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HomeMy WebLinkAboutBethel Area Power Plan Feasibility Assessment; Appendix C; Energy Resources & Technologies 1984 Alaska Power Authority LIBRARY COPY Bethe | APPENDIX C Energy Resources and Technologies Bethel Area Power Plan Feasibility Assessment APPENDIX C ENERGY RESOURCES AND TECHNOLOGIES DRAFT Prepared for Harza Engineering Company and the Alaska Power Authority by Herb A. Bartick Ralph R. Stefano of Stefano and Associates, Inc. Anchorage, Alaska Draft April 1984 Chapter II. III. Iv. bo TABLE OF CONTENTS INTRODUCTION DESCRIPTION. OF ENERGY RESOURCES Diesel Fuel Oil, Coal Resource Natural Gas Resource Solar Resource Geothermal Resource Wind Resource Peat Resource Wood Resource Conservation DESCRIPTION OF ENERGY SUPPLY TECHNOLOGIES Diesel Generating Units Steam Turbines Gas and Oil-Fired Combustion Turbines Organic Rankine Cycle Tidal Energy Wave Energy-: - Ocean Current Energy Ocean Thermal Energy Solar Power Generation Solar Photovoltaic Systems Geothermal Energy Nuclear Energy Direct Combustion: Electric Heating Heat Pumps Solar Heating Geothermal District Heating District Heating (Steam/Hot Water) Cogeneration Systems Combined Cycle Systems Coal Gasification Combined Cycle Wind Turbines Fuel Cells EVALUATION OF ENERGY TECHNOLOGIES Introduction Evaluation Criteria Evaluation Results Chapter v. VI. APPENDIX APPENDIX APPENDIX APPENDIX TABLE OF CONTENTS (Cont'd) SELECTION OF ENERGY TECHNOLOGIES Introduction Economic Evaluation Technology Selection CONCEPTUAL DESIGNS, COSTS, AND ENVIRONMENTAL CONSIDERATIONS Introduction : Conceptual Designs of Coal-Fired Steam Plants Conceptual Designs of Fuel Cell Power Plants : Cost Estimates Environmental Considerations REFERENCES EXHIBITS c-1. Cc-2 C=3 c-4 - Coal Resource Assessment - Fuel Cell Assessment - Wind Resources and Technology - Conservation Assessment -ii- viI-1 vVI-1 vVI-10 VI-16 VI-17 Table No. II-1 II-2 II-3 Iv-1 IV=2 IV=3 Iv=4 IV=-5 Vel V=2 VI-1 bp LIST OF TABLES Title Diesel and Heating Fuels Used in the Bethel Area Analysis of Selected Alaska and Western Coals United States Peat Resources Technology Evaluation Criteria Rating System : Ranking of Electric Power Technologies Ranking of Heating Technologies Ranking of Electricity and Heating Technologies Ranking of Support Technologies Preliminary Selection of Candidate Technologies Economic Evaluation of Electric Power Technologies Economic Evaluation of Heating Technologies Ecomomic Evaluation of Electricity and Heating Technologies Economic Evaluation of Support Technologies Emission Standards -iii- Pag e II-3 II-5 II-8 Iv-3 Iv-5 IV-6 IvV-7 LIST OF EXHIBITS Exhibit No. Title 1 Distillation Range of Petroleum Products from Crude Oil 2 Electric Power Technology Evaluation 3 Heating Technology Evaluation 4 Electricity and Heating Technology Evaluation 5 Support Technology Evaluation 6 Cost of Power Evaluation Criteria 7 Optimal Coal Plant Capacity, Combined Coal and Diesel Generation 8 Proposed District Heating System - Bethel 9 Typical Coal-Fired Steam Plant Specifications, 10 MW Capacity . 10 Flow Diagram - Coal Alternative 1 Tl Flow Diagram - Coal Alternative 2 12 Flow Diagram - Coal Alternative 3 13 Flow Diagram ~ Coal Alternative 4 14 Flow Diagram - Coal Alternative 5 15 Flow Diagram - Coal Alternative 6 16 -Flow Diagram - Coal Alternative 7 17 Coal Plant Operation Parameters 18 Conceptual Layout - Coal Plant 19 Schematic Diagram - Fuel Cell Plant 20 Conceptual Layout - Fuel Cell Plant 21 Fuel Cell Plant Performance -iv- vy Exhibit No. 22 23 24 bh LIST OF EXHIBITS (cont'd) Title Heat Rate for Fuel Cell Power Plant Coal Plant Costs Estimated Construction Cost of Fuel Cell Plant Chapter I INTRODUCTION The purpose of this assessment of energy resources and technologies is to determine the most attractive generating facilities, excluding conventional hydroelectric plants, for meeting the projected 2002 energy needs for the Bethel study area. The Bethel study area comprises the City of Bethel and 12 villages located within 50 miles of Bethel. Hydroelectric alternatives are discussed in Appendix DP. Currently, electrical power in the study area is supplied by numerous diesel generators. Fuel oil is used for space and water heating. Energy needs over the 20-year study period are projected to increase by nearly 32 percent, with ‘heating requirements being about ten times greater than electrical requirements, This assessment of non-hydro energy resources and tech=- nology is presented in six chapters and four appendices. Chapter II presents a general discussion of the energy resources that are available in, or could be imported to, the Bethel study area. The resources discussed are diesel fuel, coal, natural gas, solar, geothermal, wind, peat, and wood. Conservation of energy is also-addressed in this chapter. Chapter III contains a description of the technologies available to develop the resources. Current technologies and those in the research and development stage are addressed. The availability, reliability, cost, performance, and environmental impacts of each technology are described. Chapter IV presents a preliminary evaluation of the tech- nologies.) identified in Chapter III. - The technologies are divided into four categories: electric power, heating, elec- tricity and heating, and support. An objective rating system is developed to compare the technologies. The rating system includes technical, cost, social, and environmental factors. Based on the ratings, the most attractive technologies are evaluated further in Chapter v. Chapter V presents an economic evaluation of the most attractive technologies. The technologies are compared on a unit cost of energy basis. Based on a unit cost comparison, the two most-promising technologies (power plants) are selected as the primary components in formulating non-hydro energy supply plans. bp Chapter VI presents the detailed description of the most promising power plants. Conceptual designs, cost estimates and environmental considerations are included. Detailed Appendix Appendix Appendix Appendix Cc c Cc c assessment of four selected technologies presented in the appendices: 7: , mW bh Coal Resource Assessment Fuel Cell Assessment Wind Resource and Technology Conservation Assessment I-2 are ‘Chapter II DESCRIPTION OF ENERGY RESOURCES Potential energy resources, excluding hydropower, that may be used in the Bethel study area are: diesel fuel, coal, natur= al gas, solar, geothermal, wind, peat, wood, and conservation. Each of these resources is described in the following para- graphs. Hydropower resources are described in Appendix D. Diesel Fuel Oil Diesel fuel oil is that portion of the distillation curve from 25 to 65 percent by volume of a barrel of crude oil or within the temperature range from 375° to 680°F (Exhibit 1). The diesel fuel and stove oil supplied to Bethel by Chevron ranges from 329°F to 507°F for the diesel and from 501°F to 635°F for the stove oil. Other properties can influence the fuel performance in a specific application. -In the diesel fuel oil classification, many properties are considered significant by the American Society for Testing Materials, such as cetane number, viscosity, carbon residue, sulfur content, flash point, ash, and copper-strip corrosion. The specification of a parti-= cular fuel or the selection of a special grade of fuel will require various allowable limits on these fuel properties. The economics of operation and the exacting demands of a diesel engine can narrow or broaden the specification limits of the petroleum fuels it can use. Diesel Fuel Oil Characteristics/Performance The characteristics of diesel fuel affecting the operation of diesel engines are described in the following paragraphs. .The most significant property which determines the perfor=- mance value of diesel fuels is its gravity. Fuels having a high API gravity are more volatile but have lower volumetric heat of combustion. Lower gravity fuels will have higher volumetric heats of combustion. The ignition quality of the fuel depends on both its ther- mal stability and on its oxidizability. This quality is usually expressed as a cetane value which is the ratio of cetane (Cj6H34) and alpha methyl napthalene (Cj1H19)- The cetane num- ber is the percentage of cetane in the hydrocarbon mixture which will provide good ignition characteristics. Diesel fuels of high cetane number differ from those of lower cetane number by having a shorter ignition lag when injected into the diesel- engine cylinder. High-cetane fuel also is ignited at lower II-1 db: compressed~air temperature than low-cetane fuel. These charac- teristics result in the difference in the performance of high- cetane and low=-cetane fuels in operating engines. The viscosity of the diesel fuel is important since it affects the amount of power required to operate the fuel pump. With lighter viscosity fuels, the pump clearances have to be closer to seal against leakage. The higher viscosity fuels create pressure loadings which must have an adequate bearing surface to permit the injection of the fuel. Further, the vis- cosity has an influential: effect on the size of the fuel drop=- lets sprayed into the cylinder. The volatility of diesel fuels must be controlled to assure low smoke and good performance. Generally, in high-speed en- gines the lower the volatility, the better, since too volatile a fuel will cause detonation. In addition, a high volatile fuel will give rise to gassing or vapor-lock problems in the fuel injection system. However, if the volatility is too low, an ignition delay will be introduced because a longer time is re- quired for the fuel droplet to go from the liquid to the gaseous state. The volatility of the fuel has a major influence on the carbon residue and its control. In small, high-speed engines, the carbon residue must be low since the combustion time is short. However, in larger, slow-speed engines with greater time for combustion, the carbon residue can approach much higher values. : “= oo eee The sulfur content of the fuel is an important. parameter since it contributes to engine wear and component corrosion. The amount of heat that results from using higher sulfur fuels depends to a large extent upon the engine operating conditions. The cloud point on diesel fuels is critical in cold weather operation because this indicates the formation of wax crystals which would plug filters and fuel lines, thus restricting . the flow of fuel to the engine. . Diesel and Heating Fuel Oil Properties. Table II-1 shows the properties of diesel fuel and heating fuel currently being used in the Bethel area. II-2 Table II-1. DIESEL & HEATING FUELS USED IN THE BETHEL AREA Diesel - Diesel / Co and Heating and Heating Tests Fuel No. 1 Fuel No. 2 Gravity . 43.7 36.0 Flask, Pensky Martens 44(112) 67(153) Kinematic Viscosity at 40°C 1.4 2.2 Pour Point, °C(°F) -45(=-50) -16(+3) Cloud Point, °C(°F) -40(-40) -12(+10) Sulfur Mass. 0.3 0.10 Corrosion 3 Hrs. @100°C 1 1A Sediment & Water, Vol. % 0.05 0.05 Carbon Residue (10% Bot.) 0.10 0.10 Ash, Mass % 0.01 0.01 Color, ASTM — 0.5 1 Cetane Number2/ 46 48 Btu/Pound, Gross 19,800 19,680 Btu/Gallon, Gross _ 134,900 137,800 - ASTM Distillation, °C(°F) 10% Recovered 165(330) 261(502) 50% Recovered 200(393) 291(556) 90% Recovered - 246 (475)}:—-+— - 320 (608) End Point 264(507) 335( 635) Vapor Pressure @37.8°C - - a/ Not applicable to heating fuels. It should be noted that the diesel fuel No. 1 and heating fuel No. 1 are identical, as are diesel fuel No. 2 and heating fuel No. 2.(1)2/ Coal Resource There are no known coal resources within the immediate Bethel area. Hence, sources elsewhere in Alaska and from areas outside of Alaska must be considered. A detailed analysis of potential coal sources, costs, and handling is described in Appendix C-l. A summary of the potential resources is provided below. 1/ Numbers in parentheses refer to references at end of text. II-3 H Alaskan Coal Sources With 1.9 trillion tons of indicated or inferred coal reser- ves, Alaska has the majority of the U.S. coal resources. Only a tiny fraction of this potential resource has been developed or is ‘under active consideration for development. Appendix C-1l summarizes the physical and economic characteristics of Alaskan coal resources. Of the sources listed, four appear to be most promising for the Bethel region. These are Nenana, Chicago Creek, Kobuk River, and Cape Beaufort. Their characteristics are given in Table II-2. Outside Coal Sources Four major coal sources exist on the West Coast of the Lower 48 and Canada. These are: Utah, Powder River Basin (Wyoming/Montana), and Prince Rupert and Vancouver, British Columbia (Roberts Bank). Each source could supply commercial quality thermal coal to major port cities for shipment to Bethel. Bethel's requirements are small relative to the mill- ions of tons these sources produce annually.. The relative at- tractiveness of these coals for Bethel depends, therefore, on their quality, and their cost to mine, transport, and handle. - Table II-2 indicates that any of these coals are of adequ- ate quality for electrical generation. The Powder River Basin, Nenana, and Chicago Creek coals' relatively lower heat content is a disadvantage for space heating. However, this disadvantage is offset by the advantage of their relatively low cost. Utah and the British Columbia coals are available in washed form (size 1-5/8 x 3/8 inches). . This is an advantage in reducing coal dust and possible water pollution problems. Natural Gas Resource The last exploratory drilling for natural gas resources in the Bethel region was jin 1961, when a well was drilled near Napatuk Creek. Results of this activity proved to be inconclu- sive. A long period of inactivity ensued. In recent years, the Calista Corporation has further evaluated the potential of gas resources in the region. Based primarily on geologic and geo- physical survey data, Calista believes they have identified what might be a "Bethel Basin" natural gas resources. The results of Calista's work to date are encouraging. Nevertheless, no definite determination of the location and extent of the resource, its depth and quality, or even its exis- tence has been made. Calista has stated an intent to further explore and, if feasible, develop the natural gas resource. The timing of such development is not presently known and may not LI-4 S-II b Area/Field Nenana, AK Chicago Creek, AK Kobuk River, AK Cape Beaufort, AK Cape Beaufort, AK Utah Powder River Basin Prince Rupert, B.C. Vancouver, B.C. Table II-2 ANALYSIS OF SELECTED ALASKA AND WESTERN COALS Rank Subbituminous Lignite Bituminous Bituminous Bituminous Bituminous Subbituminous Bituminous Bituminous Moisture Content . (percent) 17.8-27.1 33.8 10.5 3.0-5.9 0.8-9.9 7.0 24.5 1.2 10.0 Volatile Matter (percent) 33.3-42.0 39.9 29.0 28.8-40.1 31.4-35.6 42.0 31.8 22.5 24-29 Fixed Ash Carbon Content (percent) (percent) 27.1-35.3 3.5-13.2., 19.2 Tel 52.9 7.6 47.8-58.0 4.1-11.6 | 52.6-56.1 2.5-15.0 46.0 7.0 40.0 3.6 61.0 15.0 55.5-58.5 16.0 Sulfur Heating Content ~~ _Value (percent ) (Btu/1b. ) 0.1-0.3 7,570-9 ,43 - 6825 0.4 10,534 0.2-0.3 11,910-14,0 12,400 - 0.7 0.3 9,300: 0.4 12,400°° 0.25 11,000 occur for a number of years, if ever. Therefore, in the absence of actual exploratory well data identifying a proven gas re- source, natural gas was not considered as a potential energy source. Importation of natural gas, in either a liquified or gase- ous state, was deemed to be infeasible because of the difficul- ties in transportation, handling, and storage. Solar Resource Solar energy in Bethel is a limited resource. The amount of the resource available varies with the seasons. Average sunlight hours per day in Bethel range from a minimum of 5.5 in ’ December, to a maximum of 19.3 in June, the yearly average being less than 12.5. Further, due to the northern latitude, the intensity of the solar radiation is considerably less than that in areas closer to the tropics. The minimum intensity at Bethel is 48.7 Btu/ft2 during December and a maximum of 1518 Btu/ft2 in June. As an example, this can be compared to 903.0 and 2186.5 for a minimum and maxi- mum in San Diego, California. Unfortunately, the time of year for which power demand is greatest is when the amount of the resource available is at a minimum. Therefore, it appears that the most usable of solar technologies are those which include energy storage. - Geothermal Resource Many areas in Alaska have potential for the development of geothermal power. Identified sources are distributed throughout the state, most areas being hot springs or volcanic activity. Known sites with temperatures in the range of 300°F and higher are located on the Arctic Slope, the Fairbanks area, and in Southeast Alaska. Variables that influence the potential devel- opment of a site include the following: location of site in relation to market, depth of source, temperature, flow rate, and end use (2). Known geothermal sources close to Bethel are sites at Tuluksak River and Oafer Creek... The Oafer Creek site is a hot spring with a temperature of 150°F and flow rate of 850 gpm. This could provide sufficient energy to fuel a 500 kilowatt organic Rankine cycle system. Temperature and flow data are not available for the Tuluksak River site, but it is also a hot spring. Both sites are approximately 50 miles east of Bethel. Due to this distance and the relatively small power potential, these sites are not considered economical sources of geothermal power. II-6 i Wind Resource ~ The wind resource of the Bethel area ranges from very good in the southern part (or the vicinity of Bethel itself) to poor towards the northeastern part. The resource is strongest through autumn, winter and spring. There is little data available over most of the study area. Adequate data is available only for Bethel, which is centrally located -within the large, lowland plain of the Lower Kuskokwim Delta. Since this terrain is simple, the Bethel data is ade- quate for assessment of the resource. The data and assessment of the wind potential for the study region are detailed in Appendix C-3. . Peat Resource Peat is a heterogeneous material of partially decomposed plant matter and inorganic minerals that has accumulated in water-saturated environments over a- period of several thousand years, Since the formation of peat is similar to the basic process of coal formation, peat is often referred to as "young coal", Most peat deposits are less than 5000 years old, whereas established subbituminous or bituminous coal deposits have taken from 50 to 100 million years to develop (3). Peat resources occur throughout the world, with the largest acreages of peatland located in the Soviet Union (228-370 mill- ion acres), Canada (34-250 million acres), and the United States (53-94 million acres) (4). Resource estimates are highly vari- able due to the uncertainty and differences in reporting meth- ods. The majority of domestic U.S. peat resources are located within three geographical regions; Alaska, North Central, and Atlantic Coast. As shown in Table II-3, the largest domestic resource is, by far, found within Alaska (3). , Peat is harvested in a number of ways, including dry meth- ods, hydraulic methods, and combined methods (5). All current methods to produce fuel peat are dry methods, in which the peat deposit is drained prior to harvesting. Two common dry methods are the milled peat method and the sod peat method. The milled peat method begins with the milling of the surface layer of peat to a depth of about one-half inch. Once the top of the milled layer is air-dried to 65 percent moisture content (usually with- in a day), it is turned over to dry the underside of the surface layer. The sod peat method is based on air-drying blocks of peat which have been cut from the peat bog and stacked on the surface to dry. This latter method seems to have the greatest potential for use in Alaska. II-7 by Table II-3 UNITED STATES PEAT RESOURCES State , . Acres Quantity?/ (Millions) (Billion Tons) Alaska 27.0b/ 61.7 Minnesota 7.2 16.5 Michigan 4.5 10.3 Florida 3.0 6.9 Wisconsin 2.8 6.4 Louisiana 1.8 4.1 North Carolina 1.2 2.7 Maine 0.78 1.8 New York 0.65 1.5 Hawaii 0.48 1.1 Georgia 0.43 1.0 Indiana 38 9 Massachusetts 235 8 Virginia 31 7 Washington 220 . 5 All Other States . 1,50 -__ 3.4 Total 52.6 "120.3 a/ Assumes peat dried to 35 percent moisture by weight. Deposits are 7 feet thick, and have a bulk density of 15 lbs’ per cubic foot. b/ Excludes peat in permafrost areas. A hydraulic peat. mining system consists of four steps: dredging of raw peat from an unprepared bog, the preparation of peat slurry, the pumping of slurry to a dewatering plant, and mechanical dewatering of the slurry to an acceptable moisture content. The first three steps are technically and economically . feasible, but the mechanical dewatering operation is technically unproven for use on fuel peat production. Historically, higher production capacity systems could only lower the peat moisture content to approximately 70 percent. II-8 - b . ) The combined method would include hydraulic collection, pumping to firm ground, sodding and spreading of sods to drying fields, plus drying, collecting, and stockpiling as in the sod peat method. Some areas in the interior of Alaska have charac- teristics that would favor this method. Energy conversion of peat is commonly done by direct com- bustion, but further processing of the peat is sometimes re- quired. Four methods of direct combustion of peat are: pulver- ized firing, cyclone combustors, grate firing, ‘and co-firing with other fuels. The Department of Energy (DOE) has sponsored a study of the possible use of peat/coal blends for electrical generation (6). The study concluded that blends containing 50 percent peat would require relatively minor design changes from coal firing practice, although the firing of peat alone calls for substantially different design approaches, Peat processing includes briquetting, wet carbonization, biogasification, and gasification. The wet carbonization and biogasification processes do not require dewatering of the peat. Briquetting and gasification processes require that the peat he dewatered below 50 percent moisture content (5). Peat has the potential for use as a fuel for both thermal generation of electricity and direct combustion heating. Its usefulness, however, depends on four key properties: degree of decomposition, bulk density, moisture content, and heat value (5). Degree of decomposition is the main parameter, since it controls the bulk density and heating value. Generally, a high- er degree of decomposition indicates good fuel peat potential, provided that other parameters are positive. Weakly decomposed peat is unsuitable for fuel peat production. In Northern cli- mates, medium decomposed peats may be suitable for fuel pur- poses, The bulk density of peat is an important parameter as it affects the transport and handling costs, as well as the re- quired fuel storage capacity. Aged, medium decomposed peat is denser than young peat. Aged peat is more economical to trans- port, contains less impurities, and.is easier to handle in con- veyors and storage bins, The density of good fuel peat exceeds 22 lb/ft3, compared to a bulk density of about 50 lb/ft? for coal. II-9 bb The most difficult technical obstacle to utilizing peat as an energy source is reducing the large water content. Natural peat is approximately 90% water. In this condition, the heat of combustion of the solid matter is less than the heat of vapori- zation of water. A reduction in the water content is necessary -to achieve an acceptable feedstock for energy utilization. The currently used commercial harvesting processes rely on solar and convective drying, a slow and-uncertain process that limits harvest to a period that is often very short. It must be recog- nized that mechanical dewatering methods can currently reduce the moisture content down to about 70% and that the foreseeable development in that area will not provide fuel directly applica- ble to combustion or gasification. About 35% moisture’ content is desireable, The heat value of peat is directly related to the moisture content, because the water to be evaporated requires part of the heat from combustion. A nominal heating value for 35% moisture content peat is 6000 Btu/lb. Heat values for coal range from about 6000 to 13,000 Btu/1b. Because of the lower density and heat value of peat as compared to coal, economic use of peat is likely to be re- stricted to those regions with local peat resources (6). An estimate of the peat. resources of Alaska was made in 1980 for the Department of Energy (4). A map-derived inventory showed a potential fuel peat-occurrence throughout the Yukon- Kuskokwim Delta, primarily to the west of Bethel. However, this resource has yet to be assessed through field investigation. Further, the delta is generally underlain by thin to moderately thick permafrost (See Appendix B). Peat within the permafrost regions is not considered a viable resource due to the overwhel- ming problems associated with its extraction (3). Based on the lack of a proven local resource, and the like- ly problems associated with harvesting the resource, peat was not considered in the formulation of energy supply plans. How- ever, should a proven local resource be discovered in the fut- ure, there would be a potential for using peat as a home heating fuel, or as a blended power plant fuel. Wood Resource The Bethel study area is within an area. of sparse vegeta- tion, with little or no timber resources (See Appendix B). Potential sources of imported wood are the Pacific Northwest, Southeast Alaska, or the forests of Interior Alaska (7). II-10 by Four characteristics of wood govern its use as a fuel resource, These are: High moisture content at harvest time Oven=-dry bulk density of 22-32 1b/ft3 Oven-dry heating value of about 8,600 Btu/lb Low sulfur content and high particulate emission con- pared to fossil fuels. 0000 Wood is commonly air-dried prior to use for heating, but the moisture content is still quite high, and the heating value low, compared to oven-dried wood, Air-dried wood has a bulk density of about 40 1b/ft3 and a heating value of 4,000 Btu/1b. Compared to coal, which has a bulk density of about 50 lb/f£t3 and a heating value ranging from 8,000 to 12,000 Btu/l1b (8), wood is quite bulky in relation to its heating value. Consequently transportation and handling of wood is more expen- sive than coal. Burning of wood does not produce sulfur dioxide pollution, but it does emit more particulates than fossil fuels because of incomplete combustion (7). Wood fuel can.be used for both electric power generation and space heating. For power generation, wood can be burned directly in solid form, or it can be gasified. Wood gasifica- tion is a sophisticated process of combusting wood in solid form to produce carbon monoxide and hydrogen, both combustible. In solid form, wood can be burned to drive a steam turbine. Wood gas, after cleaning, can be used to drive internal combustion engines. Wood for power generation in the Bethel study area is not deemed to be feasible at this time, due to the large quanti- ty of wood to be handled relative to its low heating value. Wood currently provides about two percent.of the space and water heating needs of the Bethel study area, and about 20 per- cent of the cooking needs (See Appendix A). Harvesting, of driftwood is quite common. The banks of the Kuskokwim River slump into the river, carrying trees and other vegetation down- stream. The trees die and are washed up along the shore, where the driftwood is then gathered by local residents. Upriver villages,-such as Tuluksak, Akiachak, Akiak, and Kwethluk, uti- lize limited standing timber resources adjacent to the village. Downriver villages, particularly Eek and Tuntutuliak, depend solely upon gathered driftwood for their wood fuel. II-11 b Since firewood gathering is a subsistence-type activity, it is difficult to accurately assess the amount of the resource that will be used in the future. Because of the limited local resource, any substantial increase in wood fuel use in the fut- ure would have to’ tap other sources. As mentioned before, the high bulk of wood relative to its heat value makes transport and handling expensive. Hence, it is not deemed to he feasible at this time to import wood from Southeast Alaska or the Pacific Northwest, However, sources from the Interior Alaska forests may have potential for the Bethel study area. The Kuskokwim Forest Survey Unit is one of ten Interior Alaska Forest Survey Units. The Kuskokwim unit contains about 2.6 million acres of commercial forest, about ten percent of the total Interior resource (7). Note that “commercial" is based solely on a sustained yield of 20 ft3 per acre per year, with no economic basis, Of this Interior commercial timber, about 64 percent is white spruce, 21 percent is birch, and 15 percent asper, balsam poplar, and other species. In addition to being - the most plentiful, white spruce is the most traditional and preferred species for fuel. The key factors controlling the economics of wood harvest- ing are the. value of the wood, the length of road or trail that must be constructed, and the transport distance of the harvested wood, When all three factors are considered for Interior Alaska, timber resources adjacent to rivers are best because of access by barge . The Kuskokwim River is navigable by 18-foot draft. ocean-going vessels from the mouth upriver 65 miles to Bethel. Shallow-draft vessels (4 feet) can travel up to river mile 465, about 65 miles upriver from McGrath (7). Hence, the Kuskokwim unit could potentially provide wood fuel resources for the Bethel region. At present, there is no formal infrastruc- ture in place to harvest and distribute this wood. A study prepared for the Kuskokwim Native Association in 1981 (9) con-. cluded that a sufficient quantity and quality of timber re- sources exist to “supply .the lumber demand of the’ Kuskokwim villages and Bethel, as well as support a timber.export facili~ ty. However, the timber land ownership is complex, encompassing Federal, State, and native lands (7). Timber harvesting has well-known environmental impacts. The loss of vegetative cover is conducive to soil erosion, which degrades water quality. Also, loss of habitat due to timber harvesting will have negative impacts on terrestrial species. These impacts are significant in light of the corresponding impact on subsistence resources. II-12 Considering the questions of environmental impact and land ownership, and the lack of an in-place system for economically harvesting and distributing wood fuel resources, this study has assumed that the present level of wood use will prevail through- out the 20-year planning period. However, future studies should look at the potential for utilizing the Interior - forest wood resources to provide or supplement space heating for the region. Also, the possibility of a local-market only lumber mill at Bethel, with byproduct wood used for space heating, should be explored further. Wood is a renewable resource, and direct combustion of wood for space heating is an appropriate technol- ogy. Conservation Conservation comprises structural and non-structural meas- ures to conserve electricity and other forms of energy. They are applicable to the residential, commercial, and industrial energy sectors. They can be considered to be an energy re=- source, since conserved energy replaces energy that would other- wise be provided by some other resource. Conservation measures are now being implemented throughout Alaska, primarily in the residential sector. The present study shows that energy uti- lized in the Bethel region for space heating is about ten times that consumed for’ electrical use. Hence, those measures which conserve space heating energy have been considered. Structural conservation measures that could be employed in the region are weatherstripping and caulking, ceilng insulation, and storm doors and windows. Other measures, such as wall and floor insulation, were not considered because these measures are difficult and potentially expensive to "retrofit" into an exist- ing structure. Non-structural measures, such as turning off unused lights and equipment, load management, and changing work and living styles, are difficult to quantify and were not con=- sidered at this level of study. Appendix C-4 to this appendix describes an assessment of the application of conservation measures to a "standard" Bethel home. The analysis showed that, with an investment of about $3,000 in structural conservation measures for the home, the resulting cost of energy that is saved will pay back the invest- ment in less than six years. II-13 Dh Chapter III DESCRIPTION OF ENERGY SUPPLY TECHNOLOGIES A number of energy supply technologies were considered for use in the Bethel area. The technologies considered include: diesel generation, steam turbine generation, oil and gas com- bustion turbines, organic Rankine cycle systems, tidal energy, wave energy, ocean current energy, ocean thermal energy conver- sion, solar power generation, solar photovoltaic systems, geo- thermal energy, nuclear energy, cogeneration system, combined cycle systems, coal gasification combined cycles, wind energy, fuel cells, solar heating, passive solar technologies, geother- mal heating technologies, and direct combustion heating techno- logies. These technologies were evaluated for possible use in the’ energy supply plans. The evaluation examined each technology to determine its technical, environmental, and economic feasibility to supply energy to the Bethel region. In addition, some tech- nologies that are in early stages of development were critically reviewed for commercialization potential within the time frame of the study. Diesel Generating Units Diesel generating units are internal combustion engines directly connected to a generator producting alternating current (AC) power. These units are constructed as an integral system. This type of power generation is widely used in Alaska due to its high reliability, ease of maintenance, and low capital costs. However, the high cost of fuel and its transportation, along with low efficiency of the units, makes this method of power generation extremely expensive (1,2,10). The performance characteristics of these. power’ systems. -| range from efficiencies of 18 percent (19,000 Btu/kWh) for small units .(5-30 kW) to about 38 percent (9,000 Btu/kWh) for large units (approximately 1 MW). The performance is worse. in the remote areas of Alaska due to poor maintenance. When waste heat recovery equipment is added to the basic diesel-unit, the ther- mal efficiencies can approach 40 to 42 percent (8500 Btu/kWh). The existing 2.1 MW diesel generators in Bethel have a thermal efficiency of about 31 percent (11,000 Btu/kWh). The reliability of diesel units is high in that they will carry their designed loads on a continuous basis if properly installed and maintained. If the unit is used as a standby peaking unit, it is very reliable and can be put on-line within TII-1 yb a few minutes. The higher reliability of low speed (900 RPM) diesel units is advantageous for rural areas. However, because of lower initial capital costs, most units now operating in Alaska are in the higher speed range of 1800 RPM. The cost of a diesel generation unit varies considerably over the range of equipment. Current costs range between $350 and $1200 per kW installed. : The availability of diesel units is such that the units are "off-the-shelf" items stocked by many manufacturers. The lead times for small units are extremely short. However, larger units in the megawatt range will require some time from initial order to the commencement of service. The environmental considerations of diesel power are fuel related. These are: fuel tank installations require integrated spill protection, which may be difficult in remote locations; and fuel handling and transfer protection devices. Steam Turbines Conventional steam plants consist of a fuel-fired boiler for generating steam which, in turn, drives a turbine-generator. The steam leaving the turbine is condensed and pumped back to the boiler where it is revaporized into high pressure steam to repeat the cycle. The fuel used in the boiler-is either coal, oil, or natural gas depending on the availability and cost of the fuel resource (1,2,11). At the end of 1977, there were a total of 951 steam elec=- trical plants operating in the United States, with approximately 320 more to be built by the year 2000. The trend in steam plant construction is to go to larger sizes with locations near the coal source. Further, boiler plants are being designed to have multi-fuel capability which will allow them to use either coal, oil or gas.. The changeover from one fuel to another does not change the overall plant efficiency substantially, as the heat rate remains about the same. If the plant is initially designed for multi-fuel capability, changeover is relatively inexpensive. However, retrofitting an existing gas or oil-fired boiler to use coal can be prohibitively expensive, in some cases approaching the cost of a new facility. The performance characteristics of these types of power plants in the United States range from less than 1000 to more than 3,000,000 lb/hr steam, and most (about 65 percent) range from 100,000 lb/hr to 1,000,000 lb/hr. Furnaces in today's units generally are larger than those in comparable boilers built only a few years ago, allowing greater fuel flexibility. III=-2 6): Most turbines used in U.S. steam electric plants are rated from 100 to 900 MW, with about 40 percent rated from 500 to 700 MW. The current average thermal efficiency of steam electric plants is about 28 to 37 percent, using steam pressures from 600 to 4500 psi and higher, with steam temperatures from 710 to 1,000°F as practical design limits. Steam electric plants have heat rates of 9,300 to 12,000 Btu per kWh with the average be-~ tween 10,000 and 10,500 Btu per kWh. In establishing the per- formance of a steam electric plant, the heat rate is generally preferred over thermal efficiency because it is more directly applicable to fuel performance. Using waste heat from non-condensing units for space heat- ing or for process heat greatly increases the heat rate of the plant. Non-condensing steam turbine generators have a heat rate as low as 4,500 Btu/kWh (thermal efficiency of 75.8 percent) when credit is given to waste heat for process purposes. The reliability of a steam power plant is high. This type of plant provides the base load for the bulk of the power pro- duced in the world and is considered to be the most reliable system now in existence. This type of plant has a long history and other plant types are usually compared to steam plants in order to gain a reliable perspective of the new plant's reliabi- lity. . The cost of a steam turbine generator, especially in the larger sizes (100-1000 MW), is about $2100 per kW and for smalli- er plants (10-100 MW), the cost is about $3100 per kW. This cost is considerably higher than in the Lower 48 due to higher ‘ labor costs in construction and added freight costs. These factors affect the steam generating plant disproportionately because of the higher share of site construction labor relative to total capital costs. Further, in Alaska steam plants must be totally enclosed and currently use low: grade coal (8,000 Btu/lb).. Therefore, higher unit investment cost are encountered due to the need for ash control and related environmental pro- tective equipment. : The availability of steam power plants for large base loads is dependent upon size and configuration. Generally, these large plants are custom designed, with delivery times of the major components (boilers, turbines) ranging from three to five years. Small plants ranging up to 10 MW can be obtained within a three-year period. The University of Alaska's 3 MW plant at Fairbanks was designed and constructed in two years. Plants of 20 MW or more many require three to five years and sometimes longer to construct. For this reason, contractual commitments are usually made to turbine and boiler manufacturers before the III-3 vo start of construction in order to take delivery of equipment simultaneously with the completion of foundations. Due to the rapid escalation of construction costs, the lead time required for this type of plant is a critical design item. The environmental considerations for a steam plant are: stack emissions, flyash, dust, ash disposal, and acid leaching. Systems to control dust, sulfur oxides, nitrogen oxides, and flyash have been designed and installed in power plants in Alaska. The University of Alaska (Fairbanks) plant is a typical example of a plant that meets all EPA regulations. Federal legislation and government policies have a major influence on the selection of fuels for use in a steam power plant. Gas or oil have lower sulfur and ash contents than coal and thereby avoid sulfur oxide and particulate emission pro- blems. Energy policies, however, strongly encourage the use of coal, which is in more plentiful supply in the United States (See Appendix C-l). Therefore, a number of plants are convert- ing or reconverting to the use of coal as a fuel source. Gas and Oil-Fired Combustion Turbines Gas and oil-fired combustion turbines. are classified as Brayton engines using either gas or oil in the turbine combus- tion chamber. The exhaust from the turbine drives both a com- pressor and an electric generator (1,2,12). Atmospheric air is drawn into the compressor, where it is pressurized and forced into the combustion chamber or burner. Fuel delivered into the combustion chamber burns, raising the temperature of the mixture of air and combustion products. The compressed, heated gases then flow through the turbine, dropping in pressure and temperature as the heat energy is converted into mechanical work. of rotation. The gases exhaust to atmospheric pressure at temperatures of 850° to 1,000°F. A portion of the power developed by the turbine is used for driving the compres- sor, while the balance is used to drive the generator. Utilities use two types of combustion turbines for the generation of electric power: aircraft and industrial. Aircraft-type combustion turbines are lightweight and are used primarily in peaking applications. Aircraft turbines are more restricted in the fuels they can burn, i.e., they primarily burn light distillate fuels, but can be adapted to burn natural gas or fuel oil by altering the fuel system and combustor. The industrial combustion turbine is a rugged, heavy-duty machine capable of using a wide variety of low cost, low-grade fuels. III-4 In the simple cycle units, the exhaust products are releas- ed directly to the atmosphere. Units using a regenerative cycle Pass the hot exhaust gases through a heat exchanger which trans- fers some of the heat to the inlet combustion air, thereby rais- ing the overall efficiency of the turbines above that of the simple cycle. Combined cycle units use’ the gas turbine and a secondary steam turbine to increase the overall efficiency of the basic system. The performance characteristics of a simple gas ‘turbine system range from 12,000 to 16,000 Btu per kWh (28 to 21 per- cent thermal ef ficiency) depending on size. The regenerative cycle gas turbine efficiencies are between 9,500 and 13,500 Btu per kWh (36 to 25 percent). The efficiency of a gas turbine is highly sensitive to the temperature of the inlet air. The over- all heat rate or thermal efficiency of a gas turbine can ap- proach that of steam turbine plant, if a regenerative cycle or heat recovery boilers and steam turbines are added to the basic system. Turbine loading is controlled by adjusting the amount of fuel burned. The air compressors run at a constant speed; the rate of air flow is essentially constant at all loads. Because of the constant air flow, gas turbine efficiency drops off rapidly below full load operation. This is caused by the lower turbine inlet temperatures* resulting from a decrease of fuel burned with no change in air flow. One technique used to in= crease the efficiency during partial load operation is the addi- tion of a regenerator in the cycle. The resultant thermal effi- ciency is higher but, even with the regenerator, there is a vapid drop in efficiency during part load operation. The reliability of a gas turbine installed in support of larger units in a standby and/or peaking mode is very high. In addition, use of combustion gas turbines to generate electrical base power in Alaska has been a common practice for a long time with high reliability. The use of the simple cycle turbines has declined dramatically in recent years, due to the rapid escala- tion of oil and gas prices. The cost of gas combustion turbines varies depending on the size of equipment and whether it is part of a combined cycle or cogeneration scheme. For systems up to 30 MW, the cost will range from $750 to $1500 per kW, depending on the degree of sophistication of the plant. The availability of gas turbines from suppliers is good. Manufacturers have been able to keep pace with the large demand. The lead time could vary, depending on the type of turbine and its associated. equipment, from off-the-shelf for the smaller III-5 simple cycle units to as much as two to three years for larger regenerative or combined cycle units. In addition, the instal- lation of the larger units usually takes about a year before the system goes on-line. However, these larger units can be put on- line far more quickly than a steam or nuclear plant and, for- this reason, they are being used for base load in spite of the high gas or oil price. Environmentally, the exhaust gas from a combustion turbine is exceptionally clean and the system requires no cooling water. However, in the severe winter conditions of Alaska, ice fog presents a serious problem. Federal regulation (Fuel Use Act) applies to combustion turbines as well as steam turbine power stations. Under this act, combustion turbines can be installed if the output capacity is limited to roughly 7 MW for single stations and 17 MW for multiple unit stations. As with steam turbines, the federal and state clean air standards apply. Organic Rankine Cycle The organic Rankine cycle is a Rankine cycle which has an organic working fluid instead of steam or water. The ideal thermodynamic cycle consists of isentropic compression (liquid working fluid), constant pressure heat addition (vaporization and superheat), isentropic expansion, and constant pressure heat rejection (including slight regeneration and complete condensa- tion). Using the organic Rankine cycle, low temperature heat can be recovered to generate electric power. The organic Rankine cycle is not the most efficient system to use with systems that produce high temperature heat. Those systems are most efficient using the standard steam Rankine cycle. Several organic fluids can be used in this cycle, such as freon, isobutane, an isohexane. The. fluid choice depends on the operating conditions and system costs. The low boiling point organic working fluid is vaporized in a heat exchanger with energy supplied from a geothermal well, diesel generator exhaust gases, or other heat source. The organic vapor is then expanded through a turbine generator for electricity production and con- densed to a liquid via an air or water cooling tower system, and pumped back to the heat exchanger to complete the cycle. This type of a system has several advantages and disadvant- ages. The advantages are the ability to utilize low temperature heating sources, use of smaller and less expensive turbines, use of high pressure with no vacuum sections, and performance of a III-6 completely .dry expansion with lower condensing temperatures. The disadvantages of this system are the expensive organic work- ing fluid, no leaks can be permitted, large heat transfer sur- faces are required, and system safety is considerably reduced because of the potential fire hazard of the organic fluid. Further, intertying sub-systems are required for purging and start-up along with fire protection. The performance characteristics of the organic Rankine cycle indicate that maximum efficiency is obtained during the winter months when the ambient air temperature is low compared to the temperature of the heat being recovered. This feature is desirable due to the seasonal load differences. The thermal efficiency is between 8 and 15 percent. The efficiency is low because the cycle uses a condensing working fluid. If this system is combined with a steam turbine plant (without waste heat recovery) having a thermal efficiency of 37 percent, then _the overall system efficiency for the power plant would be about 6 percent. The reliability of an organic Rankine system should be high because the system is completely sealed and is operating at moderate temperatures with non-corrosive working fluids... How- ever, if a leak should develop within the organic sub-system, no health hazard would exist but a safety hazard may exist. The cost of an organic Rankine ‘system is about $3650 per kW. This is considerably higher than.’any of the standard energy producing technologies. Y The availability of this type of equipment is limited even though the technology associated with the organic Rankine cycle has been known for many years. However, the technology was not economically feasible. until the price of oil increased. These systems using geothermal energy, waste heat or other energy sources may be competitive with other power systems. Availabil- ity would then increase. Environmental concerns in the use of an organic Rankine cycle system would include “thermal pollution and potential spills or leaks of organic fluids... All thermodynamic power cycles require heat rejection to the environment. This system would use a liquid or air-cooled heat rejection system.. Since the system contains an organic working fluid, the potential exists for spills or leaks of this fluid and the re- sulting contamination of soil or water resources. A control system, would be required. ITI-7 Tidal Energy Tidal energy is a form of hydroelectric power generation harnessing some of the enormous potential of the sea. There is an estimated 1.1 million megawatts of tidal energy, dissipated by friction in the coastal waters of the world, that could theo~ retically be converted to electrical power. |The process for harnessing this tidal energy is relatively simple in concept but difficult in application. A reservoir of water is created by damming a large tidal pool. Contained within the dam's struc- ture are sluiceways and turbines. The incoming tide is passed through the sluiceways to the reservoir, then shut off as the tide recedes. The water is released at low tide through the turbines to generate electrical power. To increase capacity, reversible turbines can be used to allow the incoming tide to also drive the turbines. A two-pool system is another possibi- lity, in which a high pool and a low pool would be constructed with turbines between the two. At high tide, incoming water would fill the high pool and low tide would drain the low pool. This allows a greater head for the water, giving it more kinetic energy to drive the turbines (13,14). The performance characteristics of tidal energy generation are dependent on the gravitational pull of the moon and, to a lesser extent, that of the sun. The maximum difference between - high and low tides is approximately 44 feet (this varies with the area of the world and the season). Due to this condition, © the head is much lower than. that in conventional forms of hydro- electric generation. Hence, much larger turbines are used so that a high discharge of water compensates for the low head. The performance of these turbines is the same as those used in conventional hydroelectric generation. The reliability of tidal energy is very high because of the predictability of the tides. The actual machinery has reliabi- lity: comparable to ‘that of conventional hydrogeneration, which - ‘is also high. However, a single pool system cannot be used to generate on demand or base load because of its dependance on the tides. . It could rather be used as part of a larger system that could use the power at any time. A two pool system is capable of handling a base load because of the flexibility it has as to when to generate the power. Costs for the tidal power vary with the site. Construction materials and labor coats have significant impact, especially in remote areas. Initial capital investment is high, but plant life expectancy is longer than conventional power plants. The development of tidal power is dependent on site condi- tions. The major considerations are: a site with an adequate III-8 bb tidal pool, availability of construction materials, and large differences in the high and low tides. Environmental impact is significant. By damming off a tidal pool, the flow rates of the tides and the flushing of the pool are changed. Sedimentation patterns are altered and river borne pollutants would not be transported to the ocean. There would be-differences in salinity, oxygen uptake, and water temp-— -erature. . Wave Energy Wave energy is the extraction of electric energy from the energy dissipated by waves on shorelines. Technologies for this extraction vary widely. They are based on the variations of surface profile and travelling deep water waves, subsurface pressure variations, subsurface fluid particle motion, or unidi- rectional motion of fluid particles in a breaking wave. Two mechanisms .that have been used for remote applications on a small scale are the Wave Activated Turbine Generator (WATG), and Isaccs wave energy pump (13,15,16). The WATG is a piston assembly with its compression chamber resting in the water. As the passing wave compresses the air in the chamber the piston drives the turbine. A system of unidi- rectional valves insures that the turbine is driven on both the up and down strokes. Presently there are models-of- the WATG available with capacities :up to 120 watts. The wave energy pump, developed by John D.Z. Isaccs, is an open ended pipe as-— sembly, containing a turbo-generator and a one-way valve. The pipe, supported in the water by a float, extends beneath the surface. As a wave passes on the downward stroke, the column of water in the pipe rises because of its higher inertia. As it rises it drives the turbines. On the upward stroke, the one-way valve prevents the water from falling. A test facility was placed in Kaneole Bay. Hawaii, in the. fall of 1976. Continuous energy output of 250 watts was generated by four-foot waves. © Performance characteristics of wave power would be affected by many factors. The amount of power generated is dependent upon wave activity, which varies with the season of the year and even the time of day. Also, only certain areas of the world have sufficient wave activity to make wave generation a viable technology. Reliability of wave generation has not yet been proven but it should be high because of the simplicity of the mechanisms. Problems that could affect the performance of a wave generator are the obstruction of intakes with biota and the pounding of _III-9 bp storm waves. The structure must be able to handle waves up to four times as strong as its usual load. , At present the only generators of this type are commercial- ly available are in the 120 W range. Large scale devices are mainly in the research and development stage. Environmental impact of a wave energy installation is re=- lated to the size of a plant required to generate usable amounts of power. The plant would act as a breakwater, and the result= ing quieter seas could change the nature of the shoreline. Also, sediment falling out of the quieter areas could affect vegetation and thus wildlife habitat. Ocean Current Energy Ocean current energy is another form of hydroelectric power generation (17-20). The ocean's currents run constantly and, in some areas, with sufficient force to power turbo-generators. The Gulf Stream, off Florida, has an estimated kinetic energy of 25,000 MW. Other powerful currents are the Kuroshio, the Somali Current, and the Brazil Current. These currents derive their power from the tradewinds. The harnessing of power in these currents can be done in a number of ways. Existing technolo= gices include large turbines and lifting foils. - Experimental designs are based on Savonius rotors and parachute driven cables... Atypical plant using turbines would consist of a large structure to house the turbines, sufficient moorings, and a mechanism for transmitting the power produced. Performance of ocean current energy is comparable to con=- ventional forms of hydropower. It can supply a constant base load and isn't dependent upon the season. Reliability is also comparable to that of conventional hydropower. Differences. associated with ocean current energy are the corrosive nature of the ocean water and the possible obstruction of intakes with biota. The cost of ocean current energy is determined mainly by the cost of the structure and the moorings. The generators themselves should not cost any more than those used in conven= tional hydropower plants. The energy source is free and operat- ing costs should be low. At present, there are no plants in operation. There are turbines available, and the technology exists to make this a commerical source of power, but at present the demonstration of this technology has not been accomplished. III-10 Environmental considerations that must be addressed are related to the disturbance of the currents. Ocean Thermal Energy Ocean Thermal Energy Conversion -(OTEC) is the application of a closed Rankine cycle to utilize the temperature gradient of the oceans. Surface water is heated by the sun, while the lower levels remain cooled. In some of the tropical areas this dif- ferential is as much as 75°F or more. By using the upper levels as a heat source and the lower levels as a heat sink, the ther- modynamic engine is driven. A typical OTEC structure comprises a hull containing the engine, an intake pipe for. surface water, and an intake pipe for subsurface water, extending down to a depth of as much as 1000 feet, and an outlet for the water. The engine itself is a closed system, containing a working. fluid that is passed through an evaporator heated by the surface water. The evaporated fluid, in a gaseous state under pressure, is used to drive a turbo-generator. The fluid is then passed to a condenser and cooled and condensed by the sub-surface water to repeat the process. Performance characteristics of OTEC are low, with an over- all efficiency of 2 to 3 percent. MTherefore, large amounts of water are required to generate usuable amounts of power. Approximately 17,000 cubic:-feet per second discharge would be required to produce 100 MW: of electric power. The efficiency could be increased by improving the heat exchangers and pumping equipment. Reliability is based on the intake pumps, the engine fluid. pump, and the possibility of obstructing the intakes with biolo- gical matter. OTEC is reliable for a base load because its energy source is constant. Cost of OTEC power is high... The Department of Energy's "test facility, OTEC 1, was budgeted- at $25.4 million for design and construction. Due to the amount of water required, the plant must be very large. This is a major factor, not only for construction, but also for the mooring of the structure. The projected cost for a commercial plant is from $2,000 to $2,500 per KW. OTEC is not currently a commercially available technology. It is still in the research and development stage, with the Department of Energy conducting extensive work to prove that the technology is viable on a large scale. When plants are avail- able, the power would have to be transmitted a long distance: to shore or could possibly be used for on-site processes. III-11 Environmental considerations. include: ocean water mixing, the possibility of metallic discharges, extracting biota from the water, biocides, fluid leaks, and the long term effect of uniform temperature distribution of the ocean. Solar Power Generation Solar Thermal Energy uses solar collectors to generate heat, which in turn is used to produce steam or another gas to drive turbo-generators. There are two basic types of collec- tions: a central receiving system, where heleostats are center- ed around a heat transfér tower, and a distributed collector system, where individual collectors heat a working fluid. Solar thermal generators operate in the same manner as conventional thermal plants with the only exception being the heat source (1,2,21,22). . ; Performance of solar thermal generation is in the range of 25 to 35 percent efficiency, but with the application of cogene= ration, efficiency is. in the 60 to 70 percent range. The amount of energy input available to the collectors varies inversely with the distance from the equator. Therefore, as you travel northward larger collectors are required to produce the same amount of electricity. Even in the most desirable locations, the area required for the collectors is approximately 6.5 square miles per megawatt. This figure is for the southwestern United States. For Alaska, the -required area would be almost three times as much. The cost of solar thermal generation is not. well establish- ed. Several test sites have been built, at fairly high cost. The test facility at Barstow, California costs in excess of $10,000/kW. A major factor in solar plants is the amount of steel required, 35 times the amount required for a coal plant. Solar power plants are not as. yet a commerically available op- tion, but extensive research and development is being conduct- ed. : . Environmental considerations are related to the size of the plant. For a plant of usable size, thousands of square miles of land must be covered by solar’ collectors. Solar Photovoltaic Systems Solar photovoltaic systems directly convert the light of the sun into electrical energy. The: sunlight is an electromag- netic wave which, when passed through a semiconductor, produces electrical current. The semiconductor used most commonly is silicon. Other materials that have been used experimentally include cadmium sulfide and gallium arsenide. Both of these III-12 bb materials show possibilities for reducing costs, but tend to have lower efficiencies (1,2,23,24,25). In all types of photovoltaic cells, power densities are low and large numbers of cells are required to produce usable amounts of power. A concentrator can be used in conjunction with the cells to obtain higher power densities. In the case of cells, output of power can be as high as 22.3 kW/ft2 of cell area. The power generated is direct current; therefore, in most applications a power conditioner is required to convert it to alternating current. Also, if the power were required at times when the sun is not shining, storage devices would be required. Performance characteristics of photovoltaic cells range from thermal efficiencies of 2 to 20 percent, depending upon the type and quality of the semiconductor. Standard crystalline silicon cells have the highest rating at 12 to 16 percent with 20 percent attainable at higher cost. Solar photovoltaic systems are extremely reliable, because they have no moving parts. Many of the first cells produced in the 1950's are still in operation. The system could be used for a base load if enough energy is produced and stored during day- light hours to make up for, times of darkness. : : Cost of photovoltaic cells is based upon the cost of the semiconductor. Silicon of semiconductor grade costs approxi- mately $27 to $32/lb. In 1978, DOE purchased photovoltaic ar- cays for around $10,000/kW. As commercialization increases and other conductors are improved, costs should decrease. Photovoltaic systems are presently available for small scale remote applications only. The Department of Energy is conducting extensive research and development. “The only environmental considerations are those involved with the large area of land to be ‘covered with the arrays of cells. Geothermal Energy Geothermal energy uses the heat from the earth's core as the energy source for electric power generation. Generation is accomplished in essentially the same manner as conventional thermal plants. High pressure steam or superheated water is extracted from deposits near the earth's surface. The steam can be used directly to drive turbines; the water can be used by reducing pressure to convert it to steam. This method of reduc- ing pressure is known as a flash system and can be done in one III-13 or two stages. Another application of geothermal heat is in a closed Rankine cycle when the energy -is low grade heat. This is called a binary cycle (1,2,26,27). Peformance characteristics of geothermal energy are 14 to 16 percent with 900,000 lbs. of steam per hour needed for 100 MW. The lifetime of a well averages 15 years. Reliability of. geothermal energy is high. Factors that affect reliability are the salinity of the extracted steam and well life. The binary cycle has a longer plant life if the working fluid does not have a high mineral content. . ‘Cost estimates for United States sites range from $400 to $650 per kW with power estimated to cost between 3.0 ‘and 3.5 ¢/kWh. A major factor in the cost is the drilling of the well. Wells cost an estimated $300,000 to $600,000 in the Lower 48 states. Costs ranging up to $1,000,000 could be experienced in Alaska for a 4,000 to 6,000 foot well. The technology for geothermal energy is well established © and has been in use in some areas for many years. Geothermal wells must be sufficiently close to the market to make power transmission economical. Environmental considerations include potential air and water pollution, land requirements, and the possibility of in- duced earthquakes. If an organic Rankine cycle is used, hydro- carbon spills may present an environmental problem along with a safety problem. Nuclear Energy Nuclear energy uses a nuclear reactor as the heat source to drive steam turbines. Present day reactors are fission reac- tors. A fission reaction occurs when heavy radioactive elements are split by neutron absorption. As the element's nuclei absorb the neutrons they split and release more neutrons, thus generat- -ing heat. The reaction, if left uncontrolled, would continue at an exceedingly high rate until all the fuel was used. This is the situation that occurs in an atomic bomb. In a reactor, the reaction is controlled by rods placed in the fuel core that absorb the free neutrons (2,28,29). The process as a whole is simple in concept; however due to the controls. required, the application is complex. Performance characteristics of nuclear energy are similar to those of other conventional thermal plants, ranging from 28 to 37 percent efficiency. Fuel efficiency would be increased III-14 Ti with the development of breeder reactors. The application of cogeneration to nuclear power would increase efficiency but is limited due to radiation. Reliability of nuclear reactors is high due in part to the amount of systems monitoring necessary. There are potential systems failures that create hazardous conditions, such as radi- ation leaks. Cost of nuclear power is estimated to be $1650/kW with a cost per kWh of 1.5¢. Initial capital and fuel costs are high. There is also a high labor cost involved because of the need for highly-trained personnel. The energy demand in the Bethel re- gion is not large enough to make nuclear power cost effective. Nuclear power is widely used today in the United States and _ Europe. However, a long implementation period is required which is partly attributable to regulatory requirements. The major environmental considerations involved with nu- clear power are the disposal of radioactive wastes and the pos- siblity of radiation leaks. These factors are heavily regulated by the Nuclear Regulatory Commission (NRC). Direct Combustion ee For space heating, direct. combistion“involves a direct- fired furnace which heats air to be circulated. Oil and gas are the most commonly used fuels today but furnaces that burn coal or wood are in use. Air circulation can be accomplished by convection or forced air. Most home heating in Bethel region is done by oil-fired stoves and convection or forced air circula- tion. Direct combustion can also be used-in a hot water heating system. Water is heated by the furnace then circulated through the structures to radiators. With this system, many buildings can be heated by a single furnace. . Direct combustion is highly efficient. Large systems range from 85 to 93 percent efficiency with a 60 to 70 percent rating for small systems. Direct combustion is a highly reliable technology. Natural convection systems are the most reliable because forced air systems rely on electric power to drive blowers. Due to the high efficiency, direct combustion is one of the least expensive heating technologies, ranging from $500 to III-15 i $2,000 per unit. The cost is approximately 1.3 ¢/Btu/hr or less. Direct combustion systems are available commercially in a wide range of sizes. Environmental considerations depend upon the fuel used, with natural gas being the most desirable. Electric Heating Electric heating can be produced by resistance heaters, inductance heaters, dielectric heaters or electric arc heaters. Resistance heating is produced by an electric current passing through a conductor with high resistance. Induction heating is produced when a magnetic material is placed within an alterna- ting induced magnetic field. Dielectric heat is produced when an insulating material (non-conductive) is placed in a high- frequency electrostatic field. Electric arc heaters are another form of resistance heaters, where the resistive material is the air between electrodes. Of all these types, resistance heating is the most commonly used. Performance efficiency of electric heating is very high with an efficiency of nearly 100 percent. Reliability is also high. Systems are simple and have no moving parts. Also, there are none of the problems associated with combustion. Cost of electric heating runs higher than that of direct combustion, but in some cases it is more economical. It re- quires no fuel lines, fuel storage, combustion chambers, or stack. Also, electric heaters require less space than direct combustion systems. Electric’ heating is commercially available for both resi- dential and industrial applications. The environmental considerations associated with resistance heating are insignificant. Heat Pumps A heat pump is a machine for either extraction or introduc- tion of heat into a system. A common example of a heat pump is a refrigerator. With a heat pump, heat is extracted from a source at a low temperature and delivered at a higher tempera-—- ture. This requires energy input from another source in the form of high temperature heat or mechanical energy. The energy TII-16 input can come from many sources, including waste heat from electric power generation, or an electrically driven compressor. A heat pump system using a compressor is a closed system com- posed of a working fluid, an evaporator, a condensor, the com- pressor, and an expansion valve. The fluid absorbs heat in the evaporator, is compressed and passed to the condenser where it releases the heat. As the fluid returns to the evaporator it. passes through the expansion valve, reducing its pressure. In some systems the process may work in either direction; the same heat pump will either heat or cool a unit. In an area such as Bethel, the heat source could be the outside air or water from rivers, lakes, or the sea. , The performance of a heat pump is best when the temperature differential between the evaporator and condensor is small. Electric power consumption is low compared to the amount of work; one kilowatt of input will perform four kilowatts of work. This is due to the energy that is taken out of the heat source. Heat pumps. are highly reliable. Each element in the heat pump system (condenser, evaporator, expansion valve) has a high reliability. Cost of heat pumps is approximately $100/kW. The cost .is dependent on the temperature range over which it-is operated and the cost of electricity. Heat pumps. are produced commercially by many major manu- facturers. The only environmental consideration is the possibility of a leak of the working fluid. . Solar Heating There are two classifications of solar heating; passive and active. Passive systems use no mechanical devices. Five types of passive systems are: direct gain, thermal storage wall, solar greenhouse, roof pond, and convective loop. Direct gain involves simply a window facing in a southerly direction. Ther- mal storage is the same principle except a dark colored wall is~- used in place of glass. The solar greenhouse is a combination of. the direct gain and thermal storage. Sun comes into the greenhouse and is stored in the walls and air space. A roof pond is. another method of thermal storage, where the heat is stored in water on the roof. A convective loop comprises a water tank placed above solar collector panels with pipes run- ning through them and back to the tank. As the water heats in the collectors it rises in the pipes and the heavier water in the tank sinks: into the collectors. III-17 Ob te) Active systems are typically composed of collectors, a storage component and energy distribution systems. A common system is collector panels with a matrix of pipes running from a water source, through the panels and to a storage tank. The water can then be passed through a heat exchanger, radiators, or a forced air system. The amount of solar input determines the performance of solar heating technologies. Solar heating works best in areas close to the. tropics. In northern latitudes, support systems are required. Solar heating systems are as reliable as the weather. In lower latitudes, systems are functional even when the sun doesn't shine. Active systems are also dependent upon the source of electricity. Cost of solar heating is dependent on the type of system applied. Most systems are relatively inexpensive initially, and in the case of passive systems, require no fuel input. Solar heating technologies are commercially available. In some areas, new construction has solar heating units built in;. and in some states, tax incentives are offered for installing solar heating systems. There are no environmental considerations for solar heating units. Geothermal District Heating Geothermal district heating uses a geothermal resource directly or indirectly for space heating. This process takes steam or hot water from the wells and either transfers it di- rectly to the area to be heated or transfers it to a heat ex- changer to exchange the geothermal heat with the heat of a "clean" working fluid which is then transferred to the area to be heated. Performance of a geothermal heating system is dependent on the temperature of the steam or hot water extracted from the earth, the quality of the steam or hot water, and the reservoir conditions. With plate and frame heat exchangers, approach temperatures of 2 to 3°F can be achieved. These types of ex- changers can provide very high thermal efficiencies. Geothermal systems are highly reliable. They are dependent only upon the life of the well and the heat exchangers. The reliability of the heat exchanger is very high. III-18 The initial cost of a geothermal. system is high, but- operating and mainténance costs are minimal if the steam or hot water does not contain high concentrations of salts and minerals that .could affect the heat transfer surfaces of the heat exchan- gers. Factors influencing initial cost are the special alloy pipes, pumps, and the cost of drilling the production and, if necessary, the reinjection wells. Drilling can cost as much as $1,000,000 per well and piping systems cost approximately $140 -per foot. Geothermal heat systems are available. However, a geother- mal resource also has to be available. Environmental considerations involved are the possiblity of a leak in the steam and potential problems caused by extracting the steam. High concentrations of salts in the geothermal fluid pose serious corrosion problems and, if removed, present a dis- posal problem. District Heating (Steam/Hot Water) District heating systems using steam or hot water are simi- lar to geothermal district heating -.systems. These types of heating systems can provide central heat for an area of residen- ces or businesses. A system is composed of a central heat source, a piping network and heat exchange units. The heat source can be direct combustion, electric heat, waste heat from a thermal power plant, or a geothermal reservoir. District heating systems are an efficient method of space heating. When direct combustion or electric heat is the source of energy, it is more efficient than individual systems. When waste heat from a thermal plant is the source of energy, the -efficiency of the thermal plant increases from about 30 to 80 percent. . District heating systems are highly reliable. The systems are dependent upon .either a thermal plant, direct combustion, electric heat or geothermal heat, all of which are highly reli- able technologies. Capital cost for district heating systems are high. Systems in Alaska are estimated to cost from $500 to $2000 per kW. The equipment for a district heating system is commercially available. Systems of both steam and hot water have been in use since the turn of the century, and are currently being used in Alaska. III-19 ay Environmental considerations are related to the heat source. Cogeneration Systems In cogeneration systems, electrical or mechanical energy and thermal energy are produced simultaneously. The most common application of cogeneration is the use of waste heat from an _ @lectric power generation station for district heating or indus- trial process heat. Types of Waste Heat Heat losses. from a power generating plant fall into three categories: water jacket heat, exhaust heat, and radiation. Jacket Heat. Jacket heat amounts to approximately 30 per- cent of the energy input to the engine and is recoverable as hot water. This hot water can be used for space heating or domes= tic hot water heating. Heat recovery systems for this heat consist of a water-to-water heat exchanger in parallel with the normal engine radiator. The generated hot water is pumped from this heat exchanger to the final heat exchanger located at the end user's facility. Thermostatically controlled valves divert the jacket water to the heat recovery-.system—-when the end user requires heat. However, when the heat requirement is satisfied, the jacket water flow is diverted back to the engine radiator for discharge of heat to the atmosphere. If the heating system is the sole source of heat for the end user, then an auxiliary heater may be required to supply heat when the jacket water supply is inadequate. Exhaust Heat. The exhaust heat is approximately 33 percent of the input energy. By installing a boiler or heat exchanger in the exhaust stream approximately 60 percent of the heat (20 percent of. the engine energy input) can normally’ be recovered and 40 percent (13 percent of engine energy input) is lost. Exhaust heat recovery systems consist of a heat exchanger in the exhaust system which produces either steam or hot water for the primary loop of a second heat exchanger. This primary loop will then transfer its heat to a secondary loop where water is heated for transmission to the end user. Radiation Heat. The radiation heat for a diesel generator is not recoverable for use at remote locations but can aid in heating the immediate area where the generator is located. This heat is that radiated from the éngine. during its operation. TII-20 it Selection of Waste Heat Recovery System The basic principles of exhaust heat recovery are simple, however, the safety and controls sub-systems are far more comp- lex than that of the jacket heat recovery system. Due to the high temperature of the exhaust, precautions must be made to ensure that: the. heat recovery boilers do not run dry; the heat exchanger is a coded pressure vessel because high pressures may develop under certain conditions; and a method of dissipating the excess heat is provided. Because of the complexity of exhaust heat recovery systems and relatively low recoverable heat available, the cost-to-bene- fit ratio is usually too high to justify this type of system on a small, unattended generating plant. For the villages in the Bethel area, it was assumed that only the jacket water system would be installed and that the heat would be used to supplement an existing system so that no auxiliary heaters were required at the generating plant. Cogeneration was more widely used in the past. Utility companies around the turn of the century supplied steam to densely populated areas and large industrial users. The appli- cation of cogeneration is again coming into use due to the in- creased costs of fuels. Cogeneration systems increase the efficiency of convention- al thermal plants from 25 or 30 percent to as much as 80 per- _ cent. Systems in which waste heat is taken from power genera- tion tend to be the most efficient. Cogeneration systems are as reliable as the individual systems involved. Thermal plants and district heating systems are highly reliable. _ Costs. for cogeneration systems are high, apptoximately $2,000 to $3,500 per kW. But with the increased efficiency, costs per kilowatt-hour are low. Cogeneration systems are commercially available and are used in many areas in Alaska. Environmental considerations are related to the type of system used. In all types of systems, environmental impact is mitigated in that the fuel efficiency is improved and waste heat to the environment is reduced. TII-21 Combined Cycle Systems Combined cycle systems are systems in which two or more thermodynamic cycles are coupled together to increase the effic- iency of a system. Combining cycles is intended to improve fuel consumption, while reducing cost and environmental impact. One application of a combined cycle is a combination of high tem=- perature gas turbines and steam turbines. In such a system, the fuel is burned in the combustion turbine to produce high tem=~ perature gas which drives turbines. After expanding through the turbine, the exhaust gas is used in a waste heat recovery boiler to generate steam to drive a steam turbine. Performance of a combined cycle system is high with thermal efficiencies around 60 percent. Reliability for combined cycle systems is high. The reli- ability of a combined cycle system would be the same as that of a combustion turbine plant and a steam turbine plant. Both of these types of plants have been in operation for many years and have established a high reliability. Cost of energy generated by combined cycle plants is lower than either conventional steam plants or gas turbine plants. Capital -costs are about $1,000 to $1,200 per kW lower than ei- ther conventional steam plants or gas turbines. The equipment for a combined cycle plant is commercially available, if combustion turbines and steam turbines are used. Environmental considerations are the same as those for gas turbines, with the exception that the heat from the exhaust gases is lower. Coal Gasification Combined Cycle Coal gasification combined cycle is the process of gasify= ing coal and using this gas in a combustion turbine. The ex=- haust gas from the turbine is then used in a waste heat recovery boiler to generate steam for use in a steam turbine. Performance of coal gasification combined cycle is in the range of 50 to 60 percent efficient. Open cycle systems are the most efficient. Reliability of coal gasification plants is high for the old type systems such as Winkler. The newer units, such as Texaco's POX, COED, fixed bed gasifier (slagging), fluidized bed gasifi- cation (two stage pressurized process), etc., are still in the process development stage. III-22 A cost estimate for a 100 MW plant is approximately $5,960 per kW. Advanced coal gasification combined cycle plants are not commercially available at present. Southern California Edison is constructing a 100 MW plant, and there is a 170 MW plant at Lunen, West Germany currently in operation. Coal gasification turbines using "dirty gas" are not. commercially available. However, turbines using clean gas along with steam turbines are commercially available. Many environmental problems are associated with the coal gasification. These are: runoff, solids, organic wastes, solid wastes, waste heat, and accidental releases of toxins and carci- nogens. Wind Turbines Wind turbine electric generators utilize the power of the wind to generate electric power. A wind turbine is composed of a rotor, a generator, and a mounting structure. The size of the rotor determines the capacity of the turbine. There are three types of generators: induction, synchronous, and direct cur- rent. The most common application of wind turbines is as part of an interconnected supply system, but there are limitations of use because the power produced continually fluctuates which would not be suitable in small power: systems. Complex controls can be added to regulate power output. Performance characteristics of wind turbines are dependent on rotor size and wind velocity. Efficiencies vary from 5 to 30 percent, with most machines between 15 and 25 percent. Large wind turbines are not considered highly reliable. Problems have been encountered with rotors failing and, in some cases, the support structure failing. There have been dangerous situations where vibrations weaken the structure, causing it to collapse. Smaller turbines are considered reliable and have been in use for many years. Cost. of wind turbines is dependent upon the size of.the rotor, with a range of $5183/kW for a 13-foot rotor to $2160/kW for an 82-foot rotor. Blade life is short and replacement blades can be a major factor in operating costs. Small wind turbines are commercially available and are in use in many areas. There are ongoing research projects by several universities and NASA on large wind turbine generators.. III-23 bp Environmental considerations are minimal, as there is no emission of pollutants. Potential concerns include land clear- ing and excavations for the structure, noise, and interference with communications such as television and radio. A more detailed discussion of wind technology is presented in Appendix C-3. Fuel Celis Fuel cells generate electric power from chemical energy without combustion. A fuel cell is composed of an anode and a cathode immersed in an electrolite separated by a semi-permeable membrane. High hydrogen content gas is passed over the anode while air is passed over the cathode. The hydrogen atoms at the anode dissociate into ions, taking on electrons. The semi-per- meable membrane allows the ions to pass through while not allow- ing the molecules to pass. The ions pass to the cathode side of the membrane and combine with oxygen to produce- water, thus releasing electrons. Each cell produces approximately 0.7 volts DC; therefore, a stack of cells is required to produce usable amounts of power. The hydrogen rich gas can be derived from many fuels such as natural gas, methanol, naphtha or propane. These gases must be passed through a catalytic converter before they can be used. The power produced is direct current, so for most applications a power conditioner is required to convert the DC into AC. Performance characteristics of fuel cells is very high with projected efficiencies as high as 52 percent depending on the type of electrolyte and fuel used. However, current fuel cell systems have an efficiency of about 40 to 45 percent. The rea=- son that such efficiency is attainable is that it is an electro=- chemical process not dependent on the Carnot cycle as are die- sels, turbines, etc. Fuel cells on a small scale have proven to be highly reli- able, and have been used in the NASA space program. Reliability is being judged on large scale units, i.e., 4.5 and 7.5 MW. The cost of fuel cell systems at present is approximately $1300 per kW with estimated large scale production costs of $350 per kW. The cost per kilowatt-hour is dependent upon the fuel used, ranging form 4.78¢ for natural gas, to 14.94¢ for ammonia in the Bethel area. Fuel cells are commercially available in small 40 kW units. Two large plants are under construction, one in Tokyo and one in New York; both are 4.5 MW plants. The availability of the fuel cell system has to be considered along with its fuel supply III-24 source. The fuel available at Bethel includes light distillate fuel, methanol, and propane gas. Environmental considerations for fuel cells include the possibility of a fuel leak. However, these considerations are somewhat less than those for conventional generating plants because no combustion takes place and hence there is no by=- product waste. A more detailed description of fuel cells is presented in Appendix C=-2. . III-25 Ub on Chapter IV EVALUATION OF ENERGY TECHNOLOGIES Introduction An evaluation of energy technologies for possible use in the energy supply plans was conducted. This evaluation examined 31 different technologies to determine technical, environmental, and economic feasibility of supplying energy to the Bethel re- gion. In addition, some of the technologies that are in the early stages of development were critically reviewed for their commercialization potential within the planning horizon of this study. Since some of the technologies overlap in the generation of electricity and in the production of energy for space heating, the technologies were divided into four categories: technolo- gies whose principal objective is to produce electricity; tech- nologies whose principal objective is to generate energy for heating; technologies which provide both electricity and heat- ing; and support technologies which assist the other technolo- gies in achieving their primary objective. The technologies within each category are: ° Electric Power Technologies Diesel Electric Steam Turbines Gas/Oil Fired Combustion Turbines Nuclear Energy Organic Rankine Cycle Ocean Energy (tidal, wave, ocean, current, ocean thermal) Fuel Cells Geothermal Solar ° Heating Technologies Direct Combustion Electric Heating Heat Pump Solar (active, passive) District Heat (geothermal) District Heat (steam/hot water) Iv-1 ° Electricity and Heating Technologies Cogeneration System Combustion Turbine-Combined Cycle Coal Gasification-Combined Cycle Geothermal : Solar ° Support Technologies Wind Systems Active Solar Passive Solar Geothermal Ocean Energy (tidal, wave, ocean current, ocean thermal) The technologies within each category were evaluated using a set of criteria that was developed for this study. Evaluation Criteria The criteria used in the technology evaluation are: ae Unit Energy Cost (estimated) b. Resource Availability Ce Degree of Commercialization d. Adaptability to Bethel Region ee Community Acceptance £. Environmental Constraints g. Equipment Sophistication and Required Training of Personnel The technologies which had ratings of 70 or greater within each of the four categories were analyzed further using a more detailed economic evaluation. The technologies were’ ranked within each of the four cate- gories by using a numerical rating. The rating system for the evaluation criteria is presented in Table IvV-l. Each criteria ranges from a value. of -30 to the maximum value. The negative value for each criteria is designed to assess major problems or flaws in the technology, without over- stating the rating of a technology by assessing zero points for a significant deficiency. IVv~2 oy Table IV-1 TECHNOLOGY EVALUATION CRITERIA RATING SYSTEM . Maximum Minimum Criteria Value Value. Unit Energy Cost : 25 -30 Resource Availability 15 -30 Degree of Commercialization 10 -30 Adaptability to Bethel Region 15 -30 Community Acceptance 10 -30 Environmental Considerations 15 -30 Equipment Sophistication and Required Training of Personnel _10 -30 Total Rating Points 100 Each of the seven criteria has been further sub-divided to permit an objective rating of all technologies. These sub- divisions are listed below. Unit Energy Costs (25) Capital Costs $ 1,000/kW 10 6,000/kW 0 2,000/kW 8 8,000/kW -5 3,000/kW 6 10,000/kW -10 4,000/kwW 4 20,000/kW -20 5,000/kW 2 30,000/kW -30 Energy Costs $ 0.01/kWh 15 0.25/kWh 2 0.05/kWh 13 0.30/kWh 0 0.10/kWh 10 0.35/kWh 10 0.15/kWh 6 0.50/kWh -30 0.20/kWh 4 Resource Availability (15) Locally available 15 Shipped from other Alaskan Sources 10 Shipped from Lower 48 or Canada 5 Resource has to be developed 0 Resource has to be discovered -20 IV-3 he Degree of Commercialization (10) Technology commercially available 10 Technology in engineering development 8 Technology in advanced development 6 “ Technology in explanatory development 0 Technology in basic research . -30 Adaptability to Bethel Region (15) Completely adaptable 15 Needs minor modification 10 Needs major modification 5 Needs major redesign 0 Not adaptable -30 Community Acceptance (10) Fully acceptable by community . 10 Acceptable by majority 7 Acceptable by minority 3 Acceptable after community education 0 Not acceptable -30 Environmental Considerations (15) No effect 15 Minimum effect/no. ‘action necessary . 10 Minimum effect/action required 5 Major effect/action required 0 Major effect/no action can be taken -30 Equipment Sophistication/Training of Personnel (10) Not sophisticated/no training involved 10 Not sophisticated/skilled labor 6 Not sophisticated/trained personnel 4 Sophisticated/skilled labor with technical supervision 0 Highly sophisticated/highly trained personnel -30 For a technology to be considered further, it must have a numerical rating of 70 or more. Evaluation Results The evaluation. of the various technologies is presented on Exhibits 2,3,4, and 5. Exhibit 2 shows the evaluation of the technologies primarily associated with the generation of elec- Iv-4 tric power. Exhibit 3 presents the evaluation of the technolo- gies dealing primarily with heating, while Exhibit 4 presents the evaluation of those technologies which generate both elec- tric power and heating energy. Exhibit 5 shows the evaluation of those technologies which support or augment the primary tech- nologies represented in Exhibits 2,3 and 4. The results of the technology evaluation are discussed in the following para- graphs. Electric Power Technologies Table IV-2 shows’ the overall ranking of the electric power technologies. : Table IV-2 RANKING OF ELECTRIC POWER TECHNOLOGIES — Technology — Overall Rating Gas/Oil Fired Turbines 76 Diesel 74 Fuel Cells 72 High Pressure Steam Turbines 70 Organic Rankine Cycle 63 Solar . 61 Ocean Energy . 32 Nuclear Energy ; 26 Geothermal 5 Based on this numerical rating, the generation of electric power by gas/oil fired turbines, diesel, fuel cells, and high pressure steam turbines will be considered further. Wind technology was not considered a candidate technology for the generation of prime electrical power because this tech- nology would require a method of electrical storage. Storage technology for wind and solar system has not advanced suffi- ciently to be used reliably for this application. The organic Rankine cycle, ocean energy, geothermal, and solar’ technologies were eliminated from further consideration. The major deficiency in the organic Rankine cycle was in the capital cost of the basic and ancillary equipment. Ocean energy technologies (tidal energy, wave energy, ocean current, and ocean thermal energy) were eliminated based on equipment cost and the judgement that these technologies will not be commer- cially available within the 20-year planning period. Geothermal energy was eliminated principally due to a lack of a defined IV-5 resource, and its poor adaptability to the Bethel region. Solar energy aS a power source was eliminated due to its high energy cost (capital and unit energy) and its degree of commercializa- tion. This technology as a power source will not be commercial in the next 20 years. Nuclear energy was eliminated primarily because of the relatively high cost of the small-scale plant. Equipment sophistication and required training of personnel are also inappropriate to the region. Heating Technologies Table IvV-3 shows the overall ranking of the heating techno- logies. Table IvV-3 RANKING OF HEATING TECHNOLOGIES Technology Overall Rating Direct Combustion 85 Electric 80 District Heat (steam/hot water) 79 Heat Pumps 69 Solar 69 District Heat (geothermal) 3 The evaluation of the heating technologies indicates that direct combustion, electric heating, and district heat using steam or hot water warrant further evaluation. The heating technologies used in the formulation of the supply plans will also utilize various conservation techniques to minimize the heat loss, The heat pump, solar heating, and district heat using geo- thermal resources were eliminated from further consideration. Electricity and Heating Technologies Table Iv-4 shows the overall ranking of the combined electricity and heating technologies. The technologies that produce both electricity and energy for heating that will be considered for further evaluation are cogeneration systems and combustion turbines-combined cycle. IV-6 Table Iv-4 RANKING OF ELECTRICITY AND HEATING TECHNOLOGIES Technology Overall Rating Cogeneration Systems 79 Combustion Turbine Systems- Combined Cycle 76 Solar 68 Coal Gasification Combined Cycle 55 Geothermal 5 The coal gasification combined cycle, geothermal, and solar were all eliminated from further consideration. The coal gasi- fication combined cycle was eliminated because of its stage of commercialization and the sophistication of equipment required. In addition, highly skilled personnel would be required. Geo- thermal was eliminated because of a lack of a defined reservoir, its lack of adaptability to the Bethel region, and the required sophisticated equipment and training of skilled personnel. The solar technologies were eliminated due to limited solar radia- tion flux in the upper latitudes. Support Technologies Table IvV-5 shows the overall ranking of the support techno- logies. Table Iv-5 RANKING OF SUPPORT TECHNOLOGIES Technology Overall Rating ‘ Wind Generation 75 Passive Solar . 74 Active Solar 67: Ocean Technologies 58 Geothermal 2 The support technologies that will supplement the electri- city and heating technologies are wind generation and. passive solar. These technologies will be supplemented by various con- servation resources such as insulation and load management de- vices. Iv-7 . The active solar, geothermal, and ocean technologies were all eliminated from further consideration. Geothermal was eli- minated due to a lack of a defined resource and the sophisti- cated equipment and skilled personnel required. The ocean tech- nologies were eliminated because they are in the development and advanced development stages. Sophisticated equipment is re- quired, with skilled personnel needed to operate. and maintain the equipment. Certain environmental considerations are also a factor. Iv-8 Chapter V SELECTION OF ENERGY TECHNOLOGIES Introduction This chapter describes the economic analysis performed to select the candidate technologies for use in formulating non- hydroelectric energy supply plans. The candidate technologies which were retained from the preliminary screening (Chapter IV) are summarized in Table V-l. Table V-1 PRELIMINARY SELECTION OF CANDIDATE TECHNOLOGIES a : ae a Overall Technologies Rating Electric Power Technologies Gas/Oil Fired Turbines 76 Diesel (base case) 74 Fuel Cells 72 High Pressure Steam Turbines 70 Heating Technologies Direct Combustion (base case) 85 Electric 80 District Heat (steam/hot water) 79 Electricity and Heating Technologies - Cogeneration Systems 79 Combustion Turbines - Combined Cycle 76 Support Technologies Wind Generation 75 Passive Solar 74 Each of these eleven technologies are further evaluated to determine which will be used in formulating energy supply plans. An examination of these technologies indicates that some can be combined since they are similar in nature. The high pressure steam turbines technology along with the steam or hot water district heating technology are combined to form a cogen- eration system. The use of gas-fired turbines to generate electricity will be eliminated as a candidate technology because a gas resource has not been defined in the Bethel region. Economic Evaluation The economic evaluation of the candidate technologies was based on a comparison of equivalent energy costs, determined as follows: Cost of Energy = (Depreciated Capital Costs) + (Fuel Cost) + (O&M Costs) (Capital Cost] [Constant A] [Design Life] + [Fuel Cost] [Heat Rate] [Constant B]/ [Heat of Combustion] + [O&M Cost] where: Cost of energy: ¢/kWh Depreciated Capital Costs: ¢/kWh Fuel Cost: ¢kWh O&M Cost: ¢kWh Capital Cost: $/kW _. Fuel Unit Cost: $/gal or $/ton Design Life: Years : : Heat Rate: Btu/kWh Heat of Combustion: Diesel Fuel No. 2 = Btu/gal Coal = Btu/lb Constant A: 11.416 x 1073 Constant Bs: Diesel Fuel No. 2 = 100 Coal = 50 x 1073 The data used in the evaluation of* the candidate technolo- gies is presented on Exhibit 6. The results of the evaluation are presented in the following paragraphs. Table vV-2 shows the economic evaluation of the electric power technologies. iD Table V-2 ECONOMIC EVALUATION OF ELECTRIC POWER TECHNOLOGIES Technology Unit Cost (¢7kWh) Fuel Cells 8.8 High Pressure Steam Turbines (coal) 14.9 Oil-Fired Turbines 14.5 Diesel (Base Case) . 17.7 Based on these results, the fuel cell and high pressure steam turbine technologies are the best candidates for use in the supply plan scenarios. However, the diesel base case, which is continuation of current practices, will also be evaluated in the supply Plans. Table V-3 shows the economic evaluation of the heating technologies. Table V-3 ECONOMIC EVALUATION OF HEATING TECHNOLOGIES / : . Technology — Unit Cost (¢7kWh) Direct Combustion (coal) 5.3 District Heating (coal fired boiler) 5.8 Direct Combustion (fuel oil) 5.6 Electric Heating 12.3 These results indicate that direct combustion. using coal is the best technology in this category, followed by district heat-: ing using a coal-fired boiler, and the base case (direct combus- tion using fuel oil). Electric heating is the least favorable technology for supplying heat energy due to the high cost of electricity. Table vV-4 shows the economic evaluation of the combined electricity and heating technologies. bp. Table V-4 ECONOMIC EVALUATION OF ELECTRICITY & HEATING TECHNOLOGIES Technology : Unit Cost (€7kWh) Cogeneration w/District Heating 5.1 Combustion Turbines (oil-fired), Combined Cycle w/Electric Heating — 9.4 Fuel Cells (w/district heating) 5.7 Combustion Turbines (w/heat recover) 7.9 The results of this evaluation show that the technologies of cogeneration with district heating and fuel cells with dis- trict heating have a cost advantage over the combustion turbines (oil-fired) combined cycle with electric heating. Table V-5 shows the economic evaluation of ‘the support technologies. . Table V=5 ECONOMIC EVALUATION OF SUPPORT TECHNOLOGIES Technology Unit.Cost (¢/7kWh) Wind -Generation 1.6 Passive Solar - The use of wind power to augment the electrical systems supply appears to be an economical technology. Technology Selection The results of the economic evaluation indicate that sever- al technologies would be suitable for formulating energy supply plans for the Bethel Area. They are: Cogeneration (coal-fired) with District Heat Fuel Cells Diesel (base case) Direct Combustion (base case) v-4 Direct Combustion (coal) Wind Generation (support) Passive Solar As shown in Table V-4, the two most-promising technologies are: . ° Cogeneration (Coal-fired steam plants with District heat) ° Fuel Cells Details of these two technologies are presented in Chapter VI. oo Chapter VI CONCEPTUAL DESIGNS, COSTS, AND ENVIRONMENTAL CONSIDERATIONS Introduction Based on the economic evaluation presented in Chapter V, a coal fired steam plant and a fuel cell plant were selected as the most viable options to supply electricity and heat to the Bethel Region. Both of these systems would also provide suffi- cient energy by-product heat so that a portion of the City of Bethel could be heated via a district heating system. The conceptual designs, cost estimates and environmental considerations for these two plants are described in this chap- ter. Conceptual Designs of Coal-Fired Steam Plants General Description The coal fired electrical generating plants considered for the Bethel area are typical of small coal fired plants. Coal will be stockpiled away from the boiler house. Pile management will be accomplished by using a bulldozer and front end loader. Coal in the storage area will be used on a first in, first out basis. Coal will be transferred into the plant by a conveyor, run through a crusher to obtain uniform size, and then stored in coal bunkers above the operating floor. From the coal bunkers, the coal will flow by gravity to mechanical stokers which will feed the fuel onto the boiler traveling grates where combustion takes place. The traveling grate continuously discharges the ash into the ash collection system. “os An emergency coal conveying system will be provided to allow continuous operation in the event of an unscheduled shut- down of the regular fuel supply system. The boiler make-up water will be taken from the city water system and will pass through a filter to remove any sediment which could cause premature deterioration of the demineralizer bed resins. A dual train cation/anion demineralizer is provid- ed, with each train capable of supplying one half of the maximum boiler feed water requirements. This allows both units operat- VIel a ing simultaneously to supply the water requirements for full boiler production on an emergency basis if normal return of the condensate is interrupted. A demineralized water storage tank with a six hour water supply will be provided. The required ‘boiler make-up will be drawn from this tank and mixed with the returning condensate, then passed through a mixed-bed type condensate polisher to remove any remaining impurities. The demineralizers are used to control boiler scaling and prevent silica from plating on the turbine blades. From the condensate polisher the feed water will go to a deaerating feed water heater which will heat and remove air and dissolved gases from the feed water before being pumped through the economizer and into the boiler. The feed water heater will have a storage capacity such that the boiler can operate at full load for ten minutes. Furnace bottom ash and fly ash from the various hoppers on the boiler and emissions control devices will be collected and transported to an enclosed ash silo by vacuum conveyors. The ashes in the silo will be emptied on a daily basis by a conveyor. with an ash conditioner or a dustless unloader. The ashes will be hauled by truck to the disposal area. Outside air for combustion will go through glycol air pre- heaters when weather conditions require, before entering the stack gas to combustion air-heat exchanger. Under these condi- tions the air is heated to approximately 400°F. This air supply will then be split with approximately 75 percent going to the . undergrate plenum and then through the fuel bed. The remaining 25 percent will enter the combustion chamber above the fuel bed via a series of nozzles along each side of the boiler. An oxygen analyzer in the flue gas stream-will automatical- ly adjust the air to fuel ratio to maintain optimum combustion efficiency. The combustion gases will leave the. furnace chamber through a combustion air heater and economizer, a multiclone type mecha- nical dust collector and a fabric filter to remove most of the particulate: material from the gas stream. before it enters the induced draft fan and is discharged to the atmosphere through the metal stack. The multiclone collector will give acceptable particulate removal however, with the proximity of the proposed plant to town, a fabric filter will be installed in order to further VI-2 vp ‘control particulate emission. With the fabric filter, notice- able particulate fall-out should be a rare occurrence. Steam turbine generators can be divided ‘into three groups depending on how exhaust from the turbine is handled. One type is the back pressure turbine. With this type, the steam from the turbine exhaust enters a process or steam heating process. As steam passes through the turbine, electricity is generated and useful work is performed by the steam in the pro- cess or heating system. In this type of turbine generator elec- tricity is the by-product. When no steam is required by the process or heating system, no electricity is generated unless an auxiliary steam air condenser to condense turbine exhaust is provided. The second type is a straight condensing turbine. In this " type of system, all the steam from the turbine exhaust is cooled and returned to the liquid state. This type of system provides maximum electrical generation for a given amount of steam but much of the heat in the steam must be discarded to the cooling medium when the steam is condensed. This system generates elec- tricity as it is required and heat is normally not recovered for process or heating use. . The third type of. turbine. generator is a combination of the first two. Steam which enters the turbine may go completely through the turbine and be condensed or it may go only part way through and be automatically taken off at some lower pressure for distribution to process or heating demand. When the need for process or heating steam decreases, the amount of steam to the condenser is automatically increased and adjusted to satisfy the electrical demand. If the amount of electricity required decreases.while the process or heating demand remains the same, then the amount of steam to the condenser decreases while the amount of steam to process or heating remains constant. For the Bethel plant only the last -two types will be consi- dered for use since electricity must be provided on demand. Power plants requiring. straight condensing machines will have air cooled condensers operating at a pressure of 2.5 inches of mercury ("Hg). Power plants with turbine-generator units arranged for by- product heat recovery will extract steam at 25 psig to heat water for a district heating system. Condensers on these units can be air cooled units operating at 2.5" Hg. When final design VI-3 bh parameters are established, the condenser operating pressures up to 25 psig should be considered. Automatic controls will allow the boiler to closely follow the electrical and district heating loads. The average electrical usage in the Bethel area in 2002 is estimated to be 4,129 kW based on the most likely projection. The estimated peak under this projection is 8,000 kW. There are two alternative approaches to meeting this demand. One alterna- tive is to size the coal-fired power generation plants to meet the peak electrical requirements, Another alternative is to size the coal-fired plants to provide electrical generation to meet the base load only, and utilize the existing diesel genera- tors at Bethel to meet the peak power requirements. The second alternative reduces the capital and operating costs by utilizing existing equipment but- increases fuel cost during the time the diesel generators are in operation. An optimization curve indicates the minimum cost/kWh of this type of system occurs at a coal plant size in the 3000-4000 kW range (Exhibit 7). Plant sizes of 10,000 kW, 15,000 kW and 20,000 kW were also considered, In these plants, the electrical power generated above the projected area requirements would be used for electric resistance heat for some of the isolated loads. Because of the complexity and sophistication of high pres- sure boilers, the operating pressure for the steam plants up to 19 MW for the Bethel area will be limited to 600 psig with a steam temperature of 750°F. For the 15,000. kw to 29,900 kW units, an operating pressure of 900 psig and a steam temperature of 900°F are used. District Heating System The preliminary evaluation of district heating for Bethel assumes a high pressure hot water system with a steam-to-water heat exchanger in the power plant delivering water at 250°F and returning water at 1f0°F, The system will-have a combination of underground .and above ground piping depending on engineering and aesthetic factors. It was also assumed that the peak electrical load and heat- ing load would occur simultaneously and, under this condition, the peak requirements of the district heat system would be pro- vided by the by-product heat recovery. viI-4 = ’ The efficiency of the selected system may be improved by overlaying the heating and power load curves and determining if the energy used to supply the peak heating load using supple- mental steam heat would more than be off-set by the additional heat recovery during off peak periods. For preliminary design, the heating season was assumed to be 5040 hr/year extending from October through April. The heat recovered was taken as 3150 Btu per kWH generated. This is equivalent to a 28 percent heat recovery for an engine with a heat rate of 11,250 Btu/kWh. The average power output of the generating plants during the heating season was determined by using electrical production data for the city of Bethel for 1981. These data indicate the fraction of the power generated in each month of the heating season, as shown below. ‘Month Percent of Annual October 8.6% November 9.9% December 11.6% January 11.5% February 10.0% March 8.8% April * 7.2% Total 67.6% The average energy usage for the year 2002 (most likely projection) was multiplied by 0.676 to obtain the average heat~ ing system load. . ! It was estimated that the maximum practical system would supply approximately 80 percent of the space and water heating requirements for the City of Bethel. The other 20 percent com- prise isolated loads such as the BIA complex where connection ‘to a central system would not be feasible. This maximum system would require approximately 12 miles of double piping (supply and return) ranging in size from 14" for the major trunk line to a minimum of 2-1/2" for the branch lines. To the extent possible, loop systems are included providing portions of the district heating system with a second. supply path in case the primary supply is interrupted. A map of the city of Bethel showing the energy usage per section and a layout for the district heating system is presented on Exhibit 8. VI-5 pd Description of Alternatives ‘ The following paragraphs. describe seven alternative coal fired steam generating facilities. Many of the characteristics described will vary with the size of the installation. A summa- ry of specifications for a standard plant of 10 MW is described { on Exhibit 9. The data presented are for a plant having straight condensing turbines and a plant having heat. recovery. The systems will have three boilers and two turbines. The two boilers will be used for operation and one will be for stand-by. Similarly, one turbine will be used for operation while the other is in a stand-by mode to provide peak power. Each system is capable of full operation with one boiler out of service. _. Coal Alternative 1: A 4,000 kW Coal-Fired Straight Con- densing Plant. This plant would provide a peak of 4,000 kW, of which 464 kW would be used in the plant and 3,536 kW would be available for distribution. The plant would consist of two 50,000 lb/hr shop assembled boilers and one 4,000 kW condensing turbine generator operating at 600 psig and 750°F. Each boiler would have the capacity to operate the turbine generator at full rating with the second boiler being used for stand-by. Two of the existing 2,100 kW diesel generators would be required along with the 4,000 kW steam turbine to meet the year 2002 peaks. All four of the existing diesel generators would be kept in service to supply emergency power. The plant load factor is estimated at 80 percent, making the average generation rate 3,200 kW, of which 371 kW would be used in the plant and 2,829 kW would be available for distribu- tion. The remaining 1,300 kW required to meet the Bethel area demand would be provided by the existing diesel generators. A flow diagram of this alternative is presented on Exhibit 10. Coal Alternative 2: A 4,000 kW Coal-Fired Plant With Heat Recovery. This plant would provide a peak generation of 4,000. kW, of which 548 kW would be used in the operation of the power plant and 3,452 kW available for distribution. This system consists of. three 50,000 lb/hr shop assembled i boilers and one 4,000. kW single automatic extraction condensing turbo-generator operating at 600 psig and 750°F. Two boilers would provide the peak power and heating requirements of the system. A third boiler would provide reserve capacity. The extraction steam would be used for the district heating system. This steam would supply 29.3 x 106 Btu/hr to the end user. VI-6 vp Approximately 25 percent of the average Bethel space and water heating requirement would be supplied by this system. This system could supply the hospital and the residential area north of the hospital east to Ridgecrest Drive and Willow Street, including the city office complex. Two of the existing 2,100 kW diesel generators would be required along with the 4,000 kW steam turbine to meet the 2002. peak demand. All four of the existing diesel generators would be kept in service to supply power during an emergency. The plant load factor for this plant is estimated at 80 percent making the average generation rate 3,200 kW, of which 476 kW would be used in the plant and 2,724 kW would be avail- able for distribution. The remaining 1,405 kW required to meet the Bethel area demand would be provided by the existing diesel generators. A flow diagram for this alternative is presented on Exhibit ll. Coal Alternative 3: 10,000 kW Coal-Fired Straight Condens- ary Plant. This plant can provide peak electrical generation of 7,000 KW, of which 947 kW would be used in the plant making 9,053 available for distribution. Normal peak operation in 2002 would be 8,837 kW with 837 kW used in the plant and 8,000 kW for distribution. Average operation would be at 4,870 kW with 741 kW for plant use and 4,129 kW for distribution. The plant would consist of three 70,000 lb/hr modular type boilers with two 5,000 kW condensing turbines operating at 600 psig and 750°F. Full generation can be maintained with one boiler out of service. Two of the existing 2,100 kW diesel generators would be required to provide emergency power if one of the 5,000 kW steam generators. is off line. A flow diagram for this alternative is ’ presented on Exhibit 12. : Coal Alternative 4: A 10,000 kW Coal-Fired Plant With Heat Recovery. This plant would generate a maximum of 10,000 kW, of which 1,241 kW would be used by the power plant making 8,758 kW available for distribution. Projected peak for 2002 would be 9,134 kW of which 8,000 kW would go for distribu- £i0n.« The average load would be 5,263 kW with 1,134 kW for the plant and 4,129 kW for distribution. The district heating system would provide an average of 72.7 x 106 Btu/hr which would supply approximately 62 percent of the space and water heating requirements for the City of Bethel. VI-7 bv? fe This system could supply Bethel Heights, the regional high school, the domestic water system, the Mission Lake area, and most of the area north of Third Avenue from Ridgecrest Drive northeast to Brown's Slough, in addition to the area described in 2. above. . The plant would consist of three 120,000 lb/hr modular type boilers and two 5,000 kW single automatic extraction condensing turbine generators operating at 600 psig and 750°F. Two of the existing 2,100 kW generators would be required to provide emergency power if one of the 5,000 kW steam genera- tors is off-line. A flow diagram for this alternative is pre- sented on Exhibit 13. Coal Alternative 5: A 10,000 kw Coal-Fired District Plant With Heat. This plant would generate a maximum of 10,000 KW of which 1,568 kW would be used by the plant, making 8,432 kW a- vailable for distribution. An average of 72.7 x 106 Btu/hr would be available from by~product heat recovery. An additional 20.6 x 106 Btu/hr would be provided by a supplemental boiler to supply approximately 80 percent of the heat required by the City Qf Bethel.. This district heating system would extend from Bethel Heights on the north, to the Bay, and from Brown's Slough on the east to the hospital area on the west. An, additional line would. extend to the airport complex and ~ pick up the trailer park and other loads adjacent to the state highway. This plant would consist of four 120,000 lb/hr modular type boilers and two 5,000 kW single automatic extraction tur- bine generators operating at 600 psig and 750°F, with extraction at 50 psig and the condenser operating at 2.5" Hg. Two of the existing 2,100 kW diesel generators: would be required for emergency power. A flow diagram for this alterna- .tive is presented on Exhibit 14. Coal Alternative 6: 15,000 kW Coal Fired Plant With Heat Recovery For District:'Heat. This plant would generate a peak of 15,000 kW of which 1,576 kW would be used by the plant and 13,424 kW would be available for distribution. Since the pro- jected electrical. demand is only 8,000 kW, a peak surplus of 5,424 kW would be available and could go to provide electrical neat for some of the more remote heating loads. This would amount to about 5.6 percent of the Bethel heating requirement. The recovery of by-product heat would provide an average of 83.4 x 106 Btu/hr to district heat, which would supply approxi- mately 71.5 percent-of the Bethel heating requirements. The. surplus electricity would supply an additional 5.6 percent of the total heating load. VI-8 de The system would consist of three 125,000 lb/hr boilers with two 7,500 kW single automatic extraction condensing turbine generators operating at 900 psig and 900°F, A flow diagram for this alternative is presented on Exhibit 15. Coal Alternative 7: A 20,000 kW Coal-Fired Plant With Heat Recovery For District Heat System. This plant would gen- erate a peak of 20,000 kW of which 2,059 kw oars be used by the plant and the balance (17,941 kW) would be available for distri- bution. Since the projected electrical demand is only 8,000 kW, a peak surplus of 9,941 kW with an average of 3,620 kW is avail- able and could go to provide electrical heat for some of the more inaccessible heating loads. This would amount to approxi- mately 10 percent of the total Bethel heating requirement. Recovery of by-product heat would provide an average of 90.8 x 10® Btu/hr to district heat or approximately 78 percent of the Bethel heating requirements. The system would consist of three 175,000 lb/hr coal-fired boilers and two 10,000 kW single automatic extraction condensing turbine generators operating at 900 psig and 900°F. A steam balance was performed for a 20,000 kW straight condensing plant for comparative purposes. A flow diagram for this alternative is presented on Exhibit 16. Summary of Alternatives A summary of operation parameters for the seven coal plant alternatives are presented on Exhibit 17. The data presented include the gross power output, the net power output (or amount available for distribution), the average Btu/hr input, the aver- age Btu/hr supplied to district heating, the percentage of the total Rethel heating requirement supplied, and the net waste heat recovered. The net waste heat recovered is the amount of heat recovered which would have been lost in the condenser in a straight condensing plant. Also shown is the annual coal re- quirement based on 10,000 Btu/1lb coal. The negative heat recovery for Plans 6 and 7 are an indica- tion of the overall inefficiency of using electrical resistance heat generated in thermal plants. Therefore, these plans are eliminated from further consideration. A conceptual layout of a typical coal plant is shown on Exhibit 18. VI-9 A fuel cell electrical power generator designed for utility applications provides efficient operation, is capable of operat- ing on a variety of fuels, and can be located in residential, commercial, or industrial sites. The power station has wide turndown capability and low minimum-power heat-rate characteris-— tics to enhance intermediate-duty application. Power plant features permit dispersed generation for use in the various villages. These features include automatic remote power plant operation, low emission and noise levels, and a heat rejection system which will be used to recover waste heat for cogeneration installations. The plant consists of a DC module, power conditioner, water treatment system, heat rejection system, and power plant con- troller. It is factory assembled on transportable pallets. Piping and wiring connections between pallets are made on site. The power station controller, which coordinates the operation of the power plant controllers and site auxiliary systems, is lo- cated in a control center along with the power plant control- lers. Remote control is available by installation of a control console connected by telephone lines to the site. . The plant also has flexibility as to fuel type. The fuel ““processor section of the DC. module can be adapted to various gaseous and liquid hydrocarbon fuels and alcohol fuels. Auxiliary subsystems provide the fluids and electrical power required for plant operation. Fluid subsystems provide fuel, pressurized air, nitrogen, hydrogen, water and waste man- agement. Electrical subsystems provide auxiliary power, unin- terruptible power, and safety monitoring. Operation of the standard power plant can be performed under three operation modes. These modes, programmed as operat- ing states in the power plant controller, are ON, OFF and HOLD. A. mode can be selected by the operator through the power plant control console. In the ON mode, all subsystems are operating. The plant May either be on load (50 to 100% power) or at zero power. In the OFF state, the plant is essentially at ambient temp- erature and pressure, with a passivation gas blanket to protect catalyst beds and fuel cells. Rated power is achievable within four hours from this condition. VI-10 bd HOLD is a non-power-producing mode designed for low-energy consumption while maintaining the power plant in a state of readiness. By periodic operation of burners and heaters for approximately one-half hour out of every 16 hours, the power plant is maintained in a condition from which rated power can be achieved within an hour. The power section is passivated and cell temperatures reduced to enhance cell stack life. The HOLD mode is especialy useful to provide high turndown and low part- power heat rate in multi-power-plant stations. An optional operating mode, STANDBY, can be incorporated to provide the ability to achieve rated power in either 15 seconds or 1 minute (time is also optional) from this non=power=-produc=- ing mode. STANDBY is a substitute for HOLD whenever rapid dis- patch to rated power is required. The selected fuel cell supply plan for Bethel is a 9 MW plant fueled by propane, with methanol as an alternative fuel. The plant would be composed of two 4.5 MW systems. The plant operates best in an ambient temperature between 25°F and 50°F. Therefore, the plant will be enclosed in a structure. The building will be approximately 80' x 20' and will not include the cooling towers or the fuel storage tanks. The three major subsystems; the power system, the fuel system, and the auxiliary support systems are described in the following paragraphs. A schematic diagram of the facility is shown on Exhibit 19. A conceptual layout of the facility is shown on Exhibit 20. Power System The power system is composed of the DC module, the power conditioner, the control system, the water treatment system, and the heat rejection system. These are described in the following paragraphs. ‘ DC Module. The DC module takes in the raw fuel and produ= ces DC power. It is composed of two sections, the cell stacks and the fuel processing unit. The cell stacks are a large number of individual cells connected in a series/parallel configuration. The stacks take in hydrogen-rich gas from the fuel processing unit and produce DC power to be transmitted to the power conditioner. There will be 8 stacks. at 675 kW using phosphoric acid as the electrolyte. The cells will be the advanced type operating at 120 psia. VI-11 bp The fuel processing unit varies, depending on the fuel feed stock, but has basically the same configuration. The function of the fuel processor is to convert the fuel into a hydrogen- vich gas and to remove substances not tolerated by the fuel cells (i.e., sulfur and carbon monoxide). The major components of the system are: the hydrodesulfurizer and zinc oxide beds, which remove sulfur compounds; the reformer, which converts the fuel to a hydrogen=-rich gas; and the high and low temperature shift converters, for transforming carbon monoxide and water to carbon dioxide and hydrogen. For sulfur-free fuels, the hydro- desulfurizer and zinc oxide beds are by-passed. This unit will have a capacity of 2,500 lb/hr of gaseous fuel. When the unit is operating on methanol, there is an additional vaporizer with an isolation valve to the HDS sub-unit. Power Conditioner. The power conditioner converts the unregulated output of the DC module to three phase, 60 Hertz AC power at utility line voltages. The DC output is fed through a breaker to an inverter which converts it to a three phase AC quasi-square wave. The square wave is then fed through a series reactors and a harmonic cancellation transformer to shade the wave to a clean sinusoidal form. This output is then fed to an output transformer to step it up to line- voltages (12). The power conditioner will operate at 4,500 KVAR. Control System. The control system includes a station controller and a controller for each subsystem. The station controller coordinates the actions of the various subsystems. Water Treatment. The water treatment system supplies water for thermal management and for the fuel processing unit. The water is supplied both from storage and condensate from the fuel gas stream. Dissolved gases and suspended solid contaminants are removed and the water is heated prior to being pumped to. the “DC module. The storage capacity of the water treatment system - ‘will be 20,000 gallons... The inlet flow rate will be 290 gpm at 200°F (max.)’ with an output flow rate. of 290 gpm at 30 psig and 40 to 150°F. Heat Rejection System. Heat rejection is accomplished through cooling plates. within the stack. Heat is transferred through a series condenser to air cooled heat exchanger or a waste heat recovery system. This. system will reject. approxi- mately 35 x 106 Btu/hr, which could be used in a district heat- ing system. The. temperature of the rejected water will vary from 200-250°F.. An auxiliary cooling tower will also be used to reject excess process heat. VI-12 hb Fuel System The fuel system stores and supplies the raw fuel for the fuel processor. The system is composed of storage tanks, pump, piping, and filtration equipment. The fuels and system .compo~ ‘nents are described below. Fuels. The power plant can operate on a light distillate fuel, natural gas, SNG, LNG, propane (LPG), methanol, biomass, and waste treatment and process by-products. The baseline light . distillate fuels can be any of a variety of light hydrocarbon fuels derived from petroleum or coal. For Bethel, the primary fuel will be propane, with methanol being an alternate. Propane will be shipped by rail barge in 30,000 gallon rail cars. Docking facilities and a grid for the barge to rest upon at low tide will be constructed near the plant. At the docking facilities, a pump house will be in- . Stalled to pump the fuel from the -barge to the storage tanks. The fuel transfer pumps will be about 25 hp. Piping from the dock to the plant will be approximately 1,000 ft in length. Methanol could be handled in a similar manner. . A more detailed description of the fuels is presented in Appendix C~2. Fuel Storage. Storage facilities would accomodate a six months supply (approximately two million gallons of propane) and would be stored in seventy pressurized tanks with 30,000 gallon Capacity each. Fuel will be fed to the fuel processor at a maximum rate of 4,000 lb/hr at 200 psig through a 10 micron fil= ter system. Fuel Dump System.. The fuel dump system receives, condenses and stores fuel and water vapor released during shut down or an over pressurization.in the fuel processor. The waste collected will be disposed of periodically. The system is composed of. a storage tank (2,500 gallon), piping, and inflow regulation. Auxiliary Support System Auxiliary support systems required for operation include: air supply, gas supply, auxiliary power, water supply, and site piping. These are described below. Air Supply. This system supplies pressurized air for pneu- matic controls, power section passivation, and turbo compressor starting. For control air the flow required is 120 standard cubic feet per minute (scfm) with a maximum of 1,220 scfm for VI-~-13 bp three seconds. The turbo compressor supply required is 8,000 scfm for thirty seconds. - Gas Supply. This system supplies nitrogen and hydrogen to the DC module. Nitrogen is used for system pressurization and purging. Hydrogen is used for passivation during start up and shut down and fuel processing system START. Nitrogen supply is 3,000 lb storage with a flow rate of 400 scfm at 375 psig. Hydrogen supply is 100 lb storage with a 25 lb/hr flow rate at 375 psig. Auxiliary Power. This system would supply power for opera- tion of on-site electrical equipment normally supplied from plant output while in operation. Start-up power is supplied from existing diesel generators. The transformer at the plant is rated 1,000 KVA. Also required is 40 KVA available power from an uninterruptible source. Water Supply. This system collects and stores condensed process water from the DC module and supplies make-up water if required. It also supplies water to the water treatment system. The system is composed of 6,000 gallons of storage, piping, and controls, .with an outflow rate of 100 gpm. Site Piping. Piping requirements include: fuel supply “and drain lines, water feed and condensate lines, steam lines, water coolant lines, nitrogen, hydrogen, control air, and fuel vent lines. : : Power Plant Specifications This specification of the fuel cell power plant will deter- mine its characteristics and capabilities. The plant specifica- tions are presented in the following paragraphs. _ Performance. ‘The: performance characteristics of the stan- dard power plant are listed on Exhibit 21... Power and Transient capability. The power plant has a nominal net electrical rating of 9 MW at unity power factor. The power range is 50% to 100% of rating. Reactive power up to 9 MVAR is available. No-load power factor correction is pro- vided when the power plant is OFF, or at STANDBY. Real power transients take 1 MW/sec when on LOAD. Rated power is available within l hour from HOLD, and 15 to 60 seconds from STANDBY. Reactive power transients can be completed within 0.20 seconds. Power. is delivered as three-phase, 60 Hz, alternating current, at utility line voltage. vI-14 rep Efficiency. At rated power, thé heat rate of the power unit is 8,300 Btu/kWh (HHV, net AC power) when operating on propane. This is equivalent to an efficiency of 44% on the’ lower heating value of the fuel. The power plant design has the long term potential of achieving a heat rate of 7,400 Btu/kWh through ‘technological improvements. Startup Time. Power plant startup takes four hours when the components are at ambient temperature. Restart takes less time when the components are still warm, e.g., 2.5 hours after a 60-hour shutdown, Restart takes 15 to 60 minutes from HOLD, which is the most economical non-power producing state. Energy and Consumables. The power plant consumes a small amount of electrical power (20 kW) in the OFF state. An average of 0.5 million Btu/hr thermal energy as fuel and 150 kW electri- cal energy are consumed during HOLD to keep the power plant in a state of readiness for dispatch to rated power within an hour. At rated power, the power plant consumes 74 million Btu/hr as fuel to produce 9 MW net AC power, and consumes up to 500 kW of electrical power for its auxiliary loads. During transitions between operating modes, nitrogen and hydrogen are used for purging and passivating catalyst beds and fuel cells. : Reliability. Based on estimated failure frequencies and mean corrective times, the unit is projected to have an availa- bility factor of 0.88 and a reliability factor of 0.92. Availability Factor = FOH + POH PH Reliability Factor = FOH PH Where: PH = Period Hours = SH + RSH + FOH + POH : SH = Service Hours . : RSH = Reserve Shutdown Hours FOH = Forced Outage Hours POH = Planned Outage Hours Power Turndown. The standard power plant operates between half and full power and at zero power. Additional controls could enable the power plant to operate continuously from zero to full power. Operation. The three operating modes of the standard power plant are ON, OFF, and HOLD. The controller provides for com- pletely automatic, local and remote operation. The operator has the capability of placing the power plant in any of. the three operating modes. The unit is designed as a dispatched load VI-15_ generator connected to a large electrical grid (line parallel). As an option, it can be configured for isolated, load- ~following Operation with "“black=-start" capability. . Part-Power Heat Rate. The heat rate at low power for a ‘single power plant installation can be reduced with the addition of a partial-flow turbocompressor and controls. fThe heat rate characteristic of a power plant designed for transition from one turbocompressor to the other at 30 percent power is shown on Exhibit 22. The heat rate at 30 percent power is 8,600 Btu/kWh. This efficiency is for the overall system efficiency. The elec- trical efficiency of the DC module actually increases with a decrease in load. Cost Estimates The cost estimates for the thermal alternatives. (coal-fired - steam plants and fuel cells) are presented in the following paragraphs. These estimates are based on manufacturer's quotes and engineering estimates. Coal-Fired Steam Plants The costs of the coal-fired steam plants for Coal Alterna- tives' 1 to 5 are presented on ExHibit 23. Coal Alternatives 6 and 7 were not. costed because they.would result in negative heat recovery. Pages 1 through 5 of Exhibit 23 present a detailed construction cost of each plant. The construction costs -in- clude: civil/structural, mechanical, electrical, piping, instru- mentation, profit, contingency, and engineering. Page 6 of Exhibit 23 summarizes the plant construction costs, district heating capital costs, annual O&M costs, and annual fuel costs. Fuel Cell Plant .Construction Costs. A summary of the costs is presented in: Exhibit 24. The installed plant. cost is estimated at $l, 300/kW.. For the 9 MW plant, this cost is $11.7 million. -The structure for the power plant will be 160,000 cubic feet (80 x 100 x 20). It is estimated that this structure will cost $1,200,000. The fuel storage for this system will be seventy 30,000 gallon tanks at a total. estimated cost of $2,100,000. The fuel off-loading and docking facilities will require a barge grid and a dock at a cost of $414,000. The piping and plumbing of this facility will require 1,000 feet of pipe at $200,000, and a pumping station at a cost of $30,000. The total estimated cost of the fuel off- loading and docking. facility is $644,000. The installation of waste heat recovery for district heat would cost approximately $3,000,000. VI-16 Dig: ration and Maintenance Costs. The cost of operation and maintenance of a fuel cell system is approximately 0.40¢/kWh. The average cost per year over the study period is $112,197. Fuel Costs. Fuel costs will vary accordingly to the fuel used, For this plant, propane will be used. The estimated cost of propane delivered to Bethel is 0.96¢/gal. Using a heat rate of 8,300 Btu/kWh (HHV), the fuel cost per kilowatt hour is 8.631¢/kWh. This corresponds to an average yearly cost of $2,421,000 over the study period. The price-of propane is re- latively stable and is expected to remain so throughout the study period. The price is projected to escalate at the infla- tion rate because of high production potential and limited de- mand. Environmental Considerations Environmental restrictions on power plants involve the Clean Air Act, which establishes ambient air quality standards for pollutants such as sulfur dioxide, nitrogen dioxide, and total suspended particles. Areas that presently do not meet the ambient air quality standards are labeled non-attainment areas. In such areas, new or modified sources of pollutants, with po- tential emissions exceeding 100 tons pet year, must obtain per- mits from local control agencies to construct and operate. Coal-Fired Steam Plants ~~ Environmental considerations. for a coal-fired steam plant involve ash disposal, smoke stack emissions control, and possi- bly runoff from the coal storage area. Ash produced in the boilers can range from 5 percent to 10 percent of the fuel input. The ash is stored by the ash handling system for later disposal, usually in a land fill. Smoke stack emissions are mainly composed of particulate, with some nitrous oxides (NO,). Particulates are mainly un- burned carbon and some light *¥1y ash. If the coal used has a high sulfur content sulfur oxide (so,) emissions could also he a problem. However, this is not ‘characteristic of Alaskan coals. Particulates can be controlled through the use of me—- chanical collectors, electrostatic precipitators, or fabric filters. Legislation concerning emission controls specifies that the best available control technology be used, i.e. fabric filters. NO, emissions can be controlled, when required, hy the regulation of the temperature in the combustion chamber. In areas of high precipitation, runoff from the coal pile _ can be a problem if not properly controlled. VI-17 For conventional coal steam and.gas turbine plants to oper- ate in non-attainment areas, extensive emissions control meas- ures are required. In some cases, such measures can be rela- tively costly, such as with a coal steam plant. Fuel Cell Plants Emissions from fuel cell systems are orders of magnitude lower than those from conventional coal plants and would only require nominal emissions control. This feature had much to do . with the selection of testing sites, as both Manhattan and Tokyo are areas with high energy requirements ‘and sow emissions re- quirements. Noise. The noise of 55dB(A) at 100 feet is below the back- ground for many industrial and commercial sites. Emissions. Emission levels are less than 10 percent of the levels allowed by the Clean Air Act. Table VI-1 shows. emission levels for standard operating conditions. . Table VI-1 EMISSION STANDARDS . Emission Components ~ Concentration Concentration (Tb/million Btu) (ib/MWH) NO, ' 0.020 0.20 So, 0.0003 : 0.003 Particulates . 0.00003 0.0003 Smoke , None None VI-18 by 1. 2. 4. 5. Te 8. 9. 10. ll. 12. REFERENCES Lapedes, Daniel, ed., Encyclopedia of Energy McGraw-Hill Book Company, New York, 1976. Considine, D.M., ed., Energy Technology Handbook McGraw- Hill Book Company, New York, 1977). "Low-Rank Coal Study, National Needs for Resource Develop= ment - Peat", Vol. 6, Dept. of Energy Contract DE-AC18- 79FC10066, 1980. Northern Technical Services’ and Ekono, Inc., “Peat Resource Estimation in Alaska", Vol. 1, Dept. of Energy Contract DE- FGO1-79ET14689, November 1980. Ibid, Vol. 2. Anson, D. et al., "The Potential for Use of Peat Blends with Coal for Electric Power Generation", presented at Joint ASME/IEEE Power Generation Conference, October 4-8, 1981,° St. Louis. : Reid, Collins Alaska Inc., "Use of Wood Energy in Remote Interior Alaskan Communities", for Alaska Division of Ener- gy and Power Development, September 1981. Dames & Moore, M. Feldman: Personal communication, 1982. Reid, Collins Alaska Inc., "Forest Development Potential in the Middle Kuskokwim", prepared for Kuskokwim Native As-=- sociation, June 1981. Ayres, R.V. and McKenna, R.P., Alternatives to the Internal Combustion Engine The John Hapkins University ‘Press, Balti- more, MD 1973. Cross, F.L. Jr., "Hidden Costs of Industrial Boiler Conver- ’ sion to Coal", Pollution Engineering, February 1979. "Fossil Energy Program Summary Document, FY1980" U.S. Dept. of Energy, January 1979. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. REFERENCES (cont'd) U.S. Congress, House, “Energy from the Ocean," prepared for the Subcommittee on Advanced Energy Technologies. and Energy Conservation Research, Development and Demonstration of the Committee on Science and Technology, 95th Congress, 2nd Sess., April 1978. , "Tidal Power Study", U.S. Energy Research and Development. Administration (ERDA), Division of Geothermal Energy, March 1977. "Project Interdependence: U.S. and World Energy outlook through 1990", November 1977. Energy Research Digest, November 20, 1978. Maury, M.F. The Physical Geography of the Sea, ca. 1854. Green, J.A., "Self-contained Ocean Resources Base", Marine Technology Society Journal, 4(5), 1970. Heronemus, W.E., et.al. "On the Extraction of Kinetic Ener- gy from Oceanic and Tidal Currents", Proceeding of the Mac . Arthur Workshop on the Feasibility " oF Extracting Usuable Energy from the Florida Current. Stewart, H.B., ed. NOAA, Miami, 1974. Steelman, G.E., "An Invention Designed to. Convert Ocean Currents into Usable Power", Proceeding of the Mac Arthur Workshop on the Feasibility of Extracting Usable Energy rom the Florida Current. Stewart, H.B. Ed. NOAA, Miami, 1974. : Manor,’ Walter, E., Jr., "Solar Energy-, Its Time is Near", Technology Review, December 1973. "Solar, Geothermal, Electric and Storage Systems Program Summary Document", U.S. Dept. of Energy, DOE/ET~0041(78)’, March 1978. Energy Research Digest, September 25, 1978. hin. 24. 25. 26. 27. 28. 29. REFERENCES (cont'd) Maycock, Paul D., "The Development of Photovoltaics as a Power Source of Large Seale Terrestrial Application", Thir- teenth IEEE Photovoltaic Specialists Conference. IEEE NO. 78CH1319-3 Washington, D.C. 5 June 1978. Barnett, A. et.al., "Achievement of 9.15 percent Efficiency in Thin Film CdS/CugS Solar Cells", Thirteenth IEEE Photo- voltaic Specialists Conference, Washington, D.C. IEEE No. 78CH1319=3, June 5, 1978. , "Geothermal Energy Prospects for the Next 50 Years", Elec- tric Power Research Institute, (Preliminary Report to the World Energy Conference) ER-611-SR, February 1978. Berman, Edward R., Geothermal Ener Noyes Data Corpora=- tion, Park Ridge, New Jersey, 1975. ““"Update Nuclear Power Program Information and Data", U.S. Dept. of Energy, Division of Nuclear Power Development, Sept. 1978. - . "U.S. Energy Supply Prospects to 2010", Committee on Nu- clear and Alternate ‘Energy Systems, Supply and Delivery Panel, 1979. dey TEMPERATURE °F EXHIBIT 1 1000 900 800 700 600 500 400 $ GASOLINE JET FUEL KEROSENE Oo 10 20-30 40 50 60° ‘70 80. 90. {00 PER CENT CRUDE OIL. 300 200 100 ALASKA POWER AUTHORITY: BETHEL AREA POWER PLAN: FEASIBILITY ASSESSMENT DISTILLATION RANGE OF PETROLEUM PRODUCTS FROM CRUDE OIL en STEFANO & ASSOCIATES, inc. CORSULTING ENGINEERS: ANCHORAGE. ALASKA HARZA ENGINEERING COMPANY December 1982 by Criteria Unit Energy Cost Resource Availability Degree of Commercialization Adaptability to Bethel Region Community Acceptance Environmental Considerations Equipment Sophistication/ Training TOTAL ELECTRIC POWER TECHNOLOGY EVALUATION Diesel Electric , Base Case 13 10 10 15 10 10 74 Steam Turbines 19 10 10 15 70 EXHIBIT 2 Gas/Oil Fired Combustion Turbines 20 10 10 15 7 10 76 Nuclear Energy 23 5 10 10 26 Organic Rankine Cycle 20 10 7 15 63 Ocean Energy 2S 15 4 10 10 32 Fuel Cells 21 72 Geo- thermal 15 Solar 15 61 EXHIBIT 3 HEATING TECHNOLOGY EVALUATION Heating by . District District Direct Electric Heat Solar Heat. Heat Criteria Combustion Heating Pump Heating (Geothermal) (Steam/HW) Unit Energy Cost : ' 24 18 22 19 24 23 Resource Availability 5 10 10 7 o 10 Degree of Commercializa- tion . 10 10, 10 10 10 10 Adaptability to Bethel Region : 15 15 0 5 -30 15 Community Acceptance 10 7 7 7 7 7 Environmental . ‘ Considerations 10 10 ' 10 15 5 10 Equipment Sophistication/ ‘ Training 10 10 - 10 6 0 4 TOTAL 84 80 69 : 69 3 79 EXHIBIT 4 ELECTRICITY AND HEATING TECHNOLOGY EVALUATION Criteria Unit Energy Cost Resource Availability Degree of Commercialization Adaptability to Bethel Region Community Acceptance Environmental Considerations Equipment Sophistication/Training TOTAL Cogene- ration Systems 18 10 10 15 16 10 6 79 Combustion Turbine Combined Cycle Systems 20 10 9. 41s 10 10 4 76 Coal Gasifi- cation Combined Cycle 10 10 | 9 10 55 Geo- thermal 15 Solar 14 15 4 10 7 10 8 68. EXHIBIT 5 SUPPORT TECHNOLOGY EVALUATION . Wind Passive Active Ocean Criteria Systems Solar Solar Geothermal Technolologies Unit Energy Cost 10 20 20 12 13 Resource Availability ” A5 10 10 0 15 Degree of Commercializa- : tion : : 8 9 9 8 : 0 Adaptability to Bethel . Region 10 5 5 -30 5 Community Acceptance , 8 . “15 7 4 10 _ Environmental . Considerations : . 10 5 10 5 0 Equipment Sophistication/ Training 6 10 6 0 0 TOTAL : 75 74 67 2 . 58 Technology Oil Fired Turbines Diesel Fuel Cells Direct Combustion Electric Heating Coal-fired Steam Electric Turbine Cogeneration w/District Heating Wind Generation EXHIBIT 6 COST OF POWER EVALUTION CRITERIA ., Capital Cost 750-1, 400 1,200-1,600 1,300 10 40 2,100-3,100 3,500 2,160-5,183 O&M Costs (&7kWh) 2.80 5.00 0.40 0.40 0.40 1.7 1.7 0.4 Design Life Tyears) 20 20 20 20 20 20 20 20 Heat Rate TBtu7kwh)- 9,500 10,300 7,500 4,266 ‘3,500 12,500 4,500 0 Fuel No. 2 Diesel No. 2 Diesel Propane No. 2 Diesel Electricity Coal Coal Air Heating Value tu/Unit 138,000 Btu/gal 138,000 Btu/gal 19,774 Btu/gal 138,000 Btu/gal 8,500 Btu/1b 8,500 Btu/1b Fuel Price init $1.60/gal $1.60/gal $0.195/1b $1.60/gal $100/ton $100/ton 17.4 17.0 16.6 16.2 15.8 15.4 ESTIMATED TOTAL COST, CENTS / KWH . 15.0 14.6 ‘142 NOTE: Bass: load supplied by cosl,. with diesel for peaking. by, i EXHIBIT / 3000 4000 5000 6000 700° COAL. PLANT CAPACITY, KW: ALASKA POWER AUTHORITY BETHEL AREA POWER PLAN. FEASIBILITY ASSESSMENT OPTIMAL COAL PLANT CAPACITY COMBINED COAL AND DIESEL GENERATION: HARZA ENGINEERING. COMPANY CONSULTING. ENGINEERS amrunmece 2: seme EXHIBIT 8 A i po a on © —w) 2 HIGH SCHOOL 4 C y £ : gD © 5.0% , 42 x 10° BTU/HR O NeJ fon \ GPM. 4000 GPM NM BROWN’S SLOUGH > PROPOSED SMALL BOAT HARBOR ® WA ey , 8.4% - FULL AREA 3 (5.1% for 60% of Area) \ N \ 2415 GPM 7 \ RIVER QJ PROPOSED PLANT LOCATION TRAILER . PARK oe LEGEND: / a) SUB AREA A i ---— SUBAREA BOUNDARY O ae / —— DISTRICT HEATING LINES 4 Pog ALASKA POWER AUTHORITY BETHEL AREA POWER PLAN ip FEASIBILITY ASSESSMENT BETHEL PROPOSED DISTRICT HEATING SYSTEM / SCALEO 500 1000 FEET IN ee STEFANO & ASSOCIATES, INC HARZA EN@)NEERING COMPANY CONSULTING ENGINEERS . ANCHORAGE, ALASKA December 1982 atte caiaeatiaaeemaeemenie nee eer areca egee ares Component Quantity Boilers 3 A. Stoker System 3 B. Combustion Air 3 Heating Cc. Emissions Control 3 D. Ash Handling 3 System E. Fuel Supply 3 System F. Fuel Sizing z G. ID Fan 3 H. FD Fan~ 3 Water Treatment A. Demineralizer i: B. Condensate 1 Polisher Boiler Feed Water Pumps 3 Turbine Generators 2 Efficiency Turbine Water Rate Plant Heat Rate Electric Plant Heat Rate Overall Efficiency TYPICAL COAL-FIRED STEAM PLANT SPECIFICATIONS 10 MW CAPACITY Straight Condensing System 70,000 lb/hr Continuous discharge traveling grate Lungstrom type flue gas to air heat exchanger Fabric Filter System, 125,000 acfm Pneumatic conveyors from first and last pass and bottom ash discharge hoppers to storage silo, with an emissions control system. Flight conveyors and bucket ele- vators from coal storage to over- head coal bunker and distributors. Crushed to 1 inch minus. 58,200 acfm 15" Hg static 33,500 acfm 6.5" Hg static Dual train cation/anion Mixed bed parallel type Twelve stage turbine, 1650 ft head, at 250°F 3600 RPM Air cooled condenser 7,500 kW 9,150 KVA 4,160V 2 Pole 10.73 1b/kWh 18,611 Btu/kWh 18,611 Btu/kWh 18% Exhibit 9 With Heat Recovery 120,000 1b/hr 210,000 acfm 100,000 acfm 15" Hg static 57,500 acfm 6.5" HG static 3600 RPM Single auto- matic extrac- tion/condenser 25 psig ex-. traction 7,500 kW 9,150 KVA 4,160V 2 Pole 18.08 1b/kWh (Max. extraction) 28,187 Btu/1b 5,437 Btu/kWh 63%/12% EXHIBIT 10 3 2p00 LB/UR AVG, TURBINE FLOW PEAK BLR, Load] 48,500 IB/#R 4 MW PLANT re 3.2 MW AVG. 600 PSIG. - 750°F AVG. ourT9eutT = \ B200KW GROSS 2B2¢q KW NET T-G COND. ALASKA POWER AUTHORITY BETHEL AREA POWER PLAN FEASIBILITY ASSESSMENT TO BOILERS -U-F FLOW DIAGRAM COAL ALTERNATIVE 1 STEFANO & ASSOCIATES, INC. HARZA ENGINEERING COMPANY CONSULTING ENGINEERS — - ao RAC “ LASi te, ee Jv mbe- 2002 oe ° -——, EXHIBIT 11 | PEAK BLUR Load BB 000 Hu 4 MW PLANT 3.2 MW AVG. Op: RESERVE . AVG. TURBINE FLOW 600 PSIG. - 750°F 49,500 LG/HR DIST. HTG. SUPPLY ZA.3 KIO” BIUR . AVG. oviPUT 3200 KW GRoss 2T24KW NET DIST. HTG. : 19,000 LO/uR 30, 500 LB/RR, T-G COND. TO BOILERS ALASKA POWER AUTHORITY BETHEL AREA POWER PLAN FEASIBILITY ASSESSMENT FLOW DIAGRAM COAL ALTERNATIVE 2 (RN DN » (ray STEFANO & ASSOCIATES, INC. CONSULTING ENGINEERS ANCHORAGE, ALASKA HARZA ENGINEERING COMPANY December 1982 EXHIBIT 12 10 MW PLANT 4.870 MW AVG. RESERVE : o. AVG. TURBINE FLow 600 PSIG. - 750 F 50,000 LE/NR AVG. OUTPUT 48710 KW GROSS : 4124 KW NET TO BOILERS ALASKA POWER AUTHORITY BETHEL AREA POWER PLAN FEASIBILITY ASSESSMENT FLOW DIAGRAM COAL ALTERNATIVE 3 ayy HARZA ENGINEERING COMPANY STEFANO & ASSOCIATES, INC. CONSULTING ENGINEERS . Coot ADR AG TASH oom Porn 2702 pn EXHIBIT 13 PEAK BLR Load 218,000 La/HR 10 MW PLANT S. O91 MW AVG. “RESERVE AVG. TURBINE FLOW. 600 PSIG. - 750°F 93,500 LB/NR SUPPLY 12.1 10% BIUH [seo] . AVG. OUTPUT 5041 KW GRoss 4129 Kw NET DIST. HTG. 1Z00o LA/uR 15,500 L6/WR T-G COND. CA TO BOILERS ALASKA POWER AUTHORITY BETHEL AREA POWER PLAN FEASIBILITY ASSESSMENT FLOW DIAGRAM COAL ALTERNATIVE 4 STEFANO & ASSOCIATES, INC. CONSULTING ENGINEERS ANCHORAGE, ALASKA HARZA ENGINEERING COMPANY December 1982 EXHIBIT 14 ' T PEAK BLE Loan + [33G,000 LA/Ke 10 MW PLANT 5. 308 MW AVG. 120,000 Le/w RESERVE SUPPLE MENTAL Heat q AVG. 20.6 x 10° BIUH . ‘ . | AVG. TURBINE F 600 PSIG - T50°F 915,500 LB/He@. DIST. _HTG. SUPPLY '93.3x (0° BMH ! AVG, QuTPUT [smu] (S808 KW Gross 4129 Kw NET DIST. HIG. 20,000 LB/KR 75,000 LB/4R’ TO BOILERS ALASKA POWER AUTHORITY BETHEL AREA POWER PLAN FEASIBILITY ASSESSMENT FLOW DIAGRAM COAL ALTERNATIVE 5 HARZA ENGINEERING COMPANY Pacamber 19R2 STEFANO & ASSOCIATES, INC. CONSULTING ENGINEERS A ORAGT “\ASK EXHIBIT 15 PEA BLA Load ZEQSC LE/UR | 15 MW PLANT 7.315 MW AVG. 12,000" Le/ne, RESERVE | AVG. Exteaction Flow BIqz,000.LB/He AVG, TURBINE FLOW 122,000 LB/HR . eo0 Psit, ~- e00°F pIST. HYG. SUPPLY AVG. DIDT, HEAT | B3.4K1D® BIUH DRAIN CLR. fe DIST. HTG. = ‘ AYA. Conn, Fuse 1" 35,000 Le/He, ALASKA POWER AUTHORITY BETHEL AREA POWER PLAN FEASIBILITY ASSESSMENT —° TO BOILERS FLOW DIAGRAM COAL ALTERNATIVE 6 HARZA ENGINEERING COMPANY STEFANO & ASSOCIATES, INC. COMSULTING ENGINEERS ANCHORAGE, ALASKA December 1982 ‘EXHIBIT 16 _ | PEAK ALE LOAD 335,500 Le/we 20 MW PLANT 9.326 MW AVG. RESERVE | AVG. EXTRACTION PLOW Mit000 LO/HR WATER HTR. : AVG, DIST. HEAT [0.8 K10© Brun 900 PSIG. - @00°F DIST. HTG. AVG. Coun FLOW 42,000 L8/HR ALASKA POWER AUTHORITY BETHEL AREA POWER PLAN FEASIBILITY ASSESSMENT TO BOILERS FLOW DIAGRAM COAL ALTERNATIVE 7 ey ee STEFANO & ASSOCIATES, INC. HARZA ENGINEERING COMPANY CONSULTING ENGINEERS _ ANCHORAGE. ALASKA _ — — — — — JFros-mber. 1982 _ Exhibit 17 COAL ‘PLANT OPERATION PARAMETERS Average Power Average Average . (kw) . Net Energy Energy to Thermal Supply Plans Gross Net Ener Input Dist. Heat * (MM eiyr) (MM Btu7yr) (MM Btu/7hr) 1. 4,000 kw Straight Cond, 3,200 2,828 24.8 60.1 0 2. 4,000 kW W/H Recovery 3,200 2,724 23.9 75.7 29.3 3. 10,000 kW Straight Cond. 4,870 4,129 36.2 90.7 . oO 4 10,000 kW W/H Recovery 5,091 4,129 36.2 143.5 72.7 5. 10,000 kw W/H Recovery & . Supp. Steam 5,308 4,129 36.2 191.3 93.3 6. 15,000 kw W/H Recovery 7,315 6,102 53.5 203.7 90.12/ 6a. 15,000 kW Straight Cond. 2/ 5,031 4,129 36.2 87.4; . 0 7. 20,000 KW W/H Recovery 9,326 7,745 87.8 263.4 102.83/ Ja. 20,000 kw Straight Cond.2/ 5,312 4,129 36.2 91.9 0 i/ Included for comparison only 2/ Average electric heat of 1,973 kW included 3/ Average electric heat of 3,620 kW included Frac/Bethel Tot/Ht/1d. percent 0 * 25 62 80 77 88 Average ( Btu/hr o 13.7 19.9 11.5 -25.5 -47.1 Coal Requirements tt Ton/7yr) 26.3 33.2 39.7 62.8 83.8 89.2 38.3 115.4 40.3 EXHIBIT 18 1000° XA *— TYPICAL COAL PILE 150° x 60° x 15° 2,278 TONS ZN FUTURE BOILER I i mT guanine | 4 N-/ te aT COAL PROCESSING ‘ ta BAG HOUSES L Lo |} =| K\_ 7 AIR CONDENSERS ABOVE Py TURBINES ALASKA POWER AUTHORITY SCALEO, 50 100 FEET BETHEL AREA POWER PLAN b1 dt . FEASIBILITY ASSESSMENT _ CONCEPTUAL LAYOUT COAL PLANT STEFANO & ASSOCIATES, INC. L. . . _ _ - . . . . . CONSULTING ENGINEERS © . ~ _ Lae f—- : i FO oo ‘ oo ~ a RAC Las’ . a pu oo mbe 2 HARZA ENGINEERING COMPANY EXHAUST AIR INTAKE TURBO — 7 7 AUXILIARY BURNER REFORMER AIR HEATER AIR HIGH TEMPERATURE SHIFT CONVERTER REFORMER FUEL HEATER ZINC HYDRO OXIDE BEDS DESULFURIZER EXHIBIT 19 CATHODE EXHAUST ER COOLER Pow! CONDITIONER AC ICOWER STEAM ELECTRICITY ‘tod | | water STEAM 1 SEPARATOR POWER WATER SECTION TREATMENT SYSTEM AIR | WATER AIR | STEAM | FUEL COOLING UNIT FUEL GAS COOLER LOW TEMPERATURE SHIFT CONVERTER FUEL INLET en STEFANO & ASSOCIATES, INC. CONSULTING ENGINEERS ANCHORAGE. ALASKA ALASKA POWER AUTHORITY BETHEL AREA POWER PLAN FEASIBILITY ASSESSMENT SCHEMATIC DIAGRAM FUEL CELL PLANT HARZA ENGINEERING COMPANY December 1982 EXHIBIT 20 — , COOLING : : COOLING . | TOWER CONTROL TOWER CENTER : WATER POWER TREATMENT POWER CONDITIONER . CONDITIONER WATER TREATMENT | | | | | | | | | | | I | | | | | | I | | | | | | I | | | | | | e i cs So CELL CELL = STACKS STACKS FUEL FUEL PROCESSOR PROCESSOR 1 “H2 No AIR WATER WASTE | STORAGE STORAGE STORAGE STORAGE STORAGE ' | FUEL SUPPLY SYSTEM | ALASKA POWER AUTHORITY BETHEL AREA POWER PLAN FEASIBILITY ASSESSMENT CONCEPTUAL LAYOUT -PUEL CELL PLANT ey STEFANO & ASSOCIATES, INC. HARZA. ENGINEERING COMPANY CONSULTING ENGINEERS Exhibit 21 Page 1 of 2 - ‘FUEL CELL PLANT PERFORMANCE Activity Real Power Rated Minimum Reactive Power Real Power Transients .On Load From Hold Reactive Power Transients Minimum to Rated Power Form and Quality Output Voltage - Output Frequency Harmonics Voltage Regulation Fault Current Efficiency Heat Rate Rated Equivalent Efficiency - Startup Time Startup from Ambient Temperature Startup from Hold Performance 9 MW net AC at sea level O MW net AC, continuous turndown to 50% power Up to 9 MVAR at + 90° 1 MW/sec up transient 15 to 60 minutes to rated 0.2 second Available to match standard grid voltages between 4 and 69 kVac, 3-phase. Nominal 60 Hz (will follow grid frequency between 61 and 57 Hz) . All triplens plus 5th, 7th, llth, and 13th harmonics cancelled. All other harmonics (17th and higher) reduced to less than 1% of fundamental for any single harmonic. 2% line-to-line unbalance +5% voltage level at rated power +10% to 20% voltage level at reduced power . Limited to 1.1 per unit, RMS for one cycle 8,300 Btu/kWh (HHV, net AC power), 7,500 for advanced concept cells 44% 4 hours Up to 1 hour FUEL CELL PLANT PERFORMANCE Ener and Consumables Used Snergy and During Power Plant Modes OFF HOLD ON (at rated) Transitions Between Power Plant Modes Start UP Shutdown Hold to On On to Hold Reliability Availability Factor Reliability Factor Fuel MMBtu/hr None 0.50(avg) 91.0 Fuel MMBtu/hr 60 None 14 None 0.88 0.92 Electrical kW 20 150(avg.) 500 Electrical kW 7,500 2,900 1,100 Negligible No pph Negligible Negligible None NQ pph 3,700 2,900 None Negligible Exhibit 21 Page 2 of 2 H2 ——pph___ Negligible 3 None HQ PPh 16 45 3 None co i = o S 8 HEAT RATE, Btu / KWH bi EXHIBIT 22 NET AG POWER, PERCENT OF RATED ex STEFANO & ASSOCIATES, INC. CONSULTING ENGINEERS ANCHORAGE, ALASKA ALASKA POWER AUTHORITY BETHEL AREA POWER PLAN FEASIBILITY ASSESSMENT HEAT RATE FOR FUEL CELL POWER PLANT HARZA. ENGINEERING COMPANY December 1982 Exhibit 23 COAL PLANT COSTS (Coal. Alternative 1: Item Mobilization & Demobilization Civil, Structural & Buildings Mechanical, Emissions Control Piping " Electrical Instrumentation Subtotals Profit 10% Subtotals (Direct Cost) Contingencies (10% of Direct Cost) Total Direct .Cost Engineering & Owner's Overhead (15% of Direct Cost) Total Construction Cost Page 1 of 6 4 MW Straight Condensing) Owner Furnished ($1000) 4,734 236 237 $5,207 $5,207 Contractor Furnished ($1000) 500 916 2,970 344 479 312 $5,521 552 $6,073 Amount ($1000) 500 916 7,704 344 715 549 $10,728 552 $11,280 1,128 $12,408 1,862 $14,270 Exhibit 23 COAI, PLANT COSTS (Coal Alternative 2: Item Mobilization & Demobilization Civil, Structural & Buildings Mechanical, Emissions Control Piping ‘ Blectrical Instrumentation Subtotals Profit 10% Subtotals (Direct Cost) Contingencies (10% of Direct Cost) Total Direct Cost Engineering & Owner's Overhead (15% of Direct Cost) Total Construction Cost Page 2 of 64 4 MW with Heat Recovery) Owner Furnished ($1000) 6,730 $7,281 Contractor Furnished ($1000) 500 976 4,294 395 479 Amount ($1000) 500 976 11,024 395) TLS 613 $14,223 696 $14,919 1,491 $16,410 2,461 $18,870 Page 3 of 6 -Exhibit 23 COAL PLANT COSTS (Coal Alternative 3: 10 MW Straight Condensing) Owner Contractor Item Furnished Furnished Amount ($1000) ($1000) . (szr000) Mobilization & Demobilization | 700. 700 Civil, Structural & Buildings 1,539 1,539 Mechanical, Emissions Control 10,683 6,757 17,440 Piping 759 "759 ' Electrical : 502 692 1,194 Instrumentation — 315 298 613 Subtotals . . $11,500 | $10, 745-$22-,245- Profit 10% 1,075. 1,075 Subtotals (Direct Cost) $11,500 $11,820 $23,320 Contingencies . (10% of Direct Cost) 2,330 Total Direct Cost , $25,650 Engineering & Owner's . , * Overhead (15% of Direct Cost) : 3,848 Total Construction Cost $29,498 bp. Exhibit 23 COAL PLANT COSTS Page 4 of 4 (Coal Alternative 4: 10 MW with Heat Recovery) Item Mobilization & Demobi lization Civil, Structural & Buildings Mechanical, Emissions Control Piping Electrical Instrumentation Subtotals Profit 10% Subtotals (Direct Cost) Contingencies ~ (10% of Direct Cost) Total Direct Cost Engineering & Owner's Overhead (15% of Direct Cost) Total Construction Cost Owner Furnished ($1000) 13,497 50.2 360 $14,359 $14,359 Contractor Furnished Amount ($1000) ($1000). 700, 700 1,658 1,658 8,535 22,032 759 759 - 692 1,194 340 700 $12,684 $27,043 1,268 = _1,268 $13,952 $28,311 2,831 $31,142 4,671 $35,813 Exhibit 23 COAL PLANT COSTS (Coal Alternative 5: Item Mobilization & Demobili zation Civil, Structural & Buildings Mechanical, Emissions Control Piping Electrical Instrumentation Subtotals Profit 10% Subtotals (Direct Cost) Contingencies (10% of Direct Cost) Total Direct Cost Engineering & Owner's Overhead (15% of Direct Cost) Total Construction Cost bp Page 5 of 6 10 MW with District Heat) Owner Furnished ($1000) 15,531 502 375 $16,408 $16,408 Contractor Furnished ($1000) 700 1,824 10,501 7389 692 350 $14,856 1,485 $16,341 Amount ($1000) 700 1,824 26,032 789 $31,264 1,485 $32,749 3,275 $36,024 5,404 $41,428. en ‘ - ‘ Page 6 of 6 Exhibit 23 COAL PLANT COSTS (Summary ) Plant District Heat Total Annual Oper. and Annual Capital Cost Capital Cost Capital Costs Maintenance Cost Fuel Costs al Alternative (Thousands of $) (Thousands of $) (Thousands of S$) (Thousands of $) (Thousands of 4,000 kw - : Straight Cond. 14,270 - 0 : 14,270 792 2,572 4,000 kw W/H Recovery 18,870 12,100 30,970 ws 832 3,247 10,000 kw Straight Cond, 29,498. 0 29,498 . 1,284 3,882 10,000 kw , W/H Recovery 35,813 33,300 69,115 1,374 6,141 10,000 kW W/H Recovery & Supp. Steam 41,428 42,200 83,628 1,484 8,195 Exhibit 24 ESTIMATED CONSTRUCTION COST OF FUEL CELL PLANT . Owner: Contractor Item “Furnished Furnished Amount . ($1000) ($1000) ($1000) Mobilization & Demobilization 700 —- 700 Fuel Cell System 11,700 . 11,700 Structural . 1,200 1,200 Fuel Storage : . 2,100 2,100 Fuel Off-Loading 644 644 Subtotals $11,700 $4,644 $16,344 Profit 10% 464 464 Subtotals (Direct Cost) $11,700 $5,108 $16,808 Contingencies (10% of Direct Cost) 7 2,521 Total Direct Cost $19,329 Engineering & Owner's Overhead (15% of Direct Cost) 2,899 Total Construction Cost $22,228