production well. MLF6/C5 1-5 LEGEND: | DIRT ROAD a MEMBRANE ROAD ss imtmim H OH LINE .- J UG CABLE —— Hag SUBMARINE CABLE --~-~--~- aT PIPE LINE — KEY MAP 0 5Mile 1.0Mie BRIDGE ieee Approximate Scale ALIGN. CORRIDOR ALT. STEEL TWR. TRANS. LINE Soteaeanseees vote este ALT. WD. POLE = ~ TRANS. LINE 0 sssessessessens aos ° nial .% WEST ALIGNMENT\ 2 TERMINAL CORRIDOR \o SWITCHING STATION = SWITCHING CA me PIER STATION="A" Ri. i! ~ x. 1 > / SN. ae = ot. oe > <— .PROPOSED . PDN, ) ee POWERPLANT ~ 72 ; a SS SITE .- ~ eae : == __- i ‘s _ - = a1 T738 ? 3S Toe ae - == 3'= SUBMARINE = aNT : - “eS CABLE TO . Le BAS —— 7 —~.- £# DUTCH HARBOR £2 — mo, i SEE FIG. 2-5 SAI ENGINEERS, ING.||7) ALASKA POWER AUTHORITY 2. PROJECT VICINITY MAP 3930 Petnick Henry Or. Senta Clere, Ca, 85050 | 7 F: | SAI Project No. S505 |Date: | -22-57 | Crawn: | Approved: [Revision _ 6-19-87 __| Ow9. No. Se St 3. 4. 5. 6. 8. 9. Waste geothermal brine and condensed steam can be injected in an injec- tion zone located near the plant site (Site E on Figure 1-3). A single 13-8/8 inch injection well should suffice for disposal of effluents from a 7 MW plant. The power plant should be located on a level bench about 1000 yards northeast of the well site, on the north side of Fox Canyon. The plant should normally operate in a semi-automatic mode. The full out- put will be produced unless sensors indicate failure of a key component, in which case the plant will automatically shut down. The plant could also be shut down by a signal from Dutch Harbor. The initial 7 MW (net) geothermal plant configuration will consist of two 2.5 MW (net) single flash units driving a steam turbine and two 2 MW (net) binary units extracting useful energy from the waste water stream of the flash unit. If demand increases, an additional 2.5 MW flash unit could be added to yield a 9.5 MW (net) system. Access during construction will be via barge to Driftwood Bay and by an unpaved road to the plant site. Access for operation and maintenance will be via a small dock at Broad Bay and a road through Makushin Valley. This road will be partially constructed of local aggregate encapsulated in a geotextile fabric. Electrical transmission will be via wooden H-pole overhead lines from the plant site to the bottom of the existing switchback in the Makushin Valley Road. From that point to Broad Bay three single conductor underground 34.5 KV transmission cables will parallel the Makushin Valley Road. At the south end of Broad Bay there will be a junction at which the underground cable is joined to four single conductor 34.5 KV submarine cables to the City of Unalaska. The total construction cost for a 7 MW (net) hybrid flash/binary system will be about $43 million including all wells, transmission facilities, and related project facilities. MLF6/C5 1-6 ENVIRONMENTAL FINDINGS eee, 1. There are no fatal enviromental factors which would preclude the proposed geothermal development. 2. The permitting process could be completed in less than one year from the decision to develop, provided that an Environmental Impact Statement is not required. There do not appear to be any significant environmental impacts which would trigger an EIS. 3. The arsenic and hydrogen sulfide content of the geothermal brine necessita- tes injection rather than surface disposal into the Makushin River. 4. Care must be taken in design, construction, alignment, and timing of construction of the Makushin Valley Road river crossings to avoid impacts on anadromous fish populations in the Makushin River. ECONOMIC FINDINGS NOTE: The following conclusions are based on an economic analysis which compared the sum of the present worths of capital and operating costs for a generating system meeting forecast load requirements for Unalaska/Dutch Harbor over the period 1988-2016. Some of the key economic assumptions include a medium diesel price trend, R.W. Beck's (1987) base case load growth forecast, and a real (uninflated) present value discount rate of 3.5 percent. The results of the economic analysis are illustrated by Figure 1-4. A financial analysis including capital repayment schemes and interest rates has not yet been undertaken. Such a financial analysis might not support the selection of geothermal alternatives as opposed to all-diesel generation if a short pay-back period were required. Subsequent to the economic analysis conducted under this feasibility study, the Power Authority conducted a preliminary analysis of the costs of financing. This preliminary analysis indicates that financing costs would total approxi- mately $3.8 million for a 7 megawatt geothermal development. Included in this $3.8 million is a cost of $1.7 million for obtaining revenue from sale of State of Alaska backed revenue bonds. Also included is $2.1 million interest during MLF6/C5 1-7 OTD LL AIL Dat FOG Pe “ ee, SOP OLIL Lf ye 47. : Qe. fey . Ope. 2 2 . | ; bt > NE? “oF , og Sf Y : f bee Lo hi bc i ho Le ow eh LY. ma fe Cw me — aoe Ke <.-€-<-- - tn ian Sane tem eee ead aki ea ae SNK ON ORNS, NS NOON a so SO WKN RN RON EN ROS NN ON oe, ex . Nove aS o Ns, NON A a an SO ON OR TSN > \ — ge se oe KS eae ada Nene ames Sess et Sh Ses ie Vea Wee A ee GTI ITF OTA I ITL STG To 7 Ae CA ff SOLA oA HIGH DIESEL PRICE foc 9.5 MW FIGURE 1-4 OF GENERATION SCENARIOS BASE CASE LOAD GROWTH 1 3 MEDIUM DIESEL PRICE GEOTHERMAL CAPACITY “Zy o2 Mw R.N)) 5 aor COMPARISON DOLE UIT OT fs AS ; eee ro, ’ of » - = i SO _ XY YN A SS S35 5S 7 — 4 co © © © © © «o o eo ° 2 o a oO & © wn ~~ ” N aol LOW DIESEL PRICE ($ 9861 NOFITIN) SNIVA LNSSSYd LAN “| ALL DIESEL Ty F construction based on a 2-year buildout and a real interest rate of 3.5 percent. (Mike Hubbard, Alaska Power Authority, personal communication to M. Feldman, May 15, 1987). These financing costs are not reflected in the economic conclusions. If they were reflected, they would unfavorably affect geothermal development versus continued reliance on diesel-fired generation. Without considering these financing factors, the cost-to-cost ratio of diesel versus 7 MW geothermal is 1:1.02. With consideration of financing costs the ratio is 1:1.07. 1. 3. 5. 1.4 1. The economic analysis indicates that under the base case assumptions a geothermal development at a scale of 5 or 7 MW would be approximately equal to continued reliance on diesel in total generation costs 1988-2016. Under the base case assumptions the 5 and 7 MW geothermal systems offer about the same cost structure. Later expansion from 7 to 9.5 MW in 2003 would be economic only under very optimistic assumptions. Assuming a high diesel price trend or a high load growth case or both further increases the cost savings from geothermal development. Increasing the present value discount rate to 4.5 percent (placing less value on future as opposed to present costs) reduces the magnitude of the cost savings from geothermal development. However the rankings of the cost for each scenario do not change. If the life of the geothermal development could be extended to 2025, greater cost savings would result from geothermal development. Some facil- ities replacement would be required under this scenario. RECOMMENDATIONS A financial feasibility analysis should be undertaken as soon as is prac— tical. Load growth in Unalaska is expected to increase at a rapid rate over the next five years due to increases in bottom fish processing activi- ties and decreases in industrial self-generation (Beck, 1987). if a geothermal development is to be economically feasible it must utilize the resource before investment in diesel capacity is committed to serve the burgeoning demand. MLF6/C5 1-8 2. Final siting and alignment for the Makushin Valley road, transmission lines and dock facilities should be determined in the field with input from ADF&G, other interested agencies and land owners (the City of Unalaska and the Ounalashka Corporation and the Aleut Corporation). 3. As soon as a decision to develop is reached, or possibly before, if devel- opment is considered likely, it would be prudent to begin the environmental approval process. This will avoid a situation in which the narrow develop- ment season is missed due to permitting delays. 4. Under base case assumptions, the geothermal alternative would only be eco- nomic assuming that an injection site is feasible at the Lower Fox Canyon (Site E on Figure 1-3). Therefore this site should be drilled before con- mittment of expenses for production facilities. 5. An additional incentive to prompt action in geothermal development is the presently depressed level of construction and drilling costs. If a deci- sion to develop is reached during the current depressed drilling market it may be possible to obtain a drill rig at a fraction of its book value. This rig could be committed to the project offering considerable saving over day-rate rental. 6. The economic feasibility of geothermal development is highly sensitive to world oil price forecasts. The project economics should be reassessed immediately before the decision to develop is reached. 1.5 ORGANIZATION OF THE FEASIBILITY STUDY REPORT The feasibility study report is bound in two volumes. Volume I contains the main report, including sections on Engineering Considerations (2.0), Environmental Considerations (3.0), Economic Analysis (4.0), Conceptual Design (5.0) and Conclusions and Recommendations (6.0). A bibliography appears at the end of Volume I. Volume II contains technical appendices on Geotechnical Field Exploration and Laboratory Testing (Appendix A), Geothermal Drilling Program and Cost Analysis (Appendix B), Air Quality Analysis (Appendix C), and Economic Analysis Details (Appendix D). MLF6/C5 1-9 Detailed cost estimates supporting the cost summaries presented in Volume I are on file at the Power Authority. MLF6/C5 1-10 2.0 ENGINEERING CONSIDERATIONS The project considered under this feasibility study employs a geothermal water-dominated resource which will require the development of three major systems: geothermal resource extraction, power generation, and transmission. The resource extraction system consists of production wells of pipelines for transportation and collection of geothermal fluids, and of effluent injection wells. The generating system includes consideration of primary steam turbine driven generating units, and possible secondary use of the remaining (lower enthalpy) geothermal fluids to power binary cycle generating units. The third Major system consists of transmission facilities. The power produced by either or both generation systems will be synchronized to a station bus, stepped up to transmission voltage levels. Then the power will be transmitted from the plant to the existing primary system by means of overhead, buried and submarine transmission lines linking the plant to the Unalaska distribution grid. Figure 2-1 illustrates the major features of the proposed geothermal development. 2.1 GEOTECHNICAL CONSIDERATIONS 2.1.1 Well Site and Plant Site Present plans are to develop the geothermal resources on Unalaska Island with a production well near the ST-1 test well on a gently sloping bench situated on the eastern flank of the Makushin Volcano. Consideration was given to locating facilities on three adjacent benches located on opposite sides of Fox Canyon (see Figure 2-3, Sites G, E and H). Benches at Sites G and E are situated at roughly the same elevation with gentle slopes down to the south or southeast. The perimeters of both benches to the north, east and south are steeply sloping down into ravines and gullies. The steep slopes are marked by fresh exposures of the site's nearly horizontally layered subsurface profile. The freshness of these exposures is indicative of a continuing failure of the gully slopes. The western margins of each bench are at the base of a hillside with relatively steep slopes. At the southwest corner of the well site, the majority of the area is occupied by a landslide deposit with a hummocky surface. Site H is located on the north side of Fox Canyon to the west of Site E. It is on more stable ground than Sites G and E but is less level. Site H is about 425 feet higher than the test well site. MLF8/A =i Based on observations of the exposures on the steep slopes at the perime- ters of the benches and information from the Alaska Department of Natural Resources report (1986), the subsurface conditions of the Proposed sites generally consist of a surface layer of volcanic ash (tephra). The tephra con- sists mainly of a silty fine sand with some organic material and a trace of gra- vels. The layer ranges in depth from approximately 3 to 13 feet at the existing well site and is generally loose in consistency. Beneath the tephra, an ash flow tuff deposit is encountered and consists of a medium dense to dense, silty gravelly sand. It is estimated that the ash flow tuff deposit is approximately 25 to 80 feet thick. Below the ash flow tuff, it is believed there is a relati- vely thick bouldery till deposit which is underlain by bedrock. To supplement the ADNR (1986) geotechnical investigation of the existing well bench, Dames & Moore obtained samples during the September 5, 1986, field investigation. The field program carried out was minimal and is described in Appendix A. The samples gathered during this investigation were tested in Dames & Moore's Anchorage laboratory. The test Program included classification type testing for all the samples and shear strength determinations on the relatively undisturbed sample. A description of laboratory testing procedures and the test results are presented in Appendix A. The classification tests on the four samples obtained in the surface tephra deposit indicate a silty fine sand with some organic material and relatively high moisture contents. The strength tests performed on the silty fine sand indicate an angle of internal friction on the order of 25 degrees with a cohe- sion intercept of approximately 200 pounds per square foot. 2.1.2 Foundation Discussion and Recommendations eo ane snecommengations It should be emphasized that the discussions and recommendations, which are based on relatively little subsurface information, are intended to be used only as a guide for preliminary foundation design. A comprehensive subsurface investigation with further analysis is required prior to final foundation design. The surface silty fine sand (tephra) deposit at both the well and the plant site (Figure 2-3, Sites G and E) may be prone to substantial consolidation under MLF8/A 2-2 additional loads imposed by the planned structures. In addition, due to the grain size distribution of the deposit, the partial saturation of the deposit and the high seismic hazard risk of the area, the tephra deposit at the site may be susceptible to liquefaction. Due to the aforementioned factors, we antici- pate that a deep foundation system that extends through the tephra and is founded in the more competent underlying ash flow tuff deposit would be the most feasible for the main structures of the Proposed power plant facility and the Proposed production well development. Driven displacement piles using locally available timber or steel pipe piles are recommended. The allowable bearing capacity for this type of foundation system would probably be in the range of 20 to 40 kips per square foot (ksf). Based on available information, it is estimated that structures supported on pile foundations would experience negligible settlement. Drilled and cast in place piles could also be used for this project. However, some difficulties may be encountered keeping the drilled excavations open and would require temporary or permanent casing. The allowable bearing capacity for this type of foundation system would be less than driven pile System and would range from approximately 10 to 30 ksf. Shallow foundations may be possible for light weight support structures. We anticipate that the allowable bearing pressure would range from 2 to 3 ksf with a minimum embedment of at least 3 feet. In addition, the structures would have to be designed to tolerate total settlements on the order of 2 to 4 inches and to mitigate the possibility of liquefaction. Further, it is recommended that care be used in the layout of the facilities and well appurtenances. It is advisable to avoid placing any structures in the area of the landslide deposit area, due to the very loose, unstable subsurface soils. In addition, the buildings should be kept away from the edge of the steep slopes at the perimeter of the benches, due to possible weakening of the bearing soils by slope erosion. It would be prudent to investigate the movement of the slopes due to undercutting by the rivers and streams, and to provide slope protection if found necessary. Alternately, a monitoring scheme could be developed to document the progression of slope migration back into the sites. MLF8/A 2-3 Suitable borrow sources for on-site road construction and structural fill (if required) are numerous along the construction access route back to Driftwood Bay. Material sites 8, 9, 10 and 11 as identified by the ADNR study (1986) could supply suitable material. An alternative to pile foundations under major facilities would be a structural fill (mat) foundation with the surficial silty soils removed and replaced. This alternative would also minimize the adverse effects of seismically loading the surficial silts. 2.2 GEOTHERMAL RESOURCE DEVELOPMENT CONSIDERATIONS eevee Geologic drilling and testing investigations to date in the Makushin Area have amply demonstrated the existence of geothermal resources capable of pro- ducing geothermal fluids at sufficient rates to generate at least 10,000 kW of power. Resource longevity is less certain because of practical limitations to well flow test time, but it probably far exceeds the estimated twenty-five to thirty years useful life of the power generation equipment. Well test data ana- lyzed by Republic Geothermal suggest a reservoir life of several hundred years. To bring this resource from the reservoir to the power generation facili- ties, wells need to be drilled to a depth of about 2,000 feet, in sufficient numbers and with adequate well bore diameter to provide the required flow on a long term basis. Due to the paucity of test well data, the probability of success for drilling several production wells in the Makushin geothermal field cannot be assessed at this phase of the project. However, for the first well a very high success probability is expected if such well can be drilled at a location imme- diately adjacent to the existing test well and at the same depth. 2.2.1 Production Well Location As noted above there is a very high probability that a production well will be successfully completed in the immediate vicinity of the ST-1 test well target. Four production well sites were considered: l. A straight hole drilled very close to ST-1 (Figure 2-3, Site G). 2. A directionally drilled well from Site H (Upper Fox Canyon Plateau, Northwest of ST-1). MLF8/A 2-4 3. A directionally drilled well from Site E (Lower Fox Canyon Plateau, northeast of ST-1). 4. Straight holes at Site E or H. It was concluded that only the first alternative offers a high probability of successful completion. Although a well at Site G is almost a certain success, this site has a logistical drawback in that it is separated from practical road access by Fox Canyon which is too broad to be feasibly accessible by road. Thus, either the steam must be piped to a road accessible plant site, or a non-road accessible plant must be built near the well. (See Section 2.4 for further discussion of this alternative.) Site H (Upper Fox Canyon Plateau) is the nearest suitable alternative drilling site to ST-l. It is approximately 425 feet higher than the ST-1 site and about 1,500 feet away. Thus, to intersect the production zone target 1, 950+ feet in ST-1) would require a horizontal kick of 1,500+ feet in 2,375+ feet of vertical distance. While difficult and costly, drilling such a well is tech- nically possible. The sub-pressure condition of the reservoir, however, imposes further limitations. Wellbore flow modeling has shown that the maximum flowing wellhead pressure which can be achieved from this resource at the ST-1 elevation will not exceed 110+ psi, no matter how large the wellbore diameter. This is insufficient pressure to allow the well to flow naturally (flashing flow) to an elevation 425 feet higher. In order to pump the well with today's geothermal pump technology a line shaft turbine pump would have to be set about 100 feet below the natural flash point of 1,150+ feet in ST-1. This means the well would have to be straight for the first 1,675+ feet from an Upper Fox Canyon Plateau well site. A 1,500 foot kick in the remaining 700 feet of vertical distance to the target is not possible with any conventional drilling technology. The only real possibility would be to use an armored cable suspended submersible pump which does not require a straight hole. Such pumps have not yet proven to be reliable in geothermal applications and cannot be recommended at this time, even if the extra costs and operation difficulties involved were judged to be accep- table. Therefore, although technically possible, this option is rejected as impractical. MLF8/A 2-5 Site E (Lower Fox Canyon Plateau) is essentially at the same elevation as the ST-1 site, thereby eliminating most of the foregoing pressure problems. However, the nearest suitable site relative to the production zone target is about 3,000 feet away (horizontally). A 3,000 foot kick in 1,950 feet ver- tically might be theoretically possible, but would be exceedingly difficult, risky and costly. Conventional directional drilling is limited to a maximum 5° deviation from the vertical per 100 feet of depth. Even if directionally drilled from ground level, the maximum kick possible with 5°/100 foot deviation and a maximum total deviation of 60° is only about 2,000 feet. Use of unconven- tional drilling technology to achieve the required kick cannot be recommended. The drilling conditions on Makushin, particularly the high temperatures and severe lost circulation, coupled with very difficult logistics make failure of such an effort highly probable. The risk-weighted cost of such wells would, at best, be several million dollars each. Like the previous option, directional drilling from Site E is rejected as impractical. Consideration was also given to drilling a straight well on the north side of Fox Canyon. This site would be most desirable as it is easily accessible by road. However, based on the resistivity studies completed in Phase III of the Republic Exploration Program (Republic 1985), it appears that the shallow geothermal reservoir does not extend to the north side of Fox Canyon. The prob- ability of reaching a geothermal reservoir there (at less than 4,000 feet) is considered quite low. However, if an injection well is drilled at Sites E or H and promising signs are detected, it might be possible to develop the production well at one of these sites. In conclusion, a straight hole near ST-1 is the recommended alternative (despite its attendant logistic difficulties) because it is the only alternative with a high success probability. 2.2.2 Effluent Disposal Three disposal alternatives were considered for the power plant effluent: injection, stream disposal, and ocean disposal. The last two methods of dis- posal were rejected. Stream disposal cannot be implemented due to environmental considerations (see Section 3.5). Disposal to the ocean at Driftwood Bay where MLF8/A 2-6 the disposal of concentration of chemical constituents may be acceptable would require the installation of brine pumping facilities and a water pipe from the plant to Driftwood Bay. These facilities may add approximately seven million dollars cost to the project and would require 280 KW to pump the effluent. These costs would severely impact the economic feasibility of the project. Under the injection well alternative, steam from the turbines would be con- densed in an air cooled condenser after which it would be combined with the liquid effluent from the plant for injection. Therefore, all of the resource produced must be injected after heat energy for power production is extracted. The capability of the injection wells to take the effluent will determine the number of wells and/or effluent pumping requirements. The number and diameter of well bore of the injection wells may be at least as large as the production wells. Assuming that the production well(s) is located near ST-1l, three sites were considered for the location of injection wells (see Figure 2-3): ° Site G located on the same plateau as the ST-1 test well. ° Site H located across Fox Canyon to the northwest. ° Site E located across Fox Canyon to the northeast. Injection at Site G on the plateau where ST-1 is located is a definite possibility. Shallow zones of high porosity and permeability are as likely here as they are on the Lower Fox Canyon Plateau and, of course, have been proven in ST-1. However, the "dry steam" zone in ST-1 at 600+ feet, while a good can- didate for injection, is very probably in direct communication with the underlying liquid geothermal reservoir. Even if an injection site were chosen at the eastern or southern edges of the plateau, there would be substantial risk in such a fractured system that any cold water injected shallow might reach the production well(s) before being heated by the rock to reservoir temperature. The Hatchabaru geothermal field in Japan is analogous geologically to Makushin and provides an example of where shallow injection had just such disastrous results. A more desirable option on the ST-1 Plateau would be to inject deeper than the production reservoir, on the order of 3,000 to 4,000 feet. While con- MLF8/A 2-7 munication is still likely between the injection and production zones, cold injection fluid would initially move deeper (until heated) in the system because of its relatively high density. There is a reasonable probability that such deep fractures would be encountered, particularly if the target selected were in the same major fault that ST-1l intersected. However, there is no direct or geophysical evidence as yet that such deep fractures exist, and an injection well drilled to these depths would be considerably more costly. Sites E and H are located across Fox Canyon from the test well site. Injec- tion at these sites would not likely affect the geothermal reservoir. Injection wells at both sites would be 300 to 600 feet deep based on resistivity test data (Republic, 1984). Site H has the advantage of being located directly across Fox Canyon from ST-1. During the exploration program, a thermal gradient well was drilled in this area. A massive cinder zone was encountered in this hole which had very high permeability. However, cinder zones are characteristically limited in areal extent, and unless the zone is connected to equally high permeability fractures and possibly to the production zone or an extensive tuff layer, it might fill up rapidly with sustained injection. Another factor which makes this site very much a second choice is its elevation. The requirement for pumping waste fluids from the plant up to this site, 425+ feet higher, would add signi- ficant cost and complexity to the plant construction and operating costs. Site E, although somewhat further from the test well site than Site H, is at the same elevation as the test well site. Site E would have lower capital and operating costs because no pumping would be required. Injection potential at Site E on Lower Fox Canyon Plateau is untested, as it is at any potential site on the east side of Makushin volcano. The geology of the area is reasonably well known, however, based on surface mapping, four tem- perature gradient/core holes, the ST-1 production well, and the 1984 resistivity survey of the area. From these data there is ample evidence (detailed below) that porosity and permeability in the upper 1,200+ feet of formation are generally pervasive in the area. The probability of encountering a suitable injection interval at almost any site is therefore believed to be quite high, on the order of 90+ percent. MLF8/A 2-8 Recent Makushin volcanics have matrix porosity and permeability ranging from very low values in the basalt flows to very high values in cinder zones and unwelded tuffs (ash layers). The Unalaska formation and plutonics are generally fractured, and characteristically have low porosity but very high perme abil— ities. Fractures are generally associated with faulting, and several major faults are known to exist in the Fox Canyon area. Direct evidence of widespread permeability in the area is the severe lost circulation encountered during the drilling of all four core holes and ST-l. In several instances, circulation could not be regained even with massive doses of lost circulation materials and cement. Furthermore, the recovered core from all five holes exhibited extensive fracturing and veining. The resistivity survey conducted in 1984 covered the entire area of prospec tive injection sites. In general, the survey showed that unaltered, unfractured rock on Makushin exhibits resistivities of 3,000 to 20,000 ohm-meters. The target for injection, highly fractured rock, unaltered and saturated with fresh water is in the 100 to 500 ohm-meter range. The geothermal reservoir rock (highly fractured, moderately altered and containing slightly saline fluids) has resistivities in the 20-50 ohm-meter range. Several modeled resistivity lines clearly show the Lower Fox Canyon Plateau to have 100 to 500 ohm-meter resistiv- ities from near the surface to more than 1,200 feet. Additional information on the geologic data interpretation relating to the geothermal resource appears in Republic, 1985 Section 5 and Appendix E. Thus on balance Site E on the Lower Fox Canyon Plateau site is believed to be the best site for an injection well, offering a high probably of success, a shallow target zone, and relatively trouble free operation. The other options discussed above entail more risk, complexity and/or cost. Because of the serious technical and economic disadvantages to the alternative injection sites, it would be prudent to verify the technical feasibility of Site E as early ‘during the project development as possible. If Site E is found to be tech- Nically infeasible, the feasibility of the entire project should be re-evaluated prior to additional commitment of production expenditures. MLF8/A 2-9 2.3 WELL AND POWER PLANT DESIGN CONSIDERATIONS eee 2.3.1 Well Design Considerations The geothermal resource will be conveyed from the production wells to the power plant site by means of insulated pipes of a diameter consistent with flows and allowable pressure drops. Likewise, the fluids for disposal from the power plant will be collected and conveyed into the injection well. To generate 5,000 kW from a flash steam cycle or 7,000 kW of power from a binary or hybrid cycle, 1,100,000 lbs of fluids will be required with steam at a turbine inlet pressure of 60 psia (well head pressure 80 psia). Three different well diameters were considered in an effort to determine which well size would result in the lowest total cost for wells. The following tabulation shows the number of wells of each size required to produce the needed resource. (See also Appendix B): Production Well Diameter Flow/Well Wells Required Total Flow 7 130,000 1bs/hr 8 1,040,000 1bs/hr 9 5/8" 350,000 1bs/hr 3 1,050,000 1bs/hr 13 3/8" 1,100,000 1bs/hr 1 1,100,000 1bs/hr Cost and success probability factors favor 13-3/8 inch wells as opposed to smaller diameter wells. A cost estimate (see Appendix B) indicates that two 7 inch diameter production wells are approximately equal in cost to a single 13-5/8 inch well. As seen in the above table, eight 7 inch wells would be needed to provide the same total flow as a single 13-3/8 inch well. A similar argument can be made against the 9-5/8 inch well alternative. If three 9-5/8 inch diameter production wells were drilled instead of one 13-3/8 inch well, the need would still exist for spare production well capacity. A minimum of one spare 9-5/8 inch well would be needed and this would not pro- vide the same margin of safety as would a single spare 13-3/8 inch well. Furthermore, four 9-5/8 inch wells would cost more than two 13-3/8 inch wells; therefore, this is obviously not the most cost effective nor most reliable option. A similar argument applies for the 7 inch well alternative. MLF8/A 2-10 Success probability also favors the 13-3/8 inch production well. A single well drilled as close as possible to the test well target has a very high proba- bility of success. Smaller diameter multiple well producers would have to be spaced out from each other so as not to create well interference. The further the target is from the known successful target, the greater the uncertainty of success. Therefore, the 13-3/8 inch diameter production well is recommended. Although a single 13-3/8 inch diameter production well could supply suf- ficient geothermal fluid to operate the proposed power plant, well problems that may develop could shut down the power plant for an extended period of time. Should the problem develop in the fall of the year, it is unlikely that a drilling rig could be moved in to do any work for perhaps six months or more. The kinds of well problems which could occur include damage due to earthquake, plugging from scale formation which may occur after long periods of production and gradual decline in production rate resulting from unforeseen resource deple- tion. Therefore, drilling one additional production well is recommended to assure adequate redundancy of supply and avoid costly remobilization in the event of a problem. In the case of the 13 3/8" diameter wells recommended, one such well will, in effect, provide 100% spare resource production capacity. 2.3.2 Generation Equipment Selection Considerations The moderate geothermal resource temperature (382°F) at Unalaska, and the projected electrical load to be served, ranging between 5000 KW and 7000 KW pre- sents a situation where the following types of power plant configurations are eligible for consideration: ° Total flow generation units in the 5000 KW to 7000 KW range. ° Medium size binary generation units in the 2500 to 5000 KW range. ° Single flash turbine generators in the 2500 KW to 5000 KW range. ° Double flash turbine generators in the 2500 KW to 5000 KW range. ° Small binary self-contained units in the range of 1000 KW. ° Hybrid power plants comprised of a combination of the single flash units and small binary or total flow units. MLF8/A 2-11 2.3.2.1 Total Flow Generating Systems The total flow cycle employing a rotary separator turbine followed by a con- densing steam turbine has been built and tested for use in low enthalpy geo- thermal resources similar to Makushin's. However, only one such plant cycle has been permanently installed in the United States. Data on availability, reliabi- lity, and maintenance experience on this single installation are lacking. In addition, the smallest size unit available is designed to produce 5000 kW which is considered to be excessive capacity in a single unit on the Unalaska system. There are no known permanent installations of two phase expansion turbine total flow systems. Thus, there is no data on which to evaluate the commercial viabi- lity of such a system. The Makushin geothermal power plant will be in a remote area and will serve as a primary source of power. Dependence on a single, experimental generating plant would introduce major but unquantifiable reliabi- lity problems in the system. It is, therefore, inappropriate to consider any total flow technologies for application at Unalaska. 2.3.2.2 Medium Size Binary Generating Systems The medium size binary generation units in the 2500 kW to 5000 kW range have been built and are successfully operating commercially in fields similar to the Makushin geothermal resource. In some instances, such plants are cost com- petitive with single flash turbine units. However, binary units have a more complicated cycle and are normally applied where the geothermal resource brine content does not permit the application of flash steam turbines. The relatively clean brine of the Makushin Reservoir nullifies this advantage. While binary cycle plants have only a slightly higher cost than single flash units applicable to the Makushin resource, they have a higher risk in reliability due to the presence of flammable fluids in this cycle. 2.3.2.3 Single Flash Generating Systems Single flash turbine generator units have the most successful worldwide operating history. The system components are commonly used in other types of generation applications. Manufacturers from the U.S., Japan, England and Italy have experience building steam turbines designed for flash steam applications dating back more than twenty years. This is more than for any other conversion MLF8/A i 2-12 technology. Therefore operation and maintenance of the major components are well known to those involved in conventional steam generation applications. Single flash turbine generators in the range of 2500 KW afford optimum plant availability due to the simplicity of the plant and its operation. All flash steam alternatives require the inclusion of a steam water separa- tor. Some plants also include a demister. Demisters are sometimes used to remove the last traces of moisture from the steam as a means of minimizing tur- bine maintenance requirements. Use of efficient steam water separators preclu- des the need for demisters. Efficient separators can obviate the need for demisters for the Makushin resource. Also, based on chemical analyses (Republic, 1984), the Makushin resource does not appear to require chemical treatment for the prevention of scaling. Single flash non-condensing power cycles are the simplest systems that can be employed. However, they are also by far the least efficient systems. Such a system in Unalaska would use approximately twice as much steam per KWH as a con- densing turbine. The adverse environmental impacts would also be proportionally greater. The number of production and reinjection wells would be double for a condensing system so that the cost saving for the plant and the simplicity of operation would be lost as a result of added cost and complexity of resource production and disposal. Single flash plants in the range of 5000 kw comprised of two 2500 KW units have the lowest cost per KW than any of the other alternatives considered for application in the Makushin resource. These turbines, however, do not use all of the energy economically recoverable from the geothermal resource and thus permit the recovery of the unused heat energy. This permits the installation of small binary units which can use this remaining heat in a cost effective power generation system. The selected flash steam pressure determines the fraction of the geothermal resource which flashes to steam for use in the steam turbine. The higher the flash pressure the lower the fraction of steam produced. On the other hand, lower steam flash pressures result in larger steam volumes per pound and less energy available from each pound of steam flashed. The net result is that lower MLF8/A 2-13 flash pressures require larger turbines. Conversely higher flash pressures require the drilling of more wells and the production and handling of more total pounds of geothermal resources. An inlet pressure of 60 psia to the single flash steam turbine is optimum for the Unalaska resource. By using the heat remaining in the unflashed geothermal water to power binary cycle units increased efficiency of resource utilization can be achieved. 2.3.2.4 Double Flash Generating Systems The double flash turbine generator cycle has substantive experience in application in geothermal resources with enthalpy similar to Makushin. These turbines have been installed in fields located in climates where water cooled cooling towers can be used. At the Makushin geothermal field, with low ambient temperatures during the winter, higher cost air-cooled condensers are recom- mended. Although higher in cost, air-cooled condensers do not unreasonably raise the cost of single flash units, a second steam flash produces substan- tially less power per pound of steam flashed and requires a larger condenser. This raises the relative cost of the condenser and the parasitic load for its fans. This coupled with the increased size of the turbine, additional control valves and steam inlets to the turbine, combine to make a double flash steam turbine less economic than using the heat in binary cycle units. 2.3.2.5 Small Binary Generating Systems Small binary units, in the range of 1000 KW each, have been successfully de- signed for applications where the geothermal resource has high scaling content. These units are favorably used where conventional flash type turbines would be directly exposed to such contaminants which would periodically reduce turbine efficiency thus requiring substantial periodic maintenance. On the other hand, binary units have flammable fluids in their operating cycle thus increasing risks and as a consequence higher exposure to operation and maintenance costs than those of flash turbine units. MLF8/A 2-14 As previously stated, the Makushin resource is of good quality, permitting the application of flash units as a primary source of generation and the small binary units as the secondary form of generation. 2.3.2.6 The Hybrid Cycle Plant The hybrid power plant cycle is comprised of two single flash steam.turbine units of similar design to be installed and operated as the plant conceptually described in paragraph 2.3.2.3 and of the same rating. These two units could serve as the building blocks for the first 5,000 kW of plant capacity and could both be installed in the same plant building. The sub- sequent building blocks could be comprised of two binary units providing a total of 2,000 kW net capacity. They would be of the same design and unit rating as those described in paragraph 2.3.2.5. They should be located in a separate power plant building for fire safety reasons. Because binary cycle units can use the heat remaining in the water not flashed for use in a steam turbine, a hybrid plant employing steam turbines plus binary cycle units permits maximun use of the resource available from each well thus minimizing well costs. Each steam turbine driven generating unit and each binary cycle unit can operate independently of the other units in the plant. 2.3.3 Transmission Line Design and Routing The transmission line will interconnect the geothermal power plant and the City of Unalaska underground primary distribution system. This transmission line must satisfy several basic criteria. The line must be readily accessible for maintenance, especially the overhead sections which are exposed to severe climatic conditions. The routing should require minimum construction of access roads. The overhead portion of the line should withstand wind and ice loading conditions prevalent in the area. Three separate corridors and several line configurations were considered before the recommended transmission system was selected. Three main corridors were considered for the installation of the overhead transmission line. Two of the corridors go through the Makushin Valley. The third corridor utilizes the Nateekin Valley which lies toughly parallel and to MLF8/A 2-15 the south of the Makushin Valley. The Nateekin corridor has the advantage of avoiding the difficult marshy conditions which characterize the lower Makushin Valley. However, aerial reconnaissance of the Nateekin route showed it to be very rugged and rocky. The route would have to transit a very exposed divide between the Nateekin Valley and the production well site to the north in the Makushin Valley. Wind conditions and unstable soils would make the route over the divide very expensive to build and maintain. Underground cable would not be practical to install over much of the Nateekin route. Overhead line would require helicopter support to build and maintain. Helicopters are not available in Unalaska for most of the year. Mobilization of a helicopter to repair a damaged overhead line would result in prolonged outages. The line could be maintained by road if one were built for this Purpose. However, such a road would involve considerable extra expense as it would not replace the Makushin Valley Road. The latter would be needed to provide a less exposed and less dangerous operator access route. Thus the Nateekin route was rejected as impractical. Three Makushin Valley routes were considered; an upland route and two through the valley floor. The upland route, designated with "U's" in Figures 2-3 and 2-4 would require heavier towers and ten long spans. This corridor was rejected due to the difficulty of constructing the line but more so due to the difficulty of access for repairs. It would be exposed to high wind conditions and would require significant construction of access roads even though heli- copter use would be extensive. A second alternate is designated with "V"s in Figures 2-3 and 2-4. This is a better solution than "U" because it would be more accessible for construction and maintenance. It also would permit the installation of underground cables. Although this route is shorter than the Proposed route, which follows the access road, it will be more costly to build because of the need to mobilize installa- tion labor and equipment along the segment of "V" which is not on the access road. Also, access for repairs on "V", although easier than "U", is more dif- ficult than for the route which follows the access road. The foundation conditions in the lower Makushin River Valley are poor, as described in the earlier section on access roads. The soft muck underlying the MLF8/A 2-16 marsh vegetation mat is incapable of supporting loads associated with transmission line structures. The transmission line towers would have to be built on foundations supported by piles. This option was rejected as tech- nically infeasible. Therefore, underground cables were selected to be installed adjacent to the operational access road. Placement of these cables should only require a thin width trench cut through the mat. The mat will likely close naturally relatively soon after cable placement. The route recommended would go underground from Point K (Broad Bay) to Point J in the Makushin Valley, and would parallel the proposed access road (see Figure 2-4). From Point J to the power plant it would go overhead on an "H" frame wood pole structure, Figure 2-7, as shown on Figure 2-3. The transmission line will generally follow the proposed road. Two transmission voltage levels (69 kV and 34.5 kV) were considered for various maximum loads up to 10,000 kW at .85 power factor. The 69 kV transmission voltage has the advantage of transmitting higher loads than the 34.5 kV at lower regulation and losses. However, the initial cost of the 69 kV overhead line and the underground and submarine cables is on the order of 10% higher than for the 34.5 kV (minimum conductor size at 69 kV insulated cables is 4/0). This 69 kV system would also require the installation of a step-down transformer (69 kV to 34.5 kV) at Dutch Harbor to interconnect with the existing 34.5 kV system. The initial cost differential of the 69 kV system over the 34.5 kV system is approximately $620,000. Thus the 34.5 kV system is recommended. The 34.5 kV transmission line with the same conductor sizes as the 69 kV line (4/0) would have the capacity to transmit the projected 7,000 kW power plant output at .85 pf. The submarine cable crossing Broad Bay will be con- nected to the existing 34.5 kV underground system without the need of transfor- mation. The underground and submarine cable portion of the line should have the mechanical and insulation strengths to provide a high degree of service reliability. The installation of poles for the overhead line and the installa- tion of the underground cable should be from the access road built for sub- sequent use by plant operating and maintenance personnel. MLF8/A 2-17 Three cable configurations were considered for the land underground cable: Option 1 - One three-conductor cable (4/0). Option 2 - Three single-conductor cables (4/0). Option 3 - Four single-conductor cables (4/0). The four cable array would provide an immediate spare in the event of a cable failure similar to the submarine cable installation. However, it was felt that the three single-conductor cable design would provide sufficient service reliability since it will not be exposed to mechanical damage. In the unlikely event that one conductor was damaged, a temporary repair could be made by laying a fourth cable on the ground. This would not be possible under Option 1. Therefore, Option 2 is recommended. Three cable configurations were considered for the submarine crossing to Dutch Harbor. Option 1 - Two three-conductor cables installed some 350 feet apart from each other to provide redundancy. Option 2 - One three-conductor cable. Option 3 - Four single-conductor cables spaced at approximately 350 feet, one of which would be used as a spare to any one of the three others. Cable switching stations would be installed at the terminations of the submarine cables. Options 1 and 3 offer redundancy in the event that one of the cables were damaged (for example, by an anchor). Option 1 would cost approximately $1 million more than Option 2, Option 3 would only cost $0.6 million more than Option 2. Therefore, Option 3 is recommended. The four single-conductor cable submarine crossing and the three single- cable underground land installation adjacent to the access road is the recom- mended system with switching stations at their respective interconnection and termination points. MLF8/A 2-18 2.4 POWER PLANT SITE SELECTION Selecting the preferred arrangement for the power plant production wells and injection wells involves balancing many considerations. These considerations include operations access, reliability, capital and O & M cost and drilling suc- cess probability. The ideal arrangement would include a high success probabil- ity production well site, power plant and injection sites in close proximity to the power plant, easy operator accessibility and low capital and 0 & M costs. In reality, no site alternative on Unalaska meets these ideal conditions. As discussed previously in this section, Site G near ST-1 offers a very high probability of yielding a production well, and is therefore the logical choice for a well. The high cost of steam and hot water pipelines (and the potential heat loss) impose a practical limitation that the power plant site be located less than one mile from the production well. Furthermore, the power plant site must have a reasonably level area for power plant facility development. Given a production well at Site G, and injection at Site E, three alter- native power plant sites meet the above criteria; they are indicated as sites G, E and H on Figure 2-3. Table 2-1 provides a summary comparison of these three alternatives. Site G (near the test well site) has the advantage of locating the plant close to the production well. The major disadvantage of this site is that the access to this site is by air. (Building a road across Fox Canyon would be a very costly venture, as the minimum span would be in excess of 1000 feet. Prefeasibility level cost analysis ruled this option out as uneconomic.) Air access would add greatly to the construction cost of the power plant and would severely restrict operator access. Access would only be during good (visual flight rule) flying weather. When plant outages occur in bad weather it would not be possible to return the plant to service until the weather improved suf- ficiently to permit flying to the site. The reduction in plant availability and production capacity would be severe penalties. As noted in Section 2.2.2, waste brine would have to be piped across Fox Canyon for injection. Site E (on the plateau to the northeast of the test well site) is reasonably accessible for construction of the power plant and is accessible by boat and MLF8/A 2-19 OPERATIONS ACCESS INJECTION WEATHER RELIABILITY O&M COST CAPITAL COST *Assumes production well(s) near ST-1 test well site. MLF8/AT1 COMPARISON OF ALTERNATIVE POWER PLANT SITES* SITE G WELL TEST SITE Road to powerplant, footbridge to well site Near Site E (requires injection effluent pipeline from G to E) More favorable than H Most difficult access in bad weather Added cost for airstrip maintenance or helicopter. Large added cost to operate air access. Savings in labor due to quicker access if by air. Highest due to air-only access during construction. Added cost for building airstrip or large cost for road bridge over Fox Canyon. Injection effluent pipeline needed across Fox Canyon. TABLE 2-1 SITE E PROPOSED PLANT SITE Road to powerplant, footbridge to well site Near Site E Same as G Easiest access for repair Additional cost for production fluid lines. Slightly higher labor cost for fair weather accesse Lowest cost even though dual production fluid pipelines (water and steam) across Fox Canyon are needed. SITE H NORTHWEST OF SITE G Road to well site, road to powerplant Near Site H Worse weather than G or E, due to higher altitude More difficult access for repair due to worse weather. Added unreliability of production fluid pump. Additional cost for production fluid pipelines and pumping. Energy cost of 280 kW to pump production fluids. Higher than E due to poor weather and need for pumping equipment to raise production fluids from well site to plant. This cost is partly offset bv somewhat shorter pipelines than E. Locations keyed to Figure 2-3. road for power plant operation. It is also within a reasonable distance from the production wells and is the nearest to the injection well site. Its major disadvantage is that both steam and water pipelines must be built from Site G across Fox Canyon to Site E. Site H is slightly closer to the production well site than Site E but is 425 feet higher than the production well site. Therefore, if the unflashed water is to be used in binary cycle units, that water would have to be pumped up to the power plant. The pumping power would reduce plant output capacity by approxima- tely 280 kW. In addition, based on causal observation during the thermal drilling investigations (Republic, 1984), the weather at this site is con- siderably worse than at any other site considered, making operation and main- tenance more difficult and expensive. Based on the above factors, it is recommended that the power plant be sited at Site E. 2.5 SITE ACCESS SELECTION The plant site, construction access roads, operator access roads and transmission line routings proposed are based on a site visit, aerial obser- vation and reports from the Engineering Geologic Technical Feasibility Study performed by the State of Alaska Department of Natural Resources in September 1986. 2.5.1 Construction Access The major access for drilling and construction equipment will be from Driftwood Bay to the plant site via an existing road (referred to as the “Driftwood Bay Road" in Figure 2-1) and a proposed new road (referred to as "Sugarloaf Road"). The existing road is in relatively good shape and will require repairs for use as indicated in the ADNR report. Repairs to this sec- tion will consist primarily of culvert placements and filling of minor washouts. A new bridge will be required in Driftwood Valley. The airstrip at Driftwood is also in good condition and could be usable with minor upgrading. The proposed Sugarloaf Road would traverse terrain similar to the Driftwood Bay Road and would be straightforward construction with only minor drainages crossed, except MLF8/A 2-20 Near the proposed plant site, where it will be necessary to construct two bridges to span deep canyons. Borrow sources for road upgrading and new construction have been identified by the ADNR Technical Feasibility Study Section K. They contain good road building material with minimal haul distances. Material Source 1 (see Figure 2-2) near Driftwood Bay can be used for airstrip and road upgrading in the valley. Barge offloading of construction equipment and material at Driftwood Bay is possible in calm weather. The northeast end of the Bay (near the existing tanks) appears to be the quietest portion with slightly more gradual beaches and generally smaller sized beach deposits (Figure 2-2). 2.5.2 Plant Site Operator and Maintenance Access Driftwood Bay is 15 miles from Unalaska and access by either water or air during bad weather conditions would be too dangerous to consider; therefore, this road is not considered suitable for access by plant operation personnel. For this reason a road from Broad Bay to the plant site for operator and main- tenance personnel access is required. Operator access to the power plant could be accomplished either by fixed wing aircraft or by helicopter. However, road access must still be maintained for delivery of heavy parts for power plant repairs and maintenance and for transmission line maintenance. The cost of owning and operating a four place fixed wing aircraft similar to a Cessna 182 would amount to approximately $50,000 per year including an estimated $12,000 per year for insurance. Helicopter operation would be considerably more expensive. The cost of a pilot if required would be in addition to the above. Because of these costs and because air access would be severely limited by weather conditions, the air access option was rejected. The most reliable operational access to the plant site is by boat from Dutch Harbor to Broad Bay and then via a road up the Makushin Valley to site B and on to the plant site by way of the Sugarloaf Road (see Figure 2-3). MLF8/A 2-21 The beach at Broad Bay is composed of medium to fine sand and generally slopes at 15 to 20 degrees. Construction of a small dock and breakwater should not be problematic geotechnically. The dock can be supported on the near shore sands, The breakwater will also be constructed from timber piles. The lower third of the Makushin Valley (from Broad Bay to Site J on Figure 2-4) is characterized by marshy surface vegetation. Any road on this material must be buoyant and flexible. Alternatively, the road could be built on the coarse material deposited on the banks of the active stream channel. Although this latter alternative was used in the past to construct a road through the valley, it is not recommended for this project. A road along the active stream channel would be too easily washed out, as evidenced by the obliteration of the old road. Furthermore, such a road would be environmentally damaging as it would cause excessive siltation. The location of the buoyant road through the lower third of the Makushin Valley is limited only by avalanche potential (at the north and south sides of the valley) and by avoidance of the active stream channel. The acceptable areas are shaded in Figure 2-4. The shaded areas exclude the avalanche zones at the sides of the valley and the unstable banks of the main stream of the Makushin River. The exact road alignment within this corridor is technically indif- ferent. The alignment should be selected in the field based on input from environmental agencies and landowner preference. A conventional road was considered for the lower third of the Makushin Valley. Such a road could be constructed along the south edge of the valley. Solid ground capable of supporting a conventional road is found at elevations just above the valley floor. However, much of this route is indicated as being prone to avalanche hazard, increasing maintenance expense and posing a safety hazard to plant operating personnel enroute to the power plant. Thus, this alternate was rejected. The road in the upper valley will be bearing for the most part on alluvial sands and gravels and road construction should be relatively conventional. Both the south and north channels (Figure 2-3, near Site 1) of the Makushin will have to be crossed with bridges. The bridges can be supported on either conventional MLF8/A 2-22 pile foundations or spread footings bearing on alluvial soils. This is a more active portion of the valley and elevations should be set with this in mind. Good alluvial borrow sources have been identified by the ADNR in this area and sufficient quantities of good quality material should be available. The Makushin Valley access road could be used for transmission line construction, for underground cable installation and access of personnel during construction and operation of the power plant. This road would not be adequate for construction access to the plant site because it has a section of extreme high grade and sharp turns for construction equipment from Site I to the pro- posed site B. Also, the section built over the flood plain would be light duty, built for use by light personnel vehicles only. A four wheel drive pickup truck (carrying a snowmobile in winter) would suffice for personnel transport. 2.5.3 Marine Terminal Facilities At Broad Bay a dock with a small crane will be required at the end of the power plant access road. This dock will require protection by a solid wood piling breakwater. Operators could cross Broad Bay from Unalaska in a work boat dedicated to the power plant. The boat must be capable of delivering main- tenance equipment, lubricants and operating supplies including isopentane. It must also be capable of transporting the vehicle, used by the operators and maintenance personnel for land transportation to and from the plant, back to the City of Unalaska for repairs and maintenance. Equipment landed at Driftwood Bay will be unloaded by cranes, or off-loaded over ramps carried on the barges, directly onto the beach or onto trucks and trailers on the beach. A temporary road on the beach will be constructed from steel mats laid directly on the beach. Barge unloading operations will only be conducted during calm weather so that protection from breakers will not be Necessary. Therefore, there will be no need for any permanent special marine facilities at Driftwood Bay. MLF8/A 2-23 2.5.4 Manned Versus Unmanned Operations In discussions between the project team and the City of Unalaska, the City Manager and the City Engineer expressed a strong preference for unattended operation. However, for comparison the attended operation option was con- sidered. The difference in capital costs between attended and unattended opera- tions is minimal. The only extra equipment which is needed for unattended operation is the Supervisory Control and Data Acquisition System (SCADA) which costs approximately $275,000. The redundant auxiliary equipment is appropriate for a remote site such as this even under attended operation. The primary difference between attended and unattended operation would be due to operating cost. Under the unattended option, operators would be present at the plant for five man-days per week at a cost of approximately $62,000 per year. Attended operation with two operators on site at all times (for safety reasons solo operation is not recommended) would cost approximately $437,000 per year. Additional transportation would add at least $25,000 per year, yielding approximately $462,000 per year added cost. This additional $462,000 cost for attended operation would have the benefit of decreasing the forced outage rate by an estimated 3 to 5 percent, improving plant availability from 75 percent (for unattended) to a maximum of 80 percent (for attended). Preliminary calculations indicate that the annual cost saving from additional availability would amount to less than half of the additional operating costs. As both local preference and project economics favor unat- tended operation, that is the recommended alternative. 2.6 PROJECT DEVELOPMENT LOGISTIC CONSIDERATIONS A drilling program to construct the production and injection wells logically precedes power plant development. Until successful wells have been constructed, it is not prudent to commit to the much greater expense of power plant and transmission facilities. Furthermore, it is important to confirm the reservoir pressure and temperature in the production wells before committing to a power plant design. Although these data are available from the test well, it is important to confirm the data from an actual production well. MLF8/A 2-24 In supporting the drilling program, two scenarios were evaluated--helicopter supported mobilization from Dutch Harbor versus barge and road supported mobili- zation from Driftwood Bay. The latter alternative requires that the Driftwood Bay road be upgraded and that the Sugarloaf Road be built prior to the drill rig mobilization. Although this option commits the cost of the Driftwood Bay and Sugarloaf Roads prior to the proven successful well program, this option actually costs less than drilling phase helicopter support from Dutch Harbor. Even though helicopter support will be needed to move the drill rig from the injection well site (Figure 2-3, Site E) to the production well (Site G), the total cost for the roads is less than the increased rig and helicopter costs. Thus, by prebuilding this road, the drilling program is no more costly, and the Driftwood Bay Road, which will be needed for power plant construction, will already be in place. Another logistical consideration is building a construction camp at the site versus daily transportation of workers lodged in Dutch Harbor. During well construction, much of which takes place around the clock, an onsite camp is a necessitye During the construction of the power plant and transmission facili- ties, crew transportation from Dutch Harbor/Unalaska would be feasible. Several facilities suitable for construction worker housing already exist in the area. However, these facilities would actually cost more than the construction site camp on a per man-day basis. Furthermore, crew transportation from town would reduce the productivity of the workers by adding a 2 to 3 hours "commute" to the working day. Thus the onsite crew camp is the preferred alternative. MLF8/A 2-25 INJEGFIO: “Loe . WELLS .PROPOSED SITE ar ‘SITE PRODUCTION: J WELL SITE, POWER*PLANT. ient : cl KEY MAP més 7 ~ MAKUSHIN RIVER. VALLEY. SMile 1.0 Mile Approximate Scale WITCHING. = CSTATION“A" i : en 4 Ss J - ALASKA POWER AUTHORITY LEGEND: DIRT ROAD MEMBRANE ROAD OH LINE UG CABLE SUBMARINE CABLE PIPE LINE BRIDGE ALIGN. CORRIDOR ALT. STEEL TWR. TRANS. LINE ALT. WD. POLE TRANS. LINE WEST TERMINAL SWITCHING STATION SUBMARINE CABLE TO DUTCH HARBOR SEE FIG. 2-5 Ase sass TWOOD BAY lS TERIAL S . SEE FIG. 2- 5 Mile 1.0 Mile Approximate Scale 0 BARGE LANDING POINT MATCH LINE | * LEGEND SEE FIG. 2-1 Q: O-. E FIG. 2-3 = Aaa INEZ aS a\~ mS i ‘MAKUSHIN VALLEY ROAD aN ) - My Yr. ROSS > QAR) Pe rrr Ne IN SKS AN ea TT OW Wp Zy tes TBM A Zécwa—|~«\ ~NALTERNATE WOOD POLE] SO LON Sa at AS a= DEES TRANSMISSION LINE FE S = ( g “Shae | S eR, Vib —e— hes ee Ve : Z OSA WNLE = Z > Ol SY '\ RS - . : G | PRODUCTION eS cle PINS Sey) : > TERR EL TOWER) > tS oe Z T (ISSION LINE Me wy PIPE LINE : SANSMISSION LINE if. a <S CROSSING DZ Nite 28 °YZF ‘SEE FIG. 2-1 SMile 1.0 Mile Approximate Scale 5 Mile 1.0 Mile bt OVERHEAD LINE TERMINATION > Approximate Scale UNDERGROUND CABLE TERMINATION 1 - LEGEND SEE FIG. 2-1 SUBMARINE CABLE TO DUTCH HARBOR SEE FIG. 2-5 =~ TRANSMISSION LINE ROUTE — == SSS 8 RR VALLEY ROAD &— - SION LINE CORRIDOR ~~). Ae oa Te y ex mya * WEST TERMINAL SWI pos est ’ ——S NSMISSION ul Son rr.) a 7 i oid an OF LTERNATE STEEL TOWER. > TRANSMISSION LINE ROUTE / i Affe: Sy neattnewe alates ata kel = WS — MAKUSHIN ; TRANSMIS Tso eo £ ITCHING STATION © C94 2 Eee TS MAKUSHIN VALLEY ACCESS ROAD AND TRANSMISSION LINE CORRIDOR Makushin Valley \ SWITCHING STATION ° GRAPHICAL SCALE: YARDS 2000 —- 3000) 4000 $000 6000 2000 = gooo' 10000 ‘11000 12000 13000 «14000 | : = SSSSaae= SUBMARINE CABLE 5 I N. E. PROFILE Ne SOUNDINGS IN FATHOMS SCALE: HORIZ. I"=1000) VERT. |"s 200! AT MEAN LOWER LOW WATER. ' —200 - 14.000! 15000! 1@000' |7000! ALASKA POWER AUTHORITY 3030 Petrick Henry Or., 8 O50 SAI ENGINEERS, INC. SUBMARINE CABLE ROUTING Title = SAI Project No. 851G5 «ge “2 RAPSs_— JO MIS POLYS THyLENE lient : SAI Project No. 8G1G5 Date: (TYP) acd \ Vg GROUND WIRE (TYP) Vee eee Lecce i | nS ade. ead ) \ GUY WIRE H-S x70! DOUGLAS FIR POLES - RAPS 10 MILS. POLYETHYLENE” GUY WIRE (TYP) Ya" EXTRA H.S. GALVW. STEEL STRAND Title; SAI ENGINEERS, INC. Sng. Seen siheiaindeaeeae oe Se 3 ALASKA POWER AUTHORITY fi OVERHEAD TRANSMISSION STRUCTURES 3.0 ENVIRONMENTAL CONSIDERATIONS ee 3.1 GENERAL PERMIT REQUIREMENTS ra ee NLS, Permits and approvals potentially required for development of the Unalaska Geothermal Project are listed in Table 3-1 along with the timing -of permit acquisition. Specific aspects of permitting are discussed below. 3.1.1 Federal Permits Most of Unalaska Island is federally owned and is part of the Alaska Maritime National Wildlife Refuge administered by the U.S. Fish and Wildlife Service (USFWS). However, most of the lands that would be potentially affected by geothermal development have been selected for ownership by the Aleut Corporation and the Ounalaska Corporation under the terms of the Alaska Native Claims Settlement Act. After conveyance, USFWS will have no direct regulatory authority over the selected lands. However, as these lands adjoin Refuge lands, the USFWS will remain interested in the land uses as they might affect the Refuge. The process of reconveyance was initiated in 1984 but has not been com- pleted. From a permitting standpoint, it is essential for land conveyance to be completed prior to development of geothermal facilities. Federal regulations prevent the development of geothermal energy within wildlife refuges (F. Ziellemaker, USFWS, personal communication to John Morsell, D&M, 2/87). Contacts with the Aleut Corporation indicate that the conveyance process is pro- ceeding with high priority placed on the lands that would be affected by the Makushin geothermal project (C. Cardinalli, Aleut Corp., personal communication to John Morsell, 2/87). The Aleut Corporation is expected to receive patent to the land sometime in mid-1988 but some activities could Probably occur prior to that time under an interim conveyance agreement. The U.S. Army Corps of Engineers (COE) will be heavily involved in the per- mit process because of its responsibility as permitting agency involved with dredge and fill of waters and coastal alterations. Road construction across wetlands will require COE permits as will barge docking facilities. A National Pollutant Discharge Elimination System (NPDES) permit would be required if wastewater were discharged into freshwater or marine environments. MLF6/C11 3-1 PERMITS, STA TABLE 3-1 TUTES AND REGULATIONS AFFECTING THE DEVELOPMENT OF THE UNALASKA GEOTHERMAL PROJECT STATUTE OR REGULATION Clean Water Act Section 404 Rivers and Harbors Act of 1899 (Section 10) Fish & Wildlife Coordination Act Endangered Species Act of 1973, 50 CFR 17 Endangered Plant Permit 50 CFR 17.62 Endangered Wildlife Pernit 50 CFR 17.22 Marine Mammals Protection Act, Endangered Species Act, Fish & Wildlife Coordination Act of 1934 Federal Water Pollution Control Act, 40 CFR 125 Underground Injection Control Clean Air Act, CFR 515-51 Clean Air Act, Section 160-169 Marine Protection, Research and Sanctuaries Act of 1972 Gravel Extraction Contracts (AS 38.05.110; 11 AAC 76) Tide Lands Le. (AS 38.05. e 30; 11 AAC 62) Fish Habitat Permit (AS 16.05.870; AS 16.05.840; 5 AAC 95.010) Fishways for Obstruction to Fish Passage (AS 16.05.840) Wastewater Disposal Permit (AS 46.03.020-100 100 18 AAC 15, 60) Solid Waste Disposal Permit (AS 46.03.020-100; 18 AAC 15, 60) Coastal Zone Consistency Determination MLF6/CT7 AGENCY U.S. Army Corps of Engineers U.S. Army Corps of Engineers U.S. Fish & Wildlife Service U.S. Fish & Wildlife Service National Marine Fisheries Service U.S. Environmental Protection Agency U.S. Environmental Protection Agency U.S. Environnental Protection Agency U.S. Environmental Protection Agency U.S. Environmental Protection Agency State of Alaska, Dept. of Natural Resources DFLWM State of Alaska, Dept. of Natural Resources DFLWM State of Alaska, Dept. of Fish & Game State of Alaska, Dept. of Fish & Game State of Alaska, Dept. of Environmental Conservation State of Alaska, Dept. of Environmental Conservation State of Alaska, Div. of Governmental Coordination DESCRIPTION Permits for discharge of dredged or filled material into navigable waters or wetlands (includes wet tundra) Permits and stipulations for any structures or work including dredging and filling, in navigable waters and adjacent wetlands Review proposed permits to be issued by Corps of Engineers or Coast Guard for any work or structures in navigable waters or adjacent wetlands Determination of threatened or endangered species presence; Stipulations on di turbance level near sensi- tive areas if endangered species are present Review proposed plans and permits for activities affecting nearshore and offshore marine resources NPDES permits for discharge into navigable waters Pernits for various classes of materials to be injected underground via wells - applicability to geothermal injection is questionable. PSD permits and standards for new source air quality Permite for the emissions of air pollutants and set standards Permits for ocean dumping Contracts for sale of gravel on state lands Lease of state-owned tidelands Permit for activities affecting anadromous fish ( mon & arctic char) Permits that guarantee fish passage in all streams in the state Permits for wastewater discharge including geothermal waste injection Permits for disposal of all solid waste Review activities in the coastal zone for consistency with Alaska Coastal Management Program TIME FRAMF. 15 days after submittal there is a 39-day period for public comment. If no objections, permit issued within 90 days 15 days after submittal there is a 30-day period for public comment. If no objections, permit issues within 90 days Variable Variable Variable Must apply 180 days prior to discharge, 30 days for public comment 30 days for response fron EPA. 30 days for public comment, 1 year maximum for final determination 30 days for response fron EPA. 30 days for public comment, 1 year maxioun for final determination 30 - 90 days Apply one season prior to construction 60 days for final action 30 days for final action 30 days for final action 60 days for final action 60 days for final action 50 days for final action, coordinated with other state permit applications This permit, administered by the U.S. Environmental Protection Agency (EPA), can be complex and will require detailed environmental monitoring plans. In light of permitting complexity and the water quality characteristics of the geothermal brine (see Section 3.5.1), the decision was made to reinject geothermal effluent into an isolated geologic formation. This obviates the need for a NPDES permit. The complexity of the federal permit process will depend on the complexity of the project and its impacts. Assuming no brine discharge to surface water and private ownership of project lands, then the only major federal agencies involved will be the COE and the EPA through its Underground Injection Control progran. As the UIC control is newly implemented, EPA is not certain if Unalaska geothermal fluid injection would necessitate a UIC permit (H. Scott, EPA Region X, personal communication to John Morsell, 1/87). It appears likely under these circumstances that the level of impact will not justify an EIS (that determination will be made by COE). With brine discharge to surface water the EPA would be involved and the possibility of an EIS requirement would be signi- ficantly increased. Other minor federal permits such as Coast Guard bridge per- mits may also be needed. 3.1.2 State Permits The Alaska Department of Fish and Game (ADF&G) has taken an active interest in the project because of its mandate to protect fish and wildlife resources. ADF&G recently completed a study of the area potentially affected by geothermal development and has prepared an environmental analysis report (Sundberg et al., 1987). Road and transmission line development will affect streams containing significant fish resources and, thus, ADF&G Fish Habitat permits will be required for bridges, culverts, buried cable stream crossings and other project activities that affect fish streams. The Alaska Department of Environmental Conservation (ADEC) will be involved with permitting reinjection of geothermal fluids through its Wastewater Discharge Permit program. ADEC will also be involved with air quality per- mitting and must certify all COE permits. A tidelands lease will be required from the Alaska Department of Natural Resources for structures in the tidal zone. MLF6/C11 3-2 Because this project lies within the coastal zone and requires more than one permit, state permits and state requirements on federal permits will be coor- dinated by the Division of Governmental Coordination (DGC). DGC will, at the same time, determine consistency with the Alaska Coastal Management program. 3.1.3 Permitting Status and Timing Pre-application coordination has been in progress with critical regulatory agencies, especially ADF&G. Project concepts have been developed with permit- ability in mind, and mitigation measures have been incorporated into designs to address specific agency concerns. It appears likely that permits for the project could be obtained in about six months, assuming that an EIS is not needed. The permit. process would logi- cally consist of the following steps: Distribution to the agencies of a reasonably detailed project descrip- tion. Pre-application meeting with interested agencies to allow discussion of concerns and to receive recommendations regarding project concepts. ° Modification of project concepts (if appropriate). ° Preparation and submittal of the various permit applications and required documentation (see Table 3-1). ° Permit follow-up and expediting. It should be emphasized that aside from the above permit process, coor- dination with the Ounalashka Corporation and the Aleut Corporation will be essential. As the primary landowners, the corporations will participate in land use decisions. 3.2 ENVIRONMENTAL ASPECTS OF CONSTRUCTION ACCESS 3.2.1 Driftwood Bay Airstrip The existing airstrip could be upgraded for possible use during project construction. No direct impacts beyond those already present will occur from these improvements. Air traffic and activity associated with the airstrip will create substantial, but temporary, disturbance to the western valley margin. MLF6/C11 3-3 This disturbance will probably temporarily reduce use of the cliffs adjacent to the airstrip by birds. Bald eagles currently roost along the bluffs and future activity could displace them to other areas. Intense disturbance will be inter- mittent and will probably not have long-term impact to the birds of Driftwood Valley. The Driftwood Bay airstrip is under the jurisdiction of the U.S. Air Force. The site is scheduled to be cleaned up and restored by the Corps of Engineers in fiscal year 1989, after which the Air Force intends to relinquish it to the Bureau of Land Management (P. Moore, U.S. Corps of Engineers, personal com- munication to Dave Denig-Chakroff, Alaska Power Authority, 6/87). After relinquishment, the site would be open for selection and conveyance to the Native corporations. Until the site is relinquished, use of the airstrip would require approval by the Air Force and a license from the Corps. If tne site is conveyed to the Native corporations, its use would be covered by the easement agreements negotiated between the Power Authority and the Ounalashka Corporation and Aleut Corporation. 3.2.2 Driftwood Bay to Sugarloaf Road Upgrading most of the existing road from the airstrip to the Makushin/ Driftwood divide will require little effort and no new disturbance to the terrain. Construction of a bridge at the crossing of the Driftwood River (where the old culvert was washed out) will be the only significant new construction. Instream work associated with bridge construction will need to be coordinated with ADF&G through its Title 16 permit system. Timing of bridge construction may be restricted to prevent disturbance to spawning or outmigration of salmon. Constraints on bridge construction will depend on the amount of instream work required. A section of new road will be required from the north side of Fox Canyon to the existing roadway. Most of the terrain crossed is dry, windblown tundra intermixed with areas devoid of vegetation and a few small marshy depressions. Wildlife value is low and no environmental problems are anticipated. COE wetland permits will be required if the roadway involves filling any wetland areas. Any such areas will be very small and no special permitting difficulties are anticipated. MLF6/C11 3-4 Personnel and equipment access from the end of the Driftwood Bay road across Fox Canyon to the geothermal well site during construction will be primarily by helicopter. Some terrain impact will occur in Fox Canyon as a result of construction of the pipeline/footbridge crossing. Disturbance of the canyon side slopes during construction will probably cause short-term erosion and possible sedimentation within the Fox Canyon stream. 3.3 ENVIRONMENTAL ASPECTS OF OPERATIONS ACCESS a ERA RUNS ACCESS 3.3.1 Makushin Valley Road Alternative Er oa i ternative Operational access to project facilities during project operation will be via a permanent road extending along the Makushin Valley bottom and up to the head of the valley to the powerplant site. This road will be constructed along the transmission line route to aid in construction of the line (see below). In the absence of mitigation planning a Makushin Valley roadway would have the potential to cause significant impacts to the Makushin River and its tributaries and, consequently, could affect the relatively valuable fish resources of the lower river. Detailed mitigation planning will be required during design and construction of the road in order to obtain Fish Habitat permits (Table 3-1) from the Alaska Department of Fish and Game (ADF&G). It will be necessary to complete applications for each stream alteration activity. It is likely that ADF&G will also require a detailed construction plan that describes equipment, techniques, timing, sequence and mitigation measures. Extensive discussions with ADF&G personnel have been held regarding location, design and construction of this road. In addition to the ADF&G permits, permits will also be required from the COE for those portions of the road that traverse wetland terrain. A substantial portion of the lower Makushin Valley is wetland. The road, as currently designed, will traverse about 5,500 feet of wetland. One of the primary impact concerns is the potential blockage of fish passage at roadway drainage structures. The Makushin River is used by adult salmon for spawning up to river mile 5.3 and possibly to the head of the valley (Sundberg et al., 1987). Rearing salmon (primarily coho) have been found throughout the valley but especially in clear tributaries that flow across the valley sides into the main stem Makushin River. In connection with this feasibility study it MLF6/C11 3-5 is not appropriate to identify the precise alignment of the road through the marshy portions of the Makushin Valley. This should be done in the field during the project design phase. Main stem crossings (if any) will be via bridges which, if designed and constructed carefully, will not interfere with fish resources. A cost contingency should be included in design estimates to allow for road realignment. Culverts may be permitted on smaller streams that do not Support spawning but the culverts will need to be designed and constructed according to ADF&G standards to allow passage of juvenile fish. Existence of a road in the Makushin Valley may also affect hydrologic and hydraulic conditions on the valley floor and, thus, indirectly affect conditions in the lower Makushin drainage. A road could block sheet flow or shallow sub- surface flow and change drainage patterns possibly affecting flow in tributaries used by fish. Careful routing and use of drainage structures will be essential to minimize potential impacts. The Makushin River has changed channels many times in the past and road designers will need to take this into account. Portions of the road may have to be armored to prevent erosion by the river and the consequent siltation of downstream areas. The road will need to be fully protected against flood events. Some impact will be unavoidable during actual construction of the road. Work in or adjacent to streams during bridge construction or culvert installa- tion will cause introduction of sediment into streams. The extent of stream siltation will depend on the methods used and flow conditions at the time of construction. Construction methods and timing when in the vicinity of streams will need to be coordinated with ADF&G. Permit stipulations will likely limit the timing of instream work to avoid times when adult salmon are present and when eggs or fry are in the gravel, leaving a narrow construction window (mid-May to mid-July). 3.3.2 Broad Bay Boat Dock Regardless of the means of access through the Makushin Valley, a pile- supported dock facility and a small breakwater will be required for docking the boats used to move personnel from Unalaska to the Makushin Valley access point. The dock will be located off the beach near the south margin of the valley in an MLF6/C11 3-6 area that is relatively rich from a biological standpoint. Some disturbance of bald eagles, seabirds, gulls and marine mammals will occur. However, docking activity will be intermittent and the breakwater may enhance habitat for some species; therefore, adverse impacts are not expected to be significant. Permits from the COE will be required for coastal structures and a tidelands lease from ADNR will be required for structures in the intertidal zone. Design and location of facilities should be carefully considered to minimize potential impacts to sensitive species. 3.4 ENVIRONMENTAL ASPECTS OF TRANSMISSION LINE ee on NE The transmission line would be elevated on poles throughout most of its length. However, the line would be buried through the lower half of the Makushin Valley; the buried portion would connect to a submarine cable that would extend from Broad Bay to Unalaska. The buried portion of the transmission line represents one of the more significant project impacts and would require special consideration relative to mitigation measures employed during construction. The cable would be laid ina trench which would be excavated through an area which is primarily wet with fine grained soils. Consequently, the potential would be high for muddy water to enter the Makushin River and/or its tributaries both during excavation of actual stream crossings and during excavation within wetlands adjacent to the various stream courses. An additional impact is associated with disturbance of strean bottom substrates at buried stream crossings. Crossings within spawning areas would probably require replacement of gravel substrate on the stream bottom to reestablish suitable spawning habitat. An indirect impact that is of concern to ADF&G is possible interference with natural patterns of shallow subsurface water flow and consequent alteration of flow within small streams that provide rearing habitat for juvenile salmon. A backfilled trench in combination with an adjacent roadway would likely have at least some effect on drainage patterns. Because the area is relatively flat, any such effects may be hard to predict. Drainage patterns and elevations should be taken into account when routing and constructing the transmission line. MLF6/C11 3-7 The buried transition from overland to subsea cable would involve some impact to the beach and intertidal zone at the vailey mouth. Portions of Broad Bay are important to razor clams, and juvenile salmon are likely to be present in the spring and early summer. A late fall-winter construction timing window is likely to be required by the resource agencies. All activities which cause disturbance to streams in the Makushin Valley will require permits from ADF&G. It is likely that an approved operating plan describing mitigation measures would be required prior to the start of work. In addition, cable burial within wetlands and associated road or workpad construc- tion would require permits from the COE. Since much of the lower Makushin Valley is wetland, a substantial permit effort will be required. 3.5 ENVIRONMENTAL ASPECTS OF BRINE DISPOSAL 3.5.1 Surface Disposal Disposal of waste geothermal fluid via a surface drainage leading to the Makushin River was initially considered as an option. The quality and volume of the brine in relation to that of the receiving waters indicated that problems could arise in meeting state and federal water quality standards for some brine components, especially arsenic and hydrogen sulfide. The ADF&G has also expressed concern about possible impacts to fish resources in the lower Makushin River as a result of toxic substances (arsenic, hydrogen sulfide and heavy metals) and temperature increases. Because of the low flow in the upper Makushin River in the winter (possibly less than 50 cfs), a brine discharge of 5 cfs would receive little dilution. A discharge of 70°C could increase the temperature of river water by 2°C at the mouth enough to significantly affect the incubation period of salmon eggs. The discharge of geothermal waste fluid at some point near the generating station would probably not be permitted without substantial treatment to lower temperature, as well as to remove arse- nic, hydrogen sulfide, and possibly other components prior to discharge. The environmental aspects of surface disposal have been examined in Sundberg et al. (1987). If it were permitted, extensive monitoring would be required. Because of the cost of on-site treatment and potential permitting difficulties, surface disposal was rejected as a feasible wastewater disposal option. MLF6/C11 3-8 3.5.2 Pipeline to Driftwood Bay Another option for brine disposal that was considered is conveyance of the brine to an offshore disposal area in Driftwood Bay via a 12-inch buried pipe- line that would parallel the roadway. Offshore discharge would probably stand a better chance of being permitted than onshore discharge because of the great dilution offered by seawater. Nevertheless, an NPDES permit would be required and the permit process could be long and complex. Because of the toxic elements in the wastewater, it is likely that some study of the marine biology of the discharge area would be required to provide a baseline against which the results of long-term monitoring could be compared to detect possible impacts. The distance offshore and design of a discharge diffuser would have to be negotiated with the agencies and would involve additional engineering costs. A buried pipeline would create additional terrain impacts and trigger the need for wetland permits in the lower Driftwood Valley. The pipeline option was rejected primarily because of these regulatory complications and because of the high construction costs. 3.5.3 Injection Because of the above environmental constraints, the option selected for disposal of brine is injection into an isolated geologic formation via injection wells near the generation facilities. Such a procedure avoids the environmental impact and permitting problems that would be associated with wastewater discharge. It also simplifies permitting for the total project by eliminating the need for an NPDES permit and possibly reducing total impacts to the point where an EIS will most likely not be needed. As mentioned in Section 3.1.1., EPA is not certain whether or not an Underground Injection Control Permit will be required. 3.6 POWERPLANT SITE IMPACTS The powerplant and associated facilities will be enclosed within either one - or two buildings. All facilities on the north side of Fox Canyon will occupy less than 3 acres, thus terrain disturbance will be minimal. Wildlife habitat value is low on the high plateau at the powerplant site and impact will not be significant. MLF6/C11 3-9 3.7 OPERATIONAL IMPACTS The generating facility will be remotely operated; therefore, human intru- sion will be minimal after construction. It is anticipated that a work crew of 2 persons will inspect the site 2-3 times per week. The crew will travel by boat to the mouth of the Makushin Valley and then by road to the powerplant site, observing the transmission line on the way. During power production, the powerplant will emit some noise, primarily from fans at the top of the building. Relative to other industrial facilities, the noise level is low and no significant disturbance of birds or mammals is antici- pated. The overland portion of the transmission line will be overhead except for the lower half of the Makushin Valley where it will be buried. Powerlines will Present some hazard to birds both from electrocution and as flight obstacles. Powerpole and conductor configuration will be designed to prevent large birds (eagles) from contacting two conductors at once and, thus, will minimize the possibility of electrocution. The design proposed in Section 5.0 avoids this problem. Furthermore, the largest concentrations of birds are at the mouth of the Makushin Valley where the lines will be buried. 3.8 CASCADING USES OF GEOTHERMAL EFFLUENT 3.8.1 Driftwood Bay The Driftwood River lowlands near the existing airstrip contain sufficient area and suitable soil foundation conditions to support either aquiculture or agricultural developments. Either prawn or shrimp operations and commercial scale greenhouse operations require large acreage for development of facilities. Driftwood Bay is very exposed to storm events and does not lend itself to water-based transportation developments. However, the Driftwood airstrip could be upgraded to provide a convenient source of transportation to Unalaska/Dutch Harbor for transfer of product to markets in the continental United States or other locations on the Pacific rim. At the present time, fresh seafoods can be shipped for $.98 per pound from Dutch Harbor to Tokyo versus $2 per pound for transportation via Anchorage to MLF6/C11 3-10 Tokyo. Completion of the airport runway extension at Unalaska next year, will increase aircraft payload limits from 15,000 pounds to 25,000 pounds which will further reduce the costs of transporting seafoods to market (Alaska Economic Report, 1986). Weather conditions on Unalaska Island are often poor and generally un- predictable. Therefore, problems can be anticipated in transferring seafood Product or agricultural products on a regular schedule from Driftwood Bay to Unalaska/Dutch Harbor. Shrimp are the primary species under consideration for on-shore mariculture operations on Unalaska (Paul Fuhs, Mayor of Unalaska, personal communication to Jim Hemming). According to Huner and Brown (1985) "There are presently no financially successful shrimp farms within the United States." However, culture techniques have been developed to the point where there does seem to be poten- tial for commercially viable operations in the United States through the use of semi-intensive pond or raceway cultures for production of shrimp. This type of technology is being actively studied at Texas A&M University and will require several more years to perfect. Additional information is being gathered through experimental operations in Hawaii, South Carolina, Texas and Japan. Even with proven technology, shellfish operations in Alaska would require simplification of legal and permitting procedures to enable those interested in mariculture to obtain clear guidelines on how they can operate and where they can place production facilities. Essentially, all successful commercial produc- tion of shrimp has thus far occurred in third-world countries where climate, labor, legal and biological factors are favorable. Research in the United States continues to focus on developing options for aquiculture in more tem- perate climates. Therefore, Alaska's options may increase in the next decade. The best options for agriculture would require the use of greenhouses because of the relatively severe Unalaska climate and techniques such as hydro- ponics which involve the cultivation of plants in water containing dissolved organic nutrients, rather than soil. Heat from thermal pipelines carrying geothermal fluids would provide a heat source needed for good plant growth. However, the pipeline for carrying effluent would add approximately seven MLF6/C11 3-11 million dollars to the plant cost and would require 280 kW to pump the effluent. Crops such as tomatoes and cucumbers have been grown commercially in greenhouse operations in southcentral Alaska using more conventional heat sources such as electricity or natural gas. However, it is doubtful that this type of operation could be commercially viable at Driftwood Bay, even ignoring the high costs of piping the brine from the powerplant site. 3.8.2 Broad Bay An assessment of available site data near the mouth of the Makushin River at Broad Bay revealed an area potential for onshore development of agriculture or mariculture facilities. This area, which is in the vicinity of Section 36, T72S, R118W, has several acres of dry, level land and low hills. However, similar to the Driftwood Bay site, piping effluent would be prohibitively expen- sive. A pipeline to Board Bay would be even more expensive to construct than a Driftwood Bay pipeline. Although the distance to Broad Bay is almost one mile shorter, the lower five miles would have to be constructed on the marshy, unstable soils of the lower Makushin Valley. In addition to the technical dif- ficulties, an effluent pipeline to Broad Bay could add to the permitting complexity by possibly triggering the need for an environmental impact state- ment. The engineering constraints on facilities development coupled with wetlands permitting problems would essentially exclude any options for aquiculture or agriculture development in that area. However, if electrical transmission lines were constructed through the area, they would benefit offshore mariculture operations such as pen-rearing of salmon. 3.8.3 Other Considerations The options considered for disposal of waste thermal fluids include surface release at the plant site, a pipeline to the coast connected to a subsea dispos-— al site, or re-injection at the well site. Thus far only the latter option appears viable because plant effluents would contain toxic components (see Section 3.3). Therefore, surface disposal would not be acceptable to the regu- latory agencies. Transportation of thermal fluids via insulated pipelines from the plant site to either Broad Bay or Driftwood Bay for oceanic disposal was determined to be too costly for further consideration. MLF6/C11 3-12 The remote location of a power plant site on the slopes of Makushin Volcano and the limited spece available at that site for facilities development would preclude either agriculture or aquiculture development. Although it is not feasible to utilize the effluent heat, it is likely that it would be feasible to utilize off-peak electric power. The geothermal plant is designed to operate at full capacity whenever it is available. This mode of operation is desirable to simplify unattended operation of the plant. The variable cost of additional generation is limited to the royalty paid for the steam which is 1-2 cents per KWH or less. Heating loads could be found which could use power dispatched only at off-peak periods. These loads might include electric space heating, domestic water heaters, or the high school swimming pool. 3.9 AIR QUALITY NOTE: A more complete discussion of air quality impacts appears in Appendix C of this report. After the useful energy is extracted from the geothermal fluids, the waste stream will pass through a condenser. Remaining steam and some gases will be condensed into the brine and injected. However, a portion of the gases in the waste stream is non-condensable. The primary non-condensable gas is hydrogen sulfide (HS). As part of this study the USEPA-recommended Industrial Source Complex (ISC) model was used to estimate emissions from the proposed project. Based on data obtained in the Phase III Exploration Study (Republic, 1985), H2S concentrations in the waste stream are expected to average 1.73 parts per million (ppm). The model was run under a worst case assumption that all non-condensable gases present in the stream will be released to the atmosphere and that the full 9.5 MW capacity is in place (7.5 MW flash steam + 2.0 MW binary). The model predicts that down-wind receptors 100 meters from the source would experience maximum 1 hour H2S concentrations of 0.25 ppm from a 9.5 MW plant of 0.17 ppm from a 5.0 or 7.0 MW plant. This compares with a State of Alaska reduced sulfur compound ambient standard of 0.02 ppm and a threshold limit value MLF6/C11 3-13 for H7S of 10.0 ppm recommended by the National Institute for Occupational Safety and Health (NIOSH). Because the Alaska ambient standards are exceeded, the Alaska Department of Environmental Conservation (ADEC) could not issue a permit without granting a variance or requiring emissions controls. There is, however, a sound justifica- tion for issuing a variance in that: l. The Alaska standard is odor-based which may not be especially important in a remote area. 2. Being a volcanic area, natural emissions may already exceed the odor threshold. 3. The emissions are 40 times lower than the health-based NIOSH standards. The emissions from the plant, even assuming 100 percent venting throughout the entire year would be less than 13 tons of H2S. This amount is well below the 250 ton per year emission which triggers the need for a Prevention of Significant Deterioration (PSD) review. Thus there should be no federal air quality permitting requirement. MLF6/C11 3-14 4.0 ECONOMIC ANALYSIS This section describes the analysis conducted to determine the economic feasibility of the proposed project. The overall approach and assumptions are described in Section 4.1. Section 4.2 describes the ELFIN generation dispatch model. Section 4.3 describes the economic model. The cases modeled and the results are reported in Section 4.4. Economic conclusions are drawn in Section 4.5. 4.1 APPROACH AND ASSUMPTIONS The purpose of the economic analysis reported here is to compare the life cycle costs of electric generation using diesel generation facilities with the costs using a generating system which includes a _ geothermal component. Alternative geothermal configurations were compared in order to determine the optimal size and timing of geothermal capacity additions. The best geothermal System was then compared with the Base Case All-Diesel scenario to determine whether geothermal resource development would be economically feasible. The working definition of "economic feasibility" is that the discounted life-cycle costs for systems including geothermal development are less than the costs for the all-diesel scenario with all other factors held constant. It is important to stress the distinction between financial and economic analyses. Economic analysis, as represented by the analysis reported herein, is intended to compare alternative systems without regard to the timing and mech- anisms for repayment of costs. By contrast, a financial analysis takes into account the repayment timing and mechanisms. Financial analyses include such considerations as interest rate and the method of repayment of capital costs (grants, revenue bonds, etc.). Logically, it is first necessary to establish the economic feasibility of a project before investigating the financial feasibility. In general no project which is economically infeasible can be financially feasible. Once economic feasibility has been demonstrated it remains to investigate the financial feasibility. This latter step has not yet been undertaken. The overall approach used in the economic analysis is diagrammed in Figure 4-1. The approach is summarized here and discussed in more detail in Sections 4.2 and 4.3. MLF6/C30 4-1 GEOTHERMAL RESOURCE ANALYSIS & DRILLING COSTS FROM MESQUITE GEOTHERMAL COST AND PERFORMANCE DATA FROM SAI LOAD FORCASTS FROM R.W. BECK DIESEL PERFORMANCE DATA FROM CITY OF UNALASKA ELFIN GENERATION ECONOMIC MODEL: CAPITAL, FIXED AND MODEL: DISPATCH BY UNIT BY YEAR leva FIGURE 4-1 OVERALL ECONOMIC ANALYSIS APPROACH NET PRESENT WORTH BY SCENARIO DAMES & MOORE The economic analysis relies on two separate models, the ELFIN Generation model and a discounted cash flow type economic model. The ELFIN model, copyrighted by the Environmental Defense Fund (EDF) uses inputs regarding available generation capacity and performance to determine which units would be most economically dispatched at any time. Performance data for diesel units were obtained from the City of Unalaska (Burton, 11/86) and N C Engine Power (Shultz, 11/86). The data were confirmed by John Flory, City Engineer, on 3/3/87. Data on geothermal performance was developed by SAI Engineers and the Mesquite Group. Load data forecasts were developed by R.W. Beck (1987) under a separate contract to the Power Authority. The annual summary results of the ELFIN model consists of load, capacity factor and variable cost by generating unit. These results are input to a spreadsheet economic model which adds in capital and fixed operating costs to determine the total annual generation costs. The economic model also discounts and sums the annual cost to find the net present value of each scenario over the life cycle of the geothermal plant. These net present values constitute a figure of merit by which alternative geothermal configurations can be compared with the All-Diesel (no project) alternative. The lower the net present value (for meeting an assumed load fore- cast scenario) the more desirable the alternative. This analysis was used during the feasibility study to define the relevant alternatives for con- sideration and to determine the preferred alternative(s). The economic analysis depends on numerous technical and economic assump- tions. It will be seen that the economic feasibility of the proposed geothermal development rests on two critical assumptions about unknown future conditions; i.ee., oil prices and utility loads. Sensitivity analyses were conducted for those two assumptions as well as all other significant assumptions. The eco- nomic assumptions are summarized in Table 4-1. Electrical generation assump- tions are shown in Table 4-2. Both sets of assumptions are discussed in more detail below. MLF6/C30 4-2 TABLE 4-1 ECONOMIC ASSUMPTIONS PARAMETER BASE CASE ASSUMPTIONS SENSITIVITY ASSUMPTIONS o Inflation Rate Zero percent: Analyses conducted None in real terms, Assumes that inflation is a wash among cases. All costs in 1986 $. o Present Value Discount Rate 3.5 percent real 4.5 percent real o Diesel Escalation Average of APA (Emmerman 11/86) APA (Emmerman 11/86) Upper Rate Lower bound and upper bound bound and lower bound price price trends applied to 1986 trends, See Figure 4-1. diesel prices, See Figure 4-1. o Unalaska City R.W. Beck (1987) base case fore- R.W. Beck (1987) high case Utility Load cast. forecast. o Interest Rate(s) Not applicable to economic analy- Not applicable sis. o Period of Analysis 25 years after first geothermal Through 2025 operations (through 2016) o Geothermal Royalty Based on conditional Land and None and Resource Agreement between Power Authority and Aleut Corp. 6/86. Assumes no further cost for multiple wells in same target MLF6/CT4 TABLE 4-2 ELECTRICAL GENERATION ASSUMPTIONS PARAMETER BASE CASE ASSUMPTIONS SENSITIVITY ASSUMPTIONS Diesel: Total capacity 4.1 MW installed as per data provided by City of Unalaska Utilities (R. Burton, personal communication, 11/86) Existing Capacity None Assume additional 855 KW units as needed to follow base load forecast case. Assume additional units as needed to follow high load forecast. Additional Capacity Forced Outage Rate 400 hours/unit/year or 4-6 None (Diesel) percent Major Maintenance Every 700,000 gallons used None (Planned Outage Rate) - (4.7 percent outage) Service Life 2.1 million gallons or 30,000 MWH None for 855 KW units. Efficiency Existing units 12-14 KWH/gal None (As per Burton 11/86) Geothermal: Capacity and Timing 5.0 MW Flash steam Additions to 7.0 MW (Available 1991) in 1995 and 9.5 MW 2001 Forced Outage Rate 8 percent None Maintenance 17 percent None (Planned Outage Rate) t Service Life 25 years 34 years Diesel and Geothermal: System Efficiency 95.4 percent None MLF6/CTS 4.1.1 Economic Assumptions INFLATION: The entire economic analysis utilizes a zero inflation assump-— tion. With the exception of diesel prices (which are discussed below) all prices are assumed to remain at their 1986 levels. This assumption does not imply that there will be zero inflation, but is intended to simplify the analy- sis. The relative merit of the alternatives for supplying Unalaska's electrical needs can be compared without invoking inflation forecasts. If assumptions were made about inflation trends, these same factors would be used to deflate each year's nominal dollar costs back to 1986 dollars. To avoid this unnecessary complication it is assumed that inflation is zero. This assumption, while appropriate to the economic analysis presented here, would not be appropriate for a financial analysis. PRESENT VALUE DISCOUNT RATE: As directed by the Power Authority, this anal- ysis assumes a 3.5 percent present value discount rate to reflect the real (inflation-free) cost of funds. Alternatively, the discount rate can be viewed as the State of Alaska's time preference for funds. As a sensitivity case a 4.5 percent real rate is used. This sensitivity case places greater relative empha- sis on near-term costs. Thus geothermal alternatives, which substitute up-front capital costs for ongoing diesel fuel costs, are less desirable under the higher discount rate. DIESEL PRICES: In late 1986 the City of Unalaska was paying $0.70 per gallon for diesel fuel used in its generating facilities (Burton, 11/86). For the economic analysis this price was projected to escalate in real (inflation free) terms to $0.90 per gallon by 1996, then to remain constant under the Power Authority's Low Price trend. Under the High Price trend the cost rises to $0.90 by 1987 then escalates 3.5 percent per year until leveling off at $1.73 in 2006. These trends are intended to bracket the upper and lower range of oil prices for the next 20 years (Emerman, Memo, 11/26/86 and Denig-Chakroff, letter to M. Feldman, 11/26/86). A Medium Price trend, which is the simple average of the high and low price in each year, was used as a Base Case. Sensitivity analyses were performed on the High and the Low Price trends. These trends are illustrated in Figure 4-2. MLF6/C30 4-3 DIESEL PRICE (1986 $ PER GAL) UNALASKA DIESEL PRICE RANGE (Based on Alaska Power Authority Forecast) . 1.7 — ao ats — | { i \ | \ | 1.6 1.5 1.4 1.3 1.2 1.1 0.9 0.8 DoT a a ae gg 1986 1990 1995 2000 2005 YEAR Oo MEDIUM + UPPER BOUND © LOWER BOUND FIGURE 4-2 LOAD FORECASTS: Load forecasts (annual peak and energy) through 2006 were projected by R. W. Beck and Associates (1987) under a separate contract with the Power Authority. The Base Case and High Case load forecasts were used in this analysis. In addition to the published study, Beck provided Dames & Moore with hourly loads for typical weeks. These typical hourly data are an important input to the ELFIN generation model. They are described in Section 4.2. INTEREST RATE: There is is no need to consider the interest rate in an eco- nomic feasibility analysis. The time value of resources consumed is captured by the net present value analysis. Capital and operating costs are simply assumed to be available in each year in which they are needed. In the financial feasibility analysis subsequent to this analysis it will be important to con- sider the sources of funds and consequent interest rates, but these are not Necessary in comparing among generation alternatives from an economic stand- point. PERIOD OF ANALYSIS: In order to reflect the relatively long life of geo- thermal development investments the life cycle costs of the various generation scenarios were compared over a period from 1988 through 2016, which represents a 25 year life of the initial geothermal installation (assumed to be operative in 1991). For sensitivity comparison, results for 1988 through 2025 were also com- pared to reflect the full utilization of additional geothermal capacity added in 2001 for the 9.5 MW (megawatt) case. 4.1.2 Generation Data and Assumptions--Diesel EXISTING DIESEL: Performance data on the six existing diesel units were ob- tained from the City of Unalaska (R. Burton, personal communication to M. Feldman, 11/86 and J. Flory, City Engineer, 3/87). The heat rate for the 1,450, 855, and 620 KW units is 14 KWH per gallon. The older 600 KW unit and the two 300 KW units operate at a heat rate of 12 KWH per gallon. Forced outage rates are assumed to be 400 hours per year or 4.6 percent. Major maintenance occurs at intervals of about 15,000 hours, and requires about 1,440 hours per unit to complete since units must be sent to Anchorage or Seattle. This results in an estimated maintenance rate of 4.7 percent (R. Schultz, N C Engine Power, personal communication to M. Feldman 11/86). MLF6/C30 4-4 ADDITIONAL CAPACITY: As load growth dictates the need for New capacity, 855 KW diesel units are added. Diesel capacity is added in order to maintain a loss of load probability (LOLP) of 3 days per year or less. The characteristics and heat rates of these units are assumed to be the same as the existing 855 KW unit. The installed cost for each of these units is assumed to be $145,000. Additional costs for switching gear ($50,000) and cooling capacity and fuel lines ($30,000) raise the total installed cost per unit to $225,000 (R. Burton, 11/86). This auxiliary equipment is assumed to last through three generating unit replacements (about 21 years). OPERATION & MAINTENANCE AND REPLACEMENT: The capital cost of an operating 855 KW diesel unit is $225,000. This includes a cost of $80,000 for cooling, fuel storage and switch gear. The life cycle cost (exclusive of fuel and routine maintenance) is $262,000. This includes depreciation on switching, cooling, fuel storage, and overhauls. The salvage value fcr the diesel engine itself is presumed to equal the disposal cost. The switching, cooling and fuel gear is assumed to last through three engines. The $262,000 life cycle cost, divided by the 30,000 MWH that each engine is expected to generate, results in a cost of $0.0087 per KWH. Routine service and maintenance adds an additional $0.008 per KWH (Burton, 11/86) resulting in a total variable cost of $0.0167 per KWH plus fuel. The fixed 0 & M cost is estimated to be $280,000 per year. According to R. Burton, this cost would remain constant regardless of the number of diesel units on line. 4.1.3 Generation Data and Assumptions - Geothermal GEOTHERMAL CAPACITY: The proposed geothermal concept is described in detail in Section 5.0. Briefly, the concept includes an initial installation of 5.0 MW of flash steam with an additional 2.0 MW of binary capacity. If diesel costs and load growth warrant, an additional 2.5 MW unit may be added in 2001, yielding a net capacity of 9.5 MW. OPERATION & MAINTENANCE: (See Section 5.4 for more detail.) Operation of either a 5, 7, or 9.5 MW geothermal plant including site access and transmission facilities associated with the geothermal development will cost $97,000 per year. Maintenance of these facilities will cost $181,000, $225,000, and MLF6/C30 4-5 $305,000 per year for 5, 7, and 9.5 MW plants, respectively. Insurance (of the generating facilities only) will cost $161,000, $208,000, and $280,000 for the 5 MW, 7 MW and 95 MW plants, respectively. These costs are fixed in that they do not change as a function of the level of generation. Variable 0&M is negligible. AVAILABILITY: The geothermal plant is expected to be availible 75 percent of the time in any year. This includes a forced outage rate of 8 percent or about 30 days per year. Planned outages for scheduled maintenance (17 percent of the time or 62 days per year) can be scheduled during the off-peak seasons. GEOTHERMAL ROYALTY: A royalty agreement between the Power Authority and the Aleut Corporation was executed on 17 June, 1986. This agreement provides the Power Authority with rights of access, lands for development and steam for use in geothermal power production. The royalty rate is a function of the amount of electricity sold from the project and the busbar cost of electric power produc-— tion in Unalaska exclusive of the geothermal development. The formula for the "Power Share" is: Power Share = KWH sold x royalty rate x City Busbar Cost The royalty rates range from 0.0325 to 0.063 per KWH depending on the energy sold from the project in any quarter. The busbar costs used in this analysis are based on an electric rate study conducted by R.W. Beck (1985). This study reports that the busbar cost for fiscal year 1986-87 will be $0.13 per KWH exclusive of fuel costs. The busbar costs (exclusive of fuel) are not expected to change over the period of analysis (R. Burton, 1986). The royalty was calcu- lated using the projected diesel fuel costs in each year plus the $0.13 non-fuel busbar cost. It should be noted that the terms of the agreement permit only a single well to be used. It is assumed that these terms could be modified to reflect the use of more than one production well and one or more injection wells at the same rate per KWH generated. An Energy Share and By-product Share royalty agreements were also included in the same royalty agreement. These rates, which would apply to non-electric heat uses were not included in the eco- nomic feasibility analysis. RIGHT OF WAY: In conjunction with the Toyalty payment and in lieu of a higher royalty rate, the Agreement with the Aleut Corporation provides for an MLF6/C30 4-6 annual easement fee of $5,000 per year. In addition, an agreement with the Ounalashka Corporation provides for payment of market value for rights-of-way across its land. Based on an estimated need for 25 acres in easements on Ounalashka Corporation lands, it is assumed for the purpose of the economic analysis that these rights-of-way will cost $10,000. GEOTHERMAL SERVICE LIFE: The geothermal wells, power plant equipment, and transmission equipment is all expected to have a useful service life of 25 years. Salvage value at the end of the service life is assumed to be exactly offset by the cost of removal. 4.2 THE ELFIN GENERATION MODEL The ELFIN Model description which follows is based on EDF, 1986. 4.2.1 General Overview The ELFIN generation model is a production simulation model which determines the least cost manner of dispatching the available generating units within a electrical generating system. It was developed by the Environmental Defense Fund (EDF), which holds the copyright. Version 1.30 was used by Dames & Moore to perform the economic analysis under a lease agreement with EDF. ELFIN was run on a VAX minicomputer. The model simulates the decisions which would be made by a utility by meeting demand within each specified "season" by bringing on line the available generating units in increasing order of variable cost. Fixed costs and capital investment decisions are not made by ELFIN. These decisions are exogenous to the model and are specified as input (insofar as the capacity is specified). The model allocates scheduled maintenance for each unit on a yearly basis in such a way as to maximize system reliability. Forced outages are allocated on a random basis. MLF6/C30 4-7 4.2.2 Load Data The load forecasts (peak and energy) anticipated for the City Utility are an important input to the ELFIN model. These forecasts were obtained from the study conducted by R.W. Beck under separate contract to the Power Authority. Appendix D reproduces the ELFIN input file. Peak and energy inputs used are shown in the variables ANPEAK and SALES. For easy reference, the peak and energy forecasts are also shown in Table 4-3. In addition to the annual peak and energy forecasts, ELFIN requires specifi- cation of the weekly load durations for typical weeks within each specified "season", These seasons do not correspond to the conventional four seasons but are specified to reflect distinct differences in electrical load within the year. Because the load in Unalaska is dominated by industrial users, these Seasons correspond to the activities of fish processors to a large extent. At the Power Authority's request, R.W. Beck provided Dames & Moore with their esti- mates of the seasonal variations and the hourly loads for one typical week within each season. These hourly loads provide ELFIN with information on the load necessary to allow it to economically dispatch generation units and to calculate the system reliability. In effect, the hourly data tell ELFIN the shape of the load duration curve. The actual raw data provided by Beck (simply reformatted for ELFIN) appear in Appendix D in the ELFIN input file as a set of variables called "Wkxxxxx". For better presentation, Dames & Moore constructed load duration curves using the same data weighted by season length and compiled annually in rank order of frequency. For the Base Case forecast, these curves are shown as Figures 4-3 through 4-5 for years 1990, 1995, and 2000, respec— tively. Figures 4-6 through 4-8 show the same years under the High Case fore- cast. Note that these load shape data are specified only for selected years. Load shape data for the years 1987, 1988, and 1989 were also input to ELFIN. These are the years in which there was a marked change in the load. ELFIN scales these loads up or down based on the specified peaks and energy sales for each year. MLF6/C30 4-8 TABLE 4-3 LOAD FORECAST FOR CITY OF UNALASKA BASE CASE HIGH CASE YEAR PEAK ENERGY PEAK ENERGY KW MWH K W MWH 1987 2,981 14,119 3,021 14,262 1988 5,157 21,311 6,283 21,617 1989 6,316 24,612 8,528 29,854 1990 7,488 29,834 9,740 35,286 1991 7,622 30,324 9,922 40,767 1992 7,708 30,615 10,034 41,199 1993 7,793 30,909 10,148 41,643 1994 7,880 31,208 11,315 42,103 1995 9,017 36,261 11,435 47,327 1996 9,105 35,568 11,558 47,820 1997 9,194 36,881 11,684 48,329 1998 9,284 37,198 11,814 48,857 1999 9,365 37,468 11,934 a9 ,332 2000 10,496 42,486 13,106 54,561 2001 10,578 42,756 13,231 55,056 2002 10,660 43,026 13,358 55,564 2003 10,743 43,311 13,489 56,087 2004 10,827 43,600 13,624 56,648 2005 10,910 43,889 13,761 $7,213 2006 10,996 44,192 13,902 57,808 Source: R. W. Beck, 1987 Tables -- V-3, v-4, V-11, v-12 MEGAWATTS 8.0 7.0 6.0 5.0 4.0 3.0 2.0 1.0 0.0 UNALASKA LOAD DURATION CURVE 10% RW BECK BASE CASE FORECAST YEAR 1990 20% 30% j$§.40% ### 50% 60% 70% PERCENT OF YEAR (8,760 HOURS) 90% 100% Dames & Moore FIGURE 4-3 MEGAWATTS 9.0 8.0 7.0 6.0 5.0 4.0 3.0 2.0 1.0 0.0 RW BECK BASE CASE FORECAST UNALASKA LOAD DURATION CURVE YEAR 1995 10% 20% 30% 40% 50% 60% 70% 80% PERCENT OF YEAR (8,760 HOURS) 100% Demes & Moore FIGURE 4-4 MEGAWATTS 11.0 10.0 9.0 8.0 7.0 6.0 5.0 4.0 3.0 2.0 1.0 0.0 RW BECK BASE CASE FORECAST UNALASKA LOAD DURATION CURVE YEAR 2000 10% 20% 30% 40% 50% 60% 70% 80% PERCENT OF YEAR (8,760 HOURS) 90% 100% Demes & Moore FIGURE 4-5 MEGAWATTS 10.0 9.0 8.0 7.0 6.0 5.0 4.0 3.0 2.0 1.0 0.0 RW BECK HIGH CASE FORECAST UNALASKA LOAD DURATION CURVE YEAR 1990 10% 20% 30% 40% 50% 60% 70% 80% PERCENT OF YEAR (8,760 HOURS) 90% 100% Dames & Moore FIGURE 4-6 MEGAWATTS RW BECK HIGH CASE FORECAST UNALASKA LOAD DURATION CURVE YEAR 1995 10% 20% 30% 40% 50% 60% 70% 80% PERCENT OF YEAR (8,760 HOURS) 90% 100% Laer are dh Whom FIGURE 4-7 MEGAWATTS RW BECK HIGH CASE FORECAST UNALASKA LOAD DURATION CURVE YEAR 2000 10% 20% 30% 40% 50% + 60% 70% 80% PERCENT OF YEAR (8,760 HOURS) 90% 100% Demerrare & boos FIGURE 4-8 4.2.3 Dispatch Order As mentioned above, ELFIN dispatches generation capacity available in order of increasing variable cost. Thus geothermal capacity, whose only variable cost is the power share royalty for geothermal steam, is dispatched whenever available in preference to diesel. Based on fuel cost alone, even the most efficient diesel unit costs upward of 6 cents per KWH versus 1 to 2 cents for geothermal. In addition, diesel has a variable 0 & M cost of about $1.7 per KWH versus zero for geothermal. When diesel capacity is used, it is dispatched in order of fuel efficiency, as variable 0 & M is essentially the same for all units. The availability of any unit is determined by the specified planned and forced outage rate. The model assigns the planned outages to the season(s) in which they have least impact on reliability, i.e., the slower season(s). The forced outages occur randomly according to a method called the "Baleriaux-Booth" algorithm. As programmed, the model assumes that the geothermal unit can be run at reduced loads as well as at full capacity. 4.2.4 ELFIN Output ELFIN can provide very detailed output showing operation and cost by indi- vidual generating unit by week. For the purpose of economic feasibility analy- sis for which it is here applied, annual totals by generating type (existing diesel, additional diesel, geothermal) are sufficient. A sample annual summary output (for the 5.0 MW geothermal capacity under the high demand case) is shown as Table 4-4. The only values which are actually used as input to the economic model are the total annual load for diesel and geothermal and the fuel and variable O & M cost per KWH for diesel generation. Other output which is of interest but does not directly become input to the economic model includes the capacity factors and the LOLP (loss of load probability). The capacity factor indicates the percentage of time that the unit is used. This factor was used to indicate whether the geothermal capacity is being sufficiently utilized. The LOLP is an indication of reliability. If this factor exceeded 1.5 days, it was taken as an indication that installed capacity was insufficient, and there- fore additional diesel units were added. In most years LOLP was held below 1 day. MLF6/C30 4-9 TABLE 4-4 RUN NUMER 1 -- 1991 -- N'A UNALASKA 5 MW GEOTHERMAL NEW HIGH CASE DEMAND 3/)20/t07 PAGE NOD. 1 ANNUAL CENERATION 1991 PEK WK NO.®# OUTAGE ~~ ENERGY -- FUL CAPACITY 87MIIU BTUs —- --MILLS/KWH--- RANK® TIME TOTAL CAVACITY OF (PERCENT) (GWH) (THE, EACH (me Kw TUEL O+M TOTAL MARGINAL COST (MW) UNITS FORCED MAINT. LOAD PUMPING TOTAL Dit) (VC) MILLS /KWH ANN. AV. (PCT) (MB) mit} 1450 KW DIESEL UNI 14! 1 4.6 4.7 5577. oO. 5577 AN 6 9907, 10 16.3 74.3 2 14.76 415 Inds!) GU KW DIESEL UNIT 1 4.6 4.7 2590. . 2590 4G (6 9907. 30 16.3 74.3 3.7.17 193 alse) 600 KW DIESEL UNIT 1 46 4.7 1519. . 1519. ws (6 9907. tO 16.3 74.3 4 628 113 4 400 KW DIESEL UNIT 1 46 1.9 oO. ° Oo U6 11550, 47.7 16.3 84.0 6 0.00 0 Wilt) JOG KW DIESEL’ UNIT 1 4.6 £.9 ao % 6 11550. 47.7 16.9 84.0 7 0.00 oO Itt & 300 KW DIESEL UNIT HOO, 1 4.6 1.9 1.6 11550 47.7 16.3 84.0 8 0.00 0 Wt A ADDITIONAL DIESEL U 7é‘7b. 9 4.6 47 6 9907. 8.0 16.3 74.3 5 29.53 322 G10) FIKST CEOTHERMAL YOOd, 4 8.0 7.0 u. vO J. "0 090 8.0 1 42.26 230 TUTAL OR AVERAGE Ato, 6 2 2751 0. 42751. iinet a 29.7 100.00 1271 UNEKGY NOI SERVED 0.00 GWH COST (W- ENN UED IN AVERAGE MAKGINAL COST 112.4 0. 00 0 (ANNUAL AVI-MAGE MAKGINAL COST 46.3 > ANNUAL VALUES-- VEAK 9900!, MW RESERVE MAKGIN 69.5 PCT LOAD 42751. OWH LOLP 0.00000) ¢ 0. 000 DAYS) TOTAL COST (MILLION $) 1271 ( # INDICATES VALUES FRON I A‘i] TYPICAL WEEK) 4.3 THE ECONOMIC MODEL The economic model is a discounted cash flow spreadsheet model which is used to generate the present value life cycle cost of each generation scenario. By comparing the life cycle cost among the scenerios, alternative geothermal con- figurations could be compared to all diesel scenarios. This comparison per- mitted us to determine the conditions under which geothermal deve lopment would be feasible. By iterating between the economic model and the generation model it was possible to determine the optimal size and deployment timing of geo- thermal capacity. The economic model was implemented on a Lotus 1-2-3 version 2.01 software package (copyright 1985 by the Lotus Development Company) run on an IBM-com- patible personal computer. A sample spreadsheet showing the results using 7.0 MW of geothermal capacity under the base case demand medium fuel price sce- nario is reproduced as Table 4-5. The spreadsheet is divided into four sections. At the top are the assump- tions which describe the scenario--the geothermal capacity, the diesel price trend, and the discount rate. Changing the latter two parameters causes the spreadsheet to recalculate for the values entered. The discounted present value over the time period indicated is the figure of merit which is used to compare the alternative scenarios. This figure is the sum of the discounted annual costs for the entire system (both diesel and geothermal) for the indicated time period, expressed in constant 1986 dollars. The lower left side of the spreadsheet shows the costs for the geothermal portion of the system and the annual loads. Years 1988 through 1991 are all zeros in this part because 1991 is the earliest time that geothermal capacity could come on line (see Figure 5-1). Variable 0&M is zero in all years reflecting the fact that geothermal 0 & M cost is completely fixed depending only on the installed capacity. The fuel cost reflects the royalty rate to be paid to the Aleut Corporation as described in Section 4.1.3 above. The geo- thermal royalty is calculated in the economic model rather than using the result of the ELFIN run, as this approach allows the economic model to calculate the Present value using either the high, medium, or low diesel price trend without MLF6/C30 4-10 TABLE 4-5 FONOMIC ANALYSTS IINDHASED 7 MW GENTHFRMAI --RASE CASE OFMAND MENTUM =—-DIFSEL PRICE TREND DISC COSTS MILLION 19R6$ $76.2 THRU 2016 = $R_-7 THRU 2025THRU 2025 LEVELITED COST ($/KWH) $0,106 THRU 2016 $0,092 THRU 2025 DISC RATE = 3.58 feneennnnnnnecenee GEQTHERM ---2-2---------2n--nn--2nnnnnnnene= )(eneeecweemennnneecenennees DIESEL --sere--ene-wennennnen n= Joneeeenennccccecce SYSTEN ----------------- ANNUAL O&M ANNUAL = TOTAL ay ANN ANNIIAL O&M ANNUAL = TOTAL = ANNUAL = AV ANN TOTAL ANN PWOANN ANNUAL = DISC ANN DISC ANN YEAR CAPITAL -eeneceennnnnnennnl FUEL ANNUAL MAD. POST/KWH CAPITAL ------------------' FUEL ANNIIAL = LOAD, COST/MWH SYSTFM = SYSTEM «SYSTEM = SYSTEM CST Annen = FIXED RTABLE COST cast ADNED = -FIXEN = VARTARLE COST ens cost cast LOAD Loan DER KWH (rene ne ne enn n ne en neem enn enn enter enna n nnn n nnn nn enn nnn ene Dee nen ern en nnn nn nen ne nnn ne nnn en nen en enn e nen e en ne nen e enn ee nee: Decreen en nn enna ene nec en en en enn n eee en en ene > (x$1000) ($1000) (x$1000) (x$1000) ($1000) — (MH) ($/KWH) (x$1000) (x $1000) (x$1000) (x$1090) ($1000) — (MWH) —($/MWH) (x$1000) (1985 $M) (MWH) — (MW) — ($/KiWH) 19AR 0 5 9 0 5 0 0 000 675 ag 35R 1,355 2,667 27,346 0.119 7,612 2,692 22,346 = 20,935 0.120 1929-6, 638 5 a 0 6,643 0 0.000 225 2R0 any 1,609 = 2,528 = 25,805 0. 0989169 R256 75. ROS 23,233 0.955 1990 = 36,056 § 0 9 36,061 0 0.000 225, 2R0 507 2,008 3,016 31,278 = 0.096 39,077 33,971 91,278 27, TAR 1249 1991 0 565 9 230 795 28,990 =—-0.027 9 an ine 419 AN2 6,361 0 126 1,597 1,341 95.351 29,676 = 0 085 1992 0 565 0 238 199° (29,143) -0.027 0 2a 4g 201 529 2,962 9.179 1,928 1,076 = 32,105 26,024 = 0 8 1993 a 565 0 237 AQ2 = 29,210 0.027 0 an 52 216 San 3,103 0 176 1,250 1,056 32,419 25,370 0 042 1998 9 555 9 2a 805 =.29,480 = 0.027 a 280 55 230 567 3,287 0.175 1,373 1,038 32,727 28,735 0 04? 1995 0 555 0 263 R2R 91,9280 076 0 2an 198 44k A127 -6,097 09H 165012119025 -27, 7500 ee 1996 0 555 0 299 R64 32,086 = 0. 027 9 RO 19R 476 Aba 6,281 0.198 1,727 4,217 3K, 347 27,0230 045 1997 0 565 0 30? 867 32,208 += 0.027 0 ann 12 500 R92 6,468 = 13K 1,759 4,197 38,676 26,317 045 199R 0 585 0 306 AT) 32,341 0.927 0 2ay 7 528 923 6,647 9138 1,798 1,179 39,008 25,630 0.066 1999 0 565 0 309 AML 32,485 0.097 0 290 199 582 953 6,847 0.:190=—s1, R271: 99,202 24,9290 087 2000 0 565 0 339 A97 34.575 0.926 9 2an 174 APT 1:78D 9 97R 17K 2,177 998 4554 27,295 49 en) c 565 0 337 902 34,707 0 028 0 2a 1a? a5? 1,316 10,190 013M 2,296 1,311 48827 26,578 4g 2002 0 565 9 340 905-34, 796 0 026 9 290 1PP AAT 1,355 10,323 9131 2,260 1,291 45,119 25,772 0 050 2n03 0 585 0 265 910 30,9390 08 0 2a 193 921 -1,303 10,479 0.193 2,902 1,270 5 AIR 25,051 008 2008 9 55 9 349 91a 35,038 0.026 9 Fo "99 960 1,039 10,687) 0.135 2,959 1,253 45,721 24,951 9051 2005 0 565 0 353 918 35,1590 076 Cc ae ane a9 1,483 10,876 = 01968 2a 1,235 46.025 23,669 = 0.05? 2006 0 S85 9 358 923 35,269 9.976 9 aan 299 1,081 1,530 11,073 9.198 2,453 120K 88382 73,013 0.953 2007 9 585 9 358 072 35,269 0 026 t pag 2090«1,081) 1590 17,073 0138 -2,852 1,176 4 2 -23,019 0.059 2008 0 565 9 35R 923 35,269 0.026 9 2R0 209 1,041 1,530 11,079 9 138 2,453 1,136 46,342 23,019 0053 2009 0 555 0 358 922 35,289 0.026 0 2an 209° -1,081 1,530 19,072 01882452 1,097 5 942 23,0130 053 2010 0 565 0 358 923 35,269 0.26 0 Rn ang 1,041 1,530) 19,073 919K 2,531,059 46, 982 -23,019 0.053 ot 0 565 0 358 9237 35,289 0 076 0 8G 209 1,041 1,920 19,073 0 19R 2,459 1,023 46,342 23,0130 053 2012 9 565 0 358 923 95,269 0.026 0 2R0 269 1,041 1,530 11,073 9.138 2,453 QRR 46,342) 23,0120 89. 2013 0 555 0 358 922 (35,269 = 0.026 9 ane 208 1,081 1,530 19,073) 0 138 7,453 958 46,342 23,013 0.82 2018 0 565 0 358 923° 35,269 = (0 026 0 2R0 209 1,041 1,530 19,073) 0.138 2,453 921 46,342 23,013 0.053 2015 0 5A5 0 358 923 35,269 0 026 0 Rn 209 1,081 1,530 19,073) 0.198 2,453, AAG 46,342 23,0130 053 2016 0 565 9 358 923 35,269 = 0.026 0 an 2091, 041 1,530) 11,073) -0.19R 2,853 A959 46,382 23,013 0.059 2017 0 555 0 258 923 38,289 0 026 4 a0 2n9 1 Mt 1,530 10,072 19K 453 R29 46,342 23,013 0.053 201k 0 565 0 35h 923° «35,269 (0.026 9 ann 2090 1,04t 1,530 19,073, 9138 2,453 800 46,942 23,013 0.053 2nig 0 565 0 358 977° 35,269 = 0. 076 0 RO 209 181 1,890 19,073 1 12R 7489 779° 46142-23013 0.053 2029 0 565 0 758 922 35,289 0.026 9 2R0 299 1,081 1,539 19,073) -0.13R 2,459 14h = 46,342 23,913 0.059 2027 0 565 0 35k 922 35,269 0 026 0 2a 209 1,041 1,830 11,072 0 128 2,453 721 46,242 23,013 0.053 2929 9 565 0 358 973 35,269 0 26 0 280, 209 1,081 1,530 11,073 -0.13R 2,453 696 46,342) 23.019 0.053 2993 0 568 0 358 023 95,989 (0.026 0 2a 209 «1,041 1,530 19,0770 9R 2,489 672 46,242 23,012 0.053 028 9 565 0 5A 923 35,289 0 026 9 Rg na 1,08) 1,530 11,073 0 138 2,453 649 48,342 23,099 0.053 298 0 565 6 358 992 35.289 8 f 290 me 14d 1590107919783 627 0h 447 -92.012 0059 Tare) 47,698 19,790 0 19,636 74,190 -1,163 0.029 1,125 MAN 7827- 9H RON.-§3, 992 4110169128, 112-80, 720 1,04 921,626 0 109 GwH ave GH AVG GWH AVG reference to ELFIN. (The royalty depends in part on the non-geothermal busbar cost which in turn depends on the diesel price.) Capital and fixed O & M costs were provided by SAI. The load for each scenario is read from the ELFIN run. The total geothermal cost in any year is the sum of fuel (royalty) and 0 & M costs plus the capital additions in any given year. Note that the capital costs are not levelized, but are simply summed into the year in which they are incurred. In effect 100 percent equity financing is implied. This is appropriate for economic analysis. Because of these capital costs, the cost per KWH is much higher in years in which capital costs are incurred. In reality a utility would spread these costs over the life of the capacity, using some bonded debt mechanism. The lower right section of Table 4-5 shows the diesel generation costs and loads. The fixed 0 & M and fuel costs and load are read from the ELFIN annual generation summary for each year. The fuel cost is modified (increased by the appropriate factor) if the high diesel price trend is specified. The costs are summed (as with geothermal) including the full cost of the capital additions in the year in which they are incurred. Finally the far right section of the spreadsheet shows the annual sums for the entire utility system. The total costs for both the geothermal and the diesel portions of the system are added then discounted by the appropriate fac- tor back to 1986. The sum of these present values constitutes the life cycle present value referred to above. 4.4 RESULTS AND SENSITIVITY ANALYSIS The results obtained from the base case analysis are presented in Table 4-6. The entries in this table are the net present values of the life cycle costs of the entire Unalaska electrical generation system. Thus each entry in the table represents the figure of merit for an entire scenario. The All Diesel scenarios include the capital costs for adding new diesel generation capacity as required by increases in the load over time. All fuel and operating costs are also included. The costs for each year from 1988 to 2016 are discounted (at 3.5 per- cent real discount rate) back to 1986. The geothermal scenarios include the capital and operating costs for generating systems which include both geothermal MLF6/C30 4-11 and diesel capacity. Thus comparison of the entries within each row of Table 4-6 provides a convenient means of determining the merits of the scenarios under identical assumptions. Within each row the only differences are the installed capacities of geothermal generation (0, 5, 7, 9.5 MW). Table 4-6 and Figure 4-9 show the results of each of the geothermal size classes under the three diesel cost trends and for the two load growth trends. The group of scenarios utilizing the Base Case load growth trend is shown in the upper portion of the table. The High Case load growth trend is shown at the lower portion of the table. The economic analysis does not yield an unequivocal answer as to the eco- nomic feasibility of geothermal versus all diesel generation. Utilizing the Base Case assumptions of medium diesel price trend, base case load growth, as well as all the other assumptions detailed in Section 4.1; the 5 and 7 MW Geothermal Scenarios are slightly higher in cost than the All Diesel scenario. In net present value terms, the least cost geothermal scenario, the 5 MW case is $0.4 million (or less than one percent) more expensive than continued reliance on diesel generation. The 7 MW case is $1.2 million more (or less than two per- cent) than the all diesel case. These differences are well within the range of uncertainty which is 5 to 25 percent for geothermal cases and unknown for the All Diesel Case. The economic feasibility of geothermal development is marginal, as revealed by sensitivity analyses conducted with respect to diesel prices, load forecast, planning horizon, discount rate, and other variables. Under the low diesel price assumption, geothermal development is not economically feasible. Under the high diesel price assumption, geothermal is advantageous. Under a discount rate higher than 3.5 percent, the all diesel alternative is preferred. Although financial analysis was not part of the scope of this economic feasibility study, a preliminary financing cost analysis was conducted by the Power Authority. This preliminary analysis indicates that financing costs would total approximately $3.8 million for a 7 megawatt geothermal development. Included in this $3.8 million is a cost of $1.7 million for obtaining revenue from sale of State of Alaska backed revenue bonds. Also included is $2.1 MLF6/C30 4-12 TABLE 4-6 ECONOMIC COMPARISON OF ALTERNATIVE GENERATION SCENARIOS FOR UNALASKA BASE CASE LOAD VS. HIGH CASE LOAD DIESEL DIESEL DIESEL ALL- +5 MW + 7 MW + 9.5 MW SCENARIO DIESEL GEOTHERMAL GEOTHERMAL GEOTHERMAL 1986 Present Worth of Scenario 1988-2016 (Million 1986$) BASE CASE LOAD GROWTH eee DIESEL PRICE: MEDIUM 73.0 73.4 74.2 80.0 LOW 60.1 68.3 70.6 77.3 HIGH 85.9 78.5 77.8 82.7 HIGH CASE LOAD GROWTH etd Aes S DIESEL PRICE: MEDIUM 93.5 89.2 87.4 92.3 LOW 77.3 81.8 82.5 87.5 HIGH 109.6 96.6 92.3 97.1 MLF6/CT9 FIGURE 4-9 OF GENERATION eee NARIOS SCH N ARISO COM \ ~ er sO NO NS DON: 4 LOND ees 7 TOTTI Ls OL ee ($ 9861 NOITIIN) SNIVA LNSSHYd LAN NNSAN Aon a SON Sats sda! HIGH DIESEL PRICE MEDIUM DIESEL PRICE LOW DIESEL PRICE fo) 9.5 MW GEOTHERMAL CAPACITY ‘] 5 Mr ZZ) 7 MW Be [77/| ALL DIESEL million interest during construction based on a 2-year buildout and a real interest rate of 3.5 percent (Mike Hubbard, Alaska Power Authority, personal communication to M. Feldman, May 15, 1987). These financing costs are not reflected in the economic conclusions. If they were reflected, they would unfa- vorably affect geothermal development versus continued reliance on diesel-fired generation. Without considering these financing factors, the cost-to-cost ratio of diesel versus 7 MW geothermal is 1:1.02. With consideration of financing costs, the ratio is 1:1.07. 4.4.1 Diesel Price Sensitivity As noted in Section 4.1.1, the low diesel price trend is not a most likely case, but rather a lower bound estimate of future price trends. Recall that this assumption has diesel prices rising gradually to $0.90 per gallon (in constant 1986 $) by 2006 and remaining constant thereafter. It is not surprising to find that geothermal development cannot compete under this assump- tion. If the high diesel price trend is assumed, geothermal development appears more economic than the All Diesel scenario. Under the base case load forecast and high diesel trend, the 7 MW geothermal development has a $8.1 million (9 percent) lower net present value. As noted above, the medium price trend yields essentially the same cost for diesel versus geothermal. 4.4.2 Load Growth Sensitivity Generally, higher loads favor geothermal development in that they provide greater utilization of the fixed costs of geothermal generation resulting in marked economies of scale. By comparison, diesel generation costs exhibit less economies of scale because they are tied to fuel costs per KWH which remain fairly constant. This tendency is apparent from Table 4-6 in that the high load growth case further increases the the gap between the Geothermal scenarios and the All Diesel scenarios. The 7 MW Geothermal scenario has a 6.5 percent lower present value than All Diesel under the medium diesel price assumption, and a 15.7 percent lower present value under the high diesel price assumption. Under the low diesel price and high load growth assumption, the All Diesel scenario remains the preferred alternative. MLF6/C30 4-13 4.4.3 Discount Rate Sensitivity Table 4-7 shows the same scenarios as Table 4-6 recalculated to show the effects of a high (4.5 as opposed to a 3.5 percent) present value discount rate. Because the costs for the development of geothermal are front-end costs as con- pared with the diesel fuel costs which are spread out over time, the. higher discount rate favors the All Diesel scenarios. However, it is interesting to note that the relative ranking of the scenarios within each row remains almost constant over the change in discount rates. The low diesel price scenarios more Strongly favor all diesel cases. The high diesel price trend still favors geothermal under the higher discount rate, although the cost savings are reduced. Under the medium diesel trend assumption, geothermal becomes signifi- cantly more costly if a 4.5 percent discount rate is used, and demand follows the base case. Under 4.5 percent discount, but assuming the high load growth and the medium price trend, 5 and 7 MW of geothermal are competitive with all diesel. 4.4.4 Project Life Sensitivity Extending the useful life of the geothermal plants would improve their advantage over all diesel scenarios. A comparison between Tables 4-6 and 4-8 illustrates the effects of extending the project life for 35 years, 25 years, or through 2025 (instead of 2016). This comparison is biased in favor of geother- mal development because it makes the optimistic assumption that the well and generating equipment will last for 35 years. Although the well test data Suggest that the Makushin Reservoir fluids are relatively clean in terms of corrosion and scale formation, this may change during production. This assump- tion favors geothermal development, particularly the 9.5 MW development. Under the base case project life, some $13 million dollars of investment, which repre- sent the last 2.5 MW of capacity added, is only utilized for 15 years (from 2001 to 2016). Under the extended project life assumption, this capacity would be utilized for the full 25 years. Although this assumption improves the 9.5 MW relative to the smaller geothermal developments, the smaller developments are still preferred to the 9.5 MW scenario. MLF6/C30 4-14 TABLE 4-7 SENSITIVITY ANALYSIS PRESENT VALUE DISCOUNT RATE 4.5 PERCENT SCENARIO BASE CASE LOAD DIESEL PRICE: MEDIUM LOW HIGH HIGH CASE LOAD DIESEL PRICE: MEDIUM LOW HIGH MLF6/CT2 ALL- DIESEL DIESEL + 5 MW GEOTHERMAL DIESEL + 7 MW GEOTHERMAL 1986 Present Worth of Scenario 1988-2016 (Million 1986$) 66.7 62.4 71.0 DIESEL + 9.5 MW GEOTHERMAL TABLE 4-8 SENSITIVITY ANALYSIS EXTENDED PROJECT LIFE DIESEL DIESEL ALL- + 5 MW +7 MW DIESEL GEOTHERMAL GEOTHERMAL SCENARIO DIESEL + 9.5 MW GEOTHERMAL 1986 Present Worth of Scenario 1988-2025 (Million 1986$) BASE CASE LOAD DIESEL PRICE: MEDIUM 102.3 81.1 80.7 LOW 82.0 74.5 76.1 HIGH 122.6 87.7 85.4 HIGH CASE LOAD DIESEL PRICE: MEDIUM 130.8 100.2 96.5 LOW 105.6 90.7 90.4 HIGH 156.0 109.7 102.5 MLF6/CT3 99.7 93.9 105.4 4.5 ECONOMIC CONCLUSIONS AND RECOMMENDATIONS EAL TUND Because the scope of the present study is limited to an economic feasibility and does not encompass tests of financial feasiblity, a firm recommendation cannot be made with respect to the desirability of geothermal development at Unalaska. The very close net present worth between the all diesel and the 7 MW geothermal development further precludes a firm recommendation. The estimated $3.8 million financing costs, in addition to the project construction costs casts further doubt on the feasibility of the geothermal project. Within these constraints, however, it may be concluded that geothermal development might pass a reasonable economic feasibility test and that financial feasibility investiga- tion is definitely warranted. The test of economic feasibility to which the proposed geothermal develop- ment was subjected was rigorous. The comparison with the all diesel alternative was rigorous in that a fairly high diesel efficiency is assumed, and that even the medium diesel price trend only results in a diesel prices rising to $1.32 per gallon (2006 through the end of the analysis). Furthermore, the diesel costs assume no additional generating plant structures or fixed operating costs despite a projected fivefold increase in installed capacity. The geothermal cost estimates used are conservative in that conservative design criteria are used, and cost estimates assume full union scale (Davis-Bacon Act) wages. Engineering cost of certain project components (such as foundations, steam pipe- lines and roads) were estimated based on very conservative designs based on uncertainty regarding actual field conditions. In addition, the drilling cost estimates allow for a 20 percent contingency allowance. The choice between the 5 and 7 MW geothermal development is too close to call based on the economic analysis alone. That choice should be based on the financial analysis as well. The 9.5 MW capacity appears to be less desirable than the 5 or 7 MW plants under the most likely conditions. However, because the 9.5 MW plant is incremental to the 7 MW development, because it occurs later in time and involves a separate mobilization, it is reasonable to defer this decision until the first phase of geothermal development is in place. If, toward the end of the century, diesel prices have risen to the high trend levels or demand has increased to the high case loads, it would be reasonable to con- MLF6/C30 4-15 sider this additional level of development. Additional reservoir performance data will also be available at that time. It is therefore recommended that the financial analysis of the 5 and 7 MW geothermal alternatives be undertaken. The "close call" between geothermal and diesel suggests that further design analysis may be indicated. Time is of the essence in that the load on the Unalaska utility is forecast to rise dramati- cally in the next few years, and that construction and especially drilling prices are currently at a very low point. If a decision to proceed is reached within the next year it may be possible to purchase rather than rent a drill rig at considerable cost savings. MLF6/C30 4-16 5.0 CONCEPTUAL DESIGN 5.1 PROJECT DESCRIPTION The proposed conceptual design of this geothermal power generation project incorporates two 13-3/8" production wells (one of which is a spare), a single 13-3/8" injection well, steam and water pipelines leading to the power plant (which will be located on the plateau to the northeast of the plateau upon which the production wells are drilled), and a water pipeline leading to the injection well. The project includes an electric power transmission system comprised of a step-up transformer overhead line from the plant site to the Makushin Valley where it is then undergrounded until it reaches the shore of Broad Bay. From the shore of Broad Bay, it will be laid under water to Amaknak Island following a path passing south of Hog Island in water depths in excess of ten fathoms. (See Figure 2-5.) The transmission line will be connected to the existing Unalaska/Dutch Harbor transmission line on Amaknak Island. Access to the geothermal power plant by operators and maintenance personnel will be over a road leading from Broad Bay to the power plant site. A small breakwater will be constructed on the shore of Broad Bay in order to form a Sheltered harbor for the work boat used to deliver men and materials across Broad Bay to the eastern end of the road to the power plant. A small pier and floats within the breakwater will facilitate mooring the work boat. The power plant will be comprised of two 2,500 kW (net out) flash steam tur- bine generator sets with air cooled condensers and two 1,000 kW (net out) binary cycle turbine generator sets with isopentane vaporizers heated by geothermal water and air cooled condensers to condense the turbine exhaust vapor. In many cases, geothermal resources are found in remote locations from popu- lated areas. The Makushin geothermal resource, however, is relatively close to and accessible from Unalaska/Dutch Harbor. The geothermal power plant in this project can be constructed for unattended operation and therefore provisions are made to monitor its operation from the existing power plant. The roads provided to the site make it accessible for periodic maintenance and to manually re-start the plant after automatic shutdown in the event of system outages. MLF8/B 5-1 The plant's cycle using flash turbines and binary units as shown in Figures 5-3 and 5-4 is selected with the objective of optimizing the economic use of the resource and minimizing project capital cost. The selection of materials, systems equipment rating and redundancies is consistent with the unattended operating criteria and in accordance with plant availability objectives in the range of 75%. In The Geysers in California, Pacific Gas and Electric Company (PG&E) has humerous power plants which were operated unattended and visited by roving crews of operators on a regular basis. Data released by PG&E in 1984 indicate that seven of their units built after 1975 averaged over 76% capacity factors during 1981 and 1982. Where geothermal power plants provide the base load block of the system demand, other types of generation generally supply intermediate and peak demands, The base load generated by geothermal plants permits the desired constant well flow of geothermal fluids. Substantial variations in well flow rates affect the long-term integrity of geothermal wells. In this project, the geothermal power plant would be operated to supply a large proportion of the system demands and thus follow the load. Therefore, to maintain constant well flow while the load varies (reduces from maximum demand) the surplus steam will be vented. Maintaining constant production well flow rates minimizes the potential for well damage which can often be attributed to starting and stopping geothermal wells. Venting steam to the atmosphere is more reliable than bypassing it to the condenser. Venting also precludes any possibility of damage resulting from the introduction of superheated steam to the condenser. Two production wells and one injection well will be drilled before pro- ceeding with work on the power plant. Two production wells are considered Necessary to insure that the plant can continue in operation even if one well becomes inoperative for any reason. The production wells will be drilled at the ST-1 test well site on a plateau MLF8/B 5-2 located on the south side of Fox Canyon (see Figure 2-3). The injection well will be located on a similar plateau on the north side of the canyon. Geothermal water and steam will be conveyed by the pipeline from the production well to the plant site to reach the plant. The pipeline will go down the side of the canyon and back up the other side to reach the power plant site. Since steam and water mixtures cannot readily be made to flow down steeply inclined pipes, it is necessary to separate the steam and water and deliver each to the power plant in separate pipelines. The most economically attractive geothermal power plant is a hybrid plant comprised of two 2,500 kW steam turbine driven generating units and two 1,000 kW binary cycle electric power generating units designed to produce 7,000 kW from a single production well. After the resource is used in the power plant all of the effluent is injected in a well drilled for this purpose. The two flash steam turbine driven electric generating units will be constructed as the first phase of power plant construction. The binary cycle units could be built during the initial construction phase or added when electric loads have increased suf- ficiently to justify their installation. Figure 5-1 shows the equipment arrangement for the flash steam plant and Figure 5-2 shows the equipment arrangement for the binary cycle portion of the plant. Figure 5-3 is a P&ID (pipe and instrumentation diagram) for a flash steam generating unit and Figure 5-4 is a P&ID for a binary cycle unit. Figure 5-5 is a single line electrical diagram showing the generation and transmission systems. Equipment will be delivered to a Driftwood Bay landing site by a barge which will be equipped to unload the materials and equipment directly onto trucks at the beach. These trucks will then deliver the materials to the plant site via the road previously constructed for delivery of the drill rig. 5.2 PROJECT DEVELOPMENT LOGISTICS AND SCHEDULE —e ee The drilling of wells for the development of geothermal resources for com- mercial applications, and specifically for power generation, represents a major initial investment phase of the program. To minimize this investment risk, it is proposed to minimize expenditures for access facilities required for well drilling operations. The road from Driftwood Bay to the north side of the MLF8/B 5-3 canyon will, however, be upgraded and the Sugarloaf Road will be built to per- mit barge and truck delivery of the drill rig to the proposed power plant site. The cost savings which would be afforded by road (versus helicopter) support during the drilling phase alone are sufficient to justify the cost of the Driftwood Bay and Sugarloaf roads. (Helicopter support will still be needed to get to the drill site from plant site.) Once well production capacities are proven, the next step will be the drilling of injection wells for disposal of geothermal effluents. The pipeline to deliver geothermal water to the plant site and injection well will be built Next. The steam water separator will be installed and the production and injec- tion wells will be tested by running geothermal water to the injection well. Flashed steam will be vented to the atmosphere during the test. The wells should be operated for a sufficient period of time in this mode to stabilize the physical parameters and chemical constituents of the resource. Verification of commercial resources is the most significant milestone in the geothermal development program. The success ratio is greatly improved when a sufficient number of production wells are programmed. Two production wells (one producer and one backup) are recommended for drilling at the same site as the ST-1 test well site. The power plant equipment, construction equipment and materials will be transported by barge to Driftwood Bay where they will be unloaded and transported by land on the road previously built for the transportation of the drill rig to the plant site. Also, a staging area at Driftwood Bay, near the eastern air strip, will be established to receive materials, equipment, and supplies delivered by sea and by air. Minor work is required to rehabilitate this landing strip. The air strip will be used during construction of the plant for delivery of personnel and unforeseen material requirements. During the well drilling and plant construction phases, the personnel will be housed at the respective sites. In the first instance, the drilling crews will be housed in trailers or tents air lifted to the well site. During the plant construction phase, the personnel will be housed in portable buildings transported from Driftwood Bay. MLF8/B 5-4 The road from Broad Bay will be constructed prior to the installation of the transmission line and underground/submarine cables. This road will serve as the access road during plant operation and will also be used for cable laying work. Figure 5-9 is a schedule of project activities and indicates the proposed order of accomplishment. 5.3 BASIS FOR DESIGN 5.3.1 Buildings The power plant buildings will be of the preengineered type. Foundations will be supported on concrete piers either cast in place or on driven piling depending upon the depth to suitable load bearing soils or rock. Building framing will be structural steel and the outside walls and roof will be in- sulated sandwich-type panels. Fiberglass skylight panels will be installed in the roof and will provide some natural lighting during daylight hours. The buildings will be designed to withstand wind velocities of 110 MPH and in accordance with UBC requirements for Seismic Zone 4. The building housing the turbine generator units will be approximately 40 feet by 120 feet in length. An overhead bridge crane will be provided to facilitate maintenance of the turbine generator sets and other equipment. The building housing the binary cycle units will be of the same type of construction but will be approximately 30 feet wide by 130 feet long. 5.3.2 Major Equipment 5.3.2.1 Steam Turbine Generator Set The steam turbine driven electric power generator set will be mounted on a fabricated steel base which will serve as a reservoir for its lubricating oil. Lube oil pumps, strainers and piping will all be factory installed on the tur- bine generator set, minimizing field labor. The turbine will be a multistage machine with an inlet pressure of 60 PSIA and a design exhaust pressure or 3.5 inches of Hg. Abs. The exhaust will face vertically upward to minimize foun- dation and piping costs. The turbine may be a high speed machine employing a speed reduction gear or it may be a 3,600 RPM machine directly driving a two MLF8/B 5-5 pole generator depending upon the particular manufacturer's specifications. If a high speed geared turbine is used to drive the generator, the generator will be a four pole machine. In either case, the generator will employ a brushless exciter and will be of the air cooled type. Generator voltage will be 4,160. The turbine generator set lube oil coolers will be located outside of the building and will be air cooled, fin tube type units. 5.3.2.2 Steam Condenser The steam condensers will be air cooled, fin tube type. Air cooled fine tube condensers were selected because they are not subject to the failures which can be caused by ice formation in wet cooling towers resulting from high velo- city winter winds. Thermostatically controlled motor driven fans will blow air across the tubes to condense the steam exhausted from the turbine. The con- denser will be of the A frame type with steam entering a header at the top. Condenser tubes will form the legs of the A and steam and condensate will flow down the tubes to condensate collection headers at the bottom. Two stage steam jet ejectors will be used to remove noncondensable gas from the condenser. The ejector interstage cooler will be of the air cooled fin tube type. All wetted parts of the condenser and noncondensable gas removal system will be constructed of 304 stainless steel. 5.3.2.3 Condensate Pumps Condensate pumps will be vertical can type pumps. Motor drivers will be TEFC enclosure. All wetted parts of the condensate pipe will be 304 stainless steel. 5.3.2.4 Instrument Air Compressors The instrument air compressors will be of the single cylinder water cooled nonlubricated type. Cooling water will be pumped through an air cooled water cooler to dissipate the heat of compression to the atmopshere outside the power plant building. MLF8/B 5-6 5.3.2.5 Air Dryer An instrument air dryer of the desiccant type will be provided. The dryer will be of the dual tower heatless regenerative type. One tower will be in ser- vice while the other is regenerated. Automatic controls will switch the air flow from the active drying tower to the regenerated tower as the desiccant in the active tower becomes saturated with moisture. 5.3.2.6 Turbine Drain System A condensate drain tank and two condensate drain pumps will be provided to pump turbine drains to the condensate receiver from which they will in turn be pumped by the condensate pumps to the injection system. The drain pumps will be automatically started and stopped by a level control switch. 5.3.2.7 Binary Cycle Generating Units As discussed in Section 2, Ormat manufactures a modular binary generator unit which would be well suited to the proposed project. The secondary fluid used by Ormat is isopentane, a flammable hydrocarbon. Each generating unit would produce approximately 1,100 kW gross which would result in a net output of approximately 950 kW per unit. These modular units contain the isopentane vaporizer and turbine-generator unit mounted on a commmon base. The base is constructed in such a way that with exterior panels in place, an envelope is formed which serves as a container for ocean transport of the units. The air cooled condensers will be shipped and installed separately because they are much larger than the water cooled condensers normally employed in the design of these package units. The vaporizer feed pump is also shipped separately and mounted alongside the module served. With the exception of the air cooled condenser, the use of which is necessary for this plant application due to possible freezing conditions, the binary cycle plant is of standard modular design. Thus, the installation costs are minimized because most of the components are assembled into modular units at the factory. Piping from the evaporator to the turbine is also factory fabricated and installed. The complete lube oil system, except for air cooled lube oil coolers, is factory fabricated and installed. The lube oil coolers are remotely installed outside of the power plant building. The generator is air cooled and employs a brushless excitation system. MLF8/B 5-7 The binary cycle power fluid feed pumps are vertical can type and employ explosion proof motors as drivers. The binary cycle fluid condensers are air cooled, fin tube type, and employ fans to blow cooling air across the tubes. The condensers are located outside of the power plant building and dissipate the latent heat of condensation to the atmosphere. Materials of construction for the binary cycle units are carbon steel because no oxygen will be present in the geothermal water used as a heat source and because the binary fluid (isopentane) is not corrosive. Fire protection for the binary cycle units will be provided by an automatic halon system. All electrical equipment in the binary cycle power plant building will be in explosion proof enclosures. Generator switchgear and motor control centers for auxiliaries employed in the binary cycle plant will be located in the building housing the steam turbine driven generating units. 5.3.2.8 Flash Generating Units The flash steam plant recommended for the Unalaska electrical system will be comprised of two 2,750 kW multistage condensing steam turbine generating units. Each steam turbine generating unit produces approximately 2,500 kW net out of the plant. All vital auxiliaries such as condensate pumps, turbine lube oil pumps and instrument air compressors will be provided with 100% capacity backup systems which will start automatically upon failure of the operating unit. This will minimize the number of outages experienced as a result of the failure of a plant auxiliary. The steam will be condensed in an air cooled finned tube con- denser. Fans are used to move the air across the tubes in order to achieve the optimum heat transfer rate. Condensate pumps will remove the steam condensate from the condenser and deliver it to the injection well. Noncondensable gases will be removed from the condenser by steam jet ejectors and the gases are vented to the atmosphere or compressed to a pressure sufficient to permit their disposal in the injection well if disposal in the atmopshere is unacceptable. Instrument and control air will be provided by one of two 100% capacity nonlubricated water cooled reciprocating air compressors. Instrument air will MLF8/B 5-8 be dried in one of two 100% capacity air dryers. Electric power will be generated at 4,160 volts and stepped up to 34.5 kV for transmission to the electric distribution system in the City of Unalaska. The plant will be designed for automatic unattended operation. Normal startup and shutdown of the plant are done manually by the plant operating staff. Malfunctions of plant equipment will result in an automatic shutdown of the turbine generator set affected or the entire plant depending upon the nature of the problem. When an automatic shutdown occurs it will be necessary for the operators to go to the plant, correct the malfunction and restart and load the generator unit affected or the entire plant if both units are forced out by the malfunction. If the plant or a generating unit shuts down, an annunciator in the plant will indicate which item of equipment failed first in order to assist the opera- tors in locating the problem and correcting the trouble. The plant electrical output capacity will be varied by venting steam to the atmosphere and/or hot water around the binary cycle generating units and sending it to the injection well. The steam condensate will be injected along with the unflashed geothermal water. By varying the output capacity, the plant will be able to match the demand on the electrical system. Since isopentane is flammable, the electrical switch gear and electrical motor control centers will be located in the building housing the steam turbine. Thus these sources of ignition will be kept away from any isopentane which might escape from a binary cycle generating unit. The generator will employ a brush- less exciter and a local control panel. The control panel enclosure will be explosion proof. Any motors or other electrical equipment in the generator building housing the binary cycle units also will have explosion proof en- closures. Explosive mixture detectors will be provided and arranged to register an alarm and shut the binary portion of the plant down if a dangerous leak is detected. Exhaust fans will be provided to remove any small leakage which may escape from the turbine shaft seals or governor valve stem seals. Isopentane piping will be welded and flanged joints kept to a minimum in order to reduce to the greatest extent possible the potential for leaks. MLF8/B 5-9 5.3.2.9 Geothermal Steam and Water Pipelines The steam-water mixture produced by the geothermal well will be conveyed together in a single 24" diameter, steel pipeline from the production well to the edge of the plateau upon which the production well is located. Near the edge of the plateau there will be a steam-water separator installed. The mixture of steam and water will be separated and each product will be conveyed in a separate pipeline from this point to the power plant. The water pipeline will be 14" diameter steel pipe and the steam pipeline will be 24" diameter steel pipe. The separation of the steam and water is Necessary because steam water mixtures will not readily flow down steeply inclined pipelines. The pressure drop in the water pipeline between the first steam water separator and the power plant will result in the flashing to steam of additional geothermal water in the pipe. This additional steam will be separated in a second steam-water separator located at the power plant and combined with the steam in the pipe leading to the turbines. Piping from the production well to the Fox Canyon crossing and from the north rim of the canyon to the power plant will be supported on conventional T type supports constructed of pipe. The pipes will be sufficiently elevated to be above expected snow depths Concrete footings will transfer the weight of the pipe to the earth. Pipe guides and anchors will be installed at appropriate locations, Pipe expansion will be accommodated by expansion loops. To span Fox Canyon (Figure 5-7) the steam and water pipes will be supported by two pipe bridges spanning the distance from the edge of the plateau to the toe of the slopes at the bottom of Fox Canyon. A third pipe support bridge will Span the Fox Canyon fork of the Makushin River. Concrete abutments will be located at the canyon rims and at the toes of the cliff faces. The pipe bridges will be free spans of about 200 feet each. There will be adequate space between the two pipes to allow operator access to the well site. The two sloping spans will be provided with stairs. Both the steam and hot water pipes will be insulated with calcium silicate insulation with a metal jacket to protect against weather and mechanical damage protection, MLF8/B 5-10 5.3.3 Access Roads Access for operations will be provided by an access road designated on Figure 2-4 as the Makushin Valley Road which will extend from Broad Bay via Makushin Valley to Point B (see Figures 2-1, 2-3 and 2-4). The route is indi- cated through points K, J, I, B. Route Section KJ, about 3.6 miles long (Figure 2-4), would be built on flood basin alluvium that is underlain by lacustrine/lagunal sediments. The flood plain in this area is flat and marshy. The road will be built using light-weight aggregate encapsulated in a geotextile membrane (Figure 2-6). There is about one mile of existing road at Broad Bay that could be improved and used as the first part of this section of the road. The proposed Makushin Valley Road will roughly parallel the southern portion of the Makushin Valley to a point where the river crosses the valley, then con- tinue west but away from the river up the valley. The road will be severely constrained by the poor subsurface conditions. Present plans call for use of a light volcanic borrow material encapsulated in geomembranes and placed in a thin section (approximately 2 feet). The idea is to float the road and treat the surface course with a Percol additive for strength and durability. This embank- ment design is illustrated in Figure 2-6. The performance of this road will require monitoring during operations, and repairs will have to be made with care Not to overload the poor bearing material. The small creek crossings along this segment will have to be bridged with open bottomed (arched) culverts. The pre- cise alignment of the KJ section should be determined in the field with input from ADF&G and the landowners. Several borrow sources have been identified by the ADNR on the south valley wall, but they have not been evaluated in terms of a light-weight (floated) road system. It may be necessary to use an upland material source west of the valley. A bridge (approximately 100 foot span) will be built to cross the north channel of the Makushin River (near Point J). A second bridge (approximately 100 foot span) may be required near Site I. The operational access road joins the old road as it leaves the valley bottom and switches back up the valley wall. This section of the old road has washed out in several sections and will MLF8/B 5-11 require significant upgrading and repair. The ADNR report describes the repairs necessary in sufficient detail for planning purposes. Repairs entail placement of culverts and the addition of rockfill to washed out or slumped areas. No major redesigns are suggested for this section but some maintenance should be factored into long-term operations. Material Source 12 is located within the switchback section and it will provide adequate rockfill. Section JI (Figure 2-4) will be easier to build than Section KJ except that it will require two bridges for the two major river crossings in the area. Good aggregate materials for road construction are available in this section. The Driftwood Bay Road, approximately 5.6 miles long, extends from Site L at the end of the airstrip to Site B (see Figure 2-2), follows the existing road and it will require major repair work. The road ascends a low alluvial fan before it goes up into Driftwood Bay Valley with an average slope of 10 percent. All roads will be built 20 feet wide and the Section LBE should be designed for AASHTO Truck Load HS-20, limiting the maximum grade to 10 percent. The roads will have no special pavement and would be built from the aggregate existing at the route site except for road Section KJ, which will have a special Percol pavement and light-weight aggregate imported from the Driftwood Bay area. The road from Point B to the power plant site is designated (Figure 2-3) the Sugarloaf Road; it is approximately 4.3 miles long, would be all new road construction and it would go north of Sugarloaf Cone. Road construction would progress rapidly across this area. The road would have to cross several, peren- nially snow filled ravines. Two bridges (approximately 200 foot spans) will be required at these crossings. Extensive maintenance work is expected in this area due to snowfall. Bridge abutments may be constructed with reinforced concrete supported on wood pile, as required. The selection of the crossings will be made in accordance with environmental constraints. All bridges could be constructed with steel deck and reinforced concrete abutments supported on wood piles, if necessary. MLF8/B 5-12 5.3.4 Transmission Facilities The selected transmission route through the Makushin Valley consists of an overhead line for 9 miles and a buried land cable for a length of about 34 miles in the lower Makushin Valley. The overhead line is routed through an-‘area where access and soil stability are adequate. The land cable is routed through the area where soil stability is poor due to the marshy nature of the Lower Valley. When the land cable reaches Broad Bay it is converted into a submarine cable for the sea crossing to Amaknak Island. The selected line route through the Makushin Valley will be maintained from the same access road built for use by the power plant operation and maintenance crews. The proposed overhead transmission line will have conductors thermally capable of carrying in excess of 10,000 kW of capacity. The minimum conductor size required for the thermal capability of 10 MW is 2/0 AWG ACSR. However, we propose using 556 MCM ACSR which would be more than adequate thermally and would give better regulation than the 2/0 size. The added cost of the 2/0 size is negligible. The 556 MCM size is also stronger than the 2/0 conductor. The generation voltage of 4160V at the power plant will be stepped up to 34.5 kV for purposes of transmission, by means of a main step-up transformer located at the power plant switchyard. The overhead transmission line struc- tures will be of the wood pole "H" frame configuration and ruling spans of approximately 600 feet will be used in the design. The overhead line will be built along the Makushin Valley from the plant site a distance of about 9 miles. This distance is determined by the soil conditions that would permit supporting the H-frame wood pole line structures. At this point the overhead line will terminate at Switching Station A and the transmission will continue in the form of three, single conductor 34.5 kV, 4/0 AWG buried cables. Preliminary calcu- lations indicate that considering the high wind velocities, conductor size, ruling spans, H-frame wood pole strengths, soil conditions, etc., the line could be constructed with H-1 70 foot poles. The cables, like the overhead lines, must be sized at 2/09 minimum from a thermal capability aspect. However, a size of 4/0 is suggested for the following reasons: MLF8/B 5-13 ° More than adequate thermal capacity ° Improved regulation and lower voltage drop ° Provide better strength especially since single conductor cables are being used ° Cost differential for the added copper is negligible ° 4/0 is the minimum size some manufacturers make at 34.5 kV. These cables will be laid in the marshy floor of the Makushin Valley for a route distance of 34 miles to Broad Bay on the west side of Unalaska Bay. At the shore another switching station will terminate the 3 land cables and the transmission will continue in the form of four single conductor, 34.5 kV, 4/0 AWG armored submarine cables across Unalaska Bay (see Figure 2-5). The sub- marine cable route distance will also be 34 miles and these cables will ter- minate in the east terminal switching station on Amaknak Island. At all the transition points from overhead line to underground cable and from land cable to submarine cable, etc., the cables will be protected from surges and lightning by the installation of lightning arresters at the switching stations, The land cable will be installed adjacent to the Makushin Valley access road. This is essential from an installation point of view and also for later maintenance, replacement, trouble shooting and repair. In the event of failure of one conductor, the fault could be located and a new single conductor section of cable could be spliced in. The submarine section of the transmission route will consist of four single- conductor cables, laid separately at a distance of about 350 feet between adja- cent cables. This would limit any possible anchor damage to only one of the four cables. Switching stations at the ends of the submarine cable section will enable the faulty cable to be disconnected and the spare healthy cable to be reconnected into the system in its place. The switching would be done manually with the circuits de-energized. Due to the difficulty of getting access to the submarine cables readily and the lack of readily available cable laying equip- MLF8/B 5-14 ment, it is felt that the ‘installation of spare single conductor submarine cable is justified for the initial installation. In addition, the project design should include marker buoys at locations at which anchor damage to the cables might occur. A 34.5 kV circuit breaker at the geothermal power plant will be on the SCADA control system and thus be suitable for remote operation with remote indication. 5.4 PROJECT CAPITAL COST ESTIMATE A comparison of Capital Costs for each of those alternatives selected for the purpose of this study is provided in Table 5-1 and summarized below: The three alternatives are: (1) 5,000 kW Flash Steam Geothermal Plant $36,684,000 (2) 7,000 kW Hyrbid Geothermal Plant $42,694,000 (5,000 kW Flash Steam + 2,000 kW Binary) (3) 9,500 kW Hyrbid Geothermal Plant $54,471,000 (7,500 kW Flash Steam + 2,000 kW Binary) A more detailed cost breakdown for the 7.0 MW hydro plant is shown in Table 5-2. Detailed cost estimates for all components are on file at the Alaska Power Authority. The cost estimates include power plant costs, infrastructure such as access roads and transmission line costs, and a docking facility at Broad Bay. Also included in the estimate are engineering, procurement, construction management and the cost of a 45 man construction camp. Unit-rates used in this study estimate reflect the material and labor costs of the fourth quarter of 1986. No escalation is added. A labor productivity factor of 30% was added to the craft manhours in order to account for the decreased productivity expected at remote construction sites. Labor rates used in the estimate represent composite crew rates which also include fringes, payroll taxes, and overtime premiums. MLF8/B 5-15 TABLE 5-1 UNALASKA GEOTHERMAL POWER PROJECT CAPITAL COST COMPARISONS (THOUSANDS OF 1986 DOLLARS) 5,000 kW 7,000 kW 9,500 kw Description Flash Steam Hybrid* Hybrid** Access Roads: Driftwood Bay Valley Road 123 123 123 Sugarloaf Road 430 430 430 Makushin Valley Road 1,059 1,059 1,059 Construction Equipment Rental 87 87 87 Pier at Broad Bay 500 500 500 Transmission Line: Overhead 1,985 1,985 2,385 Underground 1,420 1,420 1,620 Submarine 1,930 1,930 1,930 Site Preparation 76 76 76 Foundations 297 347 422 Building Facilities 304 445 545 Substation 144 144 244 Switching Stations 218 218 218 Gathering System 3,969 3,969 4,549 Power Plant Eqpt & Installation 6,229 10,115 13,147 Subtotal 18,771 22,848 27,335. Productivity Factor 2,188 2,338 2,797 Inland Transportation 574 753 901 Mobilization & Demobilization 1,044 1,244 1,744 Distributed Costs 1,358 1,358 1,625 Subtotal 23,935 28,541 34,402 Insurance & Bond 641 765 922 Subtotal 24,576 29,306 35,324 Contractor's Profit 2,458 2,930 3,553 Subtotal 27,034 32,236 38,877 Wells Drilling Cost 5,085 5,085 8,918 Subtotal 32,119 37,321 47,795 Engineering & Procurement (5%) 1,606 1,866 2,390 Construction Management (2%) 642 747 956 Spare Parts 250 300 350 Subtotal 34,617 40,234 51,491 Contingency (7% excl well costs) 2,067 2,460 2,980 PROJECT COST 36,684 42,694 54,471 * Refer to Table 5-2 for detailed backup for 7,000 kW plant costs. ** Requires one additional production well and one additional Injection well. TABLE 5-2 DETAIL COST ESTIMATE 7,000 kW HYBRID GEOTHERMAL POWER PLANT (Item- Page #)* Access Roads 1. Driftwood Bay Valley Road Repair Road from Driftwood Bay to $ 23,820 (a-17) Site "B" (5.6 miles) ° Bridge One 100 Ft. Span Structural Steel 72,615 (b-17) ° Bridge Abutments 26,356 (c-17) Total Driftwood Bay Valley Road $ 122,791 2. Sugarloaf Road Site "B" to Power Plant Site Section B-E New Road (4.3 miles) ° Clear and Grub $ 19,000 (d-18) ° Cut & Fill 13,770 (e-18) ° Culvert 54,615 (£-18) ° Bridge Abutments 52,716 (g-18) ° Bridges (2 ea) 200 Ft. Span Structural 290,460 (h-18) Steel Total Sugar Loaf Road 430,561 3. Makushin Valley Road Broad Bay to Site "B" Section K-J (5.1 miles) ° Excavating & Hauling Pumice $ 315,949 (1-14) ° Spreading Compacting Pumice and Gravel 406,760 (3-14) on Membrane ° Surface Coating 119,753 (k-14) ° Drain Pipe 21,461 (1-14) * Refers to item and page number in Detailed Estimate on file at the Alaska Power Authority. 06/30/87 Page 1 of 6 0165M (Iten- Page #)* Section J-B (4.1 miles) ° Clear & Grub 18,000 (m-15) ° Cut & Fill 14,175 (n-15) ° Bridges (2 ea) Structural Steel 98,476 (0-15) ° Bridge Abutments 52,716 (p-15) ° Drain Pipe 11,526 (q-15) Total Makushin Valley Road 4. Construction Equipment $ 87,438 (r-12) Total Construction Equipment Pier at Broad Bay $ 500,000 (s-22) Total Pier at Broad Bay 34.5 kV Overhead Transmission Line 1. 556 ACSR Conductor on “H-Frame" Wood $ 1,984,752 (t-46) Structures (9 miles) Total 34.5 kV Overhead Transmission Line 34.5 kV Underground Cable 1. 3-1/C-4/0, 34.5 kV Land Cable (3.5 miles) $ 1,420,000 (u-47) Installation $1,164,930 Cable Material and Potheads ($673,070) Total 34.5 kV Underground Cable 34.5 kV Submarine Cable 1. 4-1/C-4/0, 34.5 kV Submarine Cable $ 1,930,000 (v-47) (3.5 miles) Installation $1,425,840 Cable Material and Potheads $1,075,860 Total 34.5 kV Submarine Cable 1,058,816 87,438 500,000 1,984,752 1,420,000 1,930,000 * Refers to item and page number in Detailed Estimate on file at the Alaska Power Authority. 06/30/87 Page 2 of 6 0165M Foundations 1. Building Foundations 2. Equipment Foundations 2 T/S ° Pumps ° L/O Console ° Transformer ° Condenser ° Switchgear ° Separator 3. Pipe Support Foundations (Gather 4, Equipment Rental Total Foundations Power Plant Buildings 1. Pre-engineered Metal Building 40 30 x 130, Complete w/Doors and W 2. Moisture Protection 3. Architectural Finishes (Main Bui Total Power Plant Building Substation 1. 35 kV Outdoor Substation Consist 6/8/10 MVA, OA/FA/FOA Cooled Tra Breaker, & Associated Equipment 2. Bus Work Total Substation Switching Stations 1. West Terminal Switching Station 2. East Terminals Switching Station 3. Switching Station “A” Total Switching Stations ing System) x 120 & indows lding) ing of nsformer, $ 76,332 155,174 94,321 21,308 $ 279,070 16,125 150,000 S$ 131,790 11,840 $ 86,554 86,554 44,548 (Item- Page #)* (w-26) (x-23,25,26) (y-25) (2-27) (aa-32) (ab-30, 31) (ac-32) (ad-48) (ac-50) (af-49) (ag-49) (ah-49) 347,135 445,195 143,630 217,656 * Refers to item and page number in Detailed Estimate on file at the Alaska Power Authority. 06/30/87 Page 3 of 6 0165M Site Preparation Clear & Grub Haul Off Cut & Fill Drainage & Sumps Structural Excavations Chain Link Fence Total Site Preparation Gathering System Power Plant Equipment and Installations 2,500 kW Flash Steam T/G Sets (2 ea) 1,100 kW Binary T/G Sets, Including 20” Steam Line, Insulated 14" Hot Water Line, Insulated 10” Reinjection Line Pipe Supports Fox Canyon Crossing Steel Bridges (3 sections) Separator (2 ea) Total Gathering System Condenser (2 ea) Air Cooled Condenser for Flash Steam Unit (2 ea) Pumps (8 ea) Tanks/Reservoirs (4 ea) Instrument Air Compressor & Air Dryer & H.E. (1 ea) Lube Oil Coolers (3 ea) Lube Oil Purifier (1 ea) 5-Ton 0.H. Crane (1 ea) Instrumentation & Control Start-Up Services Plant Piping System, Electrical Gen. Neutral Grounding Cubicles (4 ea) 4,160 V Metalclad Switchgear 100 kW Emergency Generator (1 ea) $ 1,500 8,654 15,750 14,908 24,115 11,308 $ 1,901,012 793,988 13,481 150,435 1,080,000 30,047 $ 3,072,960 2,170,600 1,556,480 36,573 16,253 78,404 20,118 30,912 46,398 300,000 340,000 455,891 54,720 229,800 27,490 (Iten- Page #)* (ai-20) (aj-20) (ak-20) (a1-20) (am-21, 22) (an-20) 76,235 (a0-36, 39) (ap-36 , 39) (aq-36, 39) (ar-36) (as-43) (at-34) 3,968,963 (au-34) (av-43) (aw-34) (ax-34, 35,43) (ay-34, 41,43) (az-35) (ba-35, 44) (bb-41) (be-41) (bd-41, 44) (be-41, 44) (b£-35,40,42,43) (bg-48) (bh-50) (bi-51) * Refers to item and page number in Detailed Estimate on file at the Alaska Power Authority. 06/30/87 Page 4 of 6 0165M 17. Communications: Fiber Optic Cable (16 miles) Fiber Optic Interface Equipment (2 ea) 18. Station Service Transformer (1 ea) 19. House Transformer, 1,000 kVA, 4,160-480 V (1 ea) 20. 480 V Load Center (1 ea) 21. 480 V MCC (4 ea) 22. P/B Stations 23. Relay Panels (4 ea) 24. Supervisory Control and Data Acquisition (SCADA) System of Geothermal Plant 25. AC Panel (1 ea) 26. DC Panel (1 ea) 27. DC Battery & Battery Charger (1 ea) 28. Raceway, Cable Tray, Cables, Junction Boxes, Pull Boxes, and Terminations 29. Grounding System 30. Plant & Indoor Lighting Fire Alarm & Detection 31. Misellaneous Electrical Items 32. Gang-Operated Disconnect Switches 33. Structural Steel: ° Air Cooled Condenser Structural Supports Total Power Plant Equipment & Installation Subtotal Productivity Factor Inland Transportation Mobilization & Demobilization Distributed Costs Subtotal Insurance & Bonding Subtotal 133,235 33,680 10,024 15,380 24,840 84,880 7,392 83,040 82,360 4,340 3,956 14,520 476,000 26,400 186,000 84,200 10,280 397,643 (Item- Page #)* (bj-53) (bk-53) (b1-51) (bm-50) (bn-51) (bo-51) (bp-52) (bq-50) (br-50) (bs-51) (bt-51) (bu-51) (bv-52) (bw-52) (bx-52) (by-52) (bz-48) (ca-29) 10,114,769 $22,847,941 2,338,300 752,680 1,244,000 1,358,000 $28,540,921 764,898 $29,305,819 * Refers to item and page number in Detailed Estimate on file at the Alaska Power Authority. 06/30/87 Page 5 of 6 0165M Contractors Profit Subtotal Wells Drilling Costs i. Production Well (1 ea) 2. Injection Well (1 ea) 3. Spare Production Well (1 ea) 4. Mob/Demob (Seattle/Unalaska) 5. Helicopter Support and Subsistance 6. Handling Charge @ 10% 7. Prof. Labor, Travel & ODC 8. Contingency @ 20% Total Well Drilling Costs Subtotal Engineering & Procurement Construction Management Spare Parts Subtotal Contingency TOTAL PROJECT COST 06/30/87 Page 6 of 6 866,572 409,904 701,857 527,606 943,100 344,918 443,520 847,523 2,930,580 $32,236,399 5,085,000 $37,321,400 1,866,070 746,430 300,000 $40,233,900 2,460,400 $42,694,300 0165M A 5% contingency was used on all costs except for drilling costs which include a 20% contingency. A special contingency of $450,000 was allowed for possible realignment of the Makushin Valley Road to avoid environmentally sensitive areas. This special contingency has been incorporated into the overall 7% project contingency shown in Table 5-1. Items not included in this study estimate are: (1) Financing fees and interest during construction (estimated to total $3.8 million -- see Section 4-4) (2) Permits/fees (a negligible cost) (3) Environmental studies cost (negligible assuming that an environmental impact statement is not required). 54.1 Additional Assumptions It is assumed that Contractor labor will be drawn from Anchorage, Alaska union halls. Accordingly, labor rates used in this estimate are composite crew rates based on Anchorage, Alaska labor union agreement. The work week is based on six 10 hour days except for drilling which is conducted on a 24 hour per day basis, seven days per week. All material and equipment is priced F.O.B. Seattle, Washington. Barging costs for all materials, construction equipment and man camp are included in the estimate based on $280/ton of shipping weight. Borrow material, sand, gravel and rocks as needed will be available to Contractor on the island at a cost of $1.50 per cubic yard as per the agreement with the Aleut Corporation. Demobilization will occur 12 months after mobilization because of the barge schedule. Standby time for construction equipment while it is waiting for retrograde barge trip is included with distributed costs. MLF8/B 5-16 Project cost of each of the alternatives except for the 9.5 MW hybrid plant assumes that the entire project will be constructed at one time, and without any interruptions. Drilling precedes all construction activities except for the road from Driftwood Bay to the power plant site. 5.5 OPERATION AND MAINTENANCE Operation and maintenance operations are described below. The costs for operation and maintenance are shown in Table 5-3. 5.5.1 Operation The power plant is designed for automatic unattended operation. Plant start-up will be done by operators who will parallel the generators with the Unalaska distribution system. The geothermal turbine generator sets will take increased load as the electric system load increases. As electric system load decreases the geothermal units will shed load. Steam will be vented to the atmosphere and hot water will be bypassed to the injection well. Condensate from the steam condenser will be pumped into the pipe conveying the geothermal water to the injection well. In the event of a failure of a plant auxiliary such as a condensate pump the standby pump will be automatically started. The standby auxiliary will be of equal capacity to the unit for which it backs up so there will be no reduction in electrical output of the plants when a spared auxiliary fails. In the event that a necessary standby auxiliary fails to start the turbine generator unit will be automatically shut down. The reduction in electrical general capacity will be made up by the remaining geothermal generating units if sufficient unused capacity is available. If the load exceeds the remaining geothermal plant capacity, diesel engine driven generators in the Unalaska power plant will pick up the additional electrical load. If the entire geothermal power plant is shut down, diesel engine driven generators located in the power station in Unalaska/Dutch Harbor will carry the electric load until the geothermal plant can be repaired and returned to operation. MLF8/B 5-17 TABLE 5-3 ANNUAL OPERATION AND MAINTENANCE COST SUMMARY DESCRIPTION PLANT TYPE AND CAPACITY. FLASH STEAM BINARY HYBRID 5 MW 5 MW 7.0 MW 9.5 MW Maintenance Labor Costsl $ 60,0002 $ 54,000 $72,000 $102,000 Parts 80,000 100,000 132,000 182,000 Road Maintenance 20,000 20,000 20,000 20,000 Dock Maintenance 1,000 1,000 1,000 1,000 Total Maintenance Cost $161,000 $175,000 $225,000 $305,000 Operating Labor Costl 62,0002 62,000 62,000 62,000 Truck3 10,000 10,000 10,000 10,000 Work Boat3 20,000 20,000 20,000 20,000 Expendable Supplies (Small Tools, Lube Oil, etc.) 5,000 5,000 5,000 5,000 Insurance4 161,000 165,000 208 ,000 280,000 Total Operating Cost $258 , 000 $262,000 $305,000 $377,000 Total Operating & Maintenance Cost $419,000 $437,000 $530,000 $682,000 1. Includes wages at $19.80 per hour + 24% fringe benefits plus overhead cost. 2. Two men, three visits per week, 8 hours per visit. 3. Includes capital cost, repairs and fuel. 4. 75% of plant at a rate of 1.25% for the covered equipment and material. Does not include wells, roads or transmission facility. MLF8/BT1 The failure of the plant auxiliary will be registered on an annunciator located in the geothermal power plant. The failure will also be transmitted from the geothermal power plant to a data collection center in Unalaska where the geothermal power plant operation will be monitored. It will, however, be Necessary to send an operator or maintenance person to the geothermal power plant in order to determine the reason for the equipment failure and to make any needed repair. Operators will need to visit the plant two or three times each week, weather permitting, to check the operation of all of the plant equipment. During these visits the plant operators will also perform routine maintenance and service on the power plant equipment. A dock with a small crane will be constructed at the end of the power plant access road. This dock will be protected by a solid piling breakwater. Operators will cross Broad Bay from Unalaska in a diesel powered work boat (+30') dedicated to the power plant. The boat will be capable of delivering small maintenance equipment, lubricants and operating supplies. Access to the power plant will be by road up the Makushin Valley. A 4-wheel drive pickup and snowmachine will be used to negotiate the road which will be snow covered during most of the winter months. The vehicle will be stored in Unalaska and ferried across Broad Bay on the work boat. Access to the well head and the steam-water separator which will be located on the south side of Fox Canyon will be by a foot bridge built on and supported by the pipe supplying steam to the power plant. Since the well can operate con- tinuously even if the power plants shut down, there will only need to be occa- sional visits to the steam water separator and well head. These inspections will assure that the level control valve on the steam water separator is func- tioning and that the piping systems have not developed any leaks. 5.5.2 Maintenance Routine maintenance on spare auxiliaries will not require the plant to be shut down and can be scheduled at any time of year. Turbine and generator main- tenance, however, should be scheduled to coincide with periods of minimum electrical loads. It is anticipated that each turbine will require an annual overhaul which will mainly consist of cleaning the stationary and rotating bla- des. Governor valves will also require annual maintenance. MLF8/B 5-18 Turbine maintenance will be facilitated by an overhead crane installed in the power plant building. The power plant building will be large enough to house the vehicle used by the operators and maintenance personnel. Also included in the power plant building are sleeping quarters which will be used by operators or maintenance personnel when weather precludes returning to Unalaska after work at the plant. A small kitchen with food storage cabinets and a Separate lavatory will also be included. Maintenance for all equipment will be done in the power plant building, therefore sufficient floor space is included for the maintenance activity. MLF8/B 5-19 [oce 2 baron TRANSFORMER even q : Diesel GENEKATOR. - 24°# STEAM FROM etre PRODUCTION WELL EONS seve ; / | rela ad \ 14°? STEAM —— 7 ‘ bog , IL 7 ‘ 4 *: Mee _| Fane] «iTcHeNnerye j wnbieniias SLEErING QUARTERS i” 14°? STEAM NCE HEATER (TYR oF 4) 2'¢ To conmenemsres Recevern TANK jo TEAH elect Jo cONDESATe Recever, ALASKA POWER AUTHORITY ----- + TO INJECTION WELLS POWER PROJECT 8000 KW FLASH STEAM PLANT GENERAL ARRANGEMENT 80165 FIGURE 5-1] 0 conor seme oeewn [hc i clent___o__ me all TUBE PRMCVAL oPACR. ALASKA POWER AUTHORITY eet] UNALASKA GEOTHERMAL Ee ee owen proscer ee: 2000 KW BINARY CYCLE PLANT GENERAL ARRANGEMENT “ Figure 6-2] | SPU @ TAM. couvedo~ pupa Jo Raman Evcle Urs, Femzecyion BLL a3 us a wee mms 8 “ ” + ENGINEERS, IN’ ALARA POWER AUTHORITY “ Fron Fan vent TURBINE GENERATOR SET 1SOPENTANE CONDENSATE Recewer, Tygeone TT... aes Lert _ Gr) ® a fo he as che SS em. Ho p—ro__F ISOPENTANE, VAPORIZER, STORAGE ISQPENTANE FEED PUMPS ISOPENTANE UNLORDING AND TRANSFER PUMP SAI ENGINEERS, INC. 2 Mes L CONDUCTOR | 34 SKY Neth pecs 4 [. wae b-b- 4% Die ar ke)- ey O/H TRANSMISSION LINE (BSGMCEM AC SE RELAYING Lt... = re : No = “OWITCHING STATION “AS 32 Y zoon Lod. i atu }- (a) es PGLAYING An oo-7 ° a's GOOA ee WB 6y32.01IND CABLE & - asks: 46 . 1 "T MAIN TRANSFORMER, + Ly 678710 MvA, OA/PA/ROA CLOT B45 kv - ateoy fA SUBMARINE = LAIO CABLE * TERMINAL (SEE DETAIL *AY) al 6 || ms 41GOv, BOOA BUS T gF t504 of I Sync a HOUSE TR ANISH iit Toou «vA re 4160. ABO ' ) 20004 eee ABOV LOAD CENTER (20004 BUS) METERING = alae RELAYING ] )e00a b ) e004 6 6 (%) space ab OO WEST TERMINAL SWITCHING STATION TRANSFER aus DETAIL "A" “Say y SUBMARINE CABLE f “at ieevre ee DETAIL A a i ff ee CAST remainaL SWITCHING STATION, NEW NEW PROJECT PROJECT pps cit 1:%/c - 34.5 CABL LOOPED IN AND ‘OF NB) SWITCHING STATION too kw EMERZENCY GENERATOR ALASKA POWER AUTHORITY ail[sa ENGINEERS, INI [3090 Preview UNALABKA QEOTHERAAL POWER PROJECT PROPOBED ELECTRICAL OYETEM SINQLE-LINE GAGRAM FIGURE 5-5 | 0 34 KY OVHD LINE FROM PRODUTION WELL TERM. oR. STEAM N loco. co EPARATOR. ys ‘ E 1000.00 PLANT COORDINATE —sl TO INJECTION WELL: I I Fee ae a 7O000KW POWER PLANT UNALASKA GEOTHERMAL PROJECT SAI ENGINEERS, INC. 95050 r SITE PLAN ALASKA POWER AUTHORITY | Tite : | CONCRETE ABUTMENT (TYP) STAIRWAY FOR FooT TRAFFIC BETWEEN PIPES (TYP) CONC. ABUTMENT (TYP) STEAM LINE ait MAKUSHIN RIVER (FORK) WATER LINE SECTION A-A NO SCALE STRUCTURES TO SUPPOR PIPE LINE CROSSING ALASKA POWER AUTHORITY FOX CANYON PIPE CROSSING PN eT CT -ES | i LIGHT WEIGHT METAL SUPERSTRUCTURE ira Ly REINFORCED CONCRETE ABUTMENT ON PILES IF NECESSARY (TYP) SECTION X-X NTS. OADWAY BRIDGE N.T.S. SAI ENGINEERS, INC. | ALASKA POWER AuTHORITY [8 TYPICAL VEHICULAR BRIDGE 3030 Petrick Henry Or., Bente Clere,Ca, 96050 PROJECT DEVELOPMENT SCHEDULE 1987 1988 1989 1990 1991 Project Approval ce Engineering/Design Civil Works Driftwood Bay Staging Area Construction Driftwood Bay Access Road Construction —_ Drill Pad Construction Td = Well Drilling (3W) Broad Bay Access Road Construction Power Plant Site Work Equipment Manufacturing and Shipping Transmission Line Construction i Equipment Installation Sateainaiameanl OH, UG and SM nn t COMMERCIAL OPERATION PROJECT DEVELOPMENT SCHEDULE Owg.o. FIGURE, 6-0 3030 Petrick Henry Or, Bente Clere,Ca, 85030 Al Promce Nn. Oc1G5 [Owens == | orewn Anno | Ticte : | 6.0 CONCLUSIONS AND RECOMMENDATIONS 6.1 TECHNICAL CONSIDERATIONS A geothermal power plant utilizing the Makushin reservoir is technically feasible for plant sizes up to 9.5 MW capacity. The preferred location for the production well pad is at the site of the test well drilled during the explora- tion program conducted by Republic Geothermal on behalf of the Alaska Power Authority. This site offers an almost certain probability of obtaining a com- mercial scale production well. The preferred location for the power plant is on the opposite (north side) of the Fox Canyon. Due to the difficulty of conveying a steam-water mixture down steeply inclined pipes, a steam water separator is recommended at the well site. Although this site requires a pair of pipelines across the canyon (one for water and one for steam) the greater ease of access to the powerplant afforded by this site offsets the cost of the pipeline. Access to the powerplant during construction will be via a road from Driftwood Bay. This approach utilizes a largely usable existing road. The only New portion of the road will be a segment from Sugarloaf to the plant site. Access to the well site during construction will be via helicopter. A pipe bridge across Fox Canyon is anticipated for operational access, Access to the powerplant site during operations will be via a dedicated crew boat which will be used to cross Unalaska Bay from the City of Unalaska to Broad Bay. A small dock will be built at the south side of Broad Bay. A road will be built from the dock up the edge of Makushin Valley to the base of an existing switchback road. Part of the Makushin Valley road will be built using an encapsulated fill design which will float on the marshy valley floor. The least cost powerplant configuration includes two 2.5 MW single flash steam generation units, An additional 2 MW of binary capacity can be added to this flash plant utilizing the hot water which is not flashed to steam by the two 2.5 MW flash steam units. If additional capacity is needed a third 2.5 MW unit can be added. This addition requires a second production well and a second injection well. The transmission route will generally follow the road from the plant site to Broad Bay. This will facilitate transmission line construction and maintenance. MLF8/C43 6-1 The line from the plant site to the lower third of the valley will consist of 34.5 KV conductors on wooden H-pole towers. At this point the line will con- tinue via three 34.5 KV underground cables to Broad Bay. There the line will connect to three single conductor 34.5 KV insulated submarine cables which will terminate at Dutch Harbor. A fourth conductor will be available as a spare, in the event that one of the three primary conductors is damaged. It is technically possible to design a power plant for remote operation. This can be accomplished by setting the plant up to run at full power and to bypass unused steam to the condenser. The plant can shut down automatically in event of malfunction. Start-up will require manual operation. Power plants cannot operate for long periods of time in an unattended mode without forced outages. Such forced outages will result in lower plant availability factors than for attended power plants of the same type. Remote monitoring of plant operations can detect problems, but corrective measures must be taken by opera- tors or maintenance personnel on location. Because the geothermal power plant will operate unattended most of the time, the Unalaska power system must main- tain sufficient back up diesel electric power generation to satisfy all elec- trical loads which cannot be curtailed for several days' duration without hardship to power consumers. Under the proposed design it is anticipated that the forced outage rate for the geothermal plant will not exceed 8 percent of the time. Planned outages for maintenance will occur about 17 percent of the time. Disposing of spent geothermal fluids in the Makushin River or its tribu- taries is precluded by the presence of arsenic in concentrations too high to rely on dilution to provide acceptable in-stream concentrations. Disposal via pipeline to Broad Bay or Driftwood Bay is prohibitively expensive. An injec- tion zone located on the same plateau as the plant site offers the preferred brine disposal option. 6.2 ENVIRONMENTAL AND PERMITTING CONSIDERATIONS No environmental constraints are envisioned within the context of the proj- ect concept proposed in this report. The most significant potential environ- mental impact concerns road and transmission line construction within the Makushin Valley and possible effects on fish resources within the Makushin River MLF8/C43 6-2 and its tributaries. Close coordination with the ADF&G is essential during design and construction. Assuming that such coordination is conducted, and mitigation of potential impacts are incorporated into the construction plans, no serious adverse impacts are anticipated. Permits for the project can probably be obtained in six months to a year assuming that an EIS is not required. An EIS should not be required assuming that the above mitigation measures are undertaken and that the geothermal brine is injected rather than disposed of in surface streams or the ocean. A pre- application agency coordination meeting should be one of the first steps in project development. Air quality modeling indicates that the worst case one hour emissions from the plant will exceed Alaska's strict odor-based standard for reduced sulfur compounds. There is a very good rationale for the ADEC to grant a variance, however, because of the remoteness of the site, ambient conditions natural to the area, and because there would not be a health risk from the anticipated con- centrations of hydrogen sulfide. Cascading uses of the geothermal effluent is problematic due to environmen- tal concerns and to cost. Use of the effluent heat at the plant site is imprac- tical due to its remote location. Transportation of the brines from either Broad Bay or Driftwood Bay via pipeline would be prohibitively expensive and would considerably increase the permitting complexity of the project. At Broad Bay the marshy ground conditions and sensitive environment make aquiculture or horticulture dubious. The best option for effluent heat use rather is to uti- lize the off-peak electrical capacity of the geothermal plant for interruptible uses such as space heating or dispatchable hot water heaters. 6.3 ECONOMIC CONSIDERATIONS A rigorous economic feasibility test indicates that a geothermal development of 5 or 7 MW might be feasible utilizing the Makushin Reservoir. Generation systems which include geothermal capacity in the configuration proposed under Section 5 of this report appear competitive with continued diesel generation except under the assumption of APA's low diesel price trend. However, a deci- sion to proceed with geothermal development must be preceded by a financial MLF8/C43 6-3 feasibility analysis which includes the effects of debt financing on the pro- posed project. This financial analysis will help to determine the optimal plant capacity. greatest Based on the economic feasibility analysis a 7 MW plant offers the cost savings. 6.4 RECOMMENDATIONS 1. MLF8/C43 A financial feasibility analysis should be undertaken as soon as is practical. Load growth in Unalaska is expected to increase at a rapid rate over the next five years. If a geothermal development is to be economically feasible it must utilize the resource before investment in diesel capacity is committed to serve the burgeoning demand. The project concept recommended in Section 5.0 of this report should be the basis for design and construction bids. Other concepts were rejected as either more costly or more environmentally damaging. Final siting and alignment for the Makushin Valley road, transmission line and dock facilities should be determined in the field with input from ADF&G, other interested agencies, and landowners. As soon as a decision to develop is reached, or possibly before if development is considered likely, it would be prudent to begin the environmental approval process. This will avoid a situation in which the narrow development season is missed due to permitting delays. An additional incentive to prompt action in geothermal development is the presently depressed construction and drilling costs. If a decision to develop is reached during the current depressed drilling market it may be possible to obtain a drill rig at a fraction of its book value. This rig could be committed to the project offering considerable saving over day-rate rental. If the financial feasibility appears to narrowly miss justifying the geothermal development, detailed design studies may reveal lower cost solutions to certain project elements than those provided by this Study. Specifically attention should be paid to the Broad Bay pier, 6-4 the Fox Canyon pipeline crossing and the bridges around Sugarloaf. In the absence of better field data, very conservative designs and cost estimates were used in this study. MLF8/C43 6-5 REFERENCES Alaska Department of Natural Resources, Division of Geological & Geophysical Surveys, Public Data File 86-60, 1986. Engineering Geology Technical Feasibility Study Makushin Geothermal Power Project, Unalaska, Alaska, 2 Vi05 plates. Alaska Economic Report, 1986. Beck, R.W. and Associates, Inc., 1985. Electric Rate Study for the City of Unalaska, Alaska, various pages. » 1986. City of Unalaska, Alaska Load Forecast and Power Market Analysis (preliminary), 54 pp. » 1987. Load Forecast and Power Market Analysis, City of Unalaska, various pages, appendices. Burton, City of Unalaska, 1986. Dames & Moore, 1985. Aleutian Regional Airport, Project Documentation--Report for the City of Unalaska, pp. 44-45. Denig-Chakroff, D., 1985. Unalaska/Dutch Harbor Reconnaissance Study Findings and Recommendations--Report for the Alaska Power Authority. Denig-Chakroff, D., Reeder, J.W., Economides, M.J. Development Potential of the Makushin Geothermal Reservoir of Unalaska Island, Alaska, 5 p. Economides, M.J., Morris, C.W., and Campbell, D.A., 1985. Evaluation of the Makushin Geothermal Reservoir, Unalaska Island. Environmental Defense Fund, 1986, ELFIN Generation Model, Version 1.3 (computer software). Fuhs, Paul, Mayor of Unalaska, Personal communication to Jim Henning. Huner and Brown, 1985. Mesquite Group, Inc., 1987. Cost Estimates and Schedules for Two Geothermal Drilling Scenarios on the Eastern Flank of Makushin Volcano on Unalaska Island, various pages. Morrison-Knudsen Company, Inc., 1981. Geothermal Potential in the Aleutians: Unalaska, p. 2-5. Reeder-J.W., Denig-Chakroff, D., and Economides, M.J., 1985. The Geology and Geothermal Resource of the Makushin Volcano Region of Unalaska Island, Alaska. Republic Geothermal, Inc., 1982. The Unalaska Geothermal Exploration Project, Phase 1A Final Report, 65 p., appendices, 3 plates in pocket. MLF8/CR » 1983. Unalaska Geothermal Project, Phase 1B Final Report Volume l, 160 pp., appendices. » 1983. Umalaska Geothermal Project, Phase 1B Final Report, Volume 1-A, plates. » 1983. Unalaska Geothermal Project, Phase 1B Final Report, Volume 2, appendices. » 1983. Unalaska Geothermal Project, Phase 1B Final Report, Volume 2-A, plates. » 1984, The Unalaska Geothermal Exploration Project, Phase II Final Report, various pages, appendices. » 1985. Unalaska Geothermal Project, Phase III Final Report, 1 V. » 1985. Unalaska Geothermal Project, Executive Final Report. Schultz, N.C. Engine Power, 1986. Sundberg, K.A., Hahn, B.L., Vining, L.J., et al., 1986. Preliminary Environmental Analysis of the Unalaska Geothermal Power Project, 1 V., plates. MLF8/CR