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Home My WebLink AboutKotzebue-Coal Fired Congeneration,District Heating And Other Energy Alternatives Feasibility Assessment-Volume One 1982Alaska Power Authority LIBRARY COPY KOTZEBUE Coal-Fired Cogeneration, District Heating and Other Energy Alternatives Feasibility Assessment VOLUME ONE by A JOINT VENTURE OF ARCTIC SLOPE TECHNICAL SERVICES, INC. RALPH STEFANO ASSOCIATES, INC. VECO, INC. ANCHORAGE , ALASKA NOVEMBER, 1982 ALASKA POWER AUTHORITY JOINT VENTURE VECO, INC., RALPH STEFANO & ASSOCIATES, INC., AND ARCTIC SLOPE TECHNICAL SERVICES, INC. (ASTS) November 12, 1982 Mr. Eric P.. Yould, Executive Director Alaska Power Authority 334 W. Fifth Avenue Anchorage, Alaska 99501 Attention: Patti DeJong, Project Manager Subject: Kotzebue Coal-fired Cogeneration, District Heating and Other Energy Alternatives Feasibility Assessment Dear Ms. DeJong: We are pleased herewith to submit the final report on the subject feasibility assessment. Kotzebue is a community with a current population of about 2,850. It is located on the Baldwin Peninsula in Kotzebue Sound, 26 miles north of the Arctic Circle. Electrical power is currently being supplied by diesel electric generation by the Kotzebue Electric Association. The purpose of this study has been to assess all available options for providing Kotzebue with a feasible, practical, and proven power generation and heating system. While the original emphasis of the study was coal-related, we have in fact analyzed all practical alternatives. The plan period was twenty (20) years - i.e. from 1982 to the year 2002; however, the economic analysis has been based on 55 years. The 20 and 55 year periods are consistent with the overall evaluation process of the State of Alaska. In other words, load projections are considered for only the first 20 years, after which time they are assumed to be constant. However, overall system life requires economic analysis over a longer period, i.e. 55 years. In analyzing the community's needs we have accomplished: ° an energy balance; ° a population and energy use forecast to the year 2002; ° technology profiles for those energy systems which conceivably could be possible in the Kotzebue environment; Alaska Power Authority Page Two November 12, 1982 ° an evaluation of these technology profiles with the purpose of selecting and analyzing in more detail those technologies which appear practical and _ possibly economically viable; ° a more detailed analysis of the preferred alternatives; ° cost analysis (First Cost Construction) of those preferred schemes; ° an evaluation of those schemes which appear to be best suited for the City of Kotzebue, based on the economic evaluation criteria provided by the Alaska Power Authority; ° recommendations on future studies. System-wise, i.e. if only the economics were considered, coal- fired cogeneration may be the most attractive alternative if coal (local or imported) can be provided for around $6.00/Mbtu, as is estimated for the coal source at Cape Beaufort. Otherwise, the most favorable alternative for the community is hydropower either with electric resistance heating or with geothermal district heating: ° For geothermal this assumes that a geothermal resource of at least 162°F with sufficient flow exists (currently an unknown, subject to confirmation by exploration; Dr. Robert Forbes, a noted expert in this field, agrees with these parameters). The geothermal resource is felt to be only marginally viable for a district heating system. ° For hydropower this assumes that the environmental impacts relating to fish, flora and fauna, and that the problems associated with a large shallow reservoir at the Buckland site, are acceptable to the community and regulatory agencies. Early follow-on into the resource confirmation, prior to detailed feasibility study and final design phases, would now be in order. Alaska Power Authority Page Three November 12, 1982 We appreciate the opportunity to have worked with you and thank you for your cooperation during all phases of this challenging study. If you have any questions regarding this report, please do not hesitate to contact us. Sincerely, ARCTIC SLOPE TECHNICAL SERVICES, INC. Linge J, pom rris (Jack) Turner, P.E. MJT/tsb enclosure KOTZEBUE Coal-Fired Cogeneration, District Heating and Other Energy Alternatives Feasibility Assessment VOLUME ONE by A JOINT VENTURE OF ARCTIC SLOPE TECHNICAL SERVICES, INC. RALPH STEFANO ASSOCIATES, INC. VECO, INC. ANCHORAGE , ALASKA NOVEMBER, 1982 ALASKA POWER AUTHORITY ACKNOWLEDGEMENTS We acknowledge and appreciate the valuable assistance and advice offered by: the people of Kotzebue Alaska Power Authority personnel Kotzebue City officials and Council Kozebue District Heat Work Group Kotzebue Electric Association NANA Corporation Maniilaq Association Arctic Lighterage Kotzebue Energy Auditors Federal and State Agencies TABLE OF CONTENTS VOLUME I TABLE OF CONTENTS TABLE OF BASIC DATA....... © Siniislie © wriaiic| ©] aijoliale wieiieiie |e, elisie|s| ei@lnle oi siiele |» sites [o's FOREWORD 6.6 06.6 026.6 055 505 80's 5.08 Ss cece ews 6 sine 6 86 6 les cine.s ows,o LL SECTION SECTION SECTION SECTION SECTION SECTION SECTION SECTION SECTION SECTION APPENDIX APPENDIX APPENDIX APPENDIX APPENDIX APPENDIX APPENDIX APPENDIX APPENDIX APPENDIX 1 Fo DOAN KD WH F&F WD GQHTQaA ARTA wD Py INTRODUCTION AND SUMMARY.....-ccecceccccceccecceeelnl PUBLIC AND AGENCY INPUT... ..ccccccccccccccccvvccs 2-1 ENERGY BALANCE......... eee e ec cescceces eee eeeeee oe del ENERGY DEMAND FORECAST .....ccccccccccccces cleilete! syste ily TECHNOLOGY PROFILES.......ceeccee eee cccccccececee dd EVALUATION OF TECHNOLOGY PROFILES............-.--6-1 DESCRIPTION OF ALTERNATIVE PLANS.......eeeeeeeeee Il COST ESTIMATES........-2220. ciel sl simie elias eel aie sieves «wi OTL ENVIRONMENTAL EVALUATION... ...cecccccccceccccc eee Inl PLAN EVALUATION.......-4. eee e eens eves ec eeccces 10-1 VOLUME II APPENDICES TABLE OF CONTENTS LITERATURE RESEARCH.......eee0- Cece reece crecccce A-1 PUBLIC COMMENTS AND AGENCY INPUT....... els ieee o| sree md GEOTHERMAL TEST-WELL PROGRAM. .....eeeeeceeee «| a\eirore me TECHNOLOGY PROFILES......... Seis) els) ole: siis\16/5 |si\6)(616) siniexs Did, CONSERVATION... cee ccccccecoee tie! © eleiie:s le islisie 1s |eieis!e efelere md COST ESTIMATES DATA...... eee e cece c reece ecees ome Fal OPERATION AND MAINTENANCE... . 2... cccccccccccccccce G-1 FUEL DEMAND... cece cece cee cecccce wlieile 6 otis; 016 | site) 9} | | eye St CALCULATION OF PRESENT WORTH OF CAPITAL COST.....I-1 COAL TRANSPORTATION ANALYSES....... cee cecccece eood=1 TABLE OF BASIC DATA TABLE OF BASIC DATA KOTZEBUE Location: Latitude 66°. 52°N Longitude 162°. 3870 Temperatures: Mean temperature February 43°F Mean temperature July Be one: Mean temperature annual 20.57:°F. Design Temperature; 97.5% -36°F Degree days per year (base 65°F) 16,151°F days Population 1981: 2,625 Number of households 1981: 660 Heat values: Propane 92,500 Btu/gallon Gasoline 120,900 Btu/gallon Kerosene (jet fuel) 132,000 Btu/gallon Fuel oil #1 136,500 Btu/gallon Fuel oil #2 138,500 Btu/gallon Conversion factors: 1 kWh 3,413 Btu 1 gallon of water 8.3453 lbs. of water Coal Values: TONS (OF Areas BTU/1b COAL Nenana (Usibelli field) 8,000 61,000 Chicago Creek 6,500 75,000 Kobuk River 10,000 49,000 Cape Beaufort 14,000 35,000 q@) Based on a constant 925 Billion BTU/year. io FOREWORD FOREWORD The residents of Kotzebue rely almost entirely on oil to meet their electrical power and space heating needs. Because of rising prices in recent years, this dependence has had a severe impact on the community. It is reasonable to assume that this impact will not lessen in future years. Recent studies by others have assessed power generation alternatives for Kotzebue, and have focused on the feasibility of using hydropower and possibly the region's coal resources for space heating and electrical power generation. A separate investigation has addressed the potential for geothermal district heating for Kotzebue. Interpretation of these reports indicated the need for a more detailed investigation of all viable alternatives, especially coal and geothermal energy. This report, then, addresses in some detail the coal and geothermal energy sources, while also addressing other viable systems including, but not limited to, hydropower, wind, and conservation. To accomplish this very broad and comprehensive task, the following approach was taken: literature survey and analysis population forecast (including economic growth where applicable) heating and electrical load forecasts community reconnaissance and public meeting energy balance assessment of energy resources and conversion technologies screening of energy alternatives to determine those for which detailed plans and economic analyses should be performed ° preparation of alternative plans ° technical, economic, social, cultural and environmental analyses of the alternative plans final assessment of alternatives agency and public review final report incorporating comments and responses to comments ° suggested future work efforts 0,00 6 oo ° ooo This work was carried out under contract (AS44.56.010) to the Alaska Power Authority by a joint venture of three Alaskan firms: VECO, Ralph Stefano & Associates, and Arctic Slope Technical Services, Inc. 1. INTRODUCTION AND SUMMARY ee ee mWNHOrO PRPRPRPR Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Table SECTION 1 INTRODUCTION AND SUMMARY TABLE OF CONTENTS BA CKOGLTOUNG ws swicicrere 5 010 sietleie 6 oiete oss 6 Goi 6 slisis s Sisinie os oie ers ciel APPrOaCh,.. oc cccsccs ccs erecscosseccssccscvecccccccccccce lus Summary of Findings........cccccccccccccceee veeccee coe lb Recommendations............ ee ewe cows Series e ctiee csc e cee dl? Sensitivity Analysis. cess cciss sce s onc rss 5 eines sees gloo) LIST OF FIGURES cel Location and Vicinity Map.......cceeeeeeeceeeeel—2 1.2 Kotzebue Area. . ccc ccc ccc eseccusecmeccscsesel=3 1.3 Energy Balance, Electrical and Space Energy....1-7 1,4 55-Year Energy Projection Concept..............1-8 1.65 Variations in Demand for Heat and Electricity for Kotzebue.........c cece eee eee ee lO 1.6 Energy Demand, Electrical and Heating PrOjeCction.a ss ssc swc s esis © wise ® teece sie sce l= 10 1.7 Outline of a District Heating Scheme...........1-12 1.8 Buckland River - Energy Availability....... eoeeL@13 1.9 Numbers of Windgenerators.......ceeeceeeeeeee ee l“15 1.10 Base Case Diesel Generation......... cece cece eee 1-18 1.11 Simplified Schematic Diagram for Cogeneration System for Kotzebue.............2..1-19 1.12 Projected Energy Demand and Deficit U9Bi2=203 Trereiccrerss wisyere wiles wicisle © elalere winieie © eisiw eine eres 1-24 LIST OF TABLES 1.1 Sensitivity of Benefit-Cost Ratio..............6. 1-23 SECTION 1 INTRODUCTION AND SUMMARY 1.0 BACKGROUND Since 1973 the world has been watching skyrocketing prices of energy in general and petroleum products, such as heating oil and diesel fuel, in particular. Many Alaskan communities rely almost entirely on oil to meet their electrical power and space heating needs, and, although Alaska possesses some of the world's largest oil reserves, the inhabitants of these communities are encountering rapidly escalating energy prices, which are not offset by similar increases in family income. With its approximately 700 residences and 2,850 inhabitants, Kotzebue is one of the largest communities in Northwest Alaska. It is located on the Baldwin Peninsula, 26 miles north of the Arctic Circle and is without overland connecting routes to Fairbanks, Anchorage or other major Alaskan communities (see Figure 1.1). Goods and materials (including fuel oil) are shipped into the community during the three months when Kotzebue Sound is free of ice. Heavy. barges, however, cannot reach Kotzebue, and shipments must be lightered to shore, thus increasing the transportation costs of these goods. Kotzebue is a regional air transportation center with regularly scheduled major airline and _ bush flights. Also economically and administratively, the city serves as the regional center of the NANA Region, which has a total population of about 5,500 (see Figure 1.2). Current electrical requirements of the community are met by Kotzebue Electric Association (KEA) at an average cost per kWh of 20¢. Heating is primarily provided through use of fuel oil in individual space heating stoves. BARROW AMBLER NS -SHUNGNAK Ap BSELAWIK KOBUK BUCKLAND LOCATION AND VICINITY MAP FIGURE 1.1 1-2 (Sema oe) BAIRD MOUNTAINS = \ hl HORA = ey BUK fi KOTZEBU i \ SHUN) \um han “ARCTIC GIRGLE...Pesnee SO caaweneee bi © © Seotewit Z/ BUCK .LAND Ts R 3x10MW LEGEND fH HYDROELECTRIC POWER POTENTIA KOTZEBUE AREA © GEOTHERMAL POTENTIAL (HoT oR WARM SPRINGS OR WELLS) North iil! COAL RESOURCE Lf ee — TRANSMISSION LINE 138 KV 38 : FIGURE 1.2 Recent studies by others have assessed power generation alternatives for Kotzebue and have focused on the feasibility of using the region's’ coal reppurces for space heating and electrical power generation 5 Another investigation has addressed, )the potential for geothermal district heating for Kotzebue . Preliminary findings of these previous studies indicated, in part that: 1) although geothermal generation of electricity or heat did not appear to be economically beneficial to Kotzebue residents, district heating using a fossil fuel energy source might be beneficial; 2) use of coal from Alaskan resources might decrease the cost of electrical power in Kotzebue if by-product heat could be sold as well. For these reasons, this Feasibility Assessment considers coal-fired generation of electricity with capture of by-product heat and distribution of the heat, by means of a city-wide district heating system. The previous studies also indicated that hydropower was promising. Although the primary focus of this study has been coal-fired cogeneration of heat and electricity, it was necessary to confirm that this option would be less costly to the consumers than other energy sources and conversion technologies. For this reason, all feasible energy resources and technologies have been considered. Where previous studies have addrpssed these technologies in some detail (for example hydropower , this report has not presumed it necessary to repeat such feasibility level work in its entirety but has only updated results and made changes in cost estimates and other areas as necessary (such changes are further discussed in Volume II, Appendix A). Becaus¢, of the high degree of local interest in geothermal energy and the need to further analyze this potential energy resource , a greater effort than might otherwise seem appropriate was directed to the geothermal alternative in this study. 1.1 APPROACH While, for reasons explained above, the primary energy resource considered has been coal for cogeneration and district heating, oil, gas, peat, geothermal, et.al. were also considered. The cost and desirability of using diesel powered generation to produce electricity with waste heat capture along with oil-fired individual stoves for heating (base case) , have been compared to: ° Cogeneration (coal-fired) steam electrical gen¢ration with hot water district heating (Alternative A) CL) ap asap let re ay eee aes See Appendix A, Section 2 for list of relevant reports. 1-4 ° Hot water coal- and oil-fired district heating combined with electrical , generation from other resources. (Alternative B) ° Hydropower generation of electricity with and without space heating (Alternative C) ° Geothermal district heating combined with, ,)power generation from other resources (Alternative D) ° Windpower generation of electricity to supplement other generation combined with feasible space heating t In the course of this study unrealistic technologies have been eliminated (see Section 6), with the most likely alternatives (Section 7) being evaluated against the base case. This procedure ensures that the optimal concepts have been identified for future study by the Alaska Power Authority. During the study, emphasis was put on the benefits likely to arise from energy conservation measures and increased energy availability by waste heat recovery. The specific work tasks covered by the feasibility assessment included: ° Literature review of previous studies, reports, etc. (See Volume II, Appendix A). ° Performance of site reconnaissance and data gathering (Volume I, Section 2 and Volume II, Appendix B). ° Establishment of an energy balance (Volume I, Section 3)! 6 ° Forecast of electrical energy and space heating needs for Kotzebue to the year 2002 (Volume I, Section 4). ° Preparation of Technology Profiles for all appropriate concepts (Volume I, Section 5 and Volume II, Appendix D). ° Evaluation of these technology profiles to provide a basis for a detailed analysis of those concepts judged to be reasonably feasible, including geothermal and hydropower (Volume I, Section 6). (1) Alternatives referred to in Section 8(Cost Estimate) and Section 10 (Economic Evaluation). T=5 ° Those alternatives determined viable or otherwise noted for further study in Section 6 have been analyzed in some detail. They comprise the Diesel Base Case; Cogeneration; District Heating; Hydropower; Geothermal; Conservation, and Wind (Volume 1, Section 7 and Volume II, Appendices C, and E). ° The environmental parameters have been assessed and are discussed in Volume I, Section 9. ° Those plans which were reviewed in detail have been further analyzed on a systems basis. The overall matrix provides for a common basis on which to assess all systems. This analysis is discussed in Volume I, Section 10 (see also Volume II, Appendices F, G, and H). ° To ensure realistic coal prices were used in the study, an assessment of the regional and Nenana (Healy) coals cost was made (Volume II, Appendix J). _We have recognized the need throughout the project for close communications with the regional corporation, the City leaders and the Kotzebue people themselves in order to incorporate, as applicable, their thoughts, concerns, and desires. 1.2 SUMMARY OF FINDINGS 1.2.1 General The overall assessments of those energy technologies and fuel resources which have been judged to be viable alternatives in this study are summarized in this subsection. To assist the reader in assimilating the report data, tables and figures from other sections of the report are repeated, in part, herein. To better understand the present system being used in Kotzebue, an energy balance was developed, where the input, output and waste energy were noted. This is represented schematically in Figure 1.3. 1-6 WASTE TOTAL 45.1% #1 ¢ = 3 2% Ls | YRECOVERED WASTE ws 2.0%. 13.6% 25.8% INPUT 100% Propane mum) 29 Fuel #4 45.2% zi) Heating FIGURE 1.3 ENERGY BALANCE, ELECTRICAL AND SPACE HEAT ENERGY 1-7 1.2.2 Energy Requirements The energy demand was analyzed (see Figure 1.6) for a 20-year period (1982 to 2002). Thereafter, i.e. 2003 to 2037, was considered constant (Figure 1.4) for the year 2002. '1), the use - in other words the same as FIGURE 1.4 55 YEAR ENERGY PROJECTION CONCEPT ener: requirements 20 0 years ” (1) State of Alaska planning requirement. 1-8 While Figure 1.6 shows the yearly projected energy demands (annual basis), Figure 1.5 shows the percentage of yearly demand (electrical versus space heating) on a monthly basis. FIGURE 1.5 VARIATIONS IN DEMAND FOR HEAT AND ELECTRICITY FOR KOTZEBUE BASED ON STATISTICS FOR ELECTRICITY AND HEATING DEGREE DAYS FOR HEAT % of yearly demand FIGURE 1.6 TOTAL ENERGY DEMAND, ELECTRICAL AND HEATING PROJECTION §50 500 450 © so] & - ot " s & sso] & , | § 3 sof & a £ S S a x 250 200 150 100 50 160 140 —— — eoocccccedees 1980 ovretre 1-10 light and appliances hot water wxrerdesees, Cold water supply 1.2.3 Energy Sources Kotzebue is presently using fuel oil for its electrical generation and space heating needs (hereafter referred to as the “base case"). In addition to this resource, all other viable options were considered. Those which were utilized in the preferred plans (i.e. systems equal to or more competitive than the base case, or which (even though not state-of-the-art) still have potential within the 55-year period of the study, are briefly discussed below: ° Fuel oil (base case) - Imported petroleum products which are utilized in KEA's’ generators and in individual homes for space heating. While the resource is not infinite, as are wind or water, it is still a viable resource. ° Coal - As a fuel, coal was analyzed for use in the cogeneration and district heating systems (see Figure 1.7). Alaska has bountiful coal resources of which only the Nenana Coal field near Fairbanks is currently producing commercially. There are a number of coal resources in or near Kotzebue (see also Figure 1.2). These sources have been analyzed from a cost basis. While they appear to be competitive cost-wise, and in some cases cheaper than Nenana Coal, the overall economics of the energy producing system seems to be competitive using either local or Nenana Coal as an energy source. ° Water - Where a high head of water, a large water source (river, lakes, or storage area), or a combination of these energy bodies can be obtained, hydropower can be produced. Normally, this renewable resource should be able to provide low-cost electrical energy (including space heating) if in fact a large enough water source is available. If one assumes that other factors such as environmental and social concerns (which also, in varying degrees, apply to all energy sources) are not objectionable, this source is usually very competitive with other resource alternatives. In the Kotzebue area _ the Buckland River is the only potential source with the required capacity range for providing adequate hydropower (see Figure 1.8). ° Geothermal - There is a possibility that a geothermal resource may be available in Kotzebue. Without an extensive drilling program, however, to prove the adequacy of this resource it would appear that the temperatures are not high enough for electrical energy production but at best might be adequate for a district heating system. l-11 iNulnl Sl Dd 7 willis Te. \ ( \ / Ro FIGURE 1.7 OUTLINE OF A DISTRICT HEATING SCHEME HEAT INPUT FROM: us Power plant 2. Boiler station 3. Incinerator 4. 5 6 Industry . Geothermal energy . Sewage system/ heat pump Solar collector FIGURE1.8 BUCKLAND RIVER - AVAILABLE ENERGY availabie hydro with 3-1) mw (3) unith-maximum Capacity frpm Buckland site 160,000 electrical heat ng e Lrequiréments (mean) ajinble hydhe units heatin penne deecree tu----- — requirements c (mean) MWH electrical requirements (mean) soonest date hydropower could be on line 1982 1992 2002 2012 2022 2032 year 1-13 ° Wind - Another renewable resource available in the Kotzebue area is wind. Since an ample wind source is available this resource was closely looked at. Figure 1.9 shows how units could be brought on _ line incrementally using wind generators. The problem today is that large units (adequate to serve the needs of Kotzebue) are not state-of-the-art but are _ only experimental or being used on special trial basis. 1.2.4 Preferred Plans While numerous energy systems concepts were studied (and are discussed in varying degrees of detail in this Feasibility Assessment), only those systems judged viable were assessed in depth. While we considered all systems, "KNOWN-STATE-OF-THE-ART" plants were given highest ratings because of the necessity for the systems to operate with a high degree of reliability considering the climate and remoteness of Kotzebue. Two plans were considered quite competitive, cost-wise. To better judge the merits of these plans (cogeneration and hydropower), we have considered them in comparison to the base case, i.e. Diesel-generated electricity and oil stoves. Additionally, two separate district heating systems were included to enable us to better assess the component possibilities in relation to other fuel sources. Those analyzed were: Capital Cost (without intgrest) $ xX 10 Distribution System Plant System Total Base case; existing diesel generation and individual oil stoves for space heating. 12,748.9 6,394.8 19,143.7 Cogeneration (Alternative A); electricity is generated and waste heat is utilized with a district heating system. 29,225.8 14,577.6 43,803.4 Coal-fired low pressure district heating (Alternative B). 18,908.3 14, 27452 33,182.5 Hydropower (Alternative C); provides electricity for (1) electrical and heating needs. 131,479.5 49,549.5 181,029.0 Geothermal (Alternative D); has been analyzed here as a fuel for a district heating system. 37,463.5 16,023.2 53,486.7 SO a cc ee Includes transmission line costs 1-14 total windgenerator capacity on line(kW) Fl GURE 1.9 NUMBERS OF WINDGENERATORS 65kW 200kW 1-15 1995 2000 2002 a 2 64ie L Base Case The Base Case considers continued use of existing diesel electric generation with oil being used as the fuel source in individual oil stoves. Capital costs of diesel generation plant are quite low in comparison to other systems; consequently units in the same size range of what exists have been planned to periodically be installed as the need for additional power is evident (see Figure 1.10). Fuel costs are not cheap in comparison to other fuels thereby making this system of questionable desirability in the long term. Like diesel electric generators, oil stoves are relatively inexpensive, but fuel costs are high, le dutad Cogeneration (Alternative A) This is a system worth pursuing in depth in an area such as Kotzebue. This single plant concept (see Figure 1.11) which uses coal as a fuel, with waste heat recovery being used in district heating systems, has significant merit. The only real unknowns (or difficulties) are: ° those of coal handling or mining in the Kotzebue area; ° those of developing a new mine, if other than Healy coal is used; and ° the difficulties associated with utilizing water as a heating source in the distribution system (including houses) in the arctic. 1.2.4.3 Hydropower (Alternative C) Hydropower appears to be a cost-effective system for Kotzebue. The overall estimate is considered conservative at about $4,400 per installed kilowatt. With a transmission line, the overall cost is about $6,000/installed kw. Areas of major concern in this system are: ° unknown environmental concerns ° unknown geotechnical (foundation) conditions and availability of building materials ° impacts of a large shallow reservoir on overall system operations and environmental consequences ° long transmission line (approximately 90 miles) from the Buckland site to Kotzebue is a weakness in the system from a reliability standpoint. 1-16 ° the need to supplement hydropower in later years with diesel electric or another system during periods in the winter. ° no ability to expand the system beyond the 30 MW of planned installed capacity. Conversely, hydropower: ° is an extremely reliable energy system ° has long life expectancy ° requires relatively little maintenance ° is usually cost effective, i.e. low cost per kWh ° is a clean source of energy. 1.3 RECOMMENDATIONS While this feasibility assessment has covered all feasible systems and resources, it is not realistic to recommend a single system because of the many resource questions yet unknown. Consequently, at least two systems should be further analyzed; they are: 1) Coal-fired cogeneration, and 2) Hydropower Both of these systems appear to be feasible long-term alternatives to the existing diesel electric generation and individual oil stove heating now being used in Kotzebue. When the cogeneration system is evaluated using the most cost- effective coal, it is slightly better in terms of net benefit. This same evaluation using more expensive coal showed hydropower to be slightly more advantageous. To ensure the best system is chosen, we believe it desirable to further evaluate the unknowns of each system in more detail. ey, FIGURE 1.10 BASE CASE DIESEL GENERATION 12,0 __ ww PEAK LOAD— 11,9 | a HI 2, oe ll ||| 2 | DD I ” | | | 1-18 FIGURE 1.11 SIMIPLIFIED SCHEMATIC DIAGRAM FOR COGENERATING SYSTEM FOR KOTZEBUE generator Tt) cS condenser steam-—water heat exchanger electric ‘power domestic hot water 1-19 Although the identification of a preferred generating and heating system is possible, we suggest, before this is done, that: ° Coal resources in the Kotzebue area (especially Kobuk and Cape Beaufort ) be drilled and tested to see if in fact sufficient quantities exist, and to further evaluate the question of opening a new»mine for a Kotzebue coal source. ° Investigations be accomplished in Kotzebue to better define the district heating system utilidors design environment. ° Studies of the environmental impact of both systems at Kotzebue, Buckland, and along the transmission route be done immediately. ° Geological and hydrological studies of the Buckland site should be done as soon as possible. ° Social aspects of these systems should be readdressed in the near term. ° Proper scheduling and adequate funding of the work should be provided in order to prevent valuable time being lost because of the Federal Energy Regulatory Commission (FERC) requirements as they apply to a hydropower system coming on line. Once these resources and environmental and social questions become more clear and more definitive, systems decisions can be made. Properly scheduled and timely accomplished they should enable the project to meet the current and future needs of the City of Kotzebue. In addition to the electrical energy and heating systems discussed, thermal and electrical energy conservation should be vigorously pursued. These conservation measures are most effective in overall energy costs to the consumer. Wind generation can also be utilized to save on nonrenewable fuel sources such as fuel oil and coal. It can compliment other renewable resource energy, for example hydropower. A wind generator test program is now being installed in Kotzebue by the State of Alaska Department of Commerce and Economic Development, Division of Energy and Power Development. This program will produce valuable information, on the basis of which a possible inclusion of wind generators in this final system can be determined. 1-20 NOTE: (1) Once the technology profiles were completed , two basic plans evolved. Since district heating is the Major energy requirement, we further evaluated two separate systems (i.e. coal-fired low-pressure and geothermal systems) for district heating. These could possibly be cost-effectively used with hydropower or the base case, and are referred to in the text as: ° Base Case ° Alternative A (Cogeneration) ° Alternative B (Coa]yfired low pressure district heating) ° Alternative C (Hydropower) ° Alternatiyp D (Geothermal district heating) (1) Referred to as Cases 1 through 11 in Vol. I, Section 10, and in Vol. II, Appendices G,H,and I. (2) District heating systems only. 1.4 SENSITIVITY ANALYSIS In order to assist in arriving at a recommendation on a system for the City of Kotzebue some of the basic assumptions, contingencies, and coal costs were varied and separate analyses conducted to determine the effect of such changes on project costs, benefits, and the benefit-cost ratio. The analyses: (1) Assumed a 2 percent growth in energy demand beyond the year 2002 (i.e., beyond the 20-year planning period); (2). Increased the construction contingency for cogeneration from 15.-to- 25 ~ percent: (i.e.,. “identical to -the hydropower case); and (3) Increased coal costs from $6.00 to $7.00 per million BTU. Table 1.1 shows the results of these additional analyses in comparison to the plans as evaluated in this document. A 25 percent increase in contingency for the cogeneration facility has a small effect on the present worth of costs for that system with a subsequent small effect on the benefit-cost ratio. An increase in the coal cost for the cogeneration facility has the result of increasing the present worth of costs for the facility by approximately $26 million and making the hydropower alternative more attractive. If the cost of coal delivered to Kotzebue were d=21 to rise to the estimated price of coal delivered from the Nenana Field (approximately $8.84 per million BTU), the present worth of project costs would increase to an amount in excess of $340 million with the subsequent effect of reducing the benefit-cost ratio to a level below 1.20. The assumed 55-year planning period and a 2 percent annual increase in energy demand result in increased cost-benefit ratios for both systems. The hydropower case has improved its standing relative to the cogeneration case because of the reduced fuel costs inherent in hydropower. Figure 1.12 illustrates the potential energy demand assuming a 2 percent annual increase in usage beyond the year 2002 as compared to the level demand normally assumed by APA procedures for years beyond the 20-year planning period. The deficit as shown is reflective of the hydropower case but a similar situation could be anticipated for the cogenerative case unless additional generating capacity is installed. An additional point to be noted for the hydropower case is that if additional generating capacity is required beyond the year 2002, a new and different generating system will need to be installed. The Buckland Site cannot expand beyond 30 MW. There are several implications from having two separate systems: First the operations and maintenance costs will probably be higher for two systems than for one system of equal capacity; and, second, economics of size related to one large system will be negated. However, as shown in Table 1-1, the fuel savings associated with hydropower can more than offset these issues. 1-22 TABLE 1.1 Sensitivity of Benefit-Cost Ratios to Various Assymptions ($ x 10°) Present Worth of Plan Evaluation Costs Benefit Base Case $402,123 $402,123 Case 2 (Cogeneration) $272,853 $402,123 Case 11 (Hydropower) $273,899 $402,123 With 25% Contingency for Construction 2) Case 2 (Cogeneration) $274,708 $402,123 Case 11 (Hydropower) $273,899 $402,123 Benefit- io Cost Rat 1.00 1.47 1.47 1.46 1.47 (a) Case 11 used a 25% contingency figure in the plan evaluation. Consequently, only Case 2 is increased here. With Increased Coal Costs (a) Case 2 (Cogeneration) $299,652 $402,123 Case 11 (Hydropower) $273,899 $402,123 (a) Assumed coal costs of $7.00 per million BTU. With 55 Year Planning Period and 2% Growth 2003-2037 Case 2 (Cogeneration) $393,227 Case 11 (Hydropower) $376,502 $673,057 (a) $673,057 (a) Includes a coal-fired cogeneration facility be developed to meet power demand not hydropower. assumed supplied to by FIGURE 1.12 PROJECTED ENERGY DEMAND AND DEFICIT projected defic with 2% growth’ potential (3) hydro surplus mwh x 10° 20 YEAR PLANNING PERIOD 55 YEAR EVALUATION PERIOD 2007 year (1) would require additional diesel electric generator, district heating system or cogeneration plant to supplement the number of hydroelectric plants or base cogeneration system. (2) assumes constant demand beyond year 2002 (3) potential hydropower surplus excluding line losses (See also figure 1.8) 1=24 = PUBLIC AND AGENCY INPUT 2.0 22 2.3 SECTION 2 PUBLIC AND AGENCY INPUT TABLE OF CONTENTS General sepereisrenorek<loheeler-LeroneleKoiohele1oisKeloNelchoheVeovonolelotone alolsiisletelelolelele 2 Agency Contacts! and Comments si. o cies wins. « sisie 6 cise 0 oie © oe Kotzebue) Reconnaissance ss <%\e/010)010/0 o:eoejes iene! eels oer aiiellekeleleis Other Contacts and Meetings........ @ lelelele Seis eioieiels wfeele sisiel oi, SECTION 2 PUBLIC AND AGENCY INPUT 2.0 GENERAL As part of the Feasibility Assessment, public and agency input was solicited. Appendix B in Volume II of this report includes all such written comments and, as applicable, responses thereto. 2.1 AGENCY CONTACTS AND COMMENTS (Please see Volume II, Appendix B) 2.2 KOTZEBUE RECONNAISSANCE Site reconnaissance of Kotzebue was conducted in January and February 1982. 2.3 OTHER CONTACTS AND MEETINGS Meetings with the City Manager of Kotzebue, Kotzebue District Heat Work Group (KDHWG), Kotzebue Electric Association (KEA), Maniilaq Association, Arctic Lighterage, NANA Corporation, and local Energy Auditors were very productive. Considerable time was spent with the KDHWG in discussions focusing on the transportation of coal from the source to Kotzebue. Public meetings were held in Kotzebue on January 20 and June 2, 1982. It was obvious that the people of Kotzebue and their leaders were very interested in the overall Feasibility Assessment and were hopeful of a result which will benefit their community by providing more economical electricity and individual home heating. 2-1 3. ENERGY BALANCE SECTION 3 ENERGY BALANCE TABLE OF CONTENTS 3.0 GONEA oc c/ohele o\s101s olele 6) 011610 o/sie/6: a0) 6 ersiele.0]elelels a siicleleieie 3.1 Energy Input at Kotzebue... ..cccccccccccsccccces Sica Energy Output at Kotzebue... .ccccccccccccccccves 3.3 Energy Usage at KotZebue....cceccscccccccscccces LIST OF FIGURES Figure 3.1 Energy Balance for all Delivered Energy ... Figure 3.2 Energy Balance, Electrical and Space Heat Energy ccccccccccccccccccsscccsescccce LIST OF TABLES Table 3.1 Energy Balance-Kotzbue....cscccccccccccccce 3-3 3-4 3-6 SECTION 3 ENERGY BALANCE 3.0 GENERAL An energy balance was developed from a compilation of existing energy resource and community data. The balance graphically depicts the energy forms now entering the village and the major end uses including energy waste. Specific attention has been directed at end uses such as space heating, water heating, lighting and appliances, and industrial processes. Kotzebue's total energy balance is depicted graphically in Figures 3.1 and 3.2 and further tabulated in Table 3.1. Tabulated components of the energy balance follow in Subsections Sel, See, sand) 3.3. Siok. ENERGY INPUT AT KOTZEBUE Input fnergy Equivalence 10 10 % of Fuel Type Gallons Btu/year kWh/year Total Propane 8,500 0.786 - 230 OFS: Gasoline 400,000 48.000 14.064 8.3 Gasoline (aviation) 670,000 80.400 23155517, 13.8 Kerosene (aviation) 500,000 66.000 19.338 11.4 Fuel #1 1,282,000 174.352 51.085 30.0 Fuel #2 (heating) 310,600 43.018 12.604 ee Fuel #2 (electric) 987,200 1366 7:22 40.059 2355 Fuel #2 USAF 225,900 31.287 9.167 55) Total energy input 580.565 170.104 100.0 3-1 3.2 ENERGY OUTPUT AT KOTZEBUE Electric Energy Lighting Appliances Space heating o0o°0 0 Street Lighting OTHER Space Heating Hot Water Heating cold water supply Cooking Ground Transportation Aviation U.S. Air Force (electric ene Total energy directly utilized (subtotal) 243.189 Total recovered waste energy © Space heating o Hot water o Heating water supply Total energy output rgy) (subtotal) 3-2 Energy Equivalence 1o%Rtu/yr 10°kwh/yr 37.046 10.855 13.471 3.9468 17.287 5.0653 6.118 1.7926 .170 -0408 145.284 42.568 Sei a9 1,201, 3.264 -956 -638 -187 14.400 4.221 29.280 8.579 9.518 were? 71.254 5.580 -148 6.780 12.508 3.665 255.697 74.919 WASTE TOTAL 56% 30.1% my aff 2 a 2.1% } ) RECOVERED WASTE Le gi| § INPUT. 100% "355 Gason ; 7.6% asoline + — 3s fe TRANSPORT ganeime (198% ae 5 Kerosene / Aviation Propane wae () 1% Heating 30.0% 0.1% 21% 34.3% 5.2% 6.3% a ELECTRICITY AND HEATING OUTPUT TOTAL 44% Fuel #2 USAF FIGURE 3.1 ENERGY BALANCE FOR ALL DELIVERED ENERGY WASTE TOTAL 45.1% ¥ g = % 3.2% LS |) RECOVERED WASTE é be a oH INPUT 100% / Propane 10.2% ss as ‘62% -~_ | Heating 31.6% 51.7% | fresting | a 9.6% 2 Bo OUTPUT | G8xe"= | 8.1% FIGURE 3.2 ENERGY BALANCE, ELECTRICAL AND SPACE HEAT ENERGY 3-4 33 ENERGY USAGE AT KOTZEBUE 109 Btu/year 106 kWh/year _s_ Total energy input 580.565 170.104 100.0 Direct energy utilized 243.189 71.254 41.9 Direct waste energy 337.736 98.850 38.1 Recoverable waste energy 74.662 21.876 12.9 Recovered waste energy 12.508 3.665 Qionk 100.0% Total energy utilized 255.697 74.919 44.0 (direct + recovered waste) Total waste energy 325.196 95.185 56.0 (direct - recovered waste) 100.0% 3-5 9=5 TABLE 3.1 ENERGY BALANCE-KOTZEBUE pagel of 2 PRODUCT INPUTS | TOTAL INPUT | CONVERSION END USE END USE ENERGY | TOTAL END USE | (10° BTU) (10% BTU) (10° BTU) ENERGY(10° BTU) PROPANE 35,800 GAL. (3,320) | (786) COOKING ANOT WATER “(eae AZ craey | (786) GASOLINE-RECUCAR 400,000 GAL. (48,000) +308 | GROUND TRANS. (44,706) & UNLEAD a a 20% AVIATION (28,280) (193,440) — — a ae an scence aan —— Sat J be GASOLINE-AVIATION ®70,000 GAL. (80,400) USAGE WASTE HEAT INPUT (ieee WASTE HEAT] RECOVERABLE W.HRECOVERED & UNRECOVERED WH. END USE | | __tre® atu) 4x0" Bru) im | etary sos AVIATION (517,120) KEROSENE-AVIATION $00,000 GAL (66,000) ee a Tein Fasteas (150,720) on (0) N/A LJ 708 | Grown i 33, JET FUEL = Resend | 708 _SPace _weatina | 652,000 GAL. ( 94,112) . HOT WATER OMMERCIAL- INCLDG. APTS. 705 a SPACE EA NGI (122,046) 428,000 GAL. (58,208) HOT WATER PUBLIC-INCLG.CITY aaa SPACE KEATING _| _—_—__{6,190)_ 100,000 GAL. (13,600) COLD/HOT WATER (3,264), (00) HOSPITAL 3 [——J70s SPACE HEATING FUEL OIL #1 1,000 GAL. (138) HOT WATER 1,282,000 GAL. ares SPACE HEATING er,000 Gat. (8,200) | HOT WATER [50 USAGE [WASTE HEAT INPUT |TOTAL WASTE HEAT | RECOVERABLE W.H.|/RECOVERED & UNRECOVERED W.H.| END USE (1c8 Bru) (10S aru) (108 stu) (io® aru) L——3308 FAA (2,488) | L———> 308” wosPiTaL tay 408 mrei2 08) a eee 308" PusLie (4,080) (52,308) (20,022) ox [COMMERCIAL] (47,462) 748) Oe (28,234) | (3823) RESIDENTIAL’ 48) HOT WATER L-€ TABLE 3.1 (cont'd) ENERGY BALANCE-KOTZEBUE page 2 of 2 T 7 SUBTOTAL ~) PRODUCT INPUTS TOTAL INPUT CONVERSION END USE END USE ENERGY END USE ENERGY (10° BTU) (10* BTU) KWH (10° BTU) KWH (iofeTu) | REROENTAL 231,100 2,007) seeveee =e COwuT RCIA CLOG APTS mae Texte arruiamce® 481.300 Gal (ee.e73) SPACE MEAT ING Seana. basa PUBLIC-NCLG CITY, i (_— se. $3,300 Gat (7,382) iaeon ecrmeny senooe 1 ae (334.5009 WOSPITAL 147,000 san) 47.940 GaLi9,e10) FUEL OW #2 res are 1,506,400 GAL. | eUene Gxt (ialeunt Qe) (20 36) Wo GEGAI ‘SenOOL J SPACE ne - wow tLecTmICAL 108.600 Gat | | a ROT WATER aa a aa nin a eer = a wosrivaL race nea Tine Dasa prone oa. nN irate oy KOT WATER “a a3 wee eae et eo 4 | TOTAL END Use ENERGy| ‘00 fa7180) J vance NEAT mPoT | TOTAL WASTE EAT wo ui oe aw Gof stw on wOSPITAL ” now-etec. | on BEnooL way ero vsnecovenco Fan tare COLD MOT WATER son MOSPITAL pases fanoaay Fenooe Poe SPACE WEATING CowmERCuAL | (aa,soe) RnDENTAL TOTAL END USE END USE ENERGY END USE ENERGY KWH (10* BTU) KWH (10% BTU) muctmerry ain FORCE 220,000 OAL (31,267) 3048 Ta7e ae 18,000 pores) waste wav eeut | TOTAL WASTE weAT RECOVERED & UeaCOvERED WH] _EmO UBE (rot aT ote am Fomce (aye a708) mecoveneD 4. ENERGY DEMAND FORECAST PPPS HLH HS oe ee ee we ow ODAIDNUSPWNHE LIST OF FIGURES Figure 4.1 Projection of Population and Size Of HouSeholds.ccececesescrecsevccessvesecsece Figure 4.2 Light and Appliances: kWh Consumption per Capita per Yearececccccccccccccccccccecs Figure 4.3 Light and Appliances: Total kWh Consumption per Yeareceeveveccccccvcccccevece Figure 4.4 Floor Area per Capita Projection. ..ssssseeseeee Figure 4.5 Total Floor Area and Space Heat Demand Projection. ccoccccccccvevcccvveseveve Figure 4.6 Space Heating Demand per Year Projection....... Figure 4.7 Hot Water, Heat Demand per Year Projection..... Figure 4.8 Cold Water Supply, Heat Demand per Year, Projection. ccccccccccscvcvcssesssccens Figure 4.9 Total Energy Demand, Electrical and Heating Projection.cccccccccccecevevsceccece LIST OF TABLES Table 4.1 Past Population Trends, Kotzebue 1909-1981...... Table 4.2 Population Projection. .csccceeccceseeceeeececece Table 4.3 Breakdown of Electric Power Usage in 1982....... Table 4.4 KEA Power Generation 1968-19B1l.cwcecceeeeeeevees Table 4.5 Light and Appliances FOreCaSt.ccecseceeeseeecere Table 4.6 Calculation of Space Heating Demand, 1981.......- Table 4.7 Heat Lost per Sq. Ft., Forecast 2002....eseeeeee Table 4.8 Total Floor Area, Forecast 2002 (Sq.ft.).cceeees Table 4.9 Space Heating Demand, Low Forecast to 2002...... Table 4.10 Space Heating Demand, High Forecast to 2002..... Table 4.11 Consumption of Hot Water, Residential, Commercial, and Public Use. ..ccccccccccccvccs Table 4.12 Total Hot Water Consumption, Forecast 2002...... Table 4.13 Heat Demand for Heating Hot Water, POKECASE ZOOZ. cr crvecccvcccvccsecessevescccce Table 4.14 Potable Water Consumption and Heat Demand SECTION 4 ENERGY DEMAND FORECAST TABLE OF CONTENTS Past Population Trends. ccccccccccccccccccccscccccccecs Present Population. cccccccccccccccccceccccccvcccecece Population Projection. ceccecccvcccscccccccsevveseseces Present and Future Household Size...cecevevcvecvsevece Light and Appliances. .cececerececseeveeseveseserevece Space Heatingecccccccccccccvscvsvsesesessssssesesece HOt Wate re cveeeeceseeeveccvcsseesseseessevssssessesese Industrial ProceSSeS.ccccccccccccccvvccvevevsevecceees SUMMALY ee eeee reese reercccrsnseesesesesessssseseveseces for Freeze Protection, EOreCCaAStm200 2icrcrcleciercle's PPE PE EES eS 1 NNNEYEWWH NUNW SECTION 4 ENERGY DEMAND FORECAST 4.1 PAST POPULATION TRENDS Kotzebue's population has grown steadily since the turn of the century. U.S Census figures for 1909 indicate a total population of 193. Through the following decades (see Table 4.1) up until 1940 the population increased at a rate of about 2.2% per annum (p.a.) showing a gradual acceleration toward the end of this period. During the years of rapid expansion characterizing the post-World War II period the population doubled twice, increasing from 372 in 1939 to 1,290 in 1960. Between 1960 and 1980 the growth rate remained stable at a more moderate 2.3% pea. The U. S. Census figure for 1980 shows a total population of 2,054. Several population estimates undertaken since 1970, however, consistently indicate a larger population than the Census. Thus, for example, the Kotzebue Land Use Plan (1976) estimated the 1976 population to be around 2,000, while City of Kotzebue statistics and figures used by the Alaska State Revenue Sharing Program point to 2,431 people in that year. The latter sources indicate an annual growth rate between 1970 and 1979 of around 4.2% (as opposed to the 2% p.a. between 1970 and 1980 implied by the Census figures). In a report for the Alaska Power Authority entitled "Assessment of Power Generation Alternatives’ for Kotzebue," Robert W. Retherford Associates estimated the 1979 population to be around 2,500. In the 1981 Kotzebue Land Use Plan the City Planning Commission accepted the 1980 population to be 2,544; this figure, in turn, being based on estimates by Quadra Engineering in connection with the “Water and Sewer Expansion Study" (1981). In an October 1981 analysis of the various population estimates, the City of Kotzebue recognized the 1981 population to be 2,847. Table 4.1 PAST POPULATION TRENDS KOTZEBUE 1909-1981 Year Population (1) (2) (3) (4) (5) (6) (7) 1981 2,847 1980 2,054 4,293 2,544 1979 2,526 @2,500 1978 2,526 1977 207431 1976 2,431 @2,000 1975 2Gh25 1974 2,125 1973 2,125 1972 1,957 1971 1,875 1970 1,696 1,696 1960 1,290 1950 623 1939 372 1929 291 1920 230 1909 193 Source: (1) U.S. Census (2) Alaska State Revenue Sharing Program (3) City of Kotzebue, October 1981 (4) Indian Health Service (5) City of Kotzebue Planning Commission; Quadra Engineering (6) Robert W. Retherford Associates (7) Alaska Consultants, Inc. 4-2 4.2 PRESENT POPULATION As can be seen, there is considerable disagreement on the size of the present population of Kotzebue. However, among consultants and the City alike there seems to be general agreement that the U.S. Census figures are too low. Short of undertaking a comprehensive survey - which is outside the scope of this study - there is no way of accurately and authoritatively determining which figures are correct. The City of Kotzebue currently has plans for a survey in the spring of 1982. Meanwhile, as mentioned above, the City Planning Commission is using the estimate developed by Quadra Engineering (ref. "Kotzebue Water and Sewer Expansion Study", January 1981), since this estimate generally is considered to be based on the most exhaustive analysis to date. It is therefore proposed that for the purposes of the present study the same estimate be used. Thus, the 1980 population is assumed to be 2,544. 4.3 POPULATION PROJECTION Over the last decade a number of population projections have been made for Kotzebue. The most recent (and, therefore, more rele- vant) ones include a 1980 estimate by Quadra Engineering (ref. "Kotzebue Water and Sewer Expansion Study", 1981) resulting ina year 2000 population of 4,000. This projection has been accepted by the City of Kotzebue Planning Commission as being "the best available." A review by this Consultant confirms this. The pro- jection, which forecasts the population to the year 2000, generally continues the level of growth seen in the '60s and '70s with an average annual growth rate of about 2.3 percent. This projection seems to adequately reflect two likely opposing -- and to a certain extent mutually neutralizing -- factors that may influence Kotzebue's population growth in the next 20 years: a slowing down of migration from outlying villages due to improved facilities and housing on the one hand, and an increase in economic activity resulting from accelerating exploration for and possible development of natural resources in Northwest Alaska, on the other. It is therefore proposed that for the purposes of this study, the energy consumption forecast be based on Quadra Engineering's pro- jection. Thus, the year 2000 population is expected to be around 4,000, increasing to 4,200 in 2002. It should be noted that this projection does not allow for the possibility that petroleum may be discovered in large commercial quantities so early in the planning period that major development will occur in time to significantly impact the year 2002 population of Kotzebue. If indeed a major oil discovery were made in the Kotzebue region soon after the scheduled offshore lease sales in 1985, and if the development phase were to start immediately following this, the population forecast -- and thereby also the energy needs forecast -- should be revised accordingly. To attempt to develop a likely scenario for the discovery and development of natural resources in the Kotzebue area at this time, and to project the resultant population increase, is irrelevant considering the uncertainties involved. It seems probable that commercial quantities will be discovered in the region. However, it also seems probable that decades could pass before this happens and development starts, possibly toward the very end of the planning period. 4.4 PRESENT AND FUTURE HOUSEHOLD SIZE In order to establish the future number of residential energy consumers, it is necessary to estimate the number of households. As was the case for the current total population, there are also widely divergent opinions on the present number of persons per household, or per housing unit: 1970 Census data indicate about 4.8 persons per household. The 1980 Census showed 2.9 persons per household, which is generally thought to be too low. In the same year (1980) the Leslie Foundation through the Maniilag Association determined the average household size in the City of Kotzebue to be 4.25, while a survey by Quadra Engineering and CETA indicated 4.88 persons per household. In order to resolve the apparent conflict and arrive at a specific figure, Quadra Engineering in the Sewer and Water Extension Study used the average of 4.25 and 4.88 -- i.e. 4.5. A household size of 4.5, however, is relatively high when compared to the state average, which according to the 1980 census was 2.5, and to other cities of similar size and population composition, such as Nome or Barrow where household size estimates indicate between 3.4 and 4.0 persons per residential unit. New information provided by two State energy auditors, who visited 80 homes in Kotzebue during the period November 1981 - January 1982 indicates about 3.8 persons per residential unit. Thus, for lack of better information, the 1980 average household size in Kotzebue is taken to be 4.0. However, as a result of declining birth rates and anticipated construction of additional housing units, the average number of persons per household is expected to decline gradually at least until the year 2000. Based upon a review of regional trends and relevant projections made for other similar-sized communities with a comparable racial mix, indications are that within the planning period the average 4-4 household size will approach the current state average. For purposes of this study, therefore, it is assumed that Kotzebue's overall average household size will gradually decline from 4.0 in 1980 to approximately 3.0 in 2002. Thus, based on the projected increase in total population, the number of households will increase from approximately 636 in 1980 to about 1400 in 2002, corresponding to an annual rate of increase in residential consumers of around 3.6%. Table 4.2 Population Projection NO. OF PERSONS YEAR POPULATION HOUSEHOLDS PER HOUSEHOLD 1) 1980 2,544 636 1981 2,625 660 1985 2,850 760 1990 3,200 900 1995 3,600 1,100 3a 2000 4,000 1,300 3.1 2002 4,200 1,400 3.0 Growth rate of population: 2.3%/year Growth rate of number of households: 3.6%/year The projection of population and households can also be seen in Figure 4.1 (1) approximate numbers FIGURE 4.1 PROJECTION OF POPULATION AND SIZE OF HOUSEHOLDS 5000 4001 total population 300: wee _ ST a tw number of —-_ households 1000) years persons per household 4.5 LIGHT AND APPLIANCES Kotzebue Electric Association has provided a breakdown of the electric power usage in the community. The breakdown was for the first eleven months of 1981, but for the purposes of this study, it has been assumed that the percentage division is the same for the whole year. Table 4.3 Breakdown of Electric Power Usage in 1981 103kwh Residential homes 2,541 21.2 Small commercial (< 50 kVA) 4,012 33.3 Large commercial (> 50 kVA) 3,635 5052 Public 531 4.4 Street lighting 50 0.4 KEA office and plant use 86 0.7 Total accounted for 10,855 90.1 Total unaccounted for (line losses etc.) 1,192 9.9 Total generated 12,047 100.0 Line losses, etc. amount to 1,192 x 103 kWh out of a total of 12,047 x 10° kWh equivalent to approximately 10%. A portion of the homes in Kotzebue have electrical water heaters. The power consumed by these must be subtracted from the total used by “residential homes" (see Table 4.3) to arrive at the power used for “light and appliances" only. Heating of water is computed as a separate item later. Since it has not been possible to visit each individual household in Kotzebue in order to determine the occurrence and nature of its electrical appliances, information gathered by two local energy auditors as well as data from KEA were used to establish a reasonable basis for calculating the power consumed by electrical hot water heaters. The two energy auditors have visited 80 homes in Kotzebue, of which 20 (25%) had electric water heaters. Information from KEA indicates that about 10 (15%) of the consumers have electric water heaters. The figures provided by KEA seem to be the more realistic, since the information from the energy auditors may not represent an average cross section of the homes. For the purposes of this assessment, it is therefore assumed that approximately 15% of all households have water heaters (corresponding to 100 homes). If it is assumed that all major hot water users, i.e. the hospital, schools, etc., do not use electricity for hot water heating and that the persons in the homes with electrical water heaters use more hot water than the average person - estimates indicate 5 gallons per day per person - then the electrical power for heating water from 32°F to 132°F is 179,000 kWh/year or 1.5 percent of Kotzebue's total yearly energy consumption. KEA has also provided the totals of electrical power generated for the years 1968 through 1981. Using the above estimated figures, i.e. 10% for losses and 1.5% for hot water heating, in conjunction with column 2 and 5 of Table 4.1: Past Population Trends, the following figures are arrived at: Table 4.4 KEA Power Generation 1968-1981 Information from KEA Light and appliances Total generation Peakload load Total 9° per capita Year 10 kwh kW Factor'3) kwh § kWh 1968 3,353 761 0.50 2,967 _— 1969 3,590 784 0.52 3,177 —_ 1970 4,180 969 0.49 3,699 2,181 1971 4,797 1,041 0.53 4,245 2,264 1972 5,019 1,008 0.57 4,442 2,270 1973 5,211 1,030 0.58 4,612 2,170 1974 Seah 1,200 0.54 5,054 2,378 1975 6,822 1,400 0.56 6,037 2,841 1976 7,881 1,568 0.57 6,975 2,869 1977 8,979 1,859 0.55 7,946 3,269 1978 10,610 1,948 0.62 9,390 3,717 1979 10,980 2,032 0.62 9,717 3,847 1980 11,154 2705 0.60 9,871 3,880 1981 12,047 2,150 0.64 10,676 4,067 (2) (1) Total generation less 11.5% for losses and hot water heating. (2) 2,625 persons estimated. (3) The load factor is computed on the basis of the total generation: total generation 365 x 24 x peakload - Anas REARS These figures indicate that during the period 1970-1981, the annual rise in electrical consumption for “light and appliances" was approximately 6% per person. In “Assessment of Power Generation Alternatives for Kotzebue" Robert W. Retherford Associates have estimated an annual per- consumer rise of 3% from 1980 to the year 2000. If the "consumer" is equal to or proportional to the "household", this translates into a per capita rise of 5% per year, based on previously madae assumptions on household sizes. It is anticipated, however, that the per capita consumption will not continue to grow at this rate throughout the whole planning period. Therefore, growth rates of 5% and 4% for 1980-1990 and 1990-2002, respectively, were used. By relating these to the population projection (see Table 4.2) the following per capita and total consumptions were arrived at. The forecast of electrical energy demand for light and appliances can be seen in Table 4.5. As there is presently no (major) electrical consumption by industry and as there seem to be no immediate plans for any new significant industrial activities, the forecast for light and appliances corresponds to the total electrical energy demand, less what is needed for heating of hot water and what is lost through line losses. In the years from 1968 to 1981 the load factor for the power plant has increased from 0.50 to 0.64 as can be seen in Table 4.4. However, this load factor increase cannot continue in the planning period, since a likely limit for the load factor is 0.60 - 0.65. Therefore, this study assumes a load factor of 0.60 as a basis for the peakload forecast for the whole planning period. Table 4.5 Light and Appliances Forecast (1) Light & appliances, Light & appliances, Peakload (2) Year per capita, kWh total, 10 kWh kw 1980 3,880 9,871 2,105 (3) 1981 4,067 10,676 2,150 §3) 1985 4,952 14,113 3,000 1990 6,320 20,224 4,500 1995 7,689 27,680 6,000 2000 9,335 36,420 8,000 2002 10,119 42,500 9,000 (1) Does not include line loss etc., which is approximately 10% of total generation. (2) Peakload is computed for a load factor of 0.60 and allows for a 10% line loss: light and appliances - 0.90 x 365 x 24 x 0.6 Peakload (3) Information from KEA The per capita and total consumptions are shown in Figures 4.2 and 4.3. To illustrate the numbers presented in Table 4.5 and Figures 4.2 and 4.3, a comparison can be made to the total electricity consumption in the greater Anchorage area in 1980. In Anchoragg total consumption less line losses was approximately 1.90 x 10 kWh; with an estimated population of 180,000 persons this yields a per capita consumption of 10,560 kWh/year. This study shows a projected consumption for Kotzebue in the year 2002 of 10,119 kWh/year per capita), The 1982 Long Term Energy Plan for the State of Alaska projects an annual 6 percent rise in electricity demand per capita in the state as a whole over the next 20 years. This would give an annual consumption of 13.890 kWh per capita in the year 2002. Thus, a saturation curve where per capita consumption approaches a "maximum" value is not seen within the 20-year planning period. Saturation would be likely to occur within a few years after the 20-year period. (1) State of Alaska: Long Term Energy Plan, 1982 Report February 1982. Alaska Electric Power Statistics 1960-1980 Sixth Edition, August 1981. 4-10 FIGURE 4.2 LIGHT AND APPLIANCES kWh CONSUMPTION PER CAPITA PER YEAR RECORDED (1) 10° kWh per year per capita year Consumption used as basis for subsequent section of report consumption in the event that annual increase is 5% from 1990 consumption in the event that annual increase is 6% from 1981 (1) From KEA records 4-11 FIGURE 4.3 LIGHT AND APPLIANCES TOTAL kWh CONSUMPTION PER YEAR 60 > io o ° PROJECTED a RECORDED (1) kWh per year x 10° 1G 1970 year FROM KEA RECORDS 4.6 SPACE HEATING The forecast for space heating demand until 2002 is based on a theoretical calculation of the actual space heating demand in 1981. The space heating demand for an individual building is a function of the floor area and the format and height of the building and the quality and level of insulation. 4.6.1 Site Reconnaissance During a site reconnaissance, all buildings have been classified by visual judgement and some buildings were physically measured. In addition to the visual classification, information provided by two local energy auditors, who had visited 80 individual homes in Kotzebue, was used. 4.6.2 Basic Data for Calculations: From a calculation of a well-insulated one story building with a floor area of 960 sq.ft., the basic heat loss per square foot was computed. Besides this calculation, information from the energy auditors has been used in figuring out the most correct basic heat loss per square foot. Heat loss not only depends upon floor area and insulation, but also on the shape and form of the individual building; therefore, a conformation factor, i.e. total surface divided by floor area, is used. The various examples are as follows: HEAT LOSS CONFOR- HEAT LOSS x 3.00 FLOOR MATION (Btu ) ~—€ONFOR= (sq.ft.) FACTOR h °F sq.ft. MATION FACTOR Calculation 960 3.06 0.252 0.247 Energy Auditors 1008 3.04 0.198 0.195 Energy Auditors 864 Sirk 0.277 0.267 Energy Auditors 960 3.06 05.232 0.227 Energy Auditors 864 3.11 0.280 0.270 Average 0.241 These figures were based on information derived from homes that are well-insulated; however, many houses have very poor insula- tion. Consequently, all houses have been given an insulation factor ranging from 1.00 for well insulated houses to 2.00 for old houses with poor or no insulation. 4.6.3 Calculation of heat loss: Based on the above: the calculations assume a basic heat loss f 0.24 i di h loss f= ° 2 —Wx F x sq.tt. ' including heat loss for venti lation, for a house with a conformation factor of 3.00 and an insulation factor of 1.00. The floor areas of individual buildings were taken from recent aerial mapping of Kotzebue, and the total surface was calculated on the basis of the actual height of the building. The heat loss was then determined as follows: floor area x conf. factor x insulation factor x 0.24/3 = heat loss (____BTU _)y h x °F In Table 4.6 the total heat loss for all buildings in Kotzebue is summarized. The buildings are roughly divided into five groups: Residential: Single residential houses. FAA: All buildings south of the airport. School & hospital: Buildings within the two blocks where the school and hospital are located. Public & commercial: Public buildings, offices, apartment buildings, churches, stores, etc. Warehouses: Warehouses in connection with commercial buildings, hangars at the airport, etc. TABLE 4.6 Calculation of Space Heating Demand, 1981 Floor area Heat loss Heat loss Heat Demand. Floor areé BIU BIU Blu x 10° per capita Group sq.ft. h x °F x sq. ft. h x °F YEAR sq.ft Residential 476,407 0.43 204,003 79,076 181 FAA 29,680 0.40 11,8900 4,609 1l School & Hosp. 216,998 0.36 77,485 30,035 83 Public & Commerce 253,625 0.36 87,192 33,798 132 Warehouses 93,625 0535 33,202 12,870 TOTAL 1,070,335 0.385 ‘1) 413,772 160,388 408 QQ) average The annual demand is based on 16,151 degree days per year in Kotzebue (Cold Climate Utility Delivery Design Manual). The total annual space heating demand is a little higher than the total output indicated in the energy balance. However, in the above calculations, heat gain from light, cooking and people is not taken into consideration. 4.6.4 Forecast to the Year 2002 The forecast to the year 2002 is based upon an evaluation of population, household size, size of residences, and _ thermal efficiency of these residences. It is assumed that towards the latter part of the plan period a part of the old and small houses will have been replaced by newer and larger homes and that the floor area per capita in residential houses therefore will increase. However, it is also assumed that as the number of persons’ per household is decreasing, there will be a need for smaller homes -- mostly for the young and the elderly. The result will be a growth in floor area per capita from 181 sq.ft. in 1981 to approximately 240 sq.ft. in 2002, while the floor area per household will be almost the same in 2002 as in 1981. For the school, hospital and commercial buildings, it is assumed that there will be a very small increase in area per capita. These assumptions are based on actual home sizes and floor areas per capita, and also on information about the trends of home sizes in the northern latitudes in the last ten years. Figure 4.4 shows the projection of floor area per capita. 4-15 FIGURE 4.4 FLOOR AREA PER CAPITA PROJECTION 20 square foot per capita | residential icommercial & public school & hospital FAA 4-16 As shown in Table 4.7, the resulting calculated heat loss per sq. ft. ranges as an average from Btu 0.43 ———_, _———____ h x °F x sq. ft. for residential buildings to Btu 0.35 ———__— 5 -—_____— nx °F x sq. £ for commercial, etc. A part of this heat loss can, especially in the residential houses, be decreased by improved insulation of existing buildings as well as by replacement of old houses with new and well- insulated houses. In order to show the effect of improved insulation of existing buildings and efficient insulation of new buildings, two fore- casts for space heating demand have been computed: a low forecast and a high forecast. For the low forecast it is assumed that improved insulation of the existing buildings will be carried out, and that efficient insulation will be installed in the new buildings. For the high forecast no improvements of insulation in the existing buildings have been assumed, and low insulation levels are anticipated in the new buildings. The heat loss per sq.ft. used as a basis in the two forecasts is shown in Table 4.7 4-17 TABLE 4.7 Heat loss per sq.ft., Forecast 2002 BTU h x °F x sq.ft. Calculation Low Forecast High forecast 1981 (1) (2) (1) (2) Residential 0.43 0.35 0.30 0.43 0735 FAA 0.40 0.33 0.30 0.40 0.35 School & Hospital 0.36 0.32 0.30 0.36 0-35 Commercial, etc. 0.35 0.33 0.30 0.35 0.35 (1) Value used for area equal to existing buildings in 1981. (2) Value used for additional new buildings. The forecast for floor areas of buildings up until 2002 can be seen in Table 4.8 and and in Figure 4.5. TABLE 4.8 Total Floor Area, Forecast 2002 (sq. ft.) School & Public, Comm. Year Residential FAA Hospital and Warehouse Total 1981 476,407 29,680 216,988 347,250 1,070,335 1985 547,000 32,000 240,000 408,000 1,227,000 1990 659,000 35,000 288,000 464,000 1,446,000 1995 792,000 40,000 330,000 526,000 1,688,000 2000 936,000 44,000 392,000 592,000 1,964,000 2002 1,008,000 46,000 420,000 630,000 2,094,000 The forecast for space heating demand for the years until 2002 can be seen in table 4.9 and 4.10 and in Figure 4.6. 4-18 FIGURE 4.5 TOTAL FLOOR AREA AND SPACE HEAT DEMAND PROJECTION Btu hx oF) (10° 10° sq. ft. ojection years Table 4.9 Space Heating Demand, Low Forecast to 2002 Floor Heat loss Heat loss Space heat YEAR area demand 6 Btu Btu x 103 Btu x 10? kwh x 10° sq*ft.x 10 h_x °F x sq.ft. hx °F year year 1981 1.07 0.39 414 160 47 1985 1.23 0.37 454 180 53 1990 1.45 0.35 509 200 59 1995 1.69 0.34 571 220 64 2000 1.96 0.33 641 250 73 2002 2.09 0.32 671 260 76 Table 4.10 Space Heating Demand, High Forecast to 2002 Floor Heat loss Heat loss Space heat YEAR area demand Btu Btu x 103 Btu x 10? Kwh x 108 sq.ft. x 106 h_x °F x sq.ft. h x °F _year year 1981 1.07 0.39 414 160 47 1985 123 0.38 471 180 54 1990 1.45 0.38 548 210 62 1995 1.69 0.37 633 250 72 2000 1.96 0.37 730 280 83 2002 2.09 0.37 780 300 89 FIGURE 4.6 SPACE HEATING DEMAND PER YEAR PROJECTION 10° Btu per year 350 30) ) 100 10° kWh per year 1 year high roe io 7 e* projection 4.7 HOT WATER The hospital and the school are the two largest hot water consumers in the community today. The hospital's total consumption of potable water is 4,200,000 gallons per year, of which, roughly estimated, 35% or 1,470,000 gallons are used as hot water. The school's total consumption of potable water is 4,450,000 gallons per year, of which, again roughly estimated, 20% or 890,000 gallons are used as hot water. The hospital's and the school's hot water consumption is, for the purpose of this study, anticipated to grow proportionally with the population. At present many residences have no hot water heaters, and hot water must be heated on stoves. That will, of course, limit the usage of hot water, but gradually the usage of hot water will increase when more new houses with easy access to hot water are built. Therefore, the per capita consumption for residential, commercial and public use additional to the above two large consumers is estimated at 5 gallons per day, compared to approximately 10 - 15 gallons per day in a fully developed community with reasonably inexpensive access to energy. Toward the end of this study's planning period, the per capita consumption of hot water in Kotzebue is anticipated to reach this level, i.e. 15 gallons per day. Tables 4.11 and 4.12 show the hot water consumption of the above described three sectors: TABLE 4.11 Consumption of Hot Water, Residential, Commercial, and Public Use Gallons per capita Gallons x 103 YEAR per day per year 1981 5 4,800 1985 6 6,300 1990 8 9,400 1995 ll 14,500 2000 14 20,500 2002 15 23,000 Table 4.12 Total Hot Water Consumption Forecast 2002 Residential, comm, Hospital School and public Total Year gal x 103 /yr gal x 103 /yr gal x 103 /yr gal x 103/yr 1981 1,500 900 4,800 7,200 1985 1,600 1,000 6,300 8,900 1990 1,800 1,100 9,400 12,300 L995 2,000 1,200 14,500 17,700 2000 2,300 1,400 20,500 24,200 2002 2,400 1,500 23,000 26,900 The total consumption of hot water per year is converted to Btu and kWh per year by using a temperature rise of 100°F, i.e. from 32°F to approximately 132°F and not taking into consideration any conversion losses at all. The heat demand for heating hot water can then be seen in Table 4.13 and in Figure 4.7 Table 4.13 Heat Demand for Heating Hot Water Forecast 2002 Year gal x 103/year Btu x 109/year kwh x 10®/year 1981 7,200 6.0 1.8 1985 8,900 7.4 2ret2 1990 12,300 10.3 3.0 1995 17,700 14.8 4.3 2000 24,200 20.2 5.9 2002 26,900 22.5 6.6 FIGURE 4.7 HOT WATER, HEAT DEMAND PER YEAR PROJECTION 25) 10° Btu per year 10° kWh per year year 4-24 4.8 INDUSTRIAL PROCESSES Currently no industrial production is taking place in Kotzebue, and for the purposes of this study none is expected within the planning period (1982-2002). However, some energy is used for heating the cold water supply to prevent freezing in the supply lines as well as in storage tanks. The city has indicated that potable water leaves the water treatment plant at a temperature of 40-42°F and returns from the circulation at a temperature close to 32°F. At the water source, the water is heated by boilers prior to being pumped to the treatment plant. The approximate present total water consumption in the community is 200,000 gallons per day, but since the water is circulating and thus losing energy continuously, an exact amount of heat to be added cannot be determined based on consumption. However, in 1982 the.water treatment plant in Kotzebue used approximately 30,000 gallons of fuel for heating the cold water supply. Furthermore, it was estimated that approximately 6,780 million Btu of waste heat was used to heat the city's potable water. Assuming that the 30,000 gallons (of fuel are gonverted at 803 efficiency, a total of 6,780 x 10° + 3,264 x 10° = 10,044 x 10 Btu per year is arrived at. The present consumption of fresh water corresponds to 76 gallons per day per person. The "Cold Climate Utilities Delivery, Design Manual" (Water Pollution Control Directorate, 1979) recommends a design figure of 120 gallons per day per person in “communities totally serviced by a piped water distribution and sewage collection system". However, in many northern communities, it is difficult to get adequate amounts of potable water. Therefore, when the population is growing, it may be necessary to limit the consumption of potable water. For the purpose of this study, it is assumed that the per capita consumption of potable water will remain constant through the planning period at 76 gallons/capita/day. In Table 4.14 and in Figure 4.8, the energy demand for heating cold water supply is shown. Table 4.14 Potable Water Consumption and Heat Demand For Freeze Protection Forecast. 2002 Gal. per Gallons/ Total Total Bnergy per yeag Year cap/day day gal.x10//yr Btu_x 10°/yr kWh x 10 /yr 1981 76 200,000 a3 10.0 239 1985 76 220,000 80 2 Sid 1990 76 240,000 88 28 a6 1995 76 270,000 99 14.0 4.1 2000 76 300,000 110 1S e4 455 2002 76 320,000 1G 16.4 4.8 4.9 SUMMARY Figure 4.9 shows a summary of the total projected energy demand for Kotzebue to the year 2002. The high and low forecasts for space heating demand are based on the projection for total floor area and on the high and low forecasts for heat loss per square foot of floor area. These forecasts are shown in Tables 4.7 and 4.8. The forecast for light and appliances is hased on the population forecast shown in Figure 4.1 and an annual 4% increase in population. FIGURE 4.8 COLD WATER SUPPLY. HEAT DEMAND PER YEAR PROJECTION 25 20) «= a 10° Btu per year 3 10° kWh per year year FIGURE 4.9 TOTAL ENERGY DEMAND, ELECTRICAL AND HEATING PROJECTION 550 160 500 140 450 @ 1 © 400} & r r Pd - o @ 350 o $19 ~ 5 e ee @ 300 S ing 2 = co = 250 low 200 light and ABO appliances 100 50 hot water ssseesdesees, COld Water et supply 1980 1990 2000 5. TECHNOLOGY PROFILES SECTION 5 TECHNOLOGY PROFILES TABLE OF CONTENTS General..... RSPR ERE CRT RA eovccesnnl Electrical Generation........... cece eeeee Se G.e ies, 6 es S S515 5-1 District Heating........... Siellene' stele G o)'siise eisiigie 6 wise @ wieiee © site 5-1 COGENETACION + asic ac eis coca s os ome Se awe BS iiete Sin S Heels © Ssh 5-2 Other Systems and Fuels............. ec cen eee vale eee cennn ls Technology Profile Details.......... eee cerccrcencccscne 3=3 SECTION 5 TECHNOLOGY PROFILES 5.0 GENERAL Technology Profiles have been prepared for all known energy alternatives potentially viable in Kotzebue. These profiles are oriented toward (1) electrical generation and (2) space heating utilizing, when practicable, cogeneration techniques. The "pure" power generation and space heating technologies are included, because a combination of two or more of these might be the most favorable solution to the power and heating needs of Kotzebue. Each technical or resource profile has been structured so that it can stand by itself. Each profile, as applicable, contains a General Description; Performance Characteristics; Costs; Special Requirements and Impacts; and a Summary. All profiles are, in turn, evaluated in accordance with the matrix outlined in Section 6. Details of each technology's assets may be found in Volume II, Appendix D. 5.1 ELECTRICAL GENERATION Technology profiles are provided for the most likely systems possible for the Kotzebue area. Since diesel electric generation currently is the power source for Kotzebue, it will be taken as the base case; the other electric generation alternatives addressed are: Steam-Electric Generating Units Cogeneration Systems Coal Gasification Combined Cycle Old Fashioned Coal Gasification by the "Kopper Totzek" Method Hydropower -- Buckland Site Wind Turbine Electrical Generators Geothermal Generation cooo°o 000 5.2. DISTRICT HEATING District heating is a collective heating system, supplying energy for space heating purposes and water heating in urban communities. The system is comprised of three elements: a central heat source, a piping system, and consumer equipment. The idea was born in the United States and has been in commercial use in many parts of the world since the beginning of this century. Having fewer fossil fuels, the Northern European countries have developed hot water district heating systems and proved them to be economical, efficient and profitable. Initially, steam was distributed, but developments showed that hot water was a more convenient heat medium, offering many technical and economical advantages, The original background for establishing the schemes was a wish to achieve greater comfort, rather than conserving energy. However, an important improvement of the environment was achieved, as a number of small, inadequate, individual stoves were replaced by one single efficient heat source. For example, in Denmark today more than 400 schemes’ serve approximately 750,000 homes all over the country. Approximately 350 of these schemes are privately owned cooperatives serving mainly the small towns and villages. Thus, a great part of these serve less than a few hundred one-family houses. Also many communities in Greenland have district heating schemes utilizing waste heat from power plants. A district heating network consists of an insulated, double pipe system, connecting the individual users with one or more central heat sources. From the heating station, hot water of approximately 200° to 240°F is sent out through the flow pipe system. In the consumers' houses the heat content of the water is released in the heating systems, and water of approximately 100° to 120°F returns through the return pipe system for reheating in the station. Surplus heat from thermal power plants (diesel engines, gas or steam turbines) offers a big potential for district heating and is easy to recover at low cost, depending on the system and installation. A modern low-temperature, water-based district heating system offers high flexibility, as almost any fuel, combustible waste material, or waste heat source may be converted into useful energy. The waste heat or central heat source is usually a heat only boiler, or an electrical power plant which has_ been converted for cogeneration. 5.3 COGENERATION In cogeneration systems, electrical or mechanical energy and useful thermal energy are produced simultaneously. Such improved efficiency systems use a combination of mechanisms to utilize more of the heat energy produced when conventional fuels are burned than is possible with any existing single system. Using cogeneration rather than separate systems to produce heat and electricity will yield net fuel savings of 10 to 30 percent. Production efficiency of generating electricity is 22 to 34 percent, and recoverable heat is 43 to 63 percent, permitting total system efficiency of 65 percent to 85 percent in cogeneration cycles. Cogeneration systems include dual-purpose power plants, waste heat utilization systems, certain types of district heating systems, and total energy systems. Such systems have been applied since the late 1880's and, in the United States, have been used much more widely in the past than they are today. In the early 1900's, most U.S. industrial plants generated their own electricity and many used the exhaust steam for industrial processes. Many utility companies supplied cogenerated steam to large industrial users and densely populated urban areas. By 1909, an estimated 150 utility companies were providing district heating. Cogeneration operations in the United States declined largely because of the availability and low cost of natural gas heating and of relatively low-cost reliable supplies of electrical power from large generation plants located in sites remote from densely populated areas. 5.4 OTHER SYSTEMS AND FUELS To ensure that all viable concepts were studied, system combinations as well as conservation techniques et.al., were studied. Examples of some of these concepts further described in Volume II are: Electrical Energy Conservation Thermal Energy Conservation Organic Rankine Cycle Heat Pump System - District Heating ooo°o Fuels analyzed for use included: Diesel Water (Hydro) Gas Coal Peat Wood Geothermal Wind oo000000 5.5 TECHNOLOGY PROFILE DETAILS Volume II, Appendix D of this report covers in detail all technology profiles further evaluated in Section 6 Consequently, the reader should familiarize himself with the details in Appendix D, as they apply to the particular technology being considered. o2 6. EVALUATION OF TECHNOLOGY PROFILES SECTION 6 EVALUATION OF TECHNOLOGY PROFILES TABLE OF CONTENTS 6.1 Systematic Evaluation ProcedureS.ceccscccccccccvesccee O-l 6.2 Results Of The Evaluation. cccceccsccccccvescccvesceses 6-6 6.3 Resource ConSiderationS..crcccccsecescvvevecvccevsecses O-9 LIST OF TABLES Table 6.1 Technology Profiles Evaluation...ccscseccceceveee 6-4 SECTION 6 EVALUATION OF TECHNOLOGY PROFILES 6.1 SYSTEMATIC EVALUATION PROCEDURE Sections 5 and 6 were utilized to more clearly define those energy alternatives which are considered realistic for Kotzebue. This enabled us to analyze only those alternatives which had proved to be potentially feasible. Consequently Sections 7, 8, 9, and 10 only address those alternatives. 6.1.1 Categories The technology profiles discussed in Section 5 (see also Volume II, Appendix D), have been sorted into several different categories, i.e.: A Technologies which mainly aim at producing electric energy. B Technologies which produce both electric energy and heat energy in significant proportions. c Technologies which mainly aim at producing heat energy. D Support systems which would support other systems producing electric energy by reducing cost or consumption. E Support systems which would support other systems producing heat energy by reducing cost or consumption. F Geothermal Energy. The technologies which have the higher ratings within each category are then combined into several alternative scenarios, each of which is described in Section 7, and evaluated in relation to one another and to the base case in Section 10. (Additionally geothermal energy conversion has been included). 6.1.2 Criteria Groups Each technology will be evaluated in three criteria groups, each of which will be assigned a maximum point number. The total of these maximum point numbers will add up to 100 as follows: Group No. Criteria Description Max Points 1 Economic criteria 45 2 Environmental criteria 25 3 Social criteria 30 T00 4 Penalty for major flaws -50 Group 4 enables a penalty to be awarded that does not adequately show up in the point system, for instance where the appropriate energy resource is not available. This technique is helpful since it is impossible to design a_ systematic evaluation methodology which will register all, sometimes conflicting and subjective, points of view. The criteria groups are further subdivided as follows: Group High Points for: Point Range 1. Economic criteria (45) 1.1 Low capital cost 0-15 1.1 Low energy cost 0-30 2. Environmental criteria (25) 2.1 Low air quality impact 0-5 2.2 Low water quality impact 0-5 2.3 Low floral/faunal impact 0-5 2.4 Low land use impact 0-5 2.5 Low aesthetics impact 0-5 3. Social criteria (30) 3.1 High level of community acceptance 0-10 3.2 High level of local employment 0-10 3.3 Low operating technology level, high safety level 0-5 3.4 High reliability 0-5 The points awarded on each technology are tabulated in Table 6.1. The basis for the assignment of rating points is shown below: Price level as of January 1, 1982 Power capacity : 5,000 kW Heating capacity: 12,500 kw (42 x 10° RBtu/h) Landed cost in Kotzebue: 10,000 Btu/lb coal- - - - - - - = $100 per ton No. 1 fuel oil- --------- $1.50 per gallon 6.1.3 Economic Criteria Points for economic criteria have been awarded in accordance with the following scales: (1) Capital Cost $ per kW points $ per kW points $ per kW points >6 ,000 0 4,500 5 3,000 10 5,700 1 4,200 6 2,700 LL 5,400 2 3,900 7 2,400 12 5,100 3 3,600 8 2,100 13 4,800 4 3,300 9 1,800 14 < 1,500 15 (2) Energy Cost (a) Power $ per kWh points $_per kWh points $ per kWh points > 0.35 0 0.25 10 0.15 20 0.33 2 0.23 12 0.13 22 0.31 4 0.21 14 0.11 24 0.29 6 0.19 16 0.09 26 0.27 8 0.17 18 0.07 28 <0.05 30 (b) Heat $ per $ per $ per mil. Btu points mil. Btu points mil. Btu points > 40 0 30 10 20.662220 38 2 28 12 LB weweude 36 4 26 14 16.....24 34 6 24 16 14..40426 32 8 22 18 l2s«es «28 <10.....30 6-3 TABLE 6.1 TECHNOLOGY PROFILES EVALUATIONS Electrical energy conservation can take so many forms, that it is not practical to evaluate all the different possibilities. Note 2 Individual heat pumps are unlikely to prove of interest under the soil and air temperatures prevailing in Kotzebue. technology here. Note 3 No attempt has been made to evaluate this The ratings for community acceptance are based on impressions from the first site visit and comments received during the public review period of the draft Final Report. The ratings for level of local employment are based on the assumption that coal will ultimately be produced from "local" coal resources. Note 5 iS 3 c D E F CATEGORY ; SPACE HEATING SUPPORT SYSTEMS le 5 _ | SPECIAL INTERES’ ELECTRICAL POWER ELECTR. POWER + SPACE HEATING ELECTRICAL POKER SUPPORT SYSTEMS - SPACE HEATING SYSTEM TECHNOLOGY PROFILE NO. 5 oil 5.2 5.16 3.9 5.4 53 5.9 5.1 3.15 7-8 = 3.10 5.16 3.64 3.66 527. 3.15 3.17 ; DIESEL H.P. STEAM ORGANIC HYDROPOWER OAL GASIFI- 8.P. STEAM HYDROPOWER | |rNDIVIDUAL INDIVIDUAL LOW PRESSURE KOPPERS-TOTZEK WIND ELECTRICAL PASSIVE ACTIVE —_ INDIVIDUAL THERMAL GEOTHERMAL TECHNOLOCY ELECTRIC ELECTRIC RANK INE. WITHOUT CATION, BACKPRESSURE INCL. ELECTR| |oIL sTovES SOLID FUEL DISTRICT COAL GASI- GENERATION SOLAR SOLAR HEAT ENERGY DISTRICT [ BASE CASE (CONDENSATION CYCLE GEN. ELecTR-HEAT COMB. CYCLE CO-GENERATION HEATING BASE CASE FURNACES HEATING FICATION Con. PUMPS CONSERVATION HEATING TURBINE) \ u RESOURCE DIESEL OIL COAL (COKE), PEAT WATER COAL COAL, PEAT WATER UEL OIL 1 COAL, KOOD COAL, WOOD COAL WIND NONE | SUN SUN + GEO, AIR NONE GEOTHERMAL WOOD, REFUSE WOOD, REFUSE PEAT PEAT REFUSE \ L EL. POWER + EL. POWER + EL POWER CAPITAL COST S/Ke 1250-1600 3,300 3,650 6,000 iS ,000-20 ,000 3,800 6,000 700 700 500-2000 5,000 1500-3200 Variable 1850 5500 See note 2 275-3300 1 | COST OF ENERGY $/Kwh 0.15-0.22 0.18 - 0.24 9.25-0.31 0.35 0.55 0.02-0.12 0.30 0.05-0.09 See note L S/oru eea-note 51 16-18 88 23 12-20 32 23 70 2.5-22 CRITERIA (MAX RATING) See note 5 | j Group HIGH RATING FOR: Rating Ranze l ECONOMIC (45) 1.1 LOW CAPITAL COST 0-15 15 9 8 0 0 7 oO 15 15 15 3 12 16 2 15 1.2 LOW ENERGY COST 0-30 17 14. 8 0 0 25 0 17 7 24 8 28 7 0 30 SUBTOTAL 32 23 16 0 | 32 j 32 32 39 40 31 2 45 | 2 ENVIRONMENTAL (25) 2.1 LOW AIR QUALITY IMPACT o- 5 3 2 3 5 2 z 5 2 L 4 2 5 5 5 5 2.2 LOW WATER QUAL. IMPACT 0- 5 4 2 3 2 x 2 2 2 a 2 L 5 5 s 5 2.3 LOW FLORAL/FAUNAL IMPACT ss 4 2 3 I 2 2 fc 2 3 2 2 5 5 5 5 2.4 LOW LAND USE IMPACT o- 5 4 3 3 2 2 3 2 3 3 3) 2 4 4 4 5 2.5 LOW AESTHETICS IMPACT 0-5 3 3 5 3 1 3 3 3 B 4 t 1 4 4 5 i SUBTOTAL 18 12 15 13 8 12 13 12 13 1S 8 20 23 23 25 3 SOCIAL CRITERLY (20) 3.1 HIGH COMMUNITY ACCEPTANCE 0-10 5 1 5 10 see note 3 1. 1 10 5 5 9 9 7 9 2 10 3.2 HIGH LOCAL EMPLOYMENT 0-10 5 10 7 O see note 4 10 10 0 2 7 8 9 2 6 1 7 3.3 LOW OPERATING ‘OLOGY LEVEL, HICH SAFETY o-5 % r 2 5 ° 1 0 5 5 5 2 S 5 3 S 3.4 HIGH RELIABILITY 0- 5 4 3 3 5 3 3 5 5 5 4 a 3 5 3 5 SUBTOTAL 16 1s 17 20 1g 1s 15 7 22 26 23 17 25 9 27 L PRELIMINARY TOTAL 66 50 48 33 22 59 28 61 67 80 42 7 5 34 7 | 4 PENALTY FOR MAJOR FLAW -10 to -50 -20 -25 -40 see note 7 -25 -25 -20 -20 -25 230 -30 -30 NATURE OF FLAW High tech High tech Imported Incon- _ Not fuily daily handl. resources Imported High tech Not fully Vevel Taval. cool! venience High techn. developed of external lacking = fuel level develoced 4 x: FINAL RATING 46 25 8 3 -3 36 28 4 47 80 17 47 ' 4 97 See Note 6 1 1 —t Note 1 Note 4 The Hydropower Alternative is included in Section 7 and re-evaluated economically under Section 8. This is being done to ensure the cost of the Retherford preferred plan in their "Assessment of Power Generation Alternatives for Kotzebue" of June 1980 has been evaluated on a similar overall cost basis to the other alternatives. Note 6 Evaluated because of the potential resource in the Kotzebue area. Note 7 Systems in range needed at Kotzebue are not conmercially available. 6-4 6.1.4 Environmental Evaluation Environmental factors were divided into 5 categories’ for evaluation: air quality, water quality, floral/faunal resources, land use and aesthetic considerations. Each was rated from 0-5, with 5 and 4 indicating little or no impact, 3 and 2 indicating moderate impact and 1 and 0 indicating most adverse impact. It was assumed that mitigating measures would be used wherever possible; actual impacts would be expected to be more severe than ratings indicate if mitigations are not adopted. The evaluations were quite subjective. Each category was evaluated for several factors, and not all were necessarily of equal weight, but all were taken into account to some extent where data were available. Factors considered in each category are given below. Air quality considerations. Types of air pollutants and their effects; expected volumes and duration of emissions; concentra- tions; odors; location of the emission in relation to the population. Water quality considerations. Types and volume of pollutants expected; volume and water quality parameters affected; type of water (surface or marine) and water use (wildlife habitat, recreational, drinking water, etc.)impacted. Floral/faunal considerations. Type of organism(s) affected; size of habitat affected; value of organisms (sport or commercial value to man, or importance in ecosystem); legal constraints (protected, threatened or endangered species). Land _use considerations. Size of area impacted; effect of the facility on adjacent areas; conflicting uses; consistency with existing land use. Aesthetic considerations. Visual impact of construction or of emissions/effluents; noise; glare; "presence" or change of existing atmosphere. 6.2 RESULTS OF THE EVALUATION The results of the evaluation as shown in Table 6.1 are: 6.261 Category A: Electrical Power Technology Prelim. Penalty Final Final No. Description Rating Rating Ranking 5. 1 Diesel Electric (Base Case) 66 -20 46 1 5. 2 High Pressure Condensation Steam Turbine 50 -25 25 3 5.16 Organic Rankine Cycle Generation 48 -50 -2 4 5. 9 Hydropower without Electrical Space Heating 33 33 2 Diesel Electric (Base Case) The Diesel Electric technology has a penalty of -20 points due to the necessity to import fuel from outside the district. Nevertheless, as the base case the technology will be subject to more detailed description and evaluation in Sections 7 through Or High Pressure Condensation Steam Turbine This technology has a penalty of -25 points due to its high technology level, which would necessitate the hiring or training of licensed boiler operators. It earns a final rating of 25 points. The technology is not included in any future scenarios, since it is inferior to backpressure steam co-generation by virtue of the latter making use of waste heat. Technology 5.3, therefore, is preferred. Organic Rankine Cycle Generation This technology has a penalty of -50 points because it is not fully developed and proven in the capacity range required, resulting in a final rating of -2. It will therefore not be included in any scenarios for further evaluation. Hydroelectric Power without Electric Space Heating This technology has a final rating of 33 points. In accordance with the wishes of the Alaska Power Authority, the technology will, together with hydropower with electric space heating, be dealt with in some more detail in Section 7.0. 6-6 622.2 Category B: Electrical Power and Space Heating Technology Prelim. Penalty Final Final No. Description Rating Rating Ranking 5. 4 Coal Gasification, Combined Cycle 22 -25 -3 3 5. 3 Backpressure Steam Co-generation 59 -25 34 1 5. 9 Hydropower with Electrical Space Heating 28 28 2 Coal Gasification, Combined Cycle This technology has a penalty of -25 due to its high level of technology. (Consequently, the technology is not included in any scenario for further investigation.) Backpressure Steam Co-generation With a preliminary rating of 59 points this technology ends up with a final rating of 34 points. The technology will be included in Alternative "A" for further investigation. Hydropower with Electrical Space Heating This technology has a final rating of 28 points. As explained previously this technology will be examined in more detail in Section 7. 6.2.3 Category C: Space Heating Technology no. Prelim. Penalty Final Final No. Description Rating Rating Ranking 5. 1 Individual Oil Stoves 61 -20 41 3 5.13 Individual Solid ‘uel Fuel Furnaces 67 -20 47 z 5. 8 Low Pressure District Heating 80 80 1 5. 5 Koppers-Totzek Coal Gasification 42 -25 17 4 Individual Oil Stoves This base case technology presently in use earns a penalty of -20 points owing to its dependence on fuel oil imported from outside the district. This technology is the base case for heating and is therefore the basis for measuring other alternatives for space heating in Sections 7 through 10. Individual Solid Fuel Furnaces This technology has a penalty of -20 points because of the inconvenience involved to the home owner compared to District Heating systems, giving a final rating of 47 points. (The technology is not included in any alternative scenario, since the final rating is considerably lower than that of other technologies.) Low Pressure District Heating This technology has a final rating of 80 points, and is included in Section 7 for further investigation. (In Section 7 the technology is used to supplement the space heating energy obtained from backpressure steam co-generation. This technology is also to be considered as the sole means of providing space heating energy.) Koppers-Totzek Coal Gasification This technology has a penalty of -25 points for a high technology level. The technology is not included in any scenario for further investigation. 6.2.4 Category D: Support Systems Producing or Saving Electrical Power Wind Generation This technology earns a preliminary rating of 77, but this is reduced by a penalty of -30 because the newer machines are not sufficiently tested in Alaska. The technology is investigated further in Section 7. Electrical Energy Conservation The technology is dealt with again in Section 7, since conservation should always be considered and practiced. 6.2.5 Category E. Support Systems Producing Savings in Space Heating Needs. Technology Prelim. Penalty Final Final No. Description Rating Rating Ranking 5.6a Passive solar 75 -30 45 2 5.6b Active solar 34 -30 4 3 5.15 Thermal energy Conservation 97 97 i Passive Solar This technology has a penalty of - 30 points, because its main benefit hinges on the use of external shutters, which is believed to be a limitation on its practical use. 6-8 Active Solar. This technology carries a penalty of -30 points due to insufficient resources. The technology is not included in any alternative for further investigation. Individual Heat Pumps Individual heat pumps are unlikely to prove of interest under the soil and air temperatures prevailing in Kotzebue. No attempt has been made to evaluate this technology here. Thermal Energy Conservation This technology has a final rating of 97, and is investigated further in alternative "E". 6.3 Resource Considerations. A number of technologies (nos. 5.2, 5.3, 5.8, 5.13, and 5.16) can function with a variety of solid fuels. Resource investigation and determination have not been a part of this feasibility assessment; consequently, assumptions had to be made. Nevertheless, when proceeding to the in-depth investigation of the reduced number of alternatives it is sometimes necessary to focus on a particular type of solid fuel to be used. This has been done as a matter of overall, but unspecific, analysis. The following are the solid fuels alternatives considered which might be available to Kotzebue from within the region or state. Coal, Cape Beaufort Coal, Kobuk River Coal, Chicago Creek Coal, Nenana Wood Peat Refuse Coal sources within the Nana Region are: - Kallarichuk River, 90 miles upstream from Kiana on the Kobuk River. - Chicago Creek on the Kugruk River 15 miles West of Candle. The Kallarichuk coals have a heating value of about 10,500 Btu/lb (as received). The Chicago Creek coals have a heating value of 6,000 — 6,500 Btu/lb (as received). It is known that there are considerable resources of wood in the Kobuk and Noatak River catchments. These resources can be floated down the rivers to Kotzebue. The cutting of wood fuel in the quantities required for Kotzebue would have a certain environmental impact in the region. Wood fuel is therefore considered a second choice, which could be investigated as a resource if local coal sources fail to prove viable. Peat around Kotzebue is in a class A2 area. This class is defined as having: - High ratio of area covered by organic soil - Medium probability that the organic soil meets DOE fuel peat requirements. - Reference: Peat Resource Estimation in Alaska. U.S. Dept. of Energy Division of Fossil Energy The following two factors contribute to making peat a poor choice as a main solid fuel for Kotzebue: the shortness of the summer during which time the peat must be harvested and air dried (if produced as milled peat or sod peat),and the environmental impact of peat production. Refuse at present is an environmental nuisance. Depending upon which alternative will eventually be the preferred one, consideration should be given to supplementing the energy from the main energy source with heat derived from the burning of refuse in a boiler suited for that purpose. 6-10 G DESCRIPTION OF ALTERNATIVE PLANS 7.0 Tel ise es 7.4 735 SECTION 7 DESCRIPTION OF ALTERNATIVE PLANS TABLE OF CONTENTS Genercailvsics eicre ¢ sic1e'o\@ clieliele|ciioiie * wiciiclic © alleiic/ole) isle el sieiee VL Base el 2 3 4 CaSe PlaNseccocccnceneesssecesssrssccssceclml INELOAUCEHONs << o 6 6 vicie.c basic orwee eviciee see —t Base Case Electrical Generation......eee7-2 Base Case Waste Heat ReECOVErY.seeeeeeeeeeI—2 Fuel Consumption... ccccccscccccccvccsessveeIn~4 Cogeneration (Alternative "A")ecceeeeeeeeeseeeI—8 el a7 3 4 > Coal- Introduction. cccccccccsccccvccccccccseses IS Alternative "A" Development...seeseeeveee/—-8 BOWEL. co eiolielsiicieie leteiiele esi eis! tere ©) Sisiel © oliel'e/ eerie VL. Turbine Generatorecccocccccccccccseseceei@1l3 BUC Sool! o Hercicicle |e! slelle sicrelie|e| sicic » olelele 6 :ecie/slerere LS fired Low-pressure District Heating System (Alternative "B").ceeeceseceeeceeeeeeeI—“18 ol 22 23 4 -5 GONSTAele:c sic o:clele/e ssils es!) o e\lci/oile/ 6) oliolioe leieliels eleit = Lo Coal-fired District Heating Station.....7-20 Water-Antifreeze Transmission Line......7-25 Distribution Network.-.cccccccccccccccsvel@2o Consumer Installations... .ccccccsccccsvee I 29 Hydropower - Buckland (Alternative "C")......7-30 -10 eal oL2 Gernera lis srcrerercieleleiele’e siecle eleiecletelate 6) e)ier6|s) siete oO Potential SitesS.cccccccccccccsescsecsecei=se Buckland (Rivers occ = oleisis ciclec o.clic)e 6 wleere siecle f= 5S Hydrology .cccccccccccccccscccccccssscesei—al GEOLOGY ielerele siclels| ieicle © o/.0!s o%e)/e1'e. 6] slieiisielelsisie siecle (fm aia Transmission Facilities.....cececeeeseeeI—42 Gost) Estimates .|< «ccs 0 sicle sicitiele olslicle + oie aa Power Production. .cccccccccccccsccessesel 42 Environmental and Other Concerns...++.+.+-7-43 Land) Satusi. .lciec o oieielo aise se ieieie 0 ollciele sisie welt eas Alternative Development Plan.....eeeeeee 7-43 Utilization of Electric Heat........++++7744 Geothermal (Alternative "D")..cccccccccccceeel 44 el Description of the Potential Geothermal ReSOUrCE...v.eccccceceevees 44 7.6 Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure aa Geologic Settingssscescccestceunsensecns 45 o3 Geothermal ReESOUrCE.ecececerccerecseseeel “50 -4 Geothermal Exploration Program..........7-51 -5 Geothermal District Heating...ccccccsccssI—5l -6 Geothermal Power Plant Organic Rankine Cycle)... ceccccccccesceevI—55 Other -(Alternatdves"E™))scccrcicls vcile oeisiere © sicle 6 oo 00 el Energy Conservation. ..cccccccccvccccscee 00 2 -Blectrical Conservatlons ccswicle sicies slcicie eo 10 03 Wind Energy. cccccccccccccccscscvceccccsccsolwis syn se Leils PRR js enle aN 7.1.4 sax ee NM ee mW sn oe oe au NN ann eee Www eee WnNnr Nn NN oe ee > PW WwW oe ee Neue sa . > . . w sANnN Si fel elie eis 6 PWR aan sx ee ann ee Ru 7.6.2 7.6.3 LIST OF FIGURES Base Case Diesel Generation......ee.e-/7-3 Projected Total Heat Demand........+..7-5 Possible Heat Recovery from Diesel Generator.ccecccccccccccccce I 6 Diesel Fuel Consumption Electric Generation (Base Case) .cesececeeeeel—7 Schematic Design for Cogeneration System...ceccccccccreI—9 Alternative A. Steam Turbine GENEFAtlON. cccecsccecccccvescseovecsel—lO Total Heat Demand...ccccccccccecrecceI~l2 Coal Fired Cogeneration Alternative BecccereccccvcccceveseImlS Of] Fired Cogeneration =...6 sc. ccsice ol LO Variation in Demand for Heat and Electricity...ccccccccsccIml7 Arrangement, Plan..cccccccccsccccesveel=23 Arrangement, Elevation. ..ccccccccseee I= 24 Load Basis for District Heating System. ..ccccceccccccccccesI—26 Layout for District Network....seeeeeeI—27 CLOSsS SeCELON ces cece rcecceccccevclec?—2o Small Hydro-Arctic Conditions........7-34 Buckland River Hydroelectric Potential. .cccccvccccccccsccceccsel@39 Buckland River Area Capacity Curve. .cccccccccscccccceel—41 Location Mapeccececccccccccccccsccccce 146 Structural Cross Section. .cceccsercee 1 —48 Nimiuk Pt. No. 1 Test Well Log.......7-49 Schematic Geothermal District Heating Concept..ccccccccccccccccelO3 Schematic Geothermal Power Concept...7-57 Present Value for Wall Construction and Heating..........7-62 Present Value for Floor Construction and Heating.........-7-63 Present Value for Roof Construction and Heating..........7-64 Figure 7.6.4 Construction Costs Per Unit Wall, Roof and Floor. .cessecseeeeeI65 Figure 7.6.5 Yearly Consumption of Heating Oil per Square Foot of Walls, Roofs, and Floors......e+++7766 Figure 7.6.6 Light and Appliances kWh/Year with Electrical Conservation......7-76 Figure 7.6.7 Possible Wind System Con£iguratlonsy. s csnis oe sic cewsic vee t= 710 Figure 7.6.8 Number of Wind Generators ON LINE. . vcccswvcccess secsecessovcsI—19 LIST OF TABLES Table 7.4.1 Kobuk River at Ambler Flow in CFS.....7-38 Table 7.4.2 Kobuk to Buckland Synthetic Flow ReCOrde.cecccccccccccccccccccee I 39 Table 7.4.3 Buckland River Acre Feet x 1000.......7-40 Table 7.6.1 Usage with Electrical Conservation....7-73 Table 7.6.2 Energy Reduction Due to Electrical Conservation.....scccesI@I5 Table 7.6.3 Power Produced by Turbine Diameter....7-81 Table 7.6.4 Annual Power Production by Wind Generators. .ccccccccccccccveceI“82 SECTION 7 DESCRIPTION OF ALTERNATIVE PLANS 7.0 GENERAL A base case plan has been developed to represent a continuation of present diesel generation of electricity and space heating practices. All alternative plans will be evaluated to meet the same heat and electrical energy demand forecast, based on: 1. Specific requests by APA to further look into the feasi- bility of the geothermal resource with a description of alternative plans for use of such a resource; and 2. The need to re-evaluate hydropower schemes (done by others) based on the same energy forecast and cost analysis as are all other alternative plans. The base case plan will be used as standard of reference for the other alternative plans; i.e.: Alternative(!) "A" (Cogeneration); Alternative(?) "B" (Coal-fired Low Pressure District Heat); Alternative(!) «cm (Hydropower - Buckland Site); Alternative!!) "D" (Geothermal); and Alternative(!) "E" (Others, e.g. conservation, insulation, wind etc.). Tel BASE CASE PLAN 7.1.1 Introduction The base case plan is a continuation of the present scheme of providing electricity to the City of Kotzebue using diesel generators. In addition to the electricity provided by diesel generators, the waste heat from these generators is partially recovered. Currently this waste heat is, for the purpose of this report, considered industrial process heat and is used to heat the city water system and the Kotzebue Electric Association offices. Under this base case scenario it is assumed that this will continue to be the case. The electrical energy demand in 2002 is projected to be 42,500 MWh (see Figure 4.3) with peak load being 9 MW. To satisfy these requirements additional generating units will have to be added. (1) Alternative is used herein to mean either a complete system or component of a system. T=. 7.1.2 Base Case Electrical Generation Based on the peak load requirements as shown in Figure 7.1.1, a 1200 KW diesel generating unit will be added on line in 1988 which will give the city a total capacity of 6025 KW with a firm capacity of 5000 KW. With the addition of this unit on line in 1988, the City of Kotzebue will have excess firm capacity until about 1991. In 1991 a 2000 KW unit will come on line providing the city with an excess of firm peak load capacity until mid 1996. In 1996 another 2000 KW unit would be scheduled to go on line which will provide firm peak load capacity to the city until the year 2002. The two 2000 KW units and the one 1200 KW unit will each be driven by a diesel engine. The engines will provide a minimum of 1.5 brake horsepower per kilowatt. These engines will run on DFA or diesel fuel No. 2. The total consumption will be approximately 485 gph at 100 percent load and will decrease to about 170 gph at 25 percent load. The engines will have a plate type heat exchanger and expansion tank on the jacket cooling water. This jacket water cooling system will also contain a thermostatic temperature control valve to automatically control the flow rate of the cooling water to either the heat exchanger or the existing air cooled radiators. Furthermore, in the cooling water piping to the heat exchanger there will also be a thermostatic control valve which will maintain the lubricating oil at the desired temperature. Each diesel unit will contain an exhaust silencer to attenuate the exhaust noise. The electric generators will be of the salient pole synchronous type, each being rated at 60 Hz. Each generator will be three phase rated at 2000 KW, 2000 KW, and 1200 KW respectfully with a power factor of 0.80. The addition of the new rotating equipment will require careful analysis to ensure compatability with the exisiting facilities. 7.1.3 Base Case Waste Heat Recovery Figure 7.1.2 shows the projected total heating load for the City of Kotzebue through 2002. This figure shows that in the year (1) Energy projections for this study were made through the year 2002. However, an update of these energy projections should be made in 1990 to confirm or modify the equipment requirements from 1990 to 2002. FIGURE 7.1.1 BASE CASE DIESEL GENERATION MW PEAK LOAD — megawatts 2002, a total heat demand (space, heat, domestic hot water, and process heat) is about 352 x 10° Btu/year. If the volumetric heating value of the diesel fuel were about 136,500 Btu/gal and that about 30 percent of the heating value can be captured for use, then approximately 48 percent of the city's heating needs could be supplied from the recovery of the waste heat from the diesel generators in 2002. Figure 7.1.3 shows the fraction of the heating demand that could be supplied by the recovery of the waste heat, along with the required additional heat. It should be noted that the present waste heat_ available at minimum load (approximately 1200 KW) is 3.8 x 106 Btu/hr, of which only a fraction is utilized. 7.1.4 Fuel Consumption The yearly fuel consumption to support the electricity generation is shown is Figure 7.1.4. 7-4 FIGURE 7.1.2 PROJECTED TOTAL HEAT DEMAND FOR THE CITY OF KOTZEBUE EXCLUDING LINE LOSSES ESTIMATED AT 15% 340 Btu/year x 10° FIGURE 7.1.3 POSSIBLE HEAT RECOVERY FROM DIESEL GENERATORS Btu/ year x 10° 450 400 350) 300 250 200 150 100 heat re a exhaust gas boiler ait , and jac total heat including | covery with year demand inelosses so Prva jacket water o*® oe! 4s8**" heat recovery with FIGURE 7.1.4 DIESEL FUEL CONSUMPTION ELECTRIC GENERATION diesel x 10° gallons year 7.2 COGENERATION (ALTERNATIVE "A") 7.2.1 Introduction Alternative "A" would be to provide electricity through the use of a steam turbine generator using the exhaust steam from the turbine to provide heat energy for the City. Heat would be distributed through a district heating system based on hot water. If the turbine is not operating at full capacity, then steam will by-pass the turbine through a PRV station to be used for district heat, process heat, and domestic hot water. A simplified schematic drawing of the overall system is shown in Figure 7.2.1. In the back-pressure steam turbine cycle shown in this figure, the boiler will produce high pressure steam at 890 psig at 905°F. This steam will then be expanded through the turbine to produce electricity and exhausted at a pressure of about 5 psig. Net overall efficiency will be approximately 22 - 27 percent. Thus fuel consumption will be 12,600 - 15,500 Btu per kWh produced. Recoverable waste heat will amount to approximately 9,000 Btu per kWh produced. The boiler to provide the steam can either be coal-fired, oil- fired, or gas fired. Costs for the coal fired and oil fired boiler are provided in Section 8.0. 7.2.2 Alternative "A" Development The development of Alternative "A" using either a coal-fired boiler or an oil fired boiler is presented below. The electrical requirements shown in Figure 4.3 and 7.1.1 will be utilized in this scenario along with the heat demand shown on Figure 7.1.2. To satisfy these demands a single 135,009 lbs per hour steam boiler (4,022 BPH) system will be installed along with two (2) - 10MW steam turbine-generators. This system will provide not only all the electrical requirements for the city but will also provide all the heating requirements (space heating, process heating and domestic hot water). The two 10MW units will provide full peak load capacity during the entire 20 year period. In case of breakdown of the steam turbine unit due to boiler failure or auxiliary systems failure the 4825 kw diesel generation capacity will provide some back-up for average load conditions. Furthermore, the diesel units should be kept operational after year the 2002 to provide peak load capacity (see Figure 7.2.2). To provide back-up capacity of the district heating system, a 25 million btu/hr oil-fired boiler will be installed. 7-8 FIGURE 7.2.1 SIMIPLIFIED SCHEMATIC DIAGRAM FOR COGENERATING SYSTEM FOR KOTZEBUE generator condenser electric power steam-water heat exchanger process = heating domestic hot water FIGURE 7.2.2 ALTERNATIVE A. STEAM TURBINE GENERATOR. PEAK LOAD REQUIREMENTS. MW electrical load 14, 13.0 12.0 11.0 10.0) 9.0 8.0) 7.0 6.0 5.0) 4.0 3.0 ~ 3800 KW firm jected peak load Existing oil stoves and oil-fired boilers should be kept operational to provide backup capacity in emergency situations. The amount of heat that would be recovered for space heating, domestic hot water, and process heat is shown in Figure 7.2.3. Furthermore, an air condenser will be required to reject the excess heat in the event the city does not utilize the heat for district heating purposes, but only for the generation of electricity. At times when recaptured heat is not sufficient to supply the total heating load, the remaining will be supplied from steam bypassing the turbine. Variations in demand for heat and electricity for Kotzebue are shown in Figure 7.2.6. 7.2.3 Boiler The boiler will have a steam capacity for total throttle flow to the turbine of about 115,000 pound of steam per hour at 890 psig and 905°F. However, to handle soot blowing, blowdown and miscellaneous radiation and leakage losses, the size of the boiler will have a steam capacity of 135,000 lb/hr. The size of the air and gas handling equipment will depend on the amount of excess air that would be required for optimum firing. This, in turn will depend on the characteristics of the coal (moisture content, carbon content, sulfur content and oxygen content). However, if the Point Hope deposits or Lisburne deposits are utilized it is estimated that the gas flow will be approximately 86.5 x 10~ cfm at full boiler output. The boiler system will require an air heater to_ furnish combustion air at approximately 400°F. This heater will be a two pass vertical tubular type which will permit the installation of gas bypass damper between stages without the need for special ducting. In addition to facilitating the bypass of the heating surface during start-up, the arrangement permits the automatic controlling of the exit gas temperature to avoid condensation. The air heater will be installed in the gas duct at the boiler outlet. The combustion air will enter and leave the unit in a cross flow pattern. High furnace temperatures are essential for clean combustion. If temperatures get too high there is a danger of slagging material accumulating on tube surfaces. If temperatures are too low the combustion gases are apt to enter the boiler convection section with some unburned fixed carbon resulting in lower efficiencies and a discharge of smoke to the atmosphere. 7-11 FIGURE 7.2.3 KOTZEBUE'S TOTAL HEAT DEMAND FOR ALL PURPOSES INCLUDING LINE LOSSES AND WASTE HEAT UTILIZATION THESE DATA HAVE BEEN CALCULATED ON A MONTHLY BASIS Btu/year x 10° 500 450 400 350 300, 250 200) utilized waste heat year 7.2.4 Turbine-Generators The turbine-generator will be steam driven with inlet steam conditions of 890 psig at 905°F and exhausting at 5 psig at 230°F. The generator will be 10 MW. The turbine will be directly connected to the generator. The back pressure steam turbine main steam valves shall be controlled such that they do not exceed 105 percent of the rated pressure. During abnormal conditions the pressure may exceed rated pressure by about 20 percent for brief periods. The temperature variations should not exceed the rated temperature by more than 15°F except during abnormal conditions. The generator will have the following rating: a. 6250 KVA b. 0.85 power factor c. 10.6 MW d. 3600 RPM e. 2 poles, 3 phases f. 4160 volts, 870 amperes, 60 Hz g- WYE connections This generator will be an air cooled synchronous unit with four corner mounted coolers. The unit will also have a_ static excitation system direct connected, including excitation cubicle. 7.2.5 Fuel The fuel for the boiler can either be gas, oil, or coal. This alternative will consider only the use of a coal-fired boiler or an oil-fired boiler. The possible coals that could be used that are near Kotzebue are the Kugruk River coals (Chicago Creek area) which are lignitic coals having a heat combustion of 6200 to 6800 Btu per pound with an average moisture content of 35 percent. A proximate analysis of this coal is: Composition COMPONENTS (Percent by wt.) Fixed carbon 19.2 Volatiles 39.0 Moisture 33.8 Ash Troy lt Sulfur 0.9 Total 100.0 This coal will probably be frozen and the drying of the coal prior to use could be accomplished using the excess waste heat from the boiler. 7=13 Another potential source of coal for use in Kotzebue would be the Point Hope coal deposits. These coals are _ low-volatile bituminous coals that have a heating value of about 14,000 Btu per pound. A proximate analysis of a sample of these coals is presented below: Composition COMPONENTS (Percent by wt.) Fixed Carbon 79.9 Volatiles 15.6 Moisture 1.7 Ash 2.8 Total 100.0 This coal would also be frozen and would have to be thawed and dried prior to use. The coal requirements for the operation of this 135,000 1b per hour boiler are presented in Figure 7.2.4. It should be noted that the coal would have to be mined in the summer and transported and stock piled for major use during the winter months. There are other coal reserves which could also supply such a system, e.g. Kobuk River coal or coal from Healy. Kobuk coal requirements are also included in Figure 7.2.4. The amount of diesel fuel or No. 6 fuel oil that would be required if the boiler were oil-fired instead of coal-fired, is presented in Figure 7.2.5. This figure is based on fuel having a volumetric heat of combustion of 136,500 Btu/gallon. 7-14 FIGURE 7.2.4 COAL REQUIREMENTS COAL FIRED COGENERATION 80 coal tons x 10° 72 64 56 > o 40 32 24 16 85 87 89 91 (ALTERNATIVE B) 93 95 97 99 year Chicago Creek / Kugruk River Coal 6,500 Btu/Ib. Nenana Coal 8,000 Btu/Ib. Kobuk River Coal 10,000 Btu/Ib. Pt. Hope Coal 14,000 Btu/Ib. 01 FIGURE 7.2.5 OIL-FIRED COGENERATION oil x 10° gallons 85 87 89 91 93 95 97 99 01 year FIGURE 7.2.6 VARIATIONS IN DEMAND FOR HEAT AND ELECTRICITY FOR KOTZEBUE BASED ON STATISTICS FOR ELECTRICITY AND HEATING DEGREE DAYS FOR HEAT 14 % of yearly demand Te) COAL- FIRED LOW-PRESSURE DISTRICT HEATING SYSTEM (ALTERNATIVE "B") Tadal General Alternative "B" provides for a coal-fired low-pressure district heating system. In this system it is assumed that all landing, bulk storing and handling of coal would take place in a location on or close to the coastline just south of the Kotzebue lagoon in a position that is compatible with the emergency North-South runway and USAF radar facilities. The alternative provides only for space heating, domestic water and potable water heating demands. In the final analysis it should be combined with a system that provides electric power, i.e. diesel power, high pressure steam generation or hydropower. Apart from coal landing, bulk storage and handling facilities - Alternative "B" comprises the following main components: Javea District heating facility Vssins Water-antifreeze transmission line, approximately 3 miles long, from the district heating facility to the existing power plant 7.3.4 Water-antifreeze distribution system Some or all of the above components have been incorporated in other alternatives, for example: In Alternative "A", heat recovery from a back pressure steam generating unit will be used as a partial energy source for a district heating system. In addition to the steam generating unit, the complete system will require: ° A supplementary coal-fired low-pressure district heating facility of about 75-80% capacity compared to that of Alternative "B" ° Water-antifreeze transmission line, full capacity ° Water-antifreeze distribution system, full capacity In Alternative "C", 7.4.1, a complete coal-fired low-pressure district heating system will also be considered as a means to cover heating needs. In Alternative "D", 7.5.3, a full capacity district heating System will also be considered as a means to cover the heating needs. 7-18 TeSielel Basic Parameters Plant Capacity designed to meet: © Space heating demands (high forecast) are derived from Table 4.10, page 4-21 as follows: Year Btu x 10? ear kWh x 10° /year 1981 160 47 2002 300 89 © Domestic water heating demands are derived from Table 4.13, page 4-24 as follows: Year Btu x 10°/year kWh x 103 /year 1981 6.0 1.8 2002 22.5 6.6 Assuming no significant seasonal demand variation, the above translates into capacities as follows: 1981 0.69 x 10° Btu/h 2002 2.57 x 10° Btu/h © Potable water heating demands are derived from Table 4.14, page 4-27 as follows: Year Btu x 109/year kWh x 103/year 1981 10.0 3.0 2002 16.6 4.8 Assuming no significant seasonal demand variation, the above translates into capacities as follows: 1981 1.14 x Loe Btu/h 2002 1.87 x 10° pBtu/h o Summary of plant capacities envisioned are 1981 2002 Btu/h x 106 Btu_x 106 Space heating 43.06 69.78 Domestic water heating 0.69 2.57 Potable water heating 1.14 1.87 Totals 44.89 74.22 The district heating system has been dimensioned for 74 MBtu/h. The design temperatures are 65°F indoors and -39°F outdoors. The flow temperature of the district heating fluid is 212°F and the return temperature 176°F. u=19 ° Zoning The zoning of the heat demand has been made in accordance with plan 7.3.2. ° Pipe insulation thickness The insulation thickness of the pipes has been dimensioned on the basis of a thermal conductivity of frozen soil of k = 2.2 W/m°c and of unfrozen soil of k = 2.0 W/m°c. The temperature of the soil will be about 25°F. Furthermore, it is considered acceptable that a zone of about 6" around the pipes thaws. This zone should be wholly within gravel backfill, in other words permafrost concerns have, in part, been addressed by this design concept. 7.43.2 Coal-Fired District Heating Station Plant Description. See also Figures 7.3.1 and 7.3.2. 7.3.2.1 Receiving and Transportation of Coal The coal is received from a truck or front loader by way of a funnel. From there the coal is transported on conveyors to the coal storage silo and from the coal storage silo to the service silos at the boilers. The silos are fitted with filling control sensors. From the service silos the coal is fed directly down into the coal funnels of the boilers. 7.3.2.2 Boilers with Traveling Grates The three boilers, type ECOCOAL R, each with a maximum capacity of about 35.7 x 10° Btu/h, are delivered with built-in travelling grates, type Cornelius Schmidt. The boilers consist of a combustion chamber part and a convection part. A large combustion chamber secures a good combustion of the coal. The convection part and the economizer, fitted with vertical flue gas pipes, are divided into sections with throttle valves controlling the flue gas temperature at about 500°F within the load area from 30-100%. 7-20 The grate is dimensioned for Kallarichuk coal with the following specifications: Calorific value, 10,500 Btu/lb Volatiles - 30% Ash - 8% Sulfur - 0.5% Grain size - o- uy" The following grain size ratio is assumed: 0 - 3/64" (culm) About 20% 3/64 - 1" = 70% T= 1/4" = 10% Varying grain sizes, especially increased contents of 0 - 1/8", can reduce the efficiency of the boiler. Heavy contents of coals of more than 1 1/4" will mean more unburned cinders. If an inferior coal quality is used the dimension of the boiler may have to be increased. Nie oi2i13 Multi Cyclone Filters The three multi cyclone filters, type RK, are divided into sections controlled by throttles in order to obtain the best possible exhaust gas velocity in the individual cyclone at varying loads. Particulate matters emitted from fuel burning equipment do not exceed 0.5 grains per cubic foot of exhaust gases corrected to standard conditions, depending on the quality of the coal. 723.224 Exhausters In order to keep a negative pressure in the combustion chamber of the boilers, exhausters are installed after each multi cyclone. 7.3.2.5 Stacks The exhaust gases are led on to the three stacks, each 100' tall. The stacks are manufactured in Corten steel with about 28" core, 4" Rockwool insulation and an external carrying mantle. The stacks are bolted to a concrete foundation. i=20 7.3.2.6 Cinders and Ash Disposal The cinders and the ashes are ejected at the bottom of the boiler and transported on a conveyor to the cinder- and ash container. Tedutet Miscellaneous Installations The pipe installation uses pre-insulated steel pipes with all necessary valves and fittings. The two pumps are designed with a pumping capacity of 100% load each. The expansion tank is provided with fittings for automatic pressure control by means of compressed air. The raw water is treated in a water treatment system and is fed to a holding tank. The conceptual design and section is shown in Figures 7.3.1 and T Side 7-22 ef-L KOTZEBUE CENTRAL DISTRICT HEATING ARRANGEMENT, PLAN Stacks Expansion tank Cfcloke se- paratprs Ash cdnveyor Ash container Boileys Circuit pumps Coal silo Service silos Funnel Coal gonveyor FIGURE 7.3.1 FIGURE 7.3.2 KOTZEBUE CENTRAL DISTRICT HEATING ARRANGEMENT, ELEVATION Stack Coal silo | —e-_,, 7a Cyclone separator Ash conveyor 7-24 7.3.3 Water-Antifreeze Transmission Line The transfer of heating energy to the distribution network will take place in a triple conduit, each pipe being steel-in-steel preinsulated piping. The internal diameter of the piping is designed for the full year 2002 demand: Internal diameter 12,75 inches External diameter 22,00 inches Insulation thickness 4 3/8 inches The length of the transmission line will depend on the actual location of the district heating facility and the line chosen. For the purpose of calculating costs the length has been taken as 3 miles. One pipe will be for delivery, one for return flow, the third is standby in the event of damage to one of the other pipes. 7.3.4 Distribution Network Figure 7.3.4 contains the lay-out for the distribution network. The network has been dimensioned on the basis of the conditions stated in Figure 7.3.3, and with the pipe dimensions chosen the maximum pressure drop in the network being about 60 psia, i.e. a maximum operation pressure of 90 psia and a test pressure of 150 psia. All pipes are underground pipes. Figure 7.3.5 shows the placing of the pipes in its excavation. The network is planned as a pre-manufactured steel-in-steel system, i.e each pipe (flow and return) consists of two steel pipes, a medium pipe and a jacket pipe. In order to obtain an efficient thermal insulation of the pipe system the room between medium and jacket pipes is filled with hard polyurethane foam (the heat conductibility is about 0.017 Btu/ft hr°F). Both jacket and medium pipes are made of mild steel 37. To protect the jacket pipe against corrosion it is provided with a 1/8 polyethylene coating. 7-25 Peon 16 e\0) a7xi BtuH eee ee o. FIGURE 7.3.3 KOTZEBUE DISTRICT HEATING LOAD BASIS FOR DISTRICT HEATING SYSTEM TO COAL FIRED PLANT FIGURE 7.3.4 KOTZEBUE DISTRICT HEATING LAYOUT FOR DISTRIBUTION NETWORK I~ KOTZEBUE DISTRICT HEATING CROSS SECTION FIGURE 7.3.5 The pipes are delivered ready-mounted from factory in lengths of about 40'. Medium pipe Jacket pipe Insulation inches inches Thickness _ inches 1 3/8 x 3/32 3 1/2 x 1/8 1732) 2 3/8 x 7/64 5 1/2 x 9/64 1 27/64 3 x 7/64 6 5/8 x 5/32 120732 3.1/2 x 1/8 7 5/8 x 11/64 1 57/64 4 1/2 x 1/8 9 5/8 x 13/64 2 23/64 6 5/8 x 5/32 12 3/4 x 13/64 2127/32 8 5/8 x 11/64 16 x 1/4 3 7/16 10 3/4 x 13/64 18 x 1/4 3 3/8 12 3/4 x 13/64 22 x 1/4 4 3/8 14 x) 7/32 22 x 1/4 3 3/4 7.3.5 Consumer Installations The price calculations are based on the individual consumers being connected to the district heating network by means of heat exchangers with a head of loss of 3 psia. However, if the existing installations are expected to be able to resist the recommended test pressure of about 150 psia, direct connection should be considered. The distribution network has been dimensioned for a cooling of 212 - 176 = 36°F. In case of direct connection the differential pressure of the consumer connection will be about 3 psia. As geothermal wells most likely will be no warmer than 162° F, size of residential radiator installations will have to be increased if geothermal heat is to provide for all heating needs. z—29 7.4 HYDROPOWER - BUCKLAND (Alternative "C") Taken in total from referenced Retherford report for APA of June 1980 titled "Assessment of Power Generation Alternatives for Kozebue". RETHERFORD'S ANALYSIS IS INCLUDED TO ASSIST THE REPORT REVIEWERS BY HAVING ALL BASIC INFORMATION IN ONE- REPORT. BASICALLY ONLY THE COST ESTIMATE, SECTION 8, HAS BEEN REDONE. IN OTHER WORDS, THERE IS NO NEED AT THIS STUDY LEVEL TO FURTHER REFINE THIS ALTERNATIVE. Task 7.4.1 General ‘1) Development of hydroelectric sites in the Arctic encounter many problems which are not present in more temperate areas of the world. Logistics problems associated with engineering and construction of hydroelectric projects in the harsh Arctic environment are certainly among the most difficult and challenging of any in the world. In addition, construction itself is a challenge, since only in protected locations, such as heated enclosures and under- ground, can construction proceed with any efficiency during the cold period. From the standpoint of annual precipitation, the Arctic is essentially a desert. Also, the topography of the Arctic is generally not suitable for high head installations. Therefore, for a hydroelectric project to be viable in the Arctic, it must have a relatively large contributing drainage basin. Stream flow in most Arctic streams and rivers either disappears or is greatly diminished during the winter months. Only the larger rivers, for instance, those with over 300 square miles of drainage area, can be expected to have any flow. Remote tribu- taries and streams with small drainage basins freeze solid. Hydroelectric sites must therefore be chosen which have adequate storage to allow for generation during the cold months when inflow is diminished, as well as to provide carry-over storage for dry years. Large accumulations of surface ice on bodies of water in the Arctic further tend to reduce the available storage, and thus necessitate larger volume reservoirs for a given power production than would be required in a more temperate climate. (1) taken from referenced Retherford report for APA, Section III (Only section, page, figures, and tables changed to reflect this report's numbering system unless otherwise noted). 7-30 To illustrate the effect of reduced winter inflows and reduction of volume due to ice (Zpcumulation, a family of curves was generated (Figure 7.4.1) which shows the required live storage volumes for given average power outputs and heads. The criteria used in developing the curves were these: ° It was assumed that there could be usable flow into the reservoir for only five months per year. ° During the remaining seven months, inflow to the reservoir would only be enough to balance the volume lost by forma- tion of ice (assumed to be an average of six feet thick). ° Reservoirs with area and capacity vs. depth characteris- tics similar to those of proposed reservoirs in the Ipewik, Kogoluletuk and Buckland Rivers were assumed. The topography of these areas is considered to be typical of the Arctic. The curves show, for example, that nearly 600,000 acre feet of storage must be provided for a 10 MW (average power output) plant where the average net head is 100 feet. This storage would be in addition to that required to regulate the stream flow over dry years. Ice on an Arctic reservoir has effects other than decreasing its storage volume. Formation of ice on intake structures may seriously reduce their capacity and consequently the power pro- duction. Ice formations also will exert tremendous pressures, both horizontal and vertical, on intake towers, trash racks, gates, and other structures, with consequent disastrous results if the structures are not structurally adequate or measures taken to remove the ice. Ice fog and spray can also present serious problems. The frozen fog or spray can increase the load on transmission line conduc- tors and other structures to the extent that they may fail. The effect of permafrost on the design of hydraulic structures in the Arctic is another serious problem requiring specialized design and construction techniques. It can be seen from the above discussion that even though a hydro site may appear promising on paper, there are many factors which must be considered before a final judgment can be given. The scope of this study did not allow more than a cursory review of dam and reservoir locations in the Kotzebue area. The poten- tial developments described in the following paragraphs appear to (2) rigures, tables and numbers changed to reflect this report's numbering system. 7—31 be more feasible, with the caveat that additional analyses will be required to firm up project parameters and to address in more detail the problem peculiar to the Arctic noted above. 7.4.2 Potential sites '1) General The City of Kotzebue is located on the northwestern end of the Baldwin Peninsula, a_ long, narrow, low lying peninsula approximately 63 miles in length and from to 11% miles in width. Drainage basins on the peninsula are very small and the highest point is 315 feet in elevation. Consequently, there are no viable hydroelectric project sites on the Peninsula. The most northerly point on the Baldwin Peninsula is only 2% miles from the Noatak River delta across Hotham Inlet. Large ice floes passing through this shallow inlet precludes’ the feasibility of constructing a submarine cable to connect Kotzebue with potential hydroelectric projects to the north. Generation facilities for Kotzebue that are not on the Baldwin Peninsula will therefore require lengthy overhead transmission lines. Due to the requirement of a long transmission line to bring hydroelectric power to Kotzebue, potentials of less than 5 MW (approximately twice the present electric power demand in Kotzebue) have not been considered for deyelopment . Future power requirements (established in Segtion 4) for Kotzebue, which indicate a demand of 9 MW fox) electrical lights and appliances with an additional 21 MW required for Electrical Reaction heaters by 2002, dictate a minimum plant capacity for the combined system of 30 MW. If then 139 kV is chosen as the appropriate transmission voltage, (predominant in the state) the transmission distance is limited to approximately 150 miles due to voltage drop limitations. q) Taken from referenced Retherford report for APA, Section III (only section, page, figures and tables changed to reflect this report's numbering system unless otherwise noted). Only the Buckland River site has potential for 1 plant to reasonably serve the power requirements of Kotzebue. While beyond the context of this study, several small hydropower plants seem unreasonable because of limited water storage, periods of almost no flow and transmission line losses. var Changed to reflect the Energy Forecast of this report to the year 2002. 1-32 As dj gjussed in the introduction and demonstrated on Figure 7 s4 oi: , large reservoir capacity and a large drainage basin are requirements that limit the number of potential sites to consider for serving Kotzebue. Four possible sites were examined in this study: Two only briefly, one moderately and the most promising, the Buckland River, in more depth. The general location of the sites is shown on Figure III-12 of the referenced Retherford assessment report. The Buckland Site is shown on Figure 7.4.2 , 7.4.3 Buckland River‘) Locations: Candle Quadrangle, Kateel River Meridian, T5N, R1OW, Section 21. Drainage Area: 2,220 sq. mi. Average Flow: 2,880 cfs Regulated Flow: 765 cfs Average Head: 100 ft. Reservoir 42,688 acres Dam Height 125 Ete Power: (prime) 16,125 kw Energy: (per yr., prime) 87,600 MWh Load Centers: Kotzebue, Candle, Deering, Selawik Distance: 98 mi. (transmission to Kotzebue) (1) paken from referenced Retherford report for APA, Section III (only section, page, figures and tables changed to reflect this report's numbering system unless otherwise noted). (2) pigures, tables and numbers changed to reflect this report's numbering system. 1-33) VE-L AVERAGE NET HEAD -(FT) 3 2 Nn ° 8 Oo 100 200 300 400 500 600 700 800 900 1000 1100 1200 LIVE STORAGE — (ACRE-FEET x 1000) FIGURE 7.4.1” SMALL HYDRO-ARCTIC CONDITIONS : APPROXIMATE LIVE STORAGE REQUIREMENT AVERAGE NET-VS-LIVE STORAGE (ALLOWS FOR 6FT. ICE COVER) | 605 1 {2.\ TRANSM Te +705 LINE \ k +430 " «, SCALE 0 Y\Ai nel Sy ~ 7933- IS MILES - POTENTIAL/16 MW “ne FIGURE 7.4.2 BUCKLAND RIVER : HYDROELECTRIC wale —=—_— The Buckland River flows northwesterly into Eschscholtz Bay, an extension of Kotzebue Sound. A suitable site for a dam 125 feet in height creating a reservoir with a normal maximum water sur- face elevation 150 appears on U.S.G.S quad sheet Candle (D-4) Alaska in Section 21, T5N, R1OW, Kateel River Meridian. The general location is shown on Figure 1.2. The reservoir is shown on Figure 7.4.22 « An ungated side channel spillway could be constructed to the north of the right dam abutment. The power- house would be constructed on the south bank of the river and preferably cut back into the bluff for added water winter protection. The drainage basin above the damsite is about 2,220 square miles and the average annual runoff is estimated to be 2880 cfs. The normal maximum water surface area at elevation 150 is 42,688 acres. A drawdown of 32 feet is required for complete regulation. An average net head of 80 feet during the winter would produce 16,125 kw of firm power. Secondary energy has not been estimated. The project could be developed in two stages of construction. The first stage would entail the installation of all project features with the exception of the powerhouse equipment. An ultimate installation of 30 MW of capacity in three units is recommended. Two 20 MW units would be installed in the first stage with a drawdown valve installed in the third leg of the penstock trifur- cation. The drawdown valve would permit sufficient drawdown to allow for ice storage during breakup and permit a regulated downstream flow in the river channel. The Buckland River Project meets the requirements for a potential hydroelectric site for Kotzebue. The damsite is 32 miles from tidewater and the reservoir capacity is large enough to regulate the flow and store ice brought in during breakup without reaching the spillway crest. It is of the proper size. to meet future forseeable load requirements of the area and is approximately 90 miles transmission distance to Kotzebue. t2Figures, tables and numbers changed to reflect this report's numbering system. 7-36 7.4.4 Hydrology?) There are no known stream gauging records on the Buckland River; however, there are 13 years of continuous gauging on the Kobuk River near Ambler. The NOAA Technical Memorandum NWS AR-10 "Mean Monthly and Annual Precipitation" shows about the same annual precipitation for the two river basins with possibly slightly more for the Buckland River as it appears that more of its drainage basin is above the 20-inch isohyet line. The 13-year record on the Kobuk shows an average runoff of 1.348 cfs per square mile of drainage basin. For conservative reasoning, an average of 1.3 cfs per square mile was used for the Buckland River. A synthetic 13-year flow (1966-1978) “ developed from the flow data on the Kobuk River, Table 7.4.1 , by determing the ratio of drainage basin (2,220/6570 = 0.3379) and the ratio of the runoff per square mile (1.3/1.348 = 0.964) and obtaining a factor (0.3379 x 0.964 = 0.326) to multiply the monthly recorded of flow on the Kobuk River ‘9, obtain a synthetic flow for the Buckland River, Table 7.4.2! a The Buckland River sypypetic flow was then converted to acre feet by month, Table 7.4.3 to determine the average cfs flow. The 8,858 cfs average annual flow for the Kobuk River calculates to 18.30 inches of precipitation runoff. The 2880 average annual flow for the Buckland River calculates to 17.65 inches of precipitation runoff annually. Stream gaging is recommended for the Buckland River to verify the synthetic calculation in this study. An Area-Capacity curve ¥35 developed for the proposed project and appears in Figure 7.4.3 - The curve shows the probable maximum drawdown to elevation 118 leaving 1,216,270 acre feet of capacity to store ice during spring breakup. This amounts to 58% of the average annual flow. (1) taken in total from Retherford Report for APA, June 1980, titled "Assessment of Power Generation Alternatives for Kotzebue" Retherford's analysis is included to assist the report reviewers of having all basic information in one report. (2) pigures, tables and numbers changed to reflect this report's numbering system. 1-39 Be-L TABLE 7.4.1(2) KOBUK RIVER AT AMBLER FLOW IN CFS Water. . Year Year Oct Nov Dec Jan Feb Mar Apr May June July Aug Sept Ave. 1966 18,580 3,000 2,400 2,000 1,600 1,000 1,200: 3,945 28,120 17,200 11,180 11,530 8,675 1967 9,406 3,000 2,000 1,300 900 800 950 15,140 58,730 30,980 23,980 12,360 13,340 1968 6,687 3,597 2,090 1,545 1,400 1,300 1,300 5,019 61,310 18,400 8,126 4,967 9,601 1969 13,520 3,560 1,500 961 827 800 1,160 15,550 7,810 5,235 12,520 5,990 5,839 1970 ~~ 4,619 2,460 1,516 1,181 1,018 990 1,017. 17,140 11,890 7,181 16,080 ° 9,037 6,220 1971 2,974 1,850 1,297 1,032 1,000 950 900 24,910 45,010 14,630 8,119 7,570 9,203 1972 6,910 3,833 2,387 1,526 1,152 974 900 20,990 36,160 10,630 11,380 11,470 9,025 1973. 5,787 4,133 3,052 2,426 2,057 1,768 1,650 30,240 45,730 19,360 39,750 21,920 14,890 1974 14,950 4,317 2,123 1,665 1,436 1,365 1,307 9,484 17,580 13,070 19,610 14,920 8,532 1975 6,565 1,947 1,097 1,000 1,000 1,000 1,113 16,760 22,870 21,750 9,790 19,830 8,760 1976 4,487 1,580 987 900 900 900 1,001 10,670 20,890 11,090 9,461 9,630 6,045 1977. 6,971 3,800 2,468 1,774 1,389 1,300 1,317 12,550 26,640 8,529 6,710 13,870 7,279 1978 _10,140 - 3,107 1,839 1,513 1,400 1,290 _1,207. 13,040 _18,930 16,230 9,887 (13,910 _ 7,742 111,596 40,184 24,756 18,823 16,079 14,437 15,022 195,438 401,670 194,285 186,593 157,004 115,151 Ave. 8,584 3,091 1,904 1,448 1,237 1,111 1,156 15,034 30,898 14,945 14,353 12,077 8,858 6,570 sq. mi. Record Ave. 8,858 = 1,348 cfs/sq. mi. Min Year (1969) 5,839 cfs = 0.889 cfs/sq. mi. 6E=£, TABLE 7.4.20). KOBUK TO BUCKLAND SYNTHETIC FLOW RECORD Ratio of drainage Areas = 2,220/6,570 = 0.3379 Ratio of runoff per sq. mi. = 1.3/1.348 = 0.964 | Factor to use in deriving Buckland Flow = 0.964 x 0.3379 = 0.326 Water Year Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep 1966 6,057 978 782 652 522 326 391 1,286 9,167 5,607. 3,645 3,759 1967 3,066 978 652 424 293 261 310 4,936 19,146 10,099 7,817 4,029 - 1968 2,180 i173 681 504 456 424 424 1,636 19,987 5,998 2,649 1,619 1969 4,408 1,161 489 313 270 261 378 5,069 2,546 1,707 4,082 l 98 1970 1,506 802 494 385 332 323 332 5,588 3,876 2,341 5,242 25946 1971 970 603 423 336 326 310 293 8,121 14,673 4,769 2,647 2,468 1972 25203 1,250 778 497 376 318 293 6,843 11,788 3,465 3,710 3,739 1973 1,887 1,347 995 791 671 576 538 9,858 14,908 6,311 12,959 7,146 1974 4,874 1,407 692 543 468 445 426 3,092 Si 731 4,261 6,393 4,864 1975 2,140 635 358 326 326 326 363 5,464 7,456 7,091 35192 6,465 1976 1,463 515 322 293 293 293 326 3,478 6,810 3,615 3,084 3,139 1977 2,273 1,239 805 578 453 424 429 4,091 8,685 2,780 2,187 4,522 1978 3,306 1,013 600 493 456 421 393 A251 (piyat 5,291 3,223 4,535 Or-L TABLE 7.4.3 BUCKLAND RIVER ACRE-FEET x 1000 1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 Total 2,233. Ave. Oct 371. 188. 133. 270. 92. 59. 138. 115. 299. 131. 89. 139. 202. 171. 78 19 81 56 a4 54 29 82 7 35 80 52 92 19 78 Nov 58. 58. 69. 68. 47. 39. 74. 80. 83. 37. 30. 73. 60. 778. 59 09 09 68 96 64 82 25 01 58 72 59 60 17 20 - 86 Dec 48. 40. 41. 30. 30. 25. 47. 61. 42. 21. 29. 49. 36. 495. 38. 00 02 80 01 32 96 75 07 47 97 76 41 83 37 11 Jan Feb 40.02 28.94 26.03 16.24 30.94 25.28 19.21 14.97 23.63 18.41 20.62 18.07 30.51 20.85 48.55 37.20 33.33 25.95 20.01 18.07 17.98 16.24 35.48 25511 30.26 25.28 376.57 290.61 28:97 22.35 Mar Apr 20.01 23.23 16.02 18.41 26.03 25.19 16.02 22.45 19.83 19.72 ‘19.03 17.40 19.52 17.40 35.35 31.96 27.31 25.30 20.01 21.56 17.98 19.36 26.03 25.48 25.84 23.34 288.98 290.80 22.23\ 122337 May 78. 302. 100. 311. 342. 498. 420. 605. 189. 335. 213. 251. 260. 3,910. 30v. 95 97 42 14 99 47 02 08 79 38 48 11 93 73 83 Jun 544. 1,137. 1,187. 151. 230. 871. 700. 885. 340. 442. 404. 515. 366. 7,778. 598. The Average of 2,084,940 Acre-Feet per year = annual average 52 27 23 32 23 58 21 54 42 89 51 89 56 17 32 Jul Aug Sep Total 344.16 223.73 223.28 2,004.69 619.88 479.81 239.32 3,142.25 368.16 162.60 96.17 2,267.31 104.78 250.55 116.01 1,375.98 143.69 321.75 174.99 1,465.64 292.72 162.47 146.60 2,168.28 212.68 227.72 222.10 92,131.30 387.37 795.42 424.47 3,507.84 261.54 392.40 288.92 2,010.18 435.25 195.92 | 384.02 2,064.15 221.89 189.30 186.46 1,427.35 170.64 134.24 268.61 1,715.12 324.76 197.83 269.38 1,824.10 3,887.52 3,733.74 3,040.33 27,104.19 299.04 287.21 233.87 2,084.94 flow of 2880 cfs. Te-L ns a 1£334—-NOILVA313 AREA-ACRES x 1,000 5 AVE. EL. 136 MAX. NORM. WS av oze'cere N 50 FIGURE 7.4.3 100 150 200 250 300 CAPACIT Y- ACRE-FEET x 10,000 BUCKLAND RIVER AREA -CAPACITY CURVE 350 400 450 500 7.4.5 Geology The proposed damsite would be located in territory basalt which apparently covers cretaceous graywacke and conglomerate. Most of the proposed reservoir area is covered with quaternary unconsoli- dated sediments. Suitability of the basalt as basement rock for a water reservoir would have to be determined in a_ field investigation. 7.4.6 Transmission Facilities Overhead transmission at 138 kV, three phase with 795 KCM ACSR conductor would result in less than 5% voltage drop and 1.4% power loss for a peak load of 20 MW. Energy losses are estimated at 3%. Transformers at the powerplant would step the generated voltage up to the 138 kV level and a step down substation near Kotzebue would connect to the existing 4.16 kV distribution system. The transmission route would lead almost due north to the Kauk River, then approximately follow the north shore of Eschscholtz Bay and along the Baldwin Peninsula to Kotzebue. The total length of the transmission line would be approximately 98 miles. The line would follow established winter trails and would be constructed during the winter season to eliminate the requirement for a permanent access road. Operational maintenance access would be by helicopter or Rolligon type vehicles. 7.4.7 Cost Estimates The Es cost of constructing the Project is presented in Section 8.0 4), which presents a summary of the direct construction cost and an _ estimate of the total capital investment, using recommended FERC account numbers. 7.4.8 Power Production The first stage of development with 10,000 kW units would have a prime capacity of 10 MW and produce 87,600 MWh of firm energy and an annual average of 53,655 MWh of secondary energy. The second stage of development with three 10,000 kW units would have a prime capacity of 20 MW and would produce 141,255 MWh of prime and average annual energy. (4) see section 8.0 of this report: Cost Estimate. 7-42 7.4.9 Environmental and Other Concerns Preliminary investigations indicate that the Buckland River supports salmon, char, pike, whitefish, turbot and grayling populations. The valley is also utilized by caribou and moose. The reservoir created by a dam at the proposed location would inundate this area and destroy part of the mammal habitat as well as spawning and rearing grounds for the fish. It has not been determined whether archaeological sites are located in the area that would be inundated. Occurrences of fossilized remains of Pleistocene mammals (mammoth, bison, etc.) have been reported in the Buckland River area, however. A detailed archaeological study is therefore recommended to locate possible sites. The topographical data used for this study indicate that the reservoir would partially flood the community of Buckland. A detailed survey would have to be performed to establish a dam height that would prevent inundation of this community. With little information available on the environmental impacts of such a project, a detailed environmental reconnaissance will have to be performed before an assessment of feasibility can be made. 7.4.10 Land Status The damsite is located within a village withdrawal and most of the reservoir within state selected land. The transmission line would traverse lands selected by the state and villages and would have to cross the proposed Selawik National Wildlife Refuge (Federal Land Policy Management Act of November 16, 1978, Emergency Order 204E) for approximately 60 miles. 7.4.11 Alternate Development Plan The cost estimates by Retherford show that approximately 38% of the total cost of construction are allocated to the transmission line. Retherford further stated that if single phase, low frequency generation and transmission would be considered, it is estimated thay the cost of transmission lines could be reduced to only 23% 5) of the total construction costs. It is assumed that the generating equipment costs approximately the same as three phase equipment. (5)petherford's write-up modified by removing his cost estimates from this paragraph. 1-43 Preliminary investigations into the availability of a. low frequency, single phase equipment, and b. phase and frequency conversion equipment indicate that Japanese or European firms are building similar equipment and are interested in supplying it for the relatively small scale applications under investigation in Alaska. 7.4.12 Utilization of Electric Heat (6) This task acknowledges capacity of electric resistance heaters as a means of satisfying the near terms (next 20 years) heating requirements. TD GEOTHERMAL (ALTERNATIVE "D") 7.5.1 Description of the Potential Geothermal Resource The use of geothermal energy as a possible alternative energy source has been investigated as part of an on-going study of the future energy needs for the city of Kotzebue. While Kotzebue does not occur in what is normally considered a_ typical geological setting for exploitable geothermal energy, two petroleum exploration test-wells (Chevron Nimiuk Point No. 1 and Cape Espenberg No. 1) discovered that an abnormally high geothermal gradient occurs.in the area. The findings of these test-wells, although not conclusive, suggested that geothermal waters may exist under Kotzebue that could be used as an alternative energy source. In addition to drilling the petroleum exploration wells, Chevron Oil Company also conducted a seismic reflection survey of the Kotzebue area to determine’ the underlying bedrock structure. These seismic data, existing State of Alaska aeromagnetic and gravity data, and the results of data obtained from the exploration wells have been previously analyzed to assess geothermal potential for the region (Energy Systems, Inc. 1981, Ehm 1981). These analyses were conducted based on the recommendations in a previous study (Retherford and Associates 1980) prepared for the Alaska Power Authority that suggested that the utilization of geothermal waters for space heating may be a viable energy alternative. Ehm (1981) and Energy Systems Inc. (1981) recommended that geothermal energy was not a likely economic source for power generation but that district heating may be feasible. (6)added for this report. 7-44 A key element in this recommendation was the interpretation of the depth to basement given in the Ehm (1981) report. The validity of this interpretation was reaffirmed in the present study. The initial depth-to-basement determination was interpreted by Chevron based on their seismic data. Mr. Ehm reanalyzed this data himself, and agreed with the Chevron interpretation (Arlan Ehm, personal communication, 1982). A leading expert on the geology of northwestern Alaska, Dr. Robert Forbes, professor emeritus of the Geophysical Institute, University of Alaska, was also consulted on this matter. Dr. Forbes felt the thinning of the basin in the direction of Kotzebue was surprising, but, based on the existing geophysical data, irrefutable. Unless’ the substantial additional costs (i.e., piping, right-of-way development, insulation, etc.) associated with a geothermal development outside the immediate environs of Kotzebue could be economically borne by the project proponents, feasibility would depend entirely on the usefulness of water at a temperature defined by the assumed geothermal gradient above the projected basement rock interface underlying Kotzebue. All individuals contacted in the present study agree in principal with recommendations contained in the Ehm (1981) and Energy Systems, Inc. (1981) reports. In order to fully analyze the possibility of any geothermal development at Kotzebue, test well(s) would need to be drilled. The costs of such a well would be extensive, and may not be justified by the present understanding of the likelihood of finding an economically viable resource. For the purposes of this study, a typical well drilling and testing sequence has been specified, and is described herein. This allows the substantial cost of such an exploration program to be included in an assessment of the economic feasibility of geothermal resource usage in the Kotzebue area, based on present understanding of the subsurface geology. 7.5.2 Geologic Setting Kotzebue lies on the northwestern edge of the Baldwin Peninsula within the Selawik Basin (Figure 7.5.1). No bedrock is exposed on the Baldwin Peninsula due to an extensive cover of non- inundated Quaternary age deposits. For this reason, any inferences concerning the pre-Quaternary geology of the area are based on projections of geologic trends from the surrounding regions, remote sensing data (i.e., seismic reflection, gravity, and aeromagnetic), and data collected from two petroleum wildcat test-wells (Chevron Nimiuk Point No. 1 and Cape Espenberg No. 1). The Selawik Basin is bordered on the south by the Seward Peninsula, a complex geologic terrain consisting of Precambrian to Quaternary sedimentary, metamorphic, and igneous rocks. The Baird and De Long Mountains form the northern boundary of the basin. These are composed predominantly of lower Paleozoic metamorphic rocks, and middle Paleozoic to Mesozoic sedimentary 7-45 9¥-L CAPE ESPENBERG | BREVIG MISSION BENE L cae, LJ mary's iGLoo 9° W PILGRIM _HOT SPRINGS ° NOATAK BAIRD MOUNTasy, Ss KIANA OnMBLER : ONOORVIK SELAWIK BASIN 5 OKoBUK ° SHUNGNAK SELAWIK ea BUCKLAND CANDLE FIGURE 7.5.1 Location map. (from Ehm 1981) and igneous rocks. In the on-land extension of the Selawik Basin, east of the Baldwin Peninsula, Cretaceous sedimentary rocks and Tertiary volcanic rocks are exposed. In the Hope Basin, west of the Baldwin Peninsula (Figure 7.5.2), Tertiary age sediments lie unconformably on Mesozoic sedimentary rocks. The Hope Basin shallows toward the east and is entirely absent east of Hotham Inlet. A seismic reflection survey was conducted by Chevron from Kotzebue southeast approximately 14.4 miles to Nimiuk Point (Figure 7.5.2). The results of this survey show that Kotzebue lies above a basement high within the Selawik Basin and is underlain by approximately 2013 feet of sedimentary rocks overlying metamorphic basement rocks. The gravity data supports this interpretation. The seismic and gravity data show that the basin deepens toward the east and south of Kotzebue. This was verified by the test-wells at Nimiuk Point and Cape Espenberg. The rocks penetrated at the Nimiuk Point test-well consist of Tertiary age conglomerate, sandstone, siltstone, clay, and minor lignitic coal (Figure 7.5.3). These unconformably overlie Cretaceous porphyritic andesite and basalt, that in turn unconformably overlie metamorphic rocks that form the regional basement. The seismic data suggest that the upper Tertiary sedimentary stratigraphy is fairly continuous from Nimiuk Point to Kotzebue. The lower portion of the sedimentary section and the volcanic rocks do not appear to occur beneath Kotzebue based on the seismic data (Figure 7.5.2). Warm water was found during drill-stem tests at both the Nimiuk Point No. 1 and Cape Espenberg No. 1 test-wells. At Nimiuk Point, within the 3557 ft to 3778 ft depth test-interval a net rise of 3385 ft. of fluid was recorded. The fluid included drilling mud, muddy salt-water, and clear salt-water. The recorded temperature for the produced waters was 107° F (42 C). The water encountered in both the Nimiuk Point No. 1 and Cape Espenberg No. 1 test-wells is connate water, or water that was included with the sediments during burial and expelled into subsurface aquifers during diagenesis (the process by which non- indurated sediments become lithified). This is ancient water and is not recharged from the surface. The size of the aquifers within the Tertiary rocks is not known. The Chevron test-wells tested the most promising hydrocarbon- bearing horizons, not the water-bearing horizons. For this reason, data concerning the aquifer size and production rates are not available. The water that was produced during the drill-stem test at Nimiuk Point contains 90,000 ppm total dissolved solids. Of this total, 76,263 ppm is NaCl (salt). The formation pressure in the tested interval was 1,552 psi and was able to push the fluid column to within 112 feet of the ground surface. 7-47 8b-L su KOTZEBUE KOTZEBUE SouND 9 NIMIUK POINT NO.1 MOTNAM INLET Sigur METAMORPHICS ee Tt ee QUATERNARY @ TERTIARY CLAsTICS TO 1923 m YS iMIUR, POINT NOt 8000" (AFTER CHEVRON) FIGURE 7.5.2 STRUCTURAL CROSS SECTION FROM KOTZEBUE TO NIMIUK POINT No. 1 FROM SEISMIC REFLECTION DATA. (from Ehm198 1) TD 1923 m LEGEND NO SAMPLES CLAY SAND & SANDSTONE GRAVEL & CONGLOMERATE COAL & WOOD VOLCANICS SCHIST CARBONATES & MARBLE FORMATION TEST BASE OF PERMAFROST FIGURE 7.5.3 Nimiuk Point No. 1 test-well log. (from Ehm 1981) 1-149 La 7.5.3 Geothermal Resource No actual geothermal exploration investigations have been performed in the Kotzebue area. The Nimiuk Point No. 1 and Cape Espenberg No. 1 test-wells were petroleum test-wells and penetrated a thick section of Tertiary to Cretaceous age sedimentary and volcanic rocks prior to entering greenschist facies metamorphic rocks at total depth. The bottom-hole temperatures in both wells are approximately the same (72 to 73 C) although the depths are significantly different, 6350 ft. and 8400 ft. respectively. These temperatures are abnormally high for their depths below the surface. At Nimiuk Point No. 1 the calculated geothermal gradient is 113.8° F/mile and at Cape Espenberg No. 1 the calculated geothermal gradient is 96° F/mile, both of which are higher than the mean value for the worldwide geothermal gradient of 86° F/mile. While the geothermal gradient data suggest the possibility of higher temperatures at depth, the basement metamorphic rocks are incapable of supporting a hot water system due to their lack of porosity and permeability. Therefore, any geothermal resource will have to be developed within the Tertiary age sedimentary section. The bottom-hole temperatures recorded in the test-wells drilled at Nimiuk Point and Cape Espenberg appear more related to the basement metamorphic rocks than the thickness of the Tertiary age section. It seems unlikely that temperatures similar to those found in the bottom of the test-wells will occur at the base of the Tertiary section underneath Kotzebue. The calculated geothermal gradient for the Nimiuk Point test-well predicts that the temperature at the base of the Tertiary section under Kotzebue is approximately 81° F. This would have to. be considered a minimum’ temperature. The maximum expected temperature would be 185° F, which is the temperature recorded at the bottom of the Nimiuk Point test-well. The actual temperature will most likely fall between these two. These temperatures are too low for generation of electrical energy and possibly even too low for district space-heating considering the severe temperature conditions that occur at Kotzebue. Within the Paris Basin, France, low-temperature (140° F or 60 C well-head) geothermal water is used for district space- heating assuming a minimum external temperature of 23° F. When external temperatures fall below 23° F a back-up system is necessary. A similar but expanded situation may be possible for Kotzebue. The geothermal water may be used for start-up water and thus avoid the cost of heating surface water (approximately 32° F to 41° F) to the temperature of the geothermal water (80.6° F to 162° F). This could result in significant fossil fuel (coal, oil, gas) savings. This is the same conclusion reached by Retherford and Associates (1980) and Energy Systems, Inc. (1981). 7-50 The quality of the geothermal water that is expected to occur beneath Kotzebue is poor. Discharge of these "brines" onto the surface could have severe environmental impacts. However, since the geothermal aquifers are not recharged from the surface, it may be necessary to re-inject the geothermal water after heat extraction to keep up the flow-rates and reservoir pressures. This closed system approach will alleviate the environmental concerns over the discharge of geothermal waters on the surface and preserve the geothermal resource. 7.5.4 Geothermal Exploration Program Data acquisition, is necessary on the geothermal resource and aquifer conditions underlying Kotzebue. The Nimiuk Point No. 1 test-well found that low-temperature geothermal waters occur in the area. The basin characteristics differ, however, between Nimiuk Point and Kotzebue. Nimiuk Point is underlain by approximately 6600 feet (2000 m) of Tertiary and late Cretaceous sedimentary and volcanic rocks overlying metamorphic basement. The seismic reflection data indicate that Kotzebue is underlain by only approximately 1980 feet of Tertiary sedimentary rocks. These sedimentary rocks have a lower thermal conductivity than the metamorphic rocks and act as an insulator. This probably accounts for the high geothermal gradients found at Nimiuk Point and Cape Espenburg and the similarity between the bottom-hole temperatures. At Kotzebue, the decreased sedimentary cover and reduced insulating effect could result in an even greater geothermal gradient and a lower temperature at the top of the metamorphic rocks. The deep aquifer conditions in the Kotzebue area are unknown. The Nimiuk Point No. 1 test-well did not test the most prom- ising water-bearing horizons. For this reason data on the aquifer size, temperature, and flow-rates are necessary prior to fully assessing the geothermal potential. These data may be gathered from drilling a geothermal test-hole to a depth of approximately 990 feet to 1980 feet. The deeper depth is recommended because it will penetrate the metamorphic basement and thereby provide the maximum amount of information on the geothermal resource. The test-hole should be drilled at a sufficient diameter to allow testing of the aquifer flow characteristics as well as water temperature. A two-phase geothermal test-well program is described in appendix "C". 7.5.5 Geothermal District Heating 7.5.5.1 General Discussion Little is known about the geothermal potential at Kotzebue (exploratory confirmation wells are needed). Because of the local interest in using geothermal energy if at all possible and 7-51 to justify any exploration to locate and define the potential resource, all engineering and economic evaluation of a geothermal alternative for Kotzebue assumes a "best case" scenario. It is presumed that if a so called "best case" scenario cannot compete with other alternative heat and electrical power sources, there will be little application for an extensive exploration program such as that described in appendix C. Conversely, if geothermal alternatives for heat and electrical power generation are shown to be economically feasible of the best case resource, it may be justifiable to pursue such an exploration program. This evaluation is based on the assumption that there is sufficient formation water available. 7.5.5.2 Design Conditions ° Water temperatures 162°F - an optimistic temperature assumption. ° Heating level at year 2002 is 38.81 x 10° Btu/Hr. This heat load value has been adjusted from the yearly averages to peak load requirements anticipated, including temperature and seasonal variations and line losses for a system design heating load of 100 x 10” Btu/Hr. ° Wells - 8 Geothermal 4 Injection ° Rate of Flow - each well assumed to be 788 gpm. 7.5.5.3 Conceptual Design Based on these assumed design loads, the heat supply using geothermal energy was evaluated. This design concept is ghown in Figure 7.5.4. To satisfy the heating demand of 100 x 10°BTU/Hr, eight geothermal wells would be required each producing 788 gpm of brine. The output from these wells would be reinjected in four injection wells. It is assumed that the eight production wells would be drilled on two pads, each containing four wells, and that the injection wells would all be contained on one pad. The concept design would require eight boost pumps to bring the geothermal fluid to the surface (112 feet) and raise its pressure to a sufficient value such that it could then pass through to the geothermal filters. Each well would have a filter which would consist of two 400 micron strainers and a hydroclone separator. These filters would remove any debris from the fluid before it would enter the main pumps and heat exchanger. After the fluid has been filtered from each well, the fluid will flow into a header system where the main geothermal transfer pump will then take the combined flow of 6300 gpm and increase its pressure to 170 psi. This high pressure is required to keep any 7-52 FIGURE 7.5.4 SCHEMATIC GEOTHERMAL DISTRICT HEATING CONCEPT ENERGY STORAGE ANK WASTE HEAT BOILER TRANSFER PUMP EOTHERMAL BOOST PUMP 8 WELLS (PRODUCTION) DISTRICT HEAT SUPPLY PUMP 7-53 DISTRICT HEAT RETURN PUMP PROCESS HEAT GEOTHERMAL INJECTION PUMP 4 WELLS (INJECTION) i dissolved gases (i.e. nitrogen, CO5) above the evolution pressure to prevent scale deposits. This high pressure geothermal stream then flows into the central plate and frame heat exchanger. The central heat exchanger will have an area of 34,332 ft. The approach temperature on the hot side will be 2°F while on the cold side it will be 6°F. The temperature of the geothermal brine entering the heat exchanger will be 162°F. The brine will leave the heat exchanger at 130°F. The temperature of the glycol solution (60% by volume ethylene glycol, 40% water --- 70°F freeze pt.) entering the exchanger (countercurrent flow) is 124°F. This solution leaves at a temperature of 160°F. The flow rate of the geothermal fluid is 6300 gpm whereas the flow rate of the glycol solution on the district heating side will be about 6600 gpm. The output geothermal fluid from the exchanger will be used to heat the process buildings and heat water for domestic use at the facility prior to being reinjected back into the formation. The geothermal brine is then reinjected into four injection wells using four injection pumps, each flowing at 1575 gpm at 820 psi. The district heating side of the central heat exchanger will take the geothermal heat and distribute it in accordance- with a specified distribution plan. To distribute this heat, two pumps will be used, one on the output side of the exchanger and one on the input side. These pumps will maintain an over-all system pressure of 70 psi. The flow rate for the glycol system is 6600 gpm. Since the pumps are large, they can be either driven electrically or through the use of diesel engines. If these pumps are driven electrically they would require 5.8 MW of power. If they were driven using diesel engines, these engines would be adapted for total waste heat recovery which would be used to supplement the geothermal energy used for district heating. The waste heat recovery from the diesel engines amounts to 22.1 x 10” Btu/hr. The heat is to be stored in a 1000 gallon tank of ethylene glycol with immersed heating coils to exhaust the heat. The temperature of the fluid leaving the tank and entering the heat exchanger in the output district heating line is 200°F. The returning fluid temperature is 165°F. Using the waste heat from diesel engines, the temperature of the district beating line is increased to about 166°F. Approximately 2.2 x 10° gallon of diesel fuel will be required to run the diesel engine to drive the pumps in the year 2002. 7-54 7.5.5.4 Major Equipment Requirements for Geothermal District Heat Source 1. Heat. Exchanger (Main) .cscscvesenesoess 34332 £t2 2. Geothermal Transfer Pump....eeeeceeceeeee 1040 HP 6300 gpm 170 psi Zi. Geothermal Well Pumps (8)...eeececececeeeee LOO/HP Each pump 75 kW/each pump 788 gpm 4. Geothermal Injection Pumps (4) ...eeeeee++l250/HP each pump 2892 kw/ each pump 1575 gpm 820 psi 5. District Heating Pumps (2)..eeeeeceeseeeeee 340 HP 25 kw 6644 gpm 50 psi 6. Heat Recovery ReESErvOiLresesececesevevevee LOND gal 7. Geothermal Transfer Pipe...-eeseeeseecceeeee 16 inch 8. District Heating Pipe..cccccccceccccceecese LS inch 9. Wells B Production. cccccccesevcsccevcccces 9 5/8" Dia. 4 Injectionesie cos cwcsceeovenessesere 9 SAS” Dias 7.5.6 Geothermal Power Plant (Organic Rankine Cycle) 7.5.6.1 General Discussion A conceptual design of a geothermal power plant for Kotzebue using a closed loop organic Rankine cycle with isobutane as the working fluid is presented in the following paragraphs. The design of this power plant is based on the assumption that there is sufficient formation water at 162°F at the basement of the metamorphic rock. In the overall design, the isobutane will exchange the heat from the geothermal brine solution, vaporize, and then transfer this energy to the turbine generator. The geothermal brine is pumped from various production wells, through a heat exchanger (pre- heater), and a high pressure boiler, and is then reinjected back into the reservoir through the injection wells. A simplified flow diagram is presented in Figure 7.5.5. 7-55 7.5.6.2 Conceptual Design The details of the conceptual design will be described as specific systems within the total plant. These systems are: (a) isobutane, (b) geothermal, (c) turbine-generator, (d) cooling water, and (e) support. (a) Isobutane System The isobutane is to extract the heat energy from the geothermal resource and transfer this energy to the turbine-generator. This system is a closed loop, two-phase organic Rankine cycle. This system works in the following manner. The condensate feed pump, (500 horse power, 4160 volts) takes the condensate from the condensate tank of 20 psia and 25°F and raises this feed to a system pressure of 155 psia to enter the pre-heater. In the pre- heater the isobutane is heated to a saturated liquid at 160°F and 155 psia. The vaporized isobutane stream then enters the turbine where its energy is extracted in performing work. The isobutane then exits the turbine in the vapor state at a temperature of 123°F and 20 psia and enters the exhaust condenser where it is condensed to a saturated liquid at 25°F and 20 psia and flows by gravity into the condensate tank from which the condensate feed pump takes suction and the cycle is repeated. This system also includes the necessary vents, drains, and provisions for charging the system with isobutane from 60,000 gallon storage tank. Due to the volatility of isobutane, the system has extensive gas monitoring equipment to detect any hydrocarbon leakage. (b) Geothermal System The geothermal system is to provide the thermal energy necessary for the isobutane system. The geothermal energy is extracted from four production wells. Each well has a down-hole booster pump to raise the fluid the final 112 feet to the surface and to act as a pressure source (90 psi). The geothermal brine is passed through a geothermal filter which consists of two 400 micron strainers and a hydroclave separator. This filter removes any of the debris from the fluid before it enters either the pumps of heat exchangers. After the brine is filtered, the flow stream is divided each using a booster pump to bring the system pressure up to 170 psi. One stream supplies the heat for the high pressure boiler to completely vaporize the isobutane while the other stream is 7-56 FIGURE 7.5.5 SCHEMATIC GEOTHERMAL POWER CONCEPT PSS GENERATOR 23 HP BOILER foerer—enyeny GEOTHERMAL FILTER PROCESS HEATING INJECTION GEOTHERMAL RESERVOIR used in the pre-heater to heat the isobutane to a saturated liquid. These booster pumps ensure that the geothermal fluid remains in the fluid state above the gas evolution pressure, thus ensuring a high heat transfer efficiency and the prevention of scale deposition. Each of the two geothermal streams are then reinjected into separate wells with the aid of injection pumps. (c) Turbine-Generator System The turbine-generator will convert the heat energy’ into electrical energy. This system consists of a turbine, generator, piping and control instrumentation. The turbine is a radial inflow unit that operates in the isobutane Rankine power cycle. The unit is designed to expand the isobutane from 155 psia to 20 psia to produce the desired power output. The isobutane vapor is supplied to the turbine through a 10-inch header and would be equipped with appropriate throttle valves and flow meters. The flow control would be regulated by the turbine governor. The turbine back-pressure is governed by the exhaust condenser. After the isobutane is heated and expanded by the geothermal fluid, it is passed through the turbine and discharged to a water-cooled condenser for recovery and reuse. The generated power output of 4160 volts would be fed into the Kotzebue power grid. (d) Air Condenser The air condenser will provide a heat sink for the organic Rankine cycle. Air is used in the turbine exhaust condenser to remove the waste heat from the isobutane working fluid. The fluid input to an air-cooled condenser is isobutane vapor. The design of the finned tube sections will require drip pockets and pressure equalization lines to maintain equal flow conditions in the tube bundles. Arrangement for the application may be vertical, mounted on an integral condensate rank, or arrangement can also be asembled for a remote condensate tank. A pressure controlled fan will provide air flow across the condenser tubes. (e) Support Systems The support systems required by the facility are: (1) isobutane flare system, (2) instrument air and nitrogen systems, and (3) industrial water system. The isobutane flare system is to safely dispose of isobutane vapors from the process and from the storage area. This flare system will dispose of the isobutane vapors during filling and draining of the system, to receive leakage from isobutane vents and drains during various operations of the plant, and to burn 7-58 the contents of the isobutane system should an emergency arise. The vapors to be disposed of are collected in a knockout drum where liquid is separated from some of the other combustible gases. From the knockout drum the gases flow to the flaring unit. The instrument air and nitrogen system will supply compressed air for instrumentation, control, and other utility use. The nitrogen is used for emergency back-up for instrumentation, and for purging of the piping and various components during initial start-up and during operation. The nitrogen will be stored in two 3,000-galllon tanks along with the isobutane. The industrial water system is to provide water for fire protection. 7.5.6.3 Major Requirements for Geothermal Power Plant als Turbine—generator..ccccccccccccsccccseel0.0 MW 2. Geothermal pre-heater feed pump........170 HP 127 kw 1034 gpm 170 psi 3. Geothermal high pressure boiler pump..1730 HP 1290 KW 10,476 gpm 170 psi 4. High pressure boiler Heating coils.ccescscccvcccccccee67955 £t2 VoLUNGs ins cnn coos nbernnne & kon eBOO ORO Ee 5. Turbine air CONGENSEr «ses. ses sews ose, 400 £t2 6. Isobutane condensate tank......-.-40,000 gal. 7. Geothermal boost pumps (14 ea.).+-+++++++46 HP 34 kw 822 gpm 57 psi 8. Geothermal injection pumps (10 ea.)....920 HP 682 kw 1151 gpm 820 psi 9. Condensate feed pump..ccccccccccvevceeee40 HP 30 kw 3525 gpm 20 psi 10. Pre-heater. ccocccccccccccccccccccccee e800 Ft ll. Geothermal Filter (Hydroclone, strainersS).......eeee+eel4 each 12. Isobutane storage tank.......+.+-.-60,000 gal. 3. Cryogenic nitrogen tank...e-eeeeeeee3,000 gal. 14, Isobutane Flare SySteM..ceceseecsceeeeel each 2 7.6 OTHER (ALTERNATIVE "E") 7.6.1 Energy Conservation 7.6.1.1 General Discussion In order to demonstrate the potential in energy conservation in future and existing houses a number of calculations have been made (see Appendix "E") concerning heat loss from traditional and improved structures. The results are shown in this section while the calculations are shown in detail in Appendix E. Insulation standards of future houses have been investigated by computing construction costs and heat losses through a number of different types of walls, floors and roofs. By way of using present worth methods optimum insulation standards have been established as well as standards for doors and windows. The possible use of thermal shutters has also been investigated by way of using present value (worth) method. For existing structures, an example is given of the possible gains from adding insulation and from general improvements such as sealing of leaks by doors and windows, etc. It is obvious that existing structures must be of a reasonably fair quality to justify the spendings done on improvements. In each case a house must be carefully audited to determine whether to improve it or to construct a new house using new standards. In this study typical housing built in 1976 by the Housing Authority has been examined as this type represents approximately 10% of the dwellings in Kotzebue and is considered to be a traditionally built house at or above average standards regarding thermal insulation. A detailed study of the heat losses from recently constructed housing has been made and an example of possible improvements is shown. With these improvements made, the heat losses have once again been calculated in order to show the net savings. The results should be seen as indications of the potential and not as exact figures of heat losses, as certain details are not taken into account. The study shows that energy savings of up to 50% can be expected for houses of this type and the necessary investments will have a pay-back time of approximately 9 years. It should, however, be noted that less drastic improvements with smaller investments will have shorter pay-back times and thus for each house life expectancy should be taken into account to determine a desired insulation standard. 7-60 7.6.1.2 Energy Conservation In New Houses In order to evaluate the benefits from improving insulation standards in new houses, calculations were made for construction costs of different types of walls, roofs, and floors. For each type the yearly heat loss was determined. For the purposes of economic calculation, real interest was set at 3.0 percent and real inflation on heating oil was set at 2.6 percent. Thus calculations can be made regardless of current overall inflation rates. The price of heating oil was set at 1.46 S$/gal. Knowing the heat loss per unit of surface, the yearly cost of maintaining 65° F on one side of the surface was determined according to the number of heating degree days for Kotzebue. Construction costs per unit of surface were calculated and this together with the costs of heating formed the basis’ for calculating the present worth figures for different surfaces. Thus the present value can be expressed as the total cost of constructing a square foot of wall (roof, floor) and maintaining the necessary temperature difference between the outer and the inner surface over a 20-year period. As the name implies, the value is at present; it is to be paid at the time of construction. As some uncertainties do exist in estimating the construction costs and in calculating the heat losses, the figures should be seen as guidelines to insulating standards and not as exact values. Construction costs have been estimated using the "Building Construction Cost Data 1982" published by the Robert S. Means Company, Inc. with an average multiplier of 2.33 from the lower 48 to Kotzebue. Conclusions: As can be seen in Figures 7.6.1 and 7.6.2, the insulation in walls should amount to 8 to 13 inches of fiberglass and in floors to 9 to 14 inches of fiberglass. Insulating roofs is normally a rather simple and cheap operation and this, in turn, increases the optimum insulation thickness to 10 to 20 inches of fiberglass as seen in Figure 7.6.3. The curve is rather flat which means that the gain from increasing insulation thickness to more than 10 inches will be limited. 7-61 FIGURE 7.6.1 PRESENT VALUE FOR WALL CONSTRUCTION AND HEATING ON A 20 YEAR BASIS 17 16 = a $ per square foot rs 13 12 5 6 7 8 9 10 11 12 13 14 15 16 17 thickness in inches FIGURE 7.6.2 PRESENT VALUE FOR FLOOR CONSTRUCTION AND HEATING ON A 20 YEAR BASIS $ per square foot insulation thickness in inches FIGURE 7.6.3 PRESENT VALUE FOR ROOF CONSTRUCTION AND HEATING ON A 20 YEAR BASIS 17 $ per square foot insulation thickness in inches FIGURE 7.6.4 CONSTRUCTION COSTS PER UNIT WALL, ROOF OR FLOOR WITH VARIOUS INSULATION STANDARDS 14 12 $ per square foot — 5 6 8 9 10 11 12 13 14 16 16 17 18 19 20 21 insulation thickness in inches FIGURE 7.6.5 YEARLY CONSUMPTION OF HEATING OIL PER SQUARE FOOT OF WALLS, ROOFS AND FLOORS FOR INSULATION STANDARDS. 0.30 0.25 gallons per square foot roofs 0.05, 0.0 18 119 «620 '24 5 6 7 8 '9 10 410 612 43g 14 456 16 117 insulation thickness in inches Windows should be of the 2- or 3-pane type as this gives energy savings as compared to single pane windows of 55 and 67 per cent respectively. Construction is, however, somewhat more expensive and thus the economic benefits are lower. Compared to single pane windows the economic savings on a 20-year basis are 39 and 42 per cent respectively. If thermal shutters are used as described, energy savings on 2- and 3-pane windows as compared to single-pane windows will be 52 and 65 per cent respectively and the economic savings will be 27 and 26 per cent respectively. Thus, it can be seen that if thermal shutters are used it will not pay off to install 3-pane windows. There will still be a small saving of energy; however, this saving is not big enough to compensate for the added construction costs. 7.6.1.3 Energy Conservation In Existing Houses In this section, an analysis was performed on an existing typical house in order to determine the possible gains from retrofitting. Current heat loss was calculated and a retrofitting program aimed at bringing the house up to the latest standards was selected. The cost of retrofitting was established together with the heat loss from the retrofitted house and this provided the basis for calculating the payback time for the capital invested in the retrofitting program. Conclusions: For a commercial investment such pay-back times would often be considered unacceptable. However, for residential investments a pay-back time of 9.3 years could be reasonable. The above-mentioned improvements would not necessarily have to be made all at one time as they do not have the same pay-back times. The installment of 2-pane windows should be given the highest priority as should the reduction of infiltration losses. The utilization of thermal shutters over 2-pane windows would pay off in approximately 7.1 years and thus should be given high priority. It is, however, recognized that added thermal comfort caused by the shutters is partly offset by the feeling of sitting inside a box. Night set-back of temperatures could provide a 7% savings of the total heating expenses. Adjustments and modifications of stoves and furnaces could provide savings of the same magnitude at a relatively low cost. 16) The study indicates that improvements should be made in the following order: 1) Sealing and caulking to reduce infiltration losses. 2) Modification or adjustments of stoves and furnaces. 3) Night set-back of temperatures introduced. 4) Replacement of single-pane windows with dual or triple pane windows. 5) Improvements of doors with urethane foam insulation or equivalent. 6) Insulation of roofs, walls and floors. 7) Installation of thermal shutters. 7.6.1.4 Impacts from Drastic Conservation Measures Until now it has been common practice to equate a high energy consumption with a high standard of living. This situation has, however, changed since the first energy shortage in the early seventies and new engineering practices have shown’ that decreasing energy consumption can be a way of increasing the standard of living. The most obvious example of this is the greatly increased thermal comfort experienced in well-insulated and sealed homes where energy consumption is decreased significantly compared to traditional houses. Where the quality of houses is below certain levels, it may be justified to construct new houses instead of improving the existing, in order to enable the people living in these houses to pay their heating bill without sacrificing other necessities. As the construction of a large number of new houses makes large investments necessary, it may often be necessary to spend available funds on either decreasing consumption or on making supplies cheaper. The economic results are fairly easily determined and if decisions are based solely on these, the operation is quite simple. However, due consideration should be given to other impacts such as improved health standards, increased satisfaction with life in general, reduced social tension, and reduced anxiety for the future as increases in oil prices will have less’ severe consequences. 7-68 In Kotzebue a portion of the houses are of such quality that replacement should be considered. If a large-scale improvement plan was carried out during the next 20 years this could result in a 50% reduction of heating expenses for private residences as compared to an uncontrolled development with heating demands as described in the forecast (see Section 4). In the high forecast it is anticipated that the growing demand for floor area is met by building more new homes. In the improvement plan it is anticipated that the Jo Max type houses are maintained while new housing is improved as described in Section 7.6.1.1. Over a 20-year period enough new houses of a quality equal to the recently constructed housing are built to meet the growing demand for floor area and to completely replace all houses that cannot be brought up to the standards of at least the Jo Max houses. This calls for construction of 835,965 square feet of new residential floor area. Anpyal space heat demand for residences in 2002 will be 6.4 x 10 Btu/year which can be provided with approximately 593,000 gallons of oil. This is approximately 140 gallons per person per year, although this is obviously disproportionally split, and residents of older housing may expend a significant part of income on heating bills. At a cost of $100 per square foot, a total replacement of the old houses will cost approximately $30 million. Thus it is obvious that from an economic point of view replacement is an expensive way of saving energy. As mentioned earlier, however, the increased standard of living is hard to evaluate economically. In Kotzebue the replacement of a large number of houses should be seen as a joint effort to ease some of the problems caused by high prices of energy and to give the people of Kotzebue energy efficient housing. 1-69 7.6.2 General It is difficult to estimate the impact of electrical conservation without structural and electrical systems audits. dology used herein attempts to provide a relative indication of the impact using broad parameters. Electrical Conservation is outside the scope of this report. The parameters used in this analysis are 1) penetration level and 2) a percent energy reduction for each application. 1) 2) Penetration varies from user to user and each broad class of user as defined in Table 3.1 is treated as a single entity. The penetration value is an estimate of the number of devices that could be retro-fitted to accommodate the conservation device under consideration. For lighting the penetration figure indicates changing incandescent fixtures co high efficiency fluorescent units, and _ replacing standard fluorescent fixtures with high efficiency units in existing structures. Power factor (P.f.) correction devices are used for inductive devices and thus the "appliance" load is affected through their use. Penetration is limited to the number of inductive devices found under’ this load category. Energy management (EM) systems can have a penetration level as high as 100% although this may be a bit extreme in the study area. The only case not considered for EM systems is residential. The percent reduction factors used to determine load reduction in the various categories are quite conservative as far as the manufacturers' literature is concerned. Lighting loads have been reduced by more than 50% using the task and available lighting strategies. This result was obtained on actual use in an Anchorage office building. A reduction factor of 18-20% is used in this analysis. The power factor devices are a little harder to quantify as no Alaskan testing results have been released as yet. Testing of power factor devices is planned to take place in Kotzebue at the water and sewer treatment facilities this spring. A conservative value of 6% reduction in energy use will be assumed pending test results. 7-70 The metho- A more exacting methodology Residential A difference in the kWh allocations exists between values given in Table 3-1 and the values used in this analysis. An amount of 27% of the total kWh useage will be attributed to lighting and 57% of the total for inductive devices. The penetration for lighting is estimated at 50%. This figure represents to some degree personal preference - some people cannot’ tolerate fluorescent lighting - as well as outside and entrance way lighting where extreme temperatures preclude the use of fluorescent devices. Power factor penetration is estimated at 75% of the inductive load. The implementation of these devices to the degree indicated would provide an overall reduction of 5.4% for the residential sector. Commercial (incl. Apts.) The lighting penetration is assumed to be 75%. This is due mainly to the ability of commercial users to recognize the economics of lighting load reduction plus the ability to implement the installation of these devices. Again, there are applications where these strategies are not relevant or cost- effective, i.e., exterior lighting, etc. Power factor penetration for the non-commercial appliances is assumed at 50%. Commercial appliances are considered to be items such as large pumps, compressors for freezers (walk-in) and large refrigeration/cooling units, fans, blowers and some resistive devices, although the major portion of the load is considered inductive. A penetration level of 75% is used. Energy management is quite applicable in this area. Large apartments and hotels are prime candidates for EM systems. Again, since the application of EM systems are structure- specific, a modest penetration of 50% is used. The results indicate a 9.4% reduction in electricl energy. Industry such as hotels and manufacturing plants have realized energy reductions as high as 25%. Stores have shown reductions of 20-30%. Public (Including city) Lighting penetration is 75% without consideration for street lighting. The power factor penetration level of 80% was developed with the assumption that the majority of the appliance loads are Ta inductive. A factor used in making this assumption is the highly inductive load developed by the sewage treatment and water utility systems. The Energy Management system penetration level of 75% reflects the dispersed quality of the public/city loads. This fact also reduced the percent reduction in energy. The overall reduction accomplished at the indicated levels of penetration is approximately 14%. School A lighting penetration level of 100% is used in the school system due to the highly structured and thus more easily controlled environment (At least where electrical energy is considered). The power factor penetration level of 50% is used due to the possible existence of kitchen facilities providing a resistive load which would not be affected by p.f. devices. Energy management has a penetration of 100%. This is due again to the highly structured environment. The overall reduction produced with these measures at the given penetration levels is in the vicinity of 20%. Hospital The lighting penetration is assumed to be 75%. This follows a similar rationale in that a structured environment is maintained in this type of facility. The penetration level for power factor devices is kept low due to the abundance of medical equipment used that may or may not accept them. A penetration level of 30% is used. The Energy Management system is rated at 100% penetration. An overall reduction of 20% is the end result of these measures. FAA Lighting penetration is kept low due to the existence of airport and facility lighting which may or may not benefit from conservation measures due to specifications of the type of lighting necessary to perform specific functions i.e., rotating beacon. The penetration used is 30%. This reflects the housing and warehouse/shop lighting load. The power factor penetration is also comparatively low due to the energy consumed by the electronic and communications equipment utilized by the FAA. A penetration of 50% is estimated. 1-12 Energy Management penetration is also reduced. This was done due to the fact that government facilities have been mandated to reduce consumption of all forms of energy and it is assumed that "manual" energy management has already been implemented. An overall reduction of 6.1% is the predicted result of the measures described. Summary The reduction in energy levels for each conservation measure have been purposely kept low due to the extremely site- and device- specific requirements necessary to develop accurate power reduction levels. Results from testing that is currently in progress should be obtained for a more precise estimation. Preliminary results are indicating that the values used in this analysis are generally conservative. Nonetheless, with the levels of penetration used and reductions assumed, the total reduction in energy realized is in the order of 10% of the total electrical load. This value could increase if new construction is designed with energy conservation as a concept and not as a retrofit. The 10% reduction in energy applied to the energy forecast is shown below in Table 7.6.1, and a graph depicting these values can be seen in Figure 7.6.6. TABLE 7.6.1 USAGE WITH ELECTRICAL CONSERVATION ENERGY FORECAST WITH ELECTRICAL ENERGY. FORECAST CONSERVATION YEAR x 103 KWH x 10° KWH 1981 10,676 9,608 1985 14,113 12,702 1990 20,224 18,202 1995 27,680 24,192 2000 36,420 32,778 2002 42,500 38,250 Additional Benefits Not Considered ° The use of the power factors controllers with penetrations indicated would serve to reduce the reactive component in the utility grid thus reducing losses in transmission and switchgear, as well as reducing fuel consumption required to provide that reactive current. The motors that operate with p.f. correction would produce less heat, thus increasing their service life. Many p.f. controllers contain loss of phase and brown-out protection which will also increase motor life in the event of partial power loss in 3-phase applications. 7-74 TABLE 7.6.2 ENERGY REDUCTION DUE TO ELECTRICAL CONSERVATION Present Present Annual Load (kWh) - = Residential} 2.541000 ae aNce ENERGY LMANAGEMENT. 1,451,026 403,506 14,630,200 UGHTS ‘ | APPLIANCE | __ 2,217,700 66,531 Commercial} — 5,293,000 1,445,100 65,028 4,793,987 (incl Apts) 50 122,923 |COM. APPLIANCE] ENERGY MANAGEMENT Bai STRT. LIGHTS win — Inc. 586,000 APPLIANCE 14,794 503,987 ENERGY y MANAGEMENT 32,169 LIGHTS 603,000 75 90,450 885000 APPLIANCE 295,000 50 8,850 748890 ENERGY MANAGEMENT 100; 79B70 LIGHTS $32,400 75 20 79,860 747 000 APPLIANCE 214,600 30 6 3863 sbeoae : MAMAGEMENT 100 , 10 66328 LIGHTS 562,000 20 33,774 7e0600 APPLIANCE 226,600 6 6,708 ENERGY = MANAGEMENT 10 37,000 : 10,67 9,551,737 resent poe “Reduction. Reduction This table represents a breakdown of the reductions possible with electrical conservation. The penetrations and % load reduction factors are to be considered conservative indications of load reductions. Percentages of reductions by user are: o Residential = 5.4% o Commercial = 9.4% o Public = 15.9% o School = 19.6% o Hospital = 20.0% o FAA = 9.9% 7-75 FIGURE 7.6.6 LIGHT AND APPLIANCES kWh/YEAR WITH ELECTRICAL CONSERVATION PROJECTED RECORDED kWh per year 10° oA : wn with electrical a conservation ,e A 7.6.3 Wind Energy 7.6.3.1 General Discussion Wind Energy utilization in the Kotzebue Sound Area can take many forms. Windmills or water pumpers could be utilized for producing mechanical energy. The illustration below shows the full menu of possibilities for wind energy conversion systems using a conventional turbine. For the purposes of this study, we have confined our discussion to the simplest and most commercially available technology. We further required the technology to have been’ successfully demonstrated in Alaska to date. Through this process grid- intertied wind generators were chosen as the best systems for Kotzebue. Even though a resistive heating wind generator looks extremely practical, one gets more economic value by displacing high quality grid electricity than by displacing demand which can be satisfied through direct combustion. The most common grid intertie system uses an induction generator and is operated primarily as a fuel saver for the base load facility. Because of the need for the induction system to have a source from which to draw a 60 cycle signal it cannot stand alone. The turbines in the 200 kw or larger class typically are of a synchronous generator type and thus are capable of stand- alone power production. However, the cost of controls are high and their developmental nature today precludes their commercial use in Kotzebue until the 1990 time period. Because of this developmental nature of the majority of the wind industry, it was necessary to estimate the commercial readiness of the large turbines for the Kotzebue Sound. Several small machines have been tested in Kotzebue successfully (once the start-up bugs were worked out), but machines larger than 10 kw should be considered a demonstration project at this time. There is presently a proposal to use Kotzebue as a test site for larger wind turbines, which if implemented will eliminate a lot of the uncertainty surrounding utility scale wind generators in Northern Alaska. The following figure assumes a phased introduction of turbines into the grid, with the smaller units being installed first. At no time does the total installed capacity of wind generators exceed 30 % of the average load on the fuel-fired base load system. =e = : eee FIGURE 7.6.7 POSSIBLE WIND SYSTEM CONFIGURATIONS A.C Ce [| a rly Qa engine a} el Uhl Liver | generator a battery water heater bank A al ee H \\\\ ALY [o.c. tie hydraulic hot water D.C. motor brake Phe heating and pump system step-up vacuum hydraulic | compressor | gear box pump storage A.C. £ = o © <£ - ° ° = D compressed ZZ storage ee me lic hydrau' 7 turbine pumped water direct D. pumped water A.C. AC. generator generator 9 < < FIGURE 7.6.8 NUMBER OF WINDGENERATORS ON-LINE 65kW 200kW total windgenerator capacity on line(kW) 1981 1985 1990 1995 2000 2002 7-79 7.6.3.2 Power Production Analysis The wind data available for Kotzebue has been collected since 1945 and is sufficient for estimating power production of a wind system. At the anemometer height (9.4m) the annual average wind speed is 13 mph (5.8m/s) with a corgesponding annual average wind power availability of 309 watts/m*. At a wind generator hub height of 59m the annual wind speed would be 16 mph (7.3m/s) with 631 watts/m* of annual average wind power. This is a significant resource with slight seasonal variations and very low diurnal fluctuations (especially during the winter months). The following table represents the annual energy output of representative turbines in Kotzebue's wind power class of 5. 7.6.3.3 Conclusions The results of this study show a reasonable number of commercially available wind turbines can supply a small portion of the annual load safely and reliably. The 30% penetration constraint placed on the wind systems is in fact a conservative assumption which only actual operating experience can refute. The problems of intertieing a larger percentage of Kotzebue's load with wind energy are mostly unknown and beyond the scope of this work. However, the potential does exist for a significant fuel savings with wind generators, and the 10% reduction shown in this analysis should be considered a practical minimum. A concerted effort to demonstrate wind energy in Alaska would accelerate the time frame proposed for introduction of the larger turbines. On the other hand, enough uncertainty exists with the technology that more optimistic assumptions should be avoided at this time. If a district heating system is pursued which involves’ some thermal storage, an assessment of the use of asynchronous wind generators for resistive heat would be important. The resistive heating technolgoy is simple, more reliable, and has_ been demonstrated in cold climates successfully. TABLE 7.6.3 POWER PRODUCED BY TURBINE DIAMETER Oy (1) Turbine Rated Rated Wind Annual Production Diameter (m) Power (kw) Speed (mph) (103 kwh) (1) See also volume II, Appendix D 7-81 TABLE 7.6.4 ANNUAL POWER PRODUCTION BY WINDGENERATORS | TOTAL % OF YEAR NO. OF TURBINES | aNNUAL PRODUCTION | TOTAL ANNUAL LOAD | 65 kw |200 kw (103 kwh) 1983 1 0 200 1984 2 0 400 1985 3 0 600 4% 1986 4 0 800 1987 5 0 1000 1988 6 0 1200 1989 7 0 1400 1990 7 il 1980 10% 1991 8 1 2180 1992 8 1 2180 1993 9 1 2380 1994 7 2 2560 1995 9 2 2960 1996 9 2 2960 1997 10 2 3160 11% 1998 8 3 3340 1999 9 3 3540 2000 10 3 3740 108 2001 8 4 3920 2002 10 4 4320 108 7-82 8. COST ESTIMATES SECTION 8 COST ESTIMATES TABLE OF CONTENTS 8.1 Generali ies icivteweweenes ste csn om ceene ee s eeeeseun TET TTT Lee 8.2 Base Case....... lp asin 1) (0 10" 0} | ©) 9110 to 10 10 [e 0) 01 #116 © j0\0'0] »: 9} 0)-01 0 |p fee. she: she) oe 8:9) 8.3 Cogeneration (Alternative A)... cece cece cece eee rece eeeees 8.4 Coal Fired Low-Pressure District Heating System Clternative |B) s6 sic .e.c-ciecaere wsonsyo:8\ asses oy ae)0 to okn folate) rete ie she) 8 5: Hydropower-Buckland Site (Alternative C).........ee cece eee 8.6 Geothermal (Alternative D)... sce cece cece ete e erent eee ee ees a 8.7 SuMMAry... csc cee ce eee e eee s eevee eeeeee Sere siareists a ase oral ere Bie ererel's SECTION 8 COST ESTIMATES 8.1 GENERAL The following cost estimates were prepared for the systems most likely to be used in Kotzebue (see Sections 7 and 10). These estimates consist of a summary and project schedule. There are differences in the degree of system details available on the various alternatives. Consequently the estimator, to provide as realistic a comparison as possible, found it necessary to vary the contingencies to offset differences in some alternatives. Additionally where detail was not available, other projects of similar sizes were used as a basis for quantities or plant components. Overall, the degree of detail provided makes for an adequate confidence level in the overall alternative comparisons and anticipated costs using 1982 as a general basis. For additional information, please refer to Appendix F, which includes additional data as used for preparing these estimates. As noted in Section 1 and elsewhere, Alternatives "B" and "D" relate to District Heating systems only. In this section, the estimates include costs for: (1) coal-fired steam electrical plant for Alternative "B", and (2) geothermal steam electrical plant for Alternative "D". Consequently only the Distribution system portion of these alternatives has been used, when applicable, in Section 10: Plan Evaluation. 8-1 8.2 BASE CASE For estimating purposes, the following data were assumed: Plant - 60' x 90' x 24' Foundation — Pilings Plant Floor - 12" concrete Plant Building Structure - insulated steel structure Site Pad - 1 acre Site Pad Thickness - 4' This project was envisioned as being constructed in a single contract and in one construction season. The project would, however, have to be constructed as three simultaneous projects by either one or two general contractors. The two projects would consist of the new diesel plant, modifications to the existing plant, office buildings, the five one-million- gallon oil storage tanks, and the distribution system. It is entirely feasible to construct the project in one season, which would result in numerous economic gains. Involved in these economic gains are reduced subsistence costs for labor, higher manpower efficiencies, reduced equipment standby time, and other overhead costs. Mobilization of the project would be by sea with construction requiring six months for the plant, other structures, and tankage and five months for the distribution system. The equipment and construction facilities for the distribution system would then be demobilized September 1 of the first season, and the balance of the equipment and construction facilities for the plant demobilizing September 1 of the following year. It is anticipated that actual construction of the plant will be completed within six months with subsequent deactivation of the construction phase to a caretaking status. For comparison of other systems,.a coal fired district heating system has been included in the basic estimate. SUMMARY - BASE CASE 8=3 DISTRIBUTION ITEM WEIGHT PLANT SYSTEM T03§) (1035) 1, MOBILIZATION TO KOTZEBUE a. Labor | $ 134.4 $ 100.8 b. Material 4,536.8 1,784.1 c. Material Shipping @ $8.50/100 1b. (Diesel Generation) 1,515 tons 257.6 (Distribution) 200 tons 100.3 d. Equipment Shipping @ $8.50/100 1b. (Diesel Generation) 215 tons 36.6 (Distribution) 230 tons 48.8 2. JOB COSTS a. Labor 2,201.1 1,379.9 b. Equipment (Rental, 1j394:.3 649.0 Maintenance, Parte, and Fuel) 3. DEMOBILIZATION TO SEATTLE a. Labor 100.8 75.6 b. Equipment Shipping (See above) 36.6 48.8 8,638.2 4,187.3 4. ADMINISTRATIVE COSTS (25 wks) a. Superintendent $ 110.3 $ 68.0 b. Field Engineering (2) 191.1 117.9 c. Administrative (2) 147.0 181.4 d, Timekeeper 58.8 36.3 e. Caretaker (12 wks) 34.4 13.6 Subtotal 541.6 417.2 TOTAL JOB COST $ 9,179.8 $4, 604.5 5. CONSTRUCTOR FEES a. Contingency (10%) $ 918.0 $ 460.5 b. Bond and Overhead (2%) 183.6 92.1 c. Profit (12%) 1,101.6 552.5 Subtotal 2,203.2 1,105.1 TOTAL CONSTRUCTION COST $11, 383.0 $5,709 .6 6. ENGINEERING FEES Professional Services (7%) $ 796.8 $ 399.7 7. CONSTRUCTION MANAGEMENT (5%) 569.1 285.5 Subtotal 1,305.9 685.2 TOTAL PROJECT COST $12, 748.9 $6 ,394.8 IJJASONDIJFMAMJIJASONDIJFMAMJJASONDISFMAMJIJASONDIJ FMAMJJASON 1. PRELIMINARY ae be ce d. Plant Diesel Generators | Oil Tankage| New Offices! Remodel Existing Offices Substation Distribu- tion System | DESIGN | | | 2. MATERIAL SUPPLY CONTRACTS PREPARATION b. ce d. Diesel Generators Oil Tankage Substation tion System 3. MATERIAL SUPPLY MANU- FACTURING Diesel Generation Oil Tankage Substation Distribu- tion System 4. FINAL DESIGN Plant and Offices Oil Tankagel Substation | Distribu- | tion System| | | | | | | | | | | | | | | Distribu- | | | | | | | | | | | | | | | 5. CONSTRUCTION be Ce Ofices and Substation 011 Tankage| Distribu- | | | Plant, | | | PROJECT SCHEDULE, BASE CASE 1982 | 1983 | 1984 8-4 1985 1986 8.3 COGENERATION (ALTERNATIVE "A") For estimating purposes, the following data were assumed: Boiler plant - 115' x 115' x 50' Coal processing and ash handling plant - 100' x 115' x 30' Foundation - pilings Plant and processing floor - 12" concrete Plant and processing building structure - insulated steel structure Site pad - 3 acres Site pad thickness - 4' This project was envisioned as being constructed in a single contract and in one construction season. This project would, however, have to be constructed as two simultaneous projects by one general contractor. The two projects would consist of the steam plant and the distribution system. It is entirely feasible to construct the project in one seasons which would result in numerous economic gains. Involved in these economic gains are reduced subsistence costs for labor, higher manpower efficiencies, reduced equipment standby time and other overhead costs. Mobilization of the project would be by sea with construction requiring 12 months for the steam plant and 5 months for the distribution system, utilizing extensive manpower double shifting. The equipment and construction facilities for the distribution system would then be demobilized September 1 of the first season, and the balance of the equipment and construction facilities for the steam plant demobilizing September 1 of the following year. It is anticipated that actual construction of the steam plant will be completed within 12 months with subsequent deactivating of the construction phase to a caretaking status. 8-5 SUMMARY - COGENERATION (ALTERNATIVE "A") 8-6 ITEM WEIGHT GENERATION OYSTER NERA SYSTEM (1058) (ros) 1. MOBILIZATION TO KOTZEBUE a. Labor $ 134.4 $ 100.8 b. Material 10,907.6 1,784.1 c. Material Shipping @ $8.50/100 1b. (Coal-Fired) 2,160 tons 367.2 (Distribution) 590 tons 100.3 d. Equipment Shipping @ $8.50/100 1b. (Coal-Fired) 220 tons 37.4 (Distribution) 287 tons 48.8 2. JOB COSTS a. Labor 5,525.3 1,379.9 b. Equipment (Rental, 1,765.0 649.0 Maintenance, Parts, and Fuel) 3. DEMOBILIZATION TO SEATTLE a. Labor 100.8 75.6 b. Equipment Shipping (See above) 37.4 48.8 18,875.1 4,187.3 4. ADMINISTRATIVE COSTS (39 wks) a. Superintendent $ 172.0 $ 68.0 b. Field Engineering (4) 596.3 117.9 c. Administrative (4) 458.7 181.4 d. Timekeeper 91.8 36.3 e. Caretaker (12 wks) 34.4 13.6 Subtotal 1,353.2 417.2 TOTAL JOB COST $20 ,228.3 $4,604.5 5. CONSTRUCTOR FEES a. Contingency (15%) $ 3,034.2 $ 690.7 b. Bond and Overhead (2%) 404.6 92.1 c. Profit (12%) 2,427.4 552.5 Subtotal 5,866.2 1,335.3 TOTAL CONSTRUCTION COST $26,094 .5 $5,939.8 6. ENGINEERING FEES Professional Services (7%) $ 1,826.6 $ 415.8 7, CONSTRUCTION MANAGEMENT (5%) 1,304.7 297.0 Subtotal 3,131.53 712.8 TOTAL PROJECT COST $29, 225.8 $6,652.6 1. PRELIMINARY DESIGN a. Plant b. Boilers c. Turbine/ Generators d. Substation e. Distribution System 2. MATERIAL SUPPLY CONTRACTS PREPARATION a. Boilers b. Turbine/ Generators ce. Substation d. Misc. Plant Equipment e. Distribution System 3. MATERIAL SUPPLY MANUFACTURING a. Boilers b. Turbine’ Generators c. Substation d. Misc. Plant Equipment e. Distribution System 4. FINAL DESIGN a. Plant b. Substation ce. Distribution System 5. CONSTRUCTION a. Plant and Substation b. Distribution System | -----— PROJECT SCHEDULE - COGENERATION (ALTERNATIVE “A") 1982 | 1983 | 1984 | M J.-S DI_M J S DI_M J_S Dl | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1985 MoJos bi 8-7 1986 | Moss Di | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1987 | MoJos Di | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1988 | MoJ_s Di | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-4 COAL-FIRED LOW PRESSURE DISTRICT HEATING SYSTEM (ALTERNATIVE "B") For estimating purposes, the following data were assumed: Boiler plant - 100' x 110' x 50' Coal processing and ash handling plant - 100' x 110' x 30' Foundation - steel pilings Plant and processing floor - 12" concrete Plant and processing building structure - insulated steel structure Site pad - 3 acres Site pad thickness - 4' This project was envisioned as being constructed in a single contract and in one construction season. This project would, however, have to be constructed as two simultantous projects by one general contractor. The two projects would consist of the heating plant and the distribution system. It is entirely feasible to construct the project in one season which would result in numerous economic gains. Involved in these economic gains are reduced subsistence costs for labor, higher manpower efficiencies, reduced equipment standby time and other overhead costs. Mobilization of the project would be by sea with construction requiring nine months for the heating plant and five months for the distribution system, utilizing extensive manpower double shifting. The equipment and construction facilities for the distribution system would then be demobilized September 1 of the first season and the balance of the equipment and construction facilities for the heating plant demobilizing June 1 of the following year. It is anticipated that actual construction of the heating plant will be completed within 9 months with subsequent deactiviating of the construction phase to a caretaking status. SUMMARY - COAL FIRED LOW-PRESSURE DISTRICT HEATING SYSTEM (ALTERNATIVE "B") COAL-F IRED DISTRIBUTION ITEM WEIGHT PLANT SYSTEM ( 1. MOBILIZATION TO KOTZEBUE a. Labor $ 134.4 $ 100.8 b. Material 6,542.4 1,784.1 c. Material Shipping @ $8.50/100 Ib. (Coal-Fired) 1,640 tons 278.8 (Distribution) 590 tons 100.3 d. Equipment Shipping @ $8.50/100 1b. (Coal-Fired) 217 tons 36.9 (Distribution) 287 tons 48.8 2. JOB COSTS a. Labor 3,837.9 1,379.9 b. Equipment (Rental, 1,145.1 439.0 Maintenance, Parts, and Fuel) 3. DEMOBILIZATION TO SEATTLE a. Labor 100.8 75.6 b. Equipment Shipping (See above) 36.9 48.8 Subtotal 12,113.2 3,977.3 4. ADMINISTRATIVE COSTS (36 wks) a. Superintendent $ 158.8 $ 68.0 b. Field Engineering (2) 275.2 117.9 c. Administrative (4) 423.4 181.4 d. Timekeeper 84.7 36.3 e. Caretaker (12 wks) 31.8 13.6 Subtotal 973.9 417.2 TOTAL JOB COST $13,087 .1 $4,394.5 5. CONSTRUCTOR FEES a. Contingency (15%) $ 1,963.1 $ 659.2 b. Bond and Overhead (2%) 261.7 87.9 c. Profit (12%) 1,570.5 527.3 Subtotal 3,795.3 1,274.4 TOTAL CONSTRUCTION COST $16 882.4 $5,668.9 6. ENGINEERING FEES Professional Services (7%) $ 1,181.7 $ 396.8 7. CONSTRUCTION MANAGEMENT Slush Fund (5%) 844.1 283.4 Subtotal 2,025.9 680.3 TOTAL PROJECT COST $18,908.3 $6,,349.2 PROJECT SCHEDULE - LOW PRESSURE DISTRICT HEATING SYSTEM 1982 | 1983 | 1984 1985 | 1986 1987 | 1988 | 1989 MoJo oS DIM JS DIM JS DI MJ S D | MoJos DIM J s Di MJ Ss DIM JS D | 1. PRELIMINARY DESIGN a. Plant b. Boilers ce. Distribution System 2. MATERIAL SUPPLY CONTRACTS PREPARATION a. Boilers b. Misc. Plant Equipment ce. Distribution System 3. MATERIAL SUPPLY MANUFACTURING a. Boilers be Misc. Plant Equipment ce. Distribution System 4. FINAL DESIGN a. Plant b. Distribution System 5. CONSTRUCTION a. Plant b. Distribution System —--------- | ----- | | Ce ee | | | | | | | | | | | | | | | | | | | | | | | | | ! | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 8-10 8.5 HYDROPOWER - BUCKLAND SITE (ALTERNATIVE ''C"') General Description: For estimating purposes, the following data were assumed: Dam - rockfill Dam height - 120' Dam crest - 10' Reservoir slope - 1.7 to l Spillway slope - 1.7 to l Spillway slope transitioned into face slope of -1.4 to 1 Concrete reservoir facing - 10" Spillway width - 1,200 to 1,000 Spillway facing - 10" Dam crest width - 2,300' Dam crest coping wall - 5' high Powerhouse — 70' x 125' Powerhouse structure - insulated steel structure The project was envisioned as being constructed as seven separate major contracts. These seven contracts would consist of the supply of all major powerhouse equipment items, all major substation equipment items, the construction of the transmission line and substation, the construction of a runway, the construction of the dam and dike, and the construction of the powerhouse. All dam, dike and powerhouse construction activities would be mobilized and demobilized by use of a 5,000' x 150' airstrip. The transmission line construction equipment and some components would be mobilized over sea to Kotzebue with some material components being mobilized by use of the airstrip. Helicopter support is seen as a requirement from both the Kotzebue and Buckland River airstrip material sites. Demobilization of the transmission line work would occur by utilizing the Buckland River airstrip. 8-11 TRUE NORTH APPROXIMATE MEAN DECLINATION, 1955 4 CONTOUR INTERVAL SO FEET DASHEO LINES REPRESENT 2% FOOT CONTOURS DATUM 1S APPRUXMATE MEAN SEA LEVEL, 8-12 HYDROPOWER - BUCKLAND SITE (ALTERNATIVE ''C"') Hydraulic Production Plant Mobilization 25,000,000 1b. @ $.29/1b. + labor Runway 5,000' x 150' (HERC) Dam & Spillway Stripping 50,000 cy @ $8.50 x 1.55 MF Quarry Stripping 20,000 cy @ $5.50 x 1.55 MF Earth Excavation 200,000 cy @ $7.50 x 1.55 MF Rock Excavation 40,000 cy @ $130 x 1.55 MF Drill Grout Holes 25,000 cy @ $40 x 1.55 MF Pressure Testing 1,000 crew hr @ $480 x 1.55 MF Grout Cement 5,000 sacks @ $62 x 1.55 MF Intake Concrete 200 cy @ $1,650 x 1.55 MF Grout Cap Concrete 3,400 cy @ $640 x 1.55 MF Spillway Concrete 8,000 cy @ $700 x 1.55 MF Headwall Concrete 300 cy @ $1,400 x 1.55 MF Spillway Flip Concrete 3,000 cy @ $700 x 1.55 MF Coping Wall Concrete 5,500 cy @ $600 x 1.55 MF Penstock Concrete 500 cy @ $470 x 1.55 MF Stoplog Metal Work 20,000 cy @ $4,60 x 1.55 MF Penstock, Tri- urification 800,000 cy @ $1.50 x 1.55 MF Bleed Valvage Rockfill Zone I 40,000 cy @ $20 x 1.55 MF Rockfill Zone IL 500,000 cy @ $12 x 1.55 MF Leveling Coarse 20,000 cy @ $30 x 1.55 MF Concrete Surface 9,500 cy @ $1,000 x 1.55 MF Subtotal Powerhouse Site Excavation 61,500 x 1.26 MF Site Excavation Rock 327,800 x 1.26 MF Poured Concrete 3,278,700 x 1.26 MF Metal Building Complete 2,090,200 x 1.26 MF Electric Lighting and Station Servicing 122,500 x 1.26 MF Electric Distri- bution and Substation 327,900 x 1.26 MF Electric Controls 655,700 x 1.26 MF Turbine and Generator Erection - 3 ea. 840,200 x 1.26 MF Mechanical Systems 369,000 x 1.26 MF Crane 327,900 x 1.26 MF Plumbing System 122,900 x 1.26 MF Offices and Finishes Complete 82,000 x 1.26 MF Subtotal Operator's House (2) Turbine and Generators 2 - 20 megawatt Kaplans 1 - 10 megawatt Kaplan Turbines Generators and Accessories Subtotal Demobilization 4,000,000 lbs. @ $.29/1b. + labor TOTAL HYDRAULIC PRODUCTION PLANT 8-—13 658 ,800 170,500 2,325,000 8,060,000 1,550,000 744,800 480,500 511,500 3,372,300 8, 680,000 651,000 3,255,000 5,115,000 364,300 124,000 1,860,000 1,240,000 9,300,000 930,000 14,725,000 —__aa 77,500 413,000 4,131,000 2,634,000 154,000 413,000 826,000 1,059,000 465,000 413,000 155,000 103,000 3,100,000 3,800,000 2,000,000 $ 9,000,000 3,500,000 64,116,800 10,844,000 400,000 6,900,000 $94,760,800 ‘HYDROPOWER - BUCKLAND SITE (ALTERNATIVE "C") Transmission Plant Mobilization 5,000,000 1b. @ $.29/1b. + labor 1,500,000 Land and Land Rights 600,000 Structures and Improvements 500,000 x 1.39 MF 695,000 Station Equipment 1,400,000 x 1.39 MF 1,946,000 Transmission Line Poles and Fixtures 66% x 98 miles 19,780,000 $220,000 mile x 1.39 MF = $305 ,800/mile Conductor and Devices 34% x 98 miles 10,190,000 Demobilization 1,500,000 1b. @ $.29/1b. + labor 1,000,000 TOTAL TRANSMISSION PLANT $35,711,000 Total: Hydraulic Production Plant Beene Transmission Plant 130,472,000 Contingency 25% 32,618,000 Total Construction Cost 163,090,000 Engineering Fees a. Professional Services (6%) 9,785,000 b. Construction Management (5%) __ 8,155,000 TOTAL PROJECT COST $181,030,000 8-14 1. 2. 3. 4. 5. 6. FERC LICENSING a. Feasibility Study b. Environmental Study ce. Application for License DESIGN a. Air Strip be. Preliminary 1. Powerhouse 2. Substation 3. Transmission Line 4. Dam & Dike MATERIAL SUPPLY CONTRACTS a. Turbine Gene- rators & Misc. b. Substation ce Poles & Con- ductor MATERIAL SUPPLY MANUFACTURING a. Turbine Gene- rators & Misc. b. Substation ce Poles & Con- ductor FINAL DESIGN a. Powerhouse b. Transmission Line c. Dam & Dike CONSTRUCTION a. Airstrip b. Powerhouse c. Transmission Line & Sub- station d. Dam & Dike PROJECT SCHEDULE - HYDROPOWER BUCKLAND SITE (ALTERNATIVE “C”) 1982 1983 1984 1985 | 1986 1987 1988 | 1989 M Jos DIM J s Di MJ Ss DI Ms s DI MJ Ss DI MJ S DI M JS DI vils Sete eae ata 8-15 8.6 GEOTHERMAL (ALTERNATIVE "D") For estimating purposes, the following data were assumed: Plant - 80'x100'x24' Foundation - Pilings Plant Floor - 12" Concrete Plant Building Structure - Insulated Steel Structure Site Pad - 2.6 acres Site Pad Thickness - 4' The project was envisioned as being constructed in three contracts and in two construction seasons. The project would, however, have to be con- structed as four simultaneous projects by either one or more general contractors. The four projects would consist of test well program, geo- thermal well program, constructing the plant and oil storage tanks, and the distribution system. Mobilization of the project would be by both air and sea with project time requirements of 6 months for the test well program, 12 months for the geothermal plant, 12 months for the drilling program, and 6 months for the distribution system. The equipment and construction facilities for the distribution system would then be demobilized September 1 of the initial season, and the balance of the equipment and construction facilities for the plant demobilizing September 1 of the following year. It is anticipated that actual well drilling and construction of the plant will be completed within 12 months with subsequent deactivation of the construction phase to a caretaking status. 8-16 SUMMARY - COGENERATION (ALTERNATIVE "'D") STEAM DISTRIBUTION ITEM WEIGHT GENERATION SYSTEM (1053) (05$) 1, TEST WELL PROGRAM $ 2,750.0 $ 100.8 2. MOBILIZATION TO KOTZEBUE a. Labor 434.4 2,415.0 b. Material 8,671.4 c. Material Shipping @ $8.50/100 1b. (Coal-Fired) 1,825 tons 310.2 (Distribution) 890 tons 151.3 d, Equipment Shipping @ $8.50/100 1b. (Coal-Fired) 215 tons 36.6 (Distribution) 225 tons 38.3 3. JOB COSTS a. Labor 8,934.9 1,646.9 b. Equipment (Rental, 996.7 318.5 Maintenance, Parts, and Fuel) 4, DEMOBILIZATION TO SEATTLE a. Labor 100.8 75.6 b. Equipment Shipping (See above) 36.6 38.3 22,271.6 4,784.7 5. ADMINISTRATIVE COSTS (39 wks) a. Superintendent $ 229.3 $ 68.0 b, Field Engineering (4) 795.1 117.9 c. Administrutlve (4) O11.6 181.4 d. Timekeeper 122.4 36.3 e. Caretaker (12 wks) 34.4 13.6 Subtotal 1,792.8 417.2 TOTAL JOB COST $24 064.4 $5,201.9 6. CONSTRUCTOR FEES a. Contingency (25%) $ 6,016.1 $1,300.5 b. Bond and Overhead (2%) 481.3 104.0 c. Profit (12%) 2,887.7 624.2 Subtotal 9,385.1 2,028.7 TOTAL CONSTRUCTION COST $33 449.5 $7,230.6 7. ENGINEERING FEES Professional Services (7%) $ 2,341.5 $ 506.1 8. CONSTRUCTION MANAGEMENT (5%) 1,672.5 361.5 Subtotal 4,014.0 867.6 TOTAL PROJECT COST $37,463.5 $8,098.2 8-17 1. 2. 3. 5. 6. TEST WELL PROGRAM PRELIMINARY DESIGN a. Drilling Program b. Plant c. Diesel Pumps d. Oil Tankage e. Distribution System MATERIAL SUPPLY CONTRACTS PREPARATION a. Diesel Pumps b. Oil Tankage c. Miscellaneous Plant Equipment d. Distribu- * tion System MATERIAL SUPPLY MANU- FACTURING a. Diesel Pumps b. Oil Tankage ce Miscellaneous Plant Equipment d. Distribu- tion System FINAL DESIGN a. Drilling Program b. Plant ¢. Distribu- tion System CONSTRUCTION a. Drilling be Plant ¢. Oil Tankage d. Distribu- tion System PROJECT SCHEDULE, GEOTHERMAL (ALTERNATE “D") 1983 8-18 8.7 SUMMARY In summary of the estimates as outlined, the following is noted: 1. It is suggested that material supply contracts should be provided for all long-lead materials for whichever alternative is selected. The final design should include and incoprorate as many drawings as possible from the material supply contractors. As few as possible general contractors should be utilized on the project, and hopefully this would only be one. Economic cost evaluations should be performed evaluating the concept of a pre-built complete module for the selected alter- native, which in most cases appears to offer cost advantages. All cost estimates as prepared are average in nature, so to speak, with each project's possible development cost being capable of either a lower or higher cost dependent upon the actual design philosophy and the project's administration procedures. The cost estimate for the geothermal program, however, is of an extremely "minimal cost" nature. The geothermal program is of a conservative nature, as outlined in Item No. 5 above, due to the following: a. Adequate aquifer flow is assumed as existing. b. No makeup water system is assumed. c. Well depth's assumed as 2,000' (shallow). d. Design temperatures for geothermal water is extremely optimistic. e. Well drilling costs are extremely optimistic. f. All system construction costs are very optimistic. In other words, the total plant cost for the geothermal program could easily be low by a factor of 20%, and if a supply water system is required by as much as 30%. Contingencies were varied by the estimators, based on the degree of system detail available and the, as judged, system technology reliability. These contingencies variances were done with the concurrence of the Alaska Power Authority. Overall capital cost summary for the most likely feasible alternatives are: 8-19 Capital Costs $ x 103 Distribution System Plant System Total Base Case $12,126 $6,103 $18,229 Cogeneration (Alt. A) 28,531 6,349 34,980 Coal Fired Low-Pressure District Heating (Alt. B) 18,907 6,349 25,256 Hydropower (Alt. C) 2 ==---- <= 181,027 w/transmission line Geothermal (Alt. D) 37,464 8,098 45,562 8-20 9. ENVIRONMENTAL EVALUATION 9.0 Sie: S13 9.4 9.5 9.6 9.7 SECTION 9 ENVIRONMENTAL EVALUATION TABLE OF CONTENTS GENELAl. coccccccveveccccvcvcvccsccesesesesesvcsees Im) Base Case: Diesel. .ccccccccccccccccccccccccccccccceIml Alternative A - Cogeneration. .ceccccccccccccccceceeInm3 Alternative B - Coal-fired Low Pressure District Heating. ccccccccccccccvccsccccccccccese se sIn5 Alternative C — Hydropower. cccccccccccccccccccscceeInm? Alternative D — Geothermal. ...cccccccccccccccccc ce eI-B Alternative E - Other Energy MeaSureS...eeeeeeee ee eID REFETENCES. ccccccccrccccccesesccsesescscsesccsceceeI—l0 LIST OF TABLES Table 9.1 Coal Pile Drainage Water..wcccccccccvvceveveseI6 SECTION 9 ENVIRONMENTAL EVALUATION 9.0 GENERAL Numerous energy alternatives for Kotzebue were placed in a matrix and their environmental impacts relatively compared in Table 6.1: Technical Profile Evaluations. Relative impact ratings were given for air quality, water quality, flora and fauna, land use, and aesthetics. The ratings were, of necessity, somewhat qualitative and no attempt was made to describe the impacts. This section will discuss expected impacts only for the alternatives felt to be most feasible. It should be stressed that an evaluation cannot be in-depth at this time because details concerning location size, in-plant processes, mitigations, and other factors are unknown. However, it is possible to discuss the impacts for each alternative in a general manner. In development of the impact ratings and in the discussion of impacts below, it was assumed that mitigations will be used whenever possible. Facility location plays an important role in impact determi- nation. It was assumed that a facility utilizing coal or oil would be placed south of the runway, in the vicinity of the landfill, and that a hydropower site would be located farther from the village, in an area such as the Buckland River. Geothermal generating facilities were assumed to be located in the vicinity of the village. Individual conservation measures or individual heating measures would be a part of each building in the area, but would not require construction of an additional facility. It is also assumed that no threatened or endangered species exist in the vicinity of proposed projects. None are presently known; should any be identified, impact of a facility at that site would be greater than discussed below. 9.1 BASE CASE -- DIESEL Diesel fuel may be used for electric generation or for individual heating by use of oil stoves. In the latter case, emissions are essentially nonpoint source in origin because of the number of sources involved. Both methods are presently used in Kotzebue. 9.1.1 Diesel Electric Generation Diesel electric facilities should produce somewhat fewer air pollution impacts than coal facilities because coal dust generation is not an issue, and oil contains less ash and sulfur than coal, resulting in less sulfur oxide and particulate emissions. However, some sulfur and nitrogen oxides as well as particulates are produced. Some odor and visibility are also associated with these emissions, and some noise will be produced. 9-1 Diesel facilities would require storage of large quantities of diesel oil, and a large spill could severely impact intertidal and pelagic organisms if it were to reach the water. Containment berms and other mitigating measures, including development of a spill prevention control and countermeasures plan, would reduce the likelihood of significant damage. Some small leaks, ruptures, or spills are likely to occur from time to time in spite of precautions. Stormwater runoff from the facility and surrounding area will impact adjacent waters to some extent. Stormwater is likely to carry some grease and oils, sediments, and traces of metals and chemicals. A number of materials are often present in power plants, including strong acids and bases, solvents, polychlorinated biphenyls (PCB's), and wastes from chemical cleaning, demineralization and other in-plant processes. Accidents may result in discharge of these materials unless spill containment measures are present. Some effluent may also be produced from drains and processes within the plant which, without mitigation, could affect surface waters. If the existing facility were enlarged, some noise, dust generation, construction equipment emissions and increased solid waste generation would result. Impact is often associated with disposal of heated water from power plants. The present facility utilizes waste heat when possible. Facilities which do not use this heat generate heated cooling water, which tends to range between 100-160° F. Disposal of this water has great impact on the surrounding environment, even in tropical areas where water is naturally warm. Environ- mental impact is greatly reduced by utilization of waste heat, and in cold areas, an energy savings also results. 9.1.2 Individual Oil Stoves The impact from the use of individual oil stoves is, in effect, nonpoint source in origin. Nonpoint sources are traditionally more difficult to control and regulate than point sources, as control measures feasible for a single large facility are often not feasible for small individual installations. Many of the impacts normally associated with a diesel burning facility located outside of the city are also generated by these individual sources within the city. Oil stove emissions are released within the town itself, and the air pollution impact on the population is immediate and direct. In contrast, a single facility could be located south of the town and prevailing winds would normally carry the emissions westward, away from the town. Should the wind shift, there would still be dilution due to the distance from town and the stack height. A number of cleaning and other in-plant processes utilized in a large facility would not be required for oil stoves, and water- related impacts, with the exception of spills, should be minimal. Oil storage problems and oil spills associated with individual stoves are also essentially a nonpoint source problem, and therefore difficult to control or regulate. In addition, it is probable that a number of small installations have lower overall efficiency than for a single large facility. 952 ALTERNATIVE A -- COGENERATION This alternative would require coal-fired steam cogeneration supplemented by coal-fired low pressure district heating. It would be accomplished by a single plant with a common dispersion system. Impacts of both the steam co-generation and the low pressure district heating would be similar, because although both systems could burn various fuels, the main fuel would likely be coal in both cases. A major consideration for all coal-fired technology will be the environmental impacts of coal extraction. Stripping of over- burden, stockpiling of that material in a manner to control erosion until it is used in rehabilitation of the mine, aspects of hydrology and water quality that are associated with mining, revegetation of disturbed areas, and other considerations of providing the feedstock will have to be assessed. Although they are not addressed in the analysis, they are recognized as important factors that will weigh heavily in considering coal- fired alternatives. Coal transport and storage facilities would be required, and construction of the transport system could impact land use, drainage, and aesthetics. Fugitive dust generated from coal piles and during unloading, crushing, and other coal handling operations is a major concern in coal-fired facilities, but a number of mitigations can be implemented to reduce dust generation. Location of the facility south of the town will prevent prevailing winds from carrying dust over the town, thus minimizing direct impact from the facility. Stack emissions would result in additional air pollution impacts; sulfur and nitrogen oxides as well as particulates would be produced in somewhat greater amounts than from an oil-fired facility, and radioactive trace metals and fluorides may possibly be found in emissions if proper control technology is not used. Coal pile storage may also result in water pollution. Various elements in the coal enter thin films of water that exist when the coal is damp and exposed to air. Rainfall will wash off this film, producing an initial runoff that is often acidic, and usually high in concentrations of iron, copper, and/or zinc. Analysis of coal pile drainage water are shown in Table 9.1. Actual characteristics and contaminant concentrations present in coal pile leachate will vary depending upon the source of the coal, the coal pile size and residence time, temperature, coal- water contact time, method of coal preparation prior to storage, and other factors. While not a local impact, each coal mining area has significant impacts. A few more obvious areas are runoff control in disturbed areas, reclamation of disturbed areas, handling of spoil, the resource, etc. Coal burning also results in production of large quantities of ash and possibly sludges from S02 scrubbers. Space would be required for storage of these materials. Coal ash can contain significant quantities of aluminum, iron, silicon, calcium, Magnesium, sodium, potassium, lead, boron, and titanium, as well as trace metals including mercury, arsenic, selenium, cadmium, copper, nickel, vanadium, and zinc (US EPA 1979). In addition, contamination of ground or surface waters may result if heavy metals, acids, bases and other compounds contained in the ash are leached from uncovered storage areas by rainfall or surface runoff. Runoff from coal storage piles, ash piles, and the facility in general can be minimized and treated before discharge, to meet NPDES discharge limitations. Discharge to the ocean would be preferable to discharge in the nearby lagoon; dilution would be greater and sea water tends to act as a buffer, minimizing the impact of solutions having extreme pH ranges. A number of materials are often present in power plants including strong acids, PCBs, strong bases, and solvents. Accidents may result in discharge of these hazardous materials unless proper spill containment measures are constructed. Some cooling water may also be discharged from the plant. This will affect the ecology of the surface waters to which it is discharged. However, it is possible that this could, in some instances, be considered a beneficial effect, depending on volume and temperature of the discharge water. Careful consideration of the thermal effects should be made prior to implementation of the operation. The size of the facility, the high stacks, and the _ stack emissions would produce visual impact. Location of the facility south of the town would minimize direct aesthetic impact on the population, and would seem to be consistent with existing use of the area, which presently includes the town landfill. (This landfill site may also prove to be a disposal site for some types of ash, if it can be used as cover or fill material and if runoff from the site can be contained.) 9-4 9.3 ALTERNATIVE B -- COAL-FIRED LOW PRESSURE DISTRICT HEATING Alternative B would utilize the coal-fired low pressure district heating system, which is a portion of Alternative A, described under Section 7.2. Impacts would be similar to those described for the coal facilities in Section 7.2, but the magnitude of stack emissions and other impacts would be reduced because coal would be used only for heating and not for electricity. Dust and leachate from coal storage and handling areas, coal leachate and ash storage, runoff from the facility site, aesthe- tic impacts, and air pollution impacts of sulfur and particulate emissions will still be issues with low pressure district heating, but mitigations are possible and impacts should not be insurmountable. 9=5 TABLE 9.1 COAL PILE DRAINAGE WATER: ANALYSES FROM NINE COAL-FIRED STEAM ELECTRIC GENERATING PLANTS High Sulfur Coal Low Sulfur (Avg. of 3 Coal Contaminant Range (mg/1) Plants) (1 Plant) Alkalinity 0 - 82 0 24 Acidity 8 - 27,810 24,800 6 BOD 0 = 10 NA NA CoD 85 - 1,099 NA NA Total Solids 1,330 - 45,000 NA NA Total Dissolved 247 - 44,050 26,500 NA Solids Total Suspended 22 - 3,302 NA NA Solids Ammonia (N) 0 im 1.8 NA NA Nitrate (N) 0.3 - Zed NA NA P 5 0.2 - 1.2 NA NA Turbidity 3 - 505 NA 6 Hardness (CaCO3) 130 - 1,850 NA NA Sulfate 133 - 21,920 16,000 NA Chloride 4 - 481 NA NA Al 825 - 1,200 1,012 NA Cr 0 - 16 8 NA Cu 1.6 - 3.4 2.6 NA Fe 0.1 - 93,000 48,000 1 Zn 0.01- 23 18 NA NA = Not available. Sources: U.S. Environmental Protection Agency, 1974. Development document for effluent guidelines and new source perfor- mance standards for the steam electric power generating point source category. EPA 440/1-74 029-a. Effluent Guidelines Division, Office of Water and Hazardous Materials, Washington, D.C. 9-6 9.4 ALTERNATIVE C -- HYDROPOWER Hydropower projects provide several advantages over other energy sources: they utilize a renewable domestic resource; they require relatively simple equipment; they have low operation and maintenance; they have 2-3 times the life of a fossil fuel plant; and environmental impacts are relatively well understood and predictable. Because of the distance between Kotzebue and the project location, the impacts would be removed from the immediate vicinity of the community,and therefore less _ noticeable. However, it whould not be assumed that because they are less noticeable, these impacts are of less importance to the environment. Air pollution impacts will tend to be _ negligible once construction is completed. However, like coal mining, construction of roads, transmission lines, and the dam itself, a number of air pollution impacts including dust generation, exhaust emissions, and noise associated with construction equipment should be expected. Erosion and sedimentation problems would also be likely. Aesthetic impacts include such items as the transmission lines, access roads, clearing of the construction site, construction of the reservoir and dam, noise, and possibly odors resulting from impoundment drawdown and plant growth of the reservoir. The magnitude of these aesthetic changes will be determined by such factors as the relative uniqueness of the aesthetic characteristics altered or created, the distance from which the structures are visible, height and construction material, the extent and magnitude of vegetation change along the shoreline, and the extent of other physical/chemical alterations that may cause odor and plant growth problems (Battelle 1974). Among the impacts will be the flora and fauna of the affected reservoir area, because of changes in aquatic and terrestrial habitat. These may tend to be as great as those of oil or coal- fired plants and resource capture. The facility would affect spawning and rearing habitat for anadromous fish, including salmon, char, sheefish, and other species. Because anadromous fish are part of the marine ecosystem as well, impacts on fish may extend to marine consumers such as the beluga whales. Terrestrial habitat would also be impacted; formation of the large, shallow reservoir would result in loss of moose and caribou feeding and migration areas. A new habitat, the "drawdown zone", will likely be created because water input seldom coincides exactly with water output. As a result, a belt of periodically inundated terrestrial habitat, sometimes described as a "bathtub ring" is formed, which a-—7 May result in vegetation’ changes. The importance’ and relationship of this new habitat to the ecosystem including area permafrost will vary with the reservoir. Reservoir formation may include additional impacts such as a decrease in downstream nutrients due to sediment entrainment; a change from a flowing to a lake habitat; a change in water quality including an increase in organic materials, a reduction in dissolved oxygen levels, and changes in water temperature; changes in riparian habitat; stimulation of shoreline erosion; and alteration of fish distribution. Impacts of hydropower projects can be significant. For this reason, there is need for extensive environmental data collection, and permitting and licensing procedures are often long and complicated compared to other types of projects. As stated previously, because of the long transmission line and unknown hydrological inflows, a 100 percent backup system should be provided. This would likely consist of continuation and expansion of diesel electric qenerators. Continued impacts from diesel electric generation (Section 9.1) should therefore also be considered when evaluating the alternative of hydropower. How- ever, positive benefits in terms of non-renewable resources savings would still occur when hydropower facilities are operational. Impacts from hydropower will be the same whether it is used to provide electrical power, or whether it is used for space heating as well. 9.5 ALTERNATIVE D -- GEOTHERMAL Geothermal projects, once in operation, are likely to have negligible air quality impacts. During construction, dust generation, construction equipment emissions, and noise would be expected. There may be some limited land and water-related impacts, including erosion/sedimentation and materials spills. Once construction is completed, the main impacts are likely to be water-related. The geothermal system will probably be a liquid- dominated system which would utilize heated subsurface water to transfer heat energy. Hot, deep-seated igneous rocks which produce very hot water do not appear to be present, so a large volume of warm water would be necessary to provide sufficient heat for system operation. Data from Nimiuk Point well #1 indicate this water is also likely to be very saline, having total dissolved solids of about 90,000 ppm (Alaska Power Authority 1981). Once heat is removed from the water, a large volume of warm saline water will require disposal, either through reinjection or surface discharge. Disposal to either fresh water or marine environments would impact the habitat to varying degrees depending upon the volume of water discharged, the salinity, 9-8 mineral content, and temperature. It is possible that moderate temperature change could, in some instances, be beneficial to wildlife, although habitat changes would result. SO, formation can cause significant odors which are quite objectionable. Removal of large volumes of subsurface water could potentially cause land subsidence, which could be of concern as Kotzebue is only 10 feet above sea level (Energy Systems Inc. 1980). Poten- tial for both surface water pollution and subsidence would be substantially reduced if water were reinjected into the ground after use. Development of a geothermal facility would also probably result in generation of some stormwater runoff. However, the facility would be relatively small, and would not be likely to contain material stockpiles or other undesirable contaminants which could be leached or carried from the site by stormwater. Stormwater impacts could be mitigated if necessary by use of an oil water separator, holding pond, or other means. 9.6 ALTERNATIVE E -- OTHER ENERGY MEASURES 9.6.1 Thermal and Electrical Conservation Energy can be conserved by both thermal and electrical means. Thermal conservation measures include retrofitting of existing structures through caulking, sealing, increased insulation, and other measures, as well as use of heat-conserving practices and materials during new construction. Electrical energy conserva- tion includes measures such as load management and use of efficient lighting. Both of these types of conservation measures have important positive environmental impact because they minimize energy loss, regardless of the energy resource used. In addition, there is no negative impact associated with use of these conservation measures. They should be considered as support systems, because in themselves they do not sufficiently meet Kotzebue needs. How- ever, individuals should be encouraged to utilize both thermal and energy conservation measures to the extent feasible, regardless of the energy source ultimately utilized by the city. 9.6.2 Wind Systems Like hydropower, wind generators have the advantage of using a renewable domestic resource which has little pollution potential. Traditional impacts associated with energy production are nearly absent in wind generation facilities. Minimal impacts involving noise, construction equipment emissions, dust generation, erosion, and increased traffic would be expected during construction. Once in operation, no appreciable air or water impacts would be expected. 9=9 However, several other less-traditional impacts should be considered. At present, large turbines have not yet proven reliable in the Arctic, so a large number of generators would be required, at least at first. They would have greater aesthetic impact than other energy producing facilities, because they must be raised and placed in open areas free from turbulence caused by other structures. Operation of the generators will also result in two less obvious, but potentially important impacts. Wind generation systems have been known to produce radiomagnetic interference. They may also produce some low frequency sound, which could cause impact of an undetermined degree to both wildlife and human populations. As stated previously, until demonstrations show differently, 100 percent backup power should be provided by the utility. The back- up facility would likely be a continuation and expansion of diesel electric generation, discussed in Section 7.1. Impacts from this backup system should therefore also be considered in addition to impacts from the wind generators themselves, when evaluating the windpower alternative. However, positive benefits in terms of non-renewable resources savings would still occur during periods when the wind facilities were operational. 9.7 REFERENCES Alaska Power Authority, 1981. Kotzebue geothermal project: biologic analysis. Prepared for Alaska Division of Energy and Power Development, authored by Arlen Ehm. Battelle Columbus Laboratories, 1974. An assessment methodology for the environmental impact of water resource projects, prepared for the Office of Research and Development US EPA, contract no. 68-01-1871. Energy Systems, Inc., 1980. Kotzebue geothermal project: analysis of currently available information and report of advisory group meetings. U.S. Environmental Protection Agency, 1979. Environmental impact assessment guidelines for new source fossil fueled steam electric generating stations, EPA 130/6/79-001. 9-10 10. PLAN EVALUATION SECTION 10 PLAN EVALUATION TABLE OF CONTENTS 10.0 Generals cicis/s</6 ¢.01</6 Slleifoliorel siieliele oielieve! 6) s\ieke epeloiexs s)is sielo) sisheie oO 10.1 Basis for Economic Analysis..... cosseve es cweecewse e LO) 10.2 Summary of Economic Analysis..... +e NGOS OED E OS aO SS -10=3 LIST OF TABLES Table 10.1 Summary Economic Evaluation 55-Year Presene WOES occ aciele olelere aleuere ouclisie/euslle.e1s eiete)c}e aie, 0) 10 FO 4 Table :10).2; <Cost=Benefrit Summary. cides sccie o sbie steicis's vice cls eliele' Sie LOS Table 10.3 Detail Summary - Case 1: Base Case....... cece - 10-6 Table 10.4 Detail Summary - Case 2: Coal-fired Cogeneration........ © allelic ellie © siolleiersieliele' oleic! ©) lie eee O-7 Table 10.5 Case 10 - Hydropower with Geothermal District; Heatings ois ssc «os .6 Siete ealleie st slelelclalsisiclaie) O—3 Table 10.6 Case 11 - Hydropower with Electrical Space Heating) = joie isles 6 cicie = cleo s sleliel'e siel erelc olcle/e) epciicl o) oie. OO SECTION 10 PLAN EVALUATION 10.0 GENERAL This section provides the basic matrix for evaluating which plan or plans would best serve the electrical and heating needs of Kotzebue. With the technologies described in Sections 5 and 7, eleven (11) plans (or cases) were considered to be viable schemes and evaluated with respect to economic and technical characteristics only. The environmental and social criteria should be further addressed in the follow-on studies, i.e. the Detailed Feasibility Study and Final Design phases. Each plan was designed to be capable of providing Kotzebue with the forecasted demands of heat and electricity; a reasonable amount of back-up capacity was incorporated. For geothermal alternatives it should be noted that a well head temperature of 162°F, which may be optimistic, has been theorized as possible. This would allow for direct utilization in district heating systems with an anticipated cooling of 36°F. It should be noted, however, that this will require larger radiator sizes in residences and direct connection of residential systems to the district heating system without the use of heat exchangers. The results of the evaluations are summarized and tabulated in Table 10.2. The case evaluation procedures are covered in Appendices G, H, I, and J. Appendix G provides computations of O&M costs for each plan, Appendix H provides the computations of fuel costs, and Appendix I provides the calculations of capital costs for each plan. A year-by-year breakdown of costs and benefits is provided in Section 10.3, Tables 10.3 through 10.6 for the following cases: Case 1: Base Case (Table 10.3) Case 2: Coal-fired cogeneration (Table 10.4) Case 10: Hydropower with geothermal district heating (Table 10.5) Case 11: Hydropower with electrical space heating (Table 10.6) 10.1 BASIS FOR ECONOMIC ANALYSIS The economic evaluation performed for the Alternatives considered in this study is based upon the Alaska Power Authority's recommended standard procedures for reconnaissance and feasibility studies. These procedures use a standard set of assumptions, some of which are presented below: ls Zero general inflation; 2. Real escalation of petroleum fuels at 2.6 percent annually and coal at 2.0 percent annually for twenty years. 10-1 are The interest rate for purposes of present worth calculations, for interest during construction calculations, and for interest and amortization calculations is 3 percent; and 4, Operation, maintenance, and fuel costs are assigned to the year in which they occur. Determination of the total present value or present worth of a project involves two primary calculations: The calculation of the annual uniform interest and amortization payment (similar to a home mortgage payment), and discounting of the future costs to the base year. Calculations of the annual uniform interest and amortization payment are handled in the following manner: First, the total investment cost of the project is summed from estimates for construction costs, equipment costs and the like, plus interest costs accrued during construction. The average, annual cost (or payment) is then calculated over the project's economic life (e.g., 50 years for hydroelectric projects, and 20 years for diesel generators) using an interest rate of 3 percent. The process described above is similar to the calculations performed by banks and mortgage companies to arrive at a mortgage payment for homes. The discount rate is an economic concept which says that the value to a recipient of $20.00 received ten years from now is less than the value the recipient would place on $20.00 received tomorrow and subsequently, that the value of $20.00 received twenty years from now is less than the perceived value of $20.00 received ten years from now. The same concept exists for payments; a person would place a greater value on $20.00 he had to spend tomorrow to make a house payment than on the $20.00 he had to pay thirty years from now to make the same payment. The rate at which the value of that $20.00 diminishes over time is called the discount rate. A discount rate of 3 percent would establish that the present value of $20.00 received ten years from now is $14.88 and for $20.00 received twenty years from now it is $11.07. Discounting of the future costs of the project is calculated by summing the capital cost payments (annual uniform interest and amortization payment), operation and maintenance costs, fuel costs, and similar items for each year and discounting the total annual cost back to the base year. Discounted costs for each year are then summed to give the present worth of plan costs. 10-2 Benefits from a project are handled in a similar manner; they are assigned in the year they occur and are discounted in the same way as costs. Plans are compared in terms of total net benefits and benefit- cost ratios. Net benefits are equal to the discounted total cost of the base case plan (benefits) less the cost of the alternative being considered. The benefit-to-cost ratio shown in this evaluation is the ratio of the present worth of the project benefits to the present worth of project costs. A number less than 1.00 means that the costs of the project are larger than the benefits to be derived from it, while a number greater than 1.00 states that benefits outweigh the costs. Net benefits and benefit-to-cost ratios are often used to evaluate alternatives, with the largest total net benefits or benefit-to-cost ratio implying the best project from an economic basis. However, in the final analysis of alternatives and selection of a preferred project a number of other criteria have to be considered. 10.2 SUMMARY OF ECONOMIC ANALYSIS The ensuing text, tables and graphics summarize the overall economic parameters for each plan (Tables 10.1 and 10.2). Tables 10.3 through 10.6 show a detailed summary of estimated costs and benefits per year for each case. This tabulation shows (1) capital cost; (2) operation and maintenance cost; (3) replacement cost of equipment; (4) fuel costs; (5) diesel generation displacement benefit; oil stove heating displacement benefit; and, (6) fuel escalation benefit. As presented in Table 10.2, Cases 2 (Coal-fired Cogeneration) and 11 (Hydropower with electrical resistance heating) are almost equal in net benefit and benefit-cost ratio. Case 10 (Hydropower with geothermal district heating) has a much lower net benefit and benefit-cost ratio. 1O=3 CASE NR ar 10. dt. TABLE 10.1 Summary Economic Evaluation 55 Year Present Worth Revised For Price of Coal at $6.00/MBTU (All figures are $ x 10°) CAPITAL Base case 18.2 Coal-fired cogeneration 62.0 Hydropower, oil stoves 199.6 Diesel generation oil-fired district heating 3335 Oil-fired cogeneration 40.6 Diesel generation, coal-fired district heating 68.3 Coal-fired power, oil stoves 35.0 Hydropower, coal- fired district heating 250012 Diesel generation, geothermal district heating 142.6 Hydropower, geo- thermal district heating 309.2 Hydropower, with electrical heating 202.2 10-4 FUEL cost 341.8 id oe. 220.3 217.6 285.4 183.2 301.0 957 L724 25.0 41.4 O&M 27.6 33.6 28.8 24.1 25.4 29.5 37.4 47.5 24.8 32.6 28.8 SINKING FUND 14.6 0.1 1.5 LoS 7 0.1 11.7 L.5 0.1 ne, 0.1 1.5 TOTAL 402.2 272.8 450.2 286.9 351-5 29:27 374.9 393.5 35155 366.9 273.59 TABLE 10.2 Cost/Benefit Summary PRESENT WORTH IN $ X 103 BENEFIT-TO- GENERAL CASE COSTS BENEFITS BENEFITS COST RATIO RANKING 1 (Base Case) $402,123 $402,123 $ 0 1.00 (a) 2 (Cogeneration) $272,853 $402,123 $129,270 1.47 i! 10 (Hydropower/ geothermal district heating) $366,810 $402,123 $ 35,313 1.10 3 11 (Hydropower w/electric resi- (c) stance heating) $273,899 $402,123 $128,224 1.47 2 (a) (b) (c) Not Applicable Economic analysis uses Cape Beaufort Coal (currently not a produ- cing mine) which is the cheapest source estimated to be available. Hydropower system utilized contingency of 25% in comparison to 10% for base case and 15% for cogeneration. On similar contin- gency percentage both Case 2 and 11 appear to be near equal. 10-5 TABLE 10.3 - DETAIL SUMMARY - CAS} BASE CASE 1. Diesel Generation and Waste Heat Capital Costs O&M Fuel ($1.28/gal.) Replacement of Existing Systems 2. Oil Stoves & Furnaces Capital Costs O&M Fuel ($1.46/gal.) Replacement Total Cost Total Discounted Cost Present worth of plan cost 1983 Present worth of plan cost 2003 - 2002: - 20373 Total present :.orth ot plan cost: ESTIMATED COSTS ($1,000) 1983 0 775 1,497 488 18 142 2,906 56 5,882 5,711 1984 0 275) 1,649 488 18 147 3,135 56 6,268 5,908 $164,922,000 237,201,000 $402,123,000 1985 oO 775 1,804 488 18 152 3,579 56 6,872 6,289 BASE CASE 1986 1987 0 0 775 WS) 2,002 2,206 488 488 20 20 158 163 3,786 4,083 56 56 7,285 7,791 6,473 6,721 1988 512 800 2,431 488 20 169 4,207 56 8,683 7,272 1989 512 800 2,679 488 20 175 4,421 56 9,151 7,441 1990 512 800 2,938 488 20 180 4,607 56 9,601 7,579 1991 680 800 3,222 488 28 188 4,911 56 10,373 7,950 1992 680 800 3,519 488 28 196 5,190 56 10,957 8,153 1993 680 800 3,842 488 28 204 5,480 56 11,578 8,364 1994 680 800 4,194 488 28 212 5,741 56 12,199 8,556 1995 680 800 4,573 488 28 220 6,074 56 12,919 8,797 1996 848 800 4,998 488 28 228 6,358 56 13,804 9,126 1997 848 800 5,455 488 28 236 6,673 56 14,584 9,361 1998 848 800 5,956 488 28 244 6,979 56 15,399 9,596 1999) 848 800 6,501 488 28 252 7,363 56 16,336 9,884 2000 848 800 7,095 488 28 260 7,763 56 17,338 10,184 2001 848 800 7,744 488 35 270 8,208 56 18,444 10,518 10-6 2002 848 800 8,405 488 35 280 9,026 56 19,938 11,039 2003 -2037 848 800 8,405 488 35 280 9,026 56 19,938 TABLE 10,4 - DETAIL SUMMARY - CASE 2: ESTIMATED COSTS ($1,000) CASE COMPONENT 1983 1984 1. Coal-fired Cogeneration: Capital Cost, Plant 0 0 Capital Cost, Distribution 0 0 Fuel 0 0 O&M 0 0 2. Diesel Generation: Capital Cost 0 0 Fuel 1,497 1,649 O&M 775 775 3. Oil Stoves: Capital Cost 18 18 Fuel 2,906 3,135 O&M 142 147 Replacement 56 56 Total Cost 5,394 5,780 Total Discounted Cost 5,237 5,448 Present worth of plan cost 1983 - 2002: $124,256,000 Present worth of plan cost 2003 - 2037: 148,597,000 Total present worth of plan cost: $272,853,000 5. Benefits Displacement of Base Case: Net Benefits: $402,123,000 Benefits $402,123,000 Cost -$272,853,000 Net $123,270, 000 Benefit - Cost Ratio: 1985 1,551 1,015 3,040 1,200 100 50 6,956 6,366 1986 1,551 1,015 3,200 1,200 100 50 7,116 6,322 1987 1,551 1,015 3,373 1,200 100 50 7,289 6,288 $402,123,000 + $272,853,000 = 1.47 COAL-FIRED COGENERATION 1988 1,551 1,015 3,560 1,200 100 50 7,476 6,261 1989 1,551 1,015 3,746 1,200 100 50 7,662 6,230 1990 1,551 1,015 3,946 1,200 100 50 7,862 6,206 1991 1,551 1,015 4,173 1,200 100 50 8,089 6,200 1992 1,551 1,015 4,413 1,200 100 50 8,329 6,198 1993 1,551 1,015 4,667 1,200 100 50 8,583 6,201 1994 1,551 1,015 4,933 1,200 100 50 8,799 6,171 1995 1,551 1,015 5,226 1,200 100 oo co oO 9,112 6,205 1996 1,551 1,015 5,523 1,200 100 9,389 6,207 1997 1,551 1,015 5,867 1,200 100 oo Co oO 9,733 6,247 1998 1,551 1,015 6,240 1,200 100 10,106 6,298 1999 1,551 1,015 6,667 1,200 100 10,533 6,373 2000 1,551 1,015 7,173 1,200 100 11,039 6,484 2001 1,551 1,015 7,706 1,200 100 11,572 6,599 10-7 2002 1,552 1,015 8,267 1,200 100 ooo 12,128 6,715 2003 -2037 1,551 1,015 8,267 1,200 100 oo oO Oo 12,133 148,597 TABLE 10.5 = CASE 10: HYDROPOWER WITH GEOVTHEKMAL DISTRICT HEATING CASE 10: HYDROPOWER WITH GEOTHERMAL DISTRICT HEATING ESTIMATED COSTS ($1,000) 2003 CASE COMPONENT 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 iss 1994 1995 1996 1997 1998 1999 2000 2001 2002 -2037 1. HYDROPOWER: Capital Cost, Plant 0 0 0 0 0 5,312 5,312 5,312 5,312 5,312 5,312 5,312 5,312 5,312 5,312 5,312 5,312 5,312 5,312 5,312 5,312 Capita! Cost, Transmission Line 0 0 0 0 0 3,470 3,470 3,470 3,470 3,470 3,470 3,470 3,470 3,470 3,470 3,470 3,470 3,470 3,470 3,470 3,470 Capital Cost, Gas Turbine 0 0 0 0 0 186 186 186 186 186 186 186 186 186 186 186 186 186 186 186 186 Fuel 0 0 0 0 0 oO 0 0 O 0 0 0 0 0 0 0 0 0 O 0 0 O&M 0 0 0 0 0 1,025 1,025 1,025 1,025 1,025 1,025 1,025 1,025 1,025 1,025 1,025 1,025 1,025 1,025 1,025 1,025 2. GEOTHERMAL DISTRICT HEATING: Capital Cost, Geothermal System 0 0 3,272 3,272 3,272 3,272 3,272 3,272 3,272 3,272 3,272 3,272 3,272 3,272 3,272 3,272 3,272 3,272 3,272 3,272 3,272 Capital Cost, Distribution 0 0 17 23) 1,123 1,123 7 LZ el23i 1,123 1,123 1,123 1,123 1,123 1,123) 1,123 1,123 1,123 1,123 1,123 1,123 1,123 1,123 O&M 0 0 175 7S Lis ES 175 175 175 5 175 175 175 ves 175 TS 175 wTS 175 175 175 Pumping Expenses 0 0 436 436 436 436 436 436 436 436 436 436 436 436 436 436 436 436 436 436 436 3. DIFSEL GENERATION: Capital Cost 0 oO 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 oO 0 Fuel 1,497 1,649 1,804 2,002 2,206 O 0 0 0 0 0 0 0 0 0 0 0 0 0 oO 0 O&M 775 775 775 775 “is 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 4. OIL STOVES: Capital Cost 18 18 0 0 0 0 0 0 0 0 0 0 0 0 0 oO 0 0 0 0 0 O&M 142 147 50 50 50 50 50 50 50 50 50 0 0 0 0 oO 0 0 0 0 0 Fuel 2,906 3,135 0 0 0 0 0 0 O 0 0 0 0 oO 0 0 0 0 0 0 0 Total Cost 5,338 5,724 7,635 7,833 8,037 15,149 15,149 15,149 15,149 15,149 15,149 15,099 15,099 15,099 15,099 15,099 15,099 15,099 15,099 15,099 15,099 Total Discounted Cost 5,183 5,395 6,987 6,960 6,933 12,687 12,318 11,959 11,610 11,273 10,944 10,590 10,282 9,982 9,691 9,409 9,135 8,869 8,611 8,360 8,360 Present worth of plan cost 1983 - 2002: $187,178,000 Present worth of plan cost 2003 - 2037: 179,632,000 Total present worth ot plan cost: $366,810,000 5. Benefits Displacement of Base ©. $402,123,000 Net Benefits: Benefits: $402,123,000 Cost: -$366,810,000 Net: “$35,313,000 Benefit-Cost Ratio: $402,123,000 + $366,810 = 1.10 10-8 TABLE 10.6 - CASE 11: HYDROPOWER WITH ELECT! CASE COMPONENT 1. llydropower: Capital Cost, Plant Capital Cost, Transmission Line Capital Cost, Gas Turbine Fuel O&M 2. Diesel Generation: Capital Cost Fuel OaM Stoves: Capital Cost O&aM Fuel Total Cost Total Discounted Cost Present worth of plan cost 1983 - 2002: Present worth of plan cost 2003 - 2037: Total present worth ot plan cost: 4. Benefits Displacement of Base Case: Net Bencfits: Benefits Cost Net Benefit-Cost Ratio: IMATED COSTS ($1,000) 1983 1984 1985 0 0 oO 0 0 0 0 0 ° 0 0 0 0 0 0 0 0 0 1,497 1,649 1,804 775 775 a2 18 18 18 142 147 152 2,906 3,135 3,579 5,338 5,724 6,328 5,183 5,345 3,591 $137,608,000 136,291,000 $273,899,000 $402,123,000 $402,123,000 $273,899,000 $128,224, 000 KICAL 1986 oo oO Oo oO 0 2,002 ats 20 158 3,786 6,741 5,989 SPACE HEATING 1987 ooo 8 Oo 0 2,206 vas 20 163 4,083 7,247 6,251 $402,123,000 + $273,899,000 = 1.47 1988 5,312 3,470 322 1,025 100 50 10,279 8,609 1989 5,312 3,470 322 1,025 100 50 10,279 8,358 1990 5,312 3,470 322 1,025 100 50 10,279 8,114 1991 5,312 3,470 322 1,025 100 50 10,279 7,878 1992 5, 312 3,470 322 1,025 100 50 10,279 7,649 1993 5,312 3,470 322 60 1,050 100 50 10,339 7,469 1994 5,312 3,470 322 ou 1,050 100 50 10,410 7,801 1995 bigs 2 3,470 322 215 1,050 100 50 10,494 7,146 1996 5,312 3,470 322 302 1,050 100 50 10,581 6,995 1997 57312 3,470 322 414 1,050 100 50 10,693 6,863 1998 5,312 3,470 322 b2g 1,050 100 50 10,806 6,734 1999 5,312 3,470 322 664 1,050 100 50 10,943 6,621 2000 5,312 3,470 322 793 1,050 100 50 11,072 6,504 2001 5,312 3,470 322 970 1,050 100 50 11,249 6,415 LO=9 2002 5,312 3,470 322 al TF 1,050 100 50 11,456 6,343 2003 -2037 5,312 3,470 322 1,177 1,050 100 50 11,456