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HomeMy WebLinkAboutAssessment of Power Generation Alternatives for Kotzebue, June 1980ASSESSMENT OF POWER GENERATION ALTERNATIVES FOR KOTZEBUE LIBRARY COPY PROPERTY OF: Alaska Power Authority 334 W. 5th Ave. Anchorage, Alaska 99501 PREPARED FOR THE ALASKA POWER AUTHORITY BY ROBERT W. RETHERFORD ASSOCIATES @ CONSULTING ENGINEERS ARCTIC DISTRICT OFFICE OF INTERNATIONAL ENGINEERING CO., INC. ANCHORAGE, ALASKA JUNE, 1980 KTZ 001 DATE ISSUED TO TIR| CidGce Toes ke NCHIC neg 3 YY (e HIGHSMITH 42.225 PRINTEDINU.S.A. CONSULTING ENGINEERS 5 AY ROBERT W. RETHERFORD ASSOCIATES ARCTIC DISTRICT OF INTERNATIONAL ENGINEERING CO., INC. PO. BOX 6410 ANCHORAGE. ALASKA 99502 PHONE (907) 344-2585 / TELEX 626-380 9706-112 June 17, 1980 RECEIVED JUN 2) 1980 Alaska Power Authority 333 W. 4th Avenue, Suite 31 ALASKA POWER AUTHORITY, Anchorage, Alaska 99501 Attn: Mr. Robert Mohn, Director of Engineering Subject: Assessment of Power Generation Alternatives for Kotzebue Dear Mr. Mohn: We are pleased to submit the final report on subject study. The following will provide a brief summary of the purpose of the study and our findings. Kotzebue is a community with a population of about 2,400, located on the Baldwin Peninsula in Kotzebue Sound, 26 miles north of the Arctic Circle. Electric Energy is presently supplied by Kotzebue Electric Association utilizing exclusively diesel electric generators. The rapidly increasing costs of diesel fuel have escalated the costs for electric energy (~18.2¢/kWh for residential consumers in 1979) to an extent where alternate electric energy resources appear to be economically very attractive. Utilizing the power requirements prepared for Kotzebue Electric Association in 1978 and extending the forecast period from 1987 to 1995, the energy and power requirements for this study have been calculated to increase from 2,300 kW (10,700 MWh) in 1979 to 10,200 kW (51,050 MWh) in 1995. This forecast has been used to determine adequacy and economic feasibility of alternate electric power resources. The following potential resources have been investigated e Hydroelectric Power Potential. e Coal Utilization. e Wind Energy Conversion. e Geothermal Energy. KTZ Oil, gas, solar, waste conversion, peat and biogas energy potential OO) have also been addressed briefly to allow an order of magnitude Y assessment. cr INTERNATIONAL ENGINEERING COMPANY, INC. A MORRISON-KNUDSEN COMPANY Mr. Robert Mohn June 17, 1980 Page 2 9706-112 (apal/p) It has been found that development of hydroelectric potential on the Buckland River and of coal resources at Chicago Creek are at this time the most promising alternatives. Either one of the resources can be developed utilizing known and proven technologies. The economic evaluation shows the hydropotential with a cost ratio of 1.03 for an interest rate of 2% if compared to continued diesel generation. At higher interest rates utilization of coal appears to be more economical, although the ratios range from .85 to .96. Busbar costs for electric energy from the alternate sources for the year 1995 have been calculated at an interest rate of 7% as follows: Source 1995 Diesel 27. 2¢/kWh Buckland River Hydro 24.1¢/kWh Coal 27. 2¢/kWh With the parameters used for the economic evaluation the trends beyond 1995 indicate further unit cost reduction for the Buckland River Project and increases for coal and diesel use. The socio- economic impact of development of either resource should be taken into account in a more detailed assessment. It can easily be seen that utilization of the coal would result in jobs for the people of the area and revenues would stay there providing benefits for the local economy, while capital investment intensive projects are likely to be constructed by highly skilled "outside" workers. Other electric energy resources such as wind, solar and geothermal have been found to be technically or economically not feasible with the equipment available at this time, or in case of geothermal cannot be properly assessed with the resource information available. The results of this study do not allow a firm recommendation to develop any of the electric power generation alternates without further investigation Initial information required for a more comprehensive assessment of the various resources would be: e Coal - Determination of reserve in place and mining methods. e Hydroelectric Potential - Determination of geotechnical conditions, streamflow records, and metereological records. Individual reconnaissance studies for the resource development can then be performed to determine the most beneficial development. Mr. Robert Mohn June 17, 1980 Page 3 9706-112 (apal/p) Wind and geothermal potential, although not suitable as firm generating sources within an electric utility of this time, should be investigated and tested to determine possible future use. Emphasis in this study has been placed on electric power generation. An approach investigating all energy uses (comfort heating, transportation etc.) could be used to assess the various resources in regard to their overall community impact. Thank you for your cooperation during the course of this study; it has been a challenge working on this project and we have appreciated the opportunity. Sincerely, Osve a. fru? Dora L. Gropp, P.E. Project Engineer DLG: kyx Enclosures ASSESSMENT OF POWER GENERATION ALTERNATIVES FOR KOTZEBUE PREPARED FOR THE ALASKA POWER AUTHORITY BY CONSULTING ENGINEERS ARCTIC DISTRICT OFFICE OF INTERNATIONAL ENGINEERING CO., ING. @ W. RETHERFORD ASSOCIATES ANCHORAGE, ALASKA JUNE, 1980 Assessment of Power Generation Alternatives for Kotzebue apal4/f2 This Report has been prepared by Dora L. Gropp, P.E. Leonard A. Fisher, P.E. Carl H. Steeby, P.E. Major resource information for the coal, geothermal, oi] and gas sections has been provided by C.C. Hawley and Associates Assessment of Power Generation Alternatives for Kotzebue ACKNOWLEDGEMENTS We would like to express our thanks to the personnel of Kotzebue Electric Association who made the utility records available for this study. People from Mauneluk informed us about ongoing studies in the area and pointed out the concerns of the local residents. The Department of Fish and Game provided us with comments in regard to proposed hydroelectric development. apal4/f3 Assessment of Power Generation Alternatives for Kotzebue TABLE OF CONTENTS PAGE In INTRODUCTION AND SUMMARY A. Introduction 1-2 B. Electric Power Requirements I=2 Ce Electric Power Resources 1-4 D. Analysis of Alternatives 17 ES Recommendations I-8 II. ELECTRIC ENERGY AND POWER REQUIREMENTS A. Introduction id B. Kotzebue Lied C. Smaller Communities in the Kotzebue Area Tiss III. ELECTRIC ENERGY RESOURCES AND CONVERSION TECHNOLOGIES A. Introduction ge Gol B. Diesel Tii-z C. Hydroelectric 1-3 D. Coal Ti=25 E. Wood Iti-35 F. Wind TI-36 G. Geothermal ITI-39 H. Oi] and Gas III-40 I. Other Resources III-42 IV. ANALYSIS OF MOST VIABLE ALTERNATE DEVELOPMENT PLANS A. Methodology and Parameters Iv-1 B. Alternates Evaluated iVe1 1. Diesel Iv-2 2. Diesel with Waste Heat Recovery Iv-2 3. Hydroelectric Potential Iv-5 4 Coal Utilization IvV-14 Cc: Cost of Power IV-16 apal4/f4 Assessment of Power Generation Alternatives for Kotzebue CONCLUSIONS AND RECOMMENDATIONS Introduction Buckland River Hydro Project Chicago Creek Coal Wind Energy Conversion Geothermal TMoOOWDYD APPENDICES A. bw COST ESTIMATES Diesel Generating Plant Hydroelectric Generating Plant Coal Mining Coal Fired Steam Plant Coal/Wood Gasification Wind Energy Conversion Systems Frequency and Phase Conversion Waste Heat Recovery Equipment General CWODNANOHPWNHEHE TECHNICAL PERFORMANCE DATA AND DESCRIPTIONS B-1 Biomass Conversion 1.1 Gas Producer 1.2 Steam Turbine Generators Wind Energy Conversion OP wr ECONOMIC ANALYSIS - DETAILS Explanation of Computer Printouts Computer Printouts C-4 Other Details C- C- C- wnre BIBLIOGRAPHY LETTER & COMMENTS E-1 Letter from Department of Fish and Game E-2 Letter from Department of Energy -ji- apal4/f5 Waste Heat Recovery and Conservation Transmission and Distribution Lines Single Wire Ground Return Transmission Distribution and Transmission Line Load Limitations Phase and Frequency Conversion In Power Transmission Parameters Used for Economic Evaluation PAGE WWNHNEE A-1 A-2 A-2 A-2 A-3 A-11 A-12 A-13 A-13 A-15 Bowmw ' OEwr BPReRH ' H t Pee oO rere? OQ Pon Assessment of Power Generation Alternatives for Kotzebue FIGURE rh apal4/f6 LIST OF FIGURES Vicinity Map Kotzebue - Projected Energy and Power Requirements Power Requirements for 12 Communities Electric Energy Requirements for 12 Communities Smal] Hydro - Arctic Conditions Noatak river ~- Hydroelectric Potential Koguluktuk River - Hydroelectric Potential Ipewik River - Hydroelectric Potential Buckland River - Hydroelectric Potential Buckland River - Area Capacity Curve Diagram of a Rudimentary Steam Power Plant Wood Gasification Clean Fuel Gas from Coal for Power Generation Annual Fuel Costs Savings Using Wind Energy Geothermal Power Production Kotzebue - Electric Energy Resources Diesel Generation - Capacity - Demand Jacket - Water & Exhaust Waste Heat Recovery System Buckland River - Hydroelectric Power Busbar Cost of Power - Small Communities Buckland River Energy Balance with Electric Heat Utilization Coal Fired Generating Plant - Capacity Demand Kotzebue - Busbar Cost of Power Ett Assessment of Power Generation Alternatives for Kotzebue apal4/f7 LIST OF TABLES Future Power Requirements Hydroelectric Power Potential - Summary Coal Reserves in the Kotzebue Area Alternate Development Plans/Cost of Energy Electrical Generating Capacity Kotzebue - Demand and Energy Projections Electric Energy and Power Requirements for 12 Communities Fuel Energy Content Kobuk River at Ambler - Flow Kobuk to Buckland - Synthetic Flow Record Buckland River - Capacity Buckland River Hydroelectric Project - Cost Estimates WECS Power & Energy Output Fuel Savings with WECS Geothermal Equivalent of Fuel Oil for Heating Single Wire Ground Return Transmission Heating Degree Days Waste Heat Availability Buckland River Project - Load/Capacity Balance Buckland River Project - Cost of Power Evaluation of Electric Heat Utilization Cost of Power Accumulated Present Worth and Equivalent Unit Costs -iv- SECTION I INTRODUCTION AND SUMMARY fy plan ‘: Yo Pan “AA y alae ay “‘g ~ 6 + | en . 2600, % te WAKING MOUNTAINS wen SECTION I INTRODUCTION AND SUMMARY A. INTRODUCTION Kotzebue, population about 2400, is located 26 miles above the Arctic Circle on the northwestern shore of the Baldwin Peninsula. The city is bounded on the west by Kotzebue Sound and on the east by Hotham Inlet. Kotzebue serves as the regional center for a total population of about 4900. Temperatures at Kotzebue average minus 15 to 20 degree F during the winter and plus 40 to 50 degrees F during the summer months. Winds average 13 miles per hour with a prevailing easterly direction during winter and westerly direction during summer. Electricity is supplied by the Kotzebue Electric Association (KEA) at an average cost per residence per month of $81.50 (~ 18.2¢/kWh). Water and sewer hookups are supplied by the City of Kotzebue; over 240 houses have water hookups and over 150 have sewer hookups. Garbage and honeybucket wastes are disposed of in an open pit. (Reference Kotzebue Profile). Robert W. Retherford Associates (RWRA), the Arctic District Office of International Engineering Company, Inc. (IECO), has been con- tracted by the State of Alaska, Alaska Power Authority (APA), to undertake this reconnaissance level study with focus on satisfying the electrical energy needs of Kotzebue. This report includes identification, engineering and economic feasibility analysis, and environmental assessment of various existing and potential energy resources and conversion technologies for local electrical generation uses. B. ELECTRIC POWER REQUIREMENTS Power requirements have been established for Kotzebue and 12 small communities in the Kotzebue Sound/Kobuk River area. The communi- ties included are located within economic transmission distance from potential energy resources. Future power requirements for 8 of these communities and Kotzebue follow closely the projections made for existing utilities at these locations. Kotzebue Electric Association has experienced an annual load growth of 10% during the last 7 years. Continuation of this trend has been assumed for the scope of this study. The following Table I-1 shows power demand and energy requirements for the communities evaluated. apal4/1 Te Section I - Introduction and Summary COMMUNITY Kotzebue Ambler Buckland Candle Deering Kiana Kivalina Kobuk Noatak Noorvik Point Hope Selawik Shungnak TOTALS 1 Noncoincident apal4/1 TABLE I-1 FUTURE POWER REQUIREMENTS kW Demand MWh Annual Energy 1980 1985 1990 1995 2000 2450 4100 6400 10200 16200 11800 20750 32250 51050 80750 108 146 184 222 260 391 530 669 808 947 138 168 198 228 258 462 580 698 816 934 04 84 114 144 174 180 298 416 534 652 138 168 198 228 258 462 580 698 816 934 185 221 257 293 329 742 875 1008 Ti41 1274 144 166 188 218 232 483 556 629 702 775 4 84 114 144 174 180 298 416 534 652 105 141 177 213 249 386 510 634 758 882 249 294 339 384 429 968 1140 1312 1484 1656 365 461 544 629 714 1278 1614 1907 2200 2493 202 255 308 361 414 739 935 TI31 1327 1523 138 168 198 228 258 462 580 698 816 934 4330 6456 1 9219 1 13484 1 19949 18533 29246 42466 62986 94406 I - 3 Section I - Introduction and Summary C. ELECTRIC POWER RESOURCES The following alternate electric power resources to the present exclusive use of diesel generation have been investigated: Hydroelectric Power Potential Coal Utilization Wind Energy Conversion Geothermal Energy Oil, gas, solar, waste conversion, peat and biogas energy potential have also been addressed briefly to allow an order of magnitude assessment. a Hydroelectric Power Potential Arctic climates pose various basic technical problems for the operation of a hydroelectric power plant. Some of these are: ° Ice formations within the reservoir on structures & equipment and at the discharge. e Flooding during break-up. e Requirement for large reservoirs to provide sufficient flow during the winter months. Hydroelectric power potentials located a great distance from a load center require long transmission lines which in turn add to the project cost. Technical limitations of the highest transmission voltage (138 kV) under consideration for the area limit the transmission line length to approximately 150 miles and future power requirements established for Kotzebue set the capacity limits between 5 and 20 MW for this distance. Coal Utilization Occurrences of coal are known in the following locations: Chicago Creek (Kugruk River) near Candle/Deering Corwin Bluffs east of Cape Lisburne e e e Point Hope e Kobuk River between Kiana and Shungnak apal4/1 I-4 Section I - Introduction and Summary TABLE I-2 HYDROELECTRIC POWER POTENTIAL SUMMARY Prime U.S.G.S. Drainage Average Average Capacity Energy Costs Map Area Flow Head Installed (Annual Costs Total (1980 Location l"=1mi. (sq.mi.) (cfs) | (ft) (kW) Mwh) (1980-1000$) $/kW) Contraints Noatak River Noatak 12,700 10,000 130 650,000 2,847,000 Not 34 A-2 Established Koguluktuk Shungnak 355 500 129 7,000 30,660 30,100 4,300 2.4 D-21 Ipewik River Point Hope 1,165 765 100 10,000 46,910 Not 342 B-2 Established Buckland River Candle 2,220 2,880 100 20,000 87,600 90,000! 4,500 34 D-4 Includes transmission to Kotzebue Distance from load center Environmental Impact Development costs eon Section I - Introduction and Summary The following table lists type, heat content and reserve for these occurrences: TABLE I-3 COAL RESERVES IN THE KOTZEBUE AREA HEAT CONTENT RESERVE LOCATION TYPE __(Btu/1b. ) (10% tons) Chicago Creek lignitic 6200-6800 >3 (Kugruk River) Corwin Bluffs bituminous 13,600 av. large Point Hope bituminous 14,000 av. unknown Kobuk River bituminous/ unknown unknown subbituminous Transportation costs for all but the Chicago Creek lignite make the utilization of coal uneconomical at this time Estimated costs for mining and transportation of the Chicago Creek coal are approximately $65/ton with an assumed production of 20-100,000 tons per year. .3. Wind Energy Conversion With an annual average windspeed of 12.8 m.p.h. Kotzebue has excellent windpower potential. Severe cold periods and extreme storms have caused failure in experimental systems installed in Kotzebue. With the questionable reliability and relatively high costs of presently available equipment, a clear recommenda- tion for the installation of wind energy conversion systems (WECS) cannot be made at this time. If utilized to displace fuel normally used to generate electric energy in the Kotzebue powerplant, the breakeven point between annual costs for the WECS and the costs for the displaced fuel occurs at 3.50-3.80 $/gallon for a 15 kW system. Smaller systems are not economical with their present life expectancy of 5 years. Experimental projects should be undertaken in Kotzebue to demonstrate equipment reliability. apal4/1 I-6 Section I - Introduction and Summary -4 Geothermal Energy Hot or warm springs occur on the Seward Peninsula and in the Kobuk River area. A stratigraphic test well drilled at Nimiuk Point on the Baldwin Peninsula only 15 miles south of Kotzebue encountered water at 162°F at 6,300 feet depth. If a well system with sufficient flow at this temperature could be developed at Kotzebue, utilization in a district heating system is conceivable. Other resources such as wood, peat and solar energy cannot be utilized in an economically feasible way at this time. The feasibility of transmission interties for small communities has been investigated for the Buckland River Project and has been found attractive for the communities of Deering, Candle, Buckland and Selawik. Waste heat from the Kotzebue generating plant is presently being utilized to heat the potable water of the community. D. ANALYSIS OF ALTERNATIVES Only the development of the Chicago Creek coal field and of the Buckland River hydroelectric power potential appear to be technically and economically feasible. Environmental constraints associated with the Buckland River Project may well preclude development of this potential however. The presently unknown extent and recover- ability of the Chicago Creek coal makes the accuracy of a feasibility assessment uncertain at this time. Both resource potentials merit further investigation, however, based on the economic analysis Continued diesel generation has been used as a base for comparisons of alternate development plans. The following Table I-4 "Alternate Development Plans/Cost of Energy" shows the alternative plans evaluated and the resulting busbar cost of energy at 7% interest. apal4/1 I-7 Section I - Introduction and Summary TABLE I-4 ALTERNATE DEVELOPMENT PLANS/COST OF ENERGY EARLIEST YEAR OF ALTERNATE PLAN OPERATION Diesel Generation only 1980 Buckland River Hydro! 1986 Buckland River Hydro with Utilization of Electric Heat Coal - Steam Plant 1984 Coal - Gasification Plant 1984 1 BUSBAR COST OF ELECTRIC ENERGY IN ¢/kWh 1980 1985 1990 1995 10.9 15.6 20.9 27.2 15.6 35.6 24.1 [oe =o 28.6 19.0 20.3 24.0 27.2 19.9 24.1 27.5 Supply to Kotzebue plus 4 small villages. It should be noted that the above are busbar costs, not costs to the consumer. E. RECOMMENDATIONS The economic analysis indicates that coal development can compete with diesel generation and that hydro development would eventually produce the cheapest electric energy. The uncertainties involved in the assumptions made for the evaluation of these resources indicate the requirement for base information such as 1. Field investigations of the Chicago Creek coal in regard to a) Reserve in place b) Mining methods c) Environmental impact 2. Field Reconnaissance of the Buckland River Project to assess a) Technical feasibility b) Environmental impact apal4/1 Section I - Introduction and Summary The field investigations then have to be followed by Ss apal4/1 Individual feasibility studies of a) Method of utilization b) Capacity and demand c) Economical aspects d) Equipment availability e) Administrative constraints In view of the relative independence from diesel oi] which the utilization of coal would bring in addition to employment for the area population in mining and trans- portation, development of this source appears to have the most benefits. Utilization of wind energy on an experimental level by the operating electric utility rather than private individuals appears to be the most promising method and should be pursued to establish an operational record in the Arctic of available equipment. There are strong indications that geothermal resources exist in the vicinity of Kotzebue. In order to assess this potential adequately, a test well should be drilled near Kotzebue and flow rates and temperature ranges be established. Expansion of the generating plant waste heat utilization program beyond its present extent is possible, but is considered to have only marginal economic benefits at this time. SECTION II ELECTRICAL ENERGY AND POWER REQUIREMENTS SECTION II ELECTRICAL ENERGY AND POWER REQUIREMENTS A. INTRODUCTION Kotzebue's location has made it the trade center for northwestern Alaska. Supplies for approximately 12 inland communities are transported through Kotzebue either by sea or by air. Population has increased from 1,696 in 1970 to approximately 2,500 in 1979. This represents a growth rate of 4% per year. Although the community's geographical location will limit the growth potential somewhat, a continuation of this growth rate is anticipated for another 10 to 15 years. Electric energy is supplied by Kotzebue Electric Association, an REA financed cooperative. Kotzebue Electric serves approximately 600 consumers (residential and commercial) at an average cost of 16¢/kWh (1978). The U.S. Air Force station located approximately 4.5 miles south of Kotzebue generates its own electric power and is presently not connected to the KEA system. Negotiations for an intertie have been under way for some time and for the purpose of this study it has been assumed that the Air Force site will be connected to the Kotzebue system. The community's location on the tip of the Baldwin Peninsula renders interties to small inland communities not economically feasible if continued generation with diesel fuel is anticipated. If, however, a less costly electric energy resource -- such as hydroelectric power or coal -- is developed, it is conceivable that several small communities could be connected to the transmission system. Electric power requirements have therefore been established for 12 villages in the Kotzebue Sound area. B. KOTZEBUE The Kotzebue Electric Association has a present firm capacity of 3,800 kW and total installed capacity of 4,825 kW using diesel generators as shown in Table II-1 (Reference: Kotzebue Electric Association Operating Reports, December 1978). apal4/m lg. Section II - Electrical Energy and Power Requirements TABLE II-1 ELECTRICAL GENERATING CAPACITY Unit # . kW Manufacturer 3 500 White Superior o 500 White Superior 5 1025 Fairbanks - Morse 6 1000 Enterprise 7 900 Solar 8 900 Solar Total Capacity: 4825 Less Largest Unit: -1025 Firm Capacity: 3800 The system peak demand in 1978 was close to 2,000 kW. Power require- ments established for Kotzebue Electric in 1978 indicate a growth rate of 10% per year for the next 10 years. This growth rate has been assumed for the study period in this report. It represents an annual increase of 7% in the number of consumers and 3% in the individual energy use leading from 1,322 kWh/mo./cons. for 600 consumers in 1979 to approximately 2,400 kWh/mo./cons. for approxi- mately 2,480 consumers in the year 2000. This represents usage at a level anticipated in southcentral Alaska in the 1980s. The growth of numbers of consumers assumed at 3% above the population growth rate reflects the trend towards smaller families and the tendency of establishing separate residences for the generations within a family who formerly live together. The ratio between population and number of consumers decreases from the present 4.2 to 2.3 in the year 2000, approaching present ratios in the Anchorage area. Examination of the 1979 utility records indicates a reversal in these trends, i.e., slower growth in number of consumers but higher increase in energy usage. The total growth is still following the forecast, except for the system peak, which remained at the 1978 level. The system experienced a load factor of .63 in 1979. Figure II-1 graphically depicts projected peak demands and energy requirements for Kotzebue (Reference KEA Power Requirements Study of 1978) and values from that graph are tabulated in Table II-2. The existing firm capacity is such that no new generation facilities will be required until 1985 to meet the projected system peak demand. If the U.S. Air Force Base is connected to the KEA system and a demand of 200 kW (300 kW peak) is assumed, new generating capacity will have to be installed sooner to meet the additional demand. apal4/m TT 2 KOTZEBUE PROJECTED ENERGY & POWER REQUIREMENTS FIGURE II-! Section II - Electrical Energy and Power Requirements TABLE II-2 KOTZEBUE DEMAND AND ENERGY PROJECTIONS Year Demand, kW? Energy, MWh? 2 1979 2,300 10,700 1980 2,450 11,800 1981 2,700 13,000 1982 3,000 14,600 1983 3,200 15,700 1984 3,750 18,950 1985 4,100 20,750 1986 4,500 22,750 1987 4,900 24,750 1988 5,350 27,050 1989 5,850 29,750 1990 6,400 32,250 1991 7,000 35,350 1992 7,700 38,750 1993 8,500 42,250 1994 9,300 46,450 1995 10,200 51,050 1996 11,200 55,750 1997 . 12,200 61,250 1998 13,400 68,250 1999 14,800 73,750 2000 16,200 80,750 1 from Figure II-1. 2 includes system losses at 11%. apal4/m II - 4 Section II - Electrical Energy and Power Requirements A connection of the Air Force Site to the KEA system would be beneficial for both systems. Supply of this load by the highly efficient KEA generating plant would lower the unit cost for electric energy for the Air Force, which presently generates with less efficient small units. It would also benefit the community of Kotzebue, where the additional revenues would help to lower the fixed costs per kWh associated with the generating plant. For the purpose of this study it has therefore been assumed the U.S. Air Force Base would be connected to the system in 1984. Annual demand would be 200 kW coincidental peak and 1,750 MWh energy. Further increase of this load is not expected. C. SMALLER COMMUNITIES IN THE KOTZEBUE AREA Kotzebue is the regional center for a vast area of Northwest Alaska which includes the villages of Ambler, Buckland, Candle, Deering, Kiana, Kivalina, Kobuk, Noatak, Noorvik, Point Hope, Selawik, and Shungnak. The vicinity map (Figure I) shows the location of these communities. The total population of these villages is approximately 2,500. (Reference Kotzebue Profile). Table II-3 gives electrical demand and energy projections for these villages. The population growth rate in these small communities is very low (<1% per year). The economy is mostly based on fishing, hunting and trapping with some mining activities in the Kobuk River and Deering areas. Future power requirements have been established from studies prepared for the existing electric utilities where applicable and by assuming similar conditions for villages without central utilities. It is generally anticipated that the individual electric energy use in these communities will approach levels that are presently experienced in the Southcentral Alaska area. This leads from approximately 1,066 kWh/mo./cons. in 1980 to approximately 1,500 kWh/mo./cons. in the year 2000 for Kiana for example. Possible mining developments and their power requirements have not been taken into account for this forecast. apal4/m LG eer) APA14/q1 COMMUNITY UTILITY Ambler 1 AVEC Buckland 3 IRA Council Candle 3 private Deering 3 IRA Council Kiana ? AVEC Kivalina ? AVEC Kobuk 3 private Noatak 1 AVEC Noorvik ! AVEC : North Slope 2 Point Hope Borough Selawik? AVEC Shungnak + AVEC TOTALS 1 2 TABLE II-3 ELECTRIC ENERGY AND POWER REQUIREMETS for 12 Communities in the Kotzebue Sound Area 1978 RESID. RATE 37. 2¢/kWh N/A N/A $65. /mo. 37. 2¢/kWh 37. 2¢/kWh N/A 37. 2¢/kWh 37. 2¢/kWh 20¢/kWh + surcharge 37. 2¢/kWh 37. 2¢/kWh 1980 108 391 138 462 ioe 180 138 462 185 742 144 483 54 180 105 386 249 968 365 1278 202 9 8 73 138 462 188 73 6733 From AVEC 1976 - Power Requirements Forecast. From North Slope Borough 1979 Power Requirement Forecast. 3 Estimated based on 1979 Community Energy Survey. le Oe COjrM Gir Py CO WD Nim BD w PAD oF CIO OO} = 3 > wo - ly ou o HI = Oo o am > kW Demand MWh Annual Energy 1990 184 669 198 698 14 416 198 698 257 1008 188 629 4 416 177 634 339 1312 544 1907 308 T131 198 698 2819 10216 1995 222 808 228 816 144 534 228 816 293 1141 210 702 144 534 213 758 384 1484 629 2200 361 1327 228 816 3284 11936 1,000 950 900| 850) 800) 750 700 650) 600) 550 > gq oo DEMAND , KW + 8 350 300 250 NOORVIK + KIANA Spee oma tc SHUNGNAK BUCKLAND DEERING KIVALINA a A ot ey “ _ + 80 82 84 86 88 YEAR 90 92 94 8 ENERGY ,MWH on it. sa YEAR ELECTRIC ENERGY REQUIREMENTS FOR 12 COMMUNITIES SECTION III ELECTRIC ENERGY RESOURCES AND CONVERSION TECHNOLOGIES SECTION III ELECTRIC ENERGY RESOURCES AND CONVERSION TECHNOLOGIES A. INTRODUCTION All electrical energy for Kotzebue is presently generated by distillate oil fired diesel engines (reciprocrating type and turbines) located in a centralized power plant. The initial energy alternatives considered for this community include the relatively nearby resources of coal, oil, gas, hydroelectric potential, geothermal, wood, wind, and others. Identified potentials are indicated on Figures III-12 and III-13 at the end of this section. Diesel generation will be the economic baseline against which the other alternatives are evaluated. A general summary of energy available in the resources considered is shown in the following table. TABLE III-1 FUEL ENERGY CONTENT Energy Content Fuel Type in Btu/pound No. 6 Fuel Oi] (Diesel) 17,400 - 19,000 Biogas : 15,000 =|, 29,700 Bituminous Coal 13,000 - 13,600 Sub Bituminous Coal 11,000 Lignitic Coal 6,500 - «75000 Low - Btu Gas 3,500 - 4,400 Water at 100 foot head 8 Hot water at 1°F temperature difference 1 Air moving at 22 mph (stp) -02 (Ref. Kilar, supplemented) apal8/c Se Section III - Electric Energy Resources and Conversion Technologies B. DIESEL In the diesel oi] engine, air is compressed in a cylinder to a high pressure. Fuel oil is injected into the compressed air, which is at a temperature above the fuel ignition point, and the fuel burns, converting thermal energy to mechanical energy by driving a piston. Diesel engines driving electrical generators are one of the most efficient simple cycle converters of chemical energy (fuel) to electrical energy. Although the diesel cycle in theory will burn any combustible matter, the practical fact of the matter is that these engines burn only high grade liquid petroleum or gas, except for multi-thousand horsepower engines which can burn heated residual oil. Waste heat from diesel engines that is subject to capture is relatively "low grade" and comes from the exhaust and cooling water. The cooling water normally is in the 160-200°F range, but it can be 250°F or higher with slight engine modification. Engines today are usually run at the cooler temperatures because of design simplicity, simpler operating routines, and first cost economy. The exhaust heat in a diesel is of higher temperature and more easily used than the cooling water heat, but higher initial costs and increased operating complexities are encountered when attempting to recover energy from the exhaust. Typically 30% of the fuel energy supplied to a diesel-electric set is converted to electricity, 30% is transferred to cooling water, 30% is exhausted as hot gas, and 10% is radiated directly from the engine block. (Reference Waste Heat). apal8/c ITI: s:2 Section III - Electric Energy Resources and Conversion Technologies cs HYDROELECTRIC POWER POTENTIAL i General 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 underground, 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 expeced to have any flow. Remote tributaries 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. To illustrate the effect of reduced winter inflows and reduction of volume due to ice accumulation, a family of curves was generated (Figure III-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. e During the remaining seven months, inflow to the reservoir would only be enough to balance the volume lost by formation of ice (assumed to be an average of six feet deep). apal8/c LTess3 Section III - Electric Energy Resources and Conversion Technologies e Reservoirs with area and capacity vs. depth characteristics 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 production. 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 conductors 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 potential developments described in the following paragraphs appear to be the more feasible, with the caveat that additional analyses will be required to firm up project parameters and to address in more detail the problems peculiar to the Arctic noted above. 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 higest point is 315 feet in elevation. Consequently, there are no viable hydroelectric project sites on the Peninsula. apal8/c Ill - 4 Section III - Electric Energy Resources and Conversion Technologies 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 development. Future power requirements (established in Section II) in Kotzebue indicate that capacities between 10 and 30 MW would be most suitable for the community's needs. If then 138 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. As discussed in the introduction and demonstrated on Figure III-1, large reservoir capacity and a large drainage basin are require- ments 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 at the end of this section. apal8/c TIT =95 9s Try AVERAGE NET HEAD -(FT) oO 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 LIVE STORAGE — (ACRE-FEET x 1000) SMALL HYDRO-ARCTIC CONDITIONS APPROX. LIVE STORAGE REQUIREMENT AVE. NET HEAD-VS-LIVE STORAGE (ALLOWS FOR6FT. ICE COVER) FIGURE IIT -| Section III - Electric Energy Resources and Conversion Technologies -2 Noatak River Location: Noatak and Baird Mtn. Quadrange Drainage Area: 12,700 sq.mi. Average Flow: 10,000 cfs Regulated Flow 10,000 cfs Average Head: 130 ft. Dam Height: 300 ft. (lower) 300 ft. (upper) Power: (prime) 325 kW Energy: (per year, prime) 2,847,000 MWh Load Center(s): Kotzebue / Distance 50 mi. (approx. transmission distance across Hotham Inlet) The Corps of Engineers proposed a dual dam and powerhouse scheme in Interim Report No. 6, Northwest Alaska, dated June 1957 for developing the hydroelectric power potential of the Noatak River. The plan called for a 300 feet high rock fill dam at approximate river mile 21 where the river cuts through the Igichuk Hills and another 300 feet high rock fill dam upstream at approximate river mile 107. As an alternative to a powerhouse at the lower dam, a 50-foot diameter tunnel 5 miles long would cut off one loop in the river channel, gain about 50 feet of additional head and place the powerhouse 10% miles from tidewater. The lower dam would create a pool that would hold about 28,000,000 acre feet, or the entire flow for about four years. The reservoir, about 16 miles wide in the central portions, would extend upstream about 34 miles. Complete regulation of the annual flow would entail a drawdown of only about 25 feet. The village of Noatak would have to be relocated. The upper site would provide storage of about 4,200,000 acre-feet. The scheme proposed the installation of 650 MW with 325 MW prime capacity at the lower plant and an installed capacity of 556 MW plant with a prime capacity of 278 MW at the upper plant. The upper plant would use the entire annual yield in the five summer months. Meanwhile the lower plant would supply the deficiency in prime demand or 47 MW. The upper plant would close down early in November and the lower plant would pick up the entire system load of 325 Mw, and would operate at this rate through the winter months. Ob- viously this plan of development is too ambitious for a com- munity the size of Kotzebue. In their Interim Report No. 6, the Corps recognized the need of excess storage capacity and provisions for handling the tailwater during winter months. Partial development of the Noatak was briefly examined and ruled out for the following reasons: apal8/c Ton 7, Section III - Electric Energy Resources and Conversion Technologies b) In A run-of-the-river plant simply would not be feasible to construct. The cost of installing structures that would withstand the powerful forces of water and ice during breakup would be prohibitive and anchor ice would create havoc. A reservoir of sufficient capacity to store the spring runoff until the ice in the reservoir plus the inflow ice has melted would be required. Otherwise, the spillway would probably jam up with ice and overtop the dam. Diversion during construction would be a tremendous undertaking, although not impossible. The village of Noatak would have to be moved. Fish handling facilities would be required. essence, partial development of the Noatak River is not recommended. The same statement may be made for any large river in the Arctic. apal8/c TITs+:8 we i DAMSITE & POWER” HOUSE ey. oe _= (LOWER PLANT) Sz” A ee : Hits §| O 4) ey) Y Loe VI). et See Soy | Ay re i fe | Ne | Mamelak [Sox {s A Ne bes \ NOATAK RIVER 1 . HYDROELECTRIC POTENTIAL | 325 MW HD FIGURE II -2 RS aS ATES * IS MILES | TTT a Section III - Electric Energy Resources and Conversion Technologies -3 Kogoluktuk River Location: Ambler River Quadrangle, Kateel River Meridian, T18N, R10E, Section 4. Drainage Area: 355 sq.mi. Average Flow: 500 cfs Regulated Flow 500 cfs Average Head: 129 ft. Reservoir 24,200 acres Dam Height: 160 ft. Power: (prime) 3,500 kW Energy: (per year, prime) 30,660 MWh Load Centers: Kobuk, Shungnak, Ambler Distance 12 - 40 mi. (approx. ) Transmission Distance to Kotzebue 200 mi. (approx. ) The Kogoluktuk River enters the Kobuk River from the north about 2% miles east of the Village of Kobuk as shown on U.S.G.S. quad sheet SHUNGNAK (D-2) Alaska. A suitable dam site may be present at river mile 6.5 in section 4, T18N, R10E Kateel River Meridian. Drainage area above the damsite is approximately 355 square miles and the estimated average annual flow is 500 cfs. A dam approximately 160 feet in height would create a reservoir with about 24,200 acres of normal maximum water surface area at elevation 400. A spillway would be provided approximately 0.5 miles west of the dam. A 10-foot diameter tunnel 1050 feet in length would gain additional head. An underground powerhouse would provide additional protection during extreme cold weather. The estimated prime power from the plant is 3500 kW. It is estimated that there will be 30,660 MWh of prime energy and 8,000 MWh of secondary energy produced annually. With an installed capacity of 7000 kW, the 1980 estimated cost of the production plant only is $30,100,000. The power and energy from this site is too much for the villages of Kobuk, Shungnak, and Ambler. Development of this site to provide electric energy for Kotzebue is considered to be too costly at this time due to the long transmission line required. The site should be kept in mind should the Ambler area mining district develop loads sufficienty to warrant construction. Care of the tailwater should be of utmost concern, if glaciation is to be avoided. apal8/c III - 10 — Ol o “g- mr 3unold pe we | MW S'S P7 WILNALOd 914193130N0AH BAIN NLNNTODOX (rs \ ’ >\ Koltioksak| ii Y Bh 98 By ae \ ( / am Y iy ic Section III - Electric Energy Resources and Conversion Technologies -4 Ipewik River Location: Point Hope Quadrangle, Umiat Meridian, T12S, R59W, Section 22. Drainage Area: 1,165 sq.mi. Average Flow: 1,500 cfs Regulated Flow 765 cfs Average Head: 100 ft. Reservoir 8,910 acres Dam Height: 150 ft. Power: (prime) 5,355 kW Energy: (per year, prime) 46,910 MWh Load Centers: Point Hope / Kotzebue Distance 25 / 130 mi. (approx. transmission line length. ) The Ipewik River enters the Kukpuk River about 28 miles east of the village of Point Hope as shown on U.S.G.S. quad sheet Point Hope (B-2) Alaska. A suitable site for a dam 150 feet in height to elevation 250 may be present in section 22, T12S, R59W, Umiat Meridian. A spillway would be constructed in the saddle approximately 0.8 miles southeast of the damsite in section 26. A tunnel 2100 feet in length would divert the water to an underground powerhouse approximately 1% miles downstream from the dam. The drainage basin above the damsite is about 1165 square miles and the average annual runoff is estimated at 1500 cfs. The normal maximum water surface area at elevation 250 is 8,910 acres. A drawdown of 75 feet during the winter would provide 323,000 acre-feet for power purposes and 53,400 acre-feet ice, or a regulated flow of 765 cfs. This would result ina net head of 100 feet and produce 5,355 kW of continuous power. This site under less severe climatic conditions would appear attractive. However, considerable studies would be required because of the inadequate reservoir capacity and approximately 30 miles of river channel to tidewater. The long transmission distance of about 130 miles (crossing Hotham Inlet) to Kotzebue is considered too far for this small potential to be a viable project for Kotzebue at this time. apal8/c III - 12 Tusikpak Lake - Mtublarak Kv Kp eh 296 Lake Makpik er ati A Wie ay ($s, CR entol : \ Angayhag. | 4 . Angayukak . a S : s/ ae Hil i 7 2 — Bee teenie . a DL lp nn “i Akoviknak y } ote ie Mtn i : j / 9 : Pumaknak 1 pF 5 ae v una { © j Tpnot\" E i : | g (Site) | Ki-~ Y . o Wie 4 / } SS OS Ned 20 ee Clift f . We | d ai ak 5 Ht, fe LK a Cape Thompson) | (x we 1) Greek ot ; J | . y IPEWIK RIVER < Agate Rock Clit, SpE f Artigotrat” 4 - A fs Fi 5.3 MW i (4 z Crowbill Pt Safe isnine Chariot 8" FIGURE It -4 i ' Section III - Electric Energy Resources and Conversion Technologies -5 Buckland River Location: Candle Quadrangle, Kateel River Meridian, T5N, R10W, 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 ft. Power: (prime) 16,125 kW Energy: (per year, prime) 87,600 MWh Load Centers: Kotzebue, Candle, Deering, Selawik Distance 98 mi. (transmission to Kotzebue) 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 surface 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 III-12 at the end of this section. The reservoir is shown on Figure III-5. An ungated side channel spillway could be constructed to the north of the right dam abutment. The powerhouse would be constructed on the south bank of the river and preferably cut back into the bluff for added 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 10 MW units would be installed in the first stage with a drawdown valve installed in the third leg of the penstock trifurcation. The drawdown valve would permit suffi- cient 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 poten- tial 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 foreseeable load requirements of the area and is approximately 90 miles transmission distance to Kotzebue. apal8/c III - 14 +785 «{o:\ TRANSMISSION] :- pt LINE suson 4 f\ 2 % \ Z oF si. ¢ | i LCT GG OE SA a E f A 19096 ) ie Lf NOE AASV ONAN = SCALE 0 $ 10 15 MILES |} i, WC = L LG ; BUCKLAND RIVER HYDROELECTRIC POTENTIAL FIGURE IL-5 Section III - Electric Energy Resources and Conversion Technologies PROJECT DESCRIPTION: a) Hydrology: There are no known stream gaging records on the Buckland River; however, there are 13 years of continuous gaging 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 jt 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) was developed from the flow data on the Kobuk River, Table III-2, by determining the ratio of drainage basins (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 record of flow on the Kobuk River to obtain a synthetic flow for the Buckland River, Table III-3. The Buckland River synthetic flow was then converted to acre feet by month, Table III-4, 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 calculations in this study. An Area-Capacity curve was developed for the proposed project and appears in Figure III-6. 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. apal8/c III - 16 Le we at APA16/H1 TABLE III-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 35097 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 eo7 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 15152 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. 8L - III APA16/H2 Water Year 1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 Oct 6,057 3,066 2,180 4,408 1,506 970 25293 1,887 4,874 2,140 1,463 25213 3,306 TABLE III-3 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 Nov Dec Jan Feb Mar Apr May Jun 978 782 652 522 326 391 1,286 9,167 978 652 424 293 261 310 4,936 19,146 LS 681 504 456 424 424 1,636 19,987 1,161 489 313 270 261 378 5,069 2,546 802 494 385 332 323 332 5,588 3,876 603 423 336 326 310 293 8,121 14,673 1,250 778 497 376 318 293 6,843 11,788 1,347 995 791 671 576 538 9,858 14,908 1,407 692 543 468 445 426 3,092 Bol 635 358 326 326 326 363 5,464 7,456 515 322 293 293 293 326 3,478 6,810 1,239 805 578 453 424 429 4,091 8,685 1,013 600 493 456 421 393 4,251 6,171 5,607 10,099 5,998 1,707 2,341 4,769 3,465 6,311 4,261 7,091 3,615 2,780 5,291 Aug 3,645 7,817 2,649 4,082 5,242 2,647 3,710 12,959 6,393 3192 3,084 2,187 33225 Sep 3,759 4,029 1,619 1,953 2,946 2,468 3,739 7,146 4,864 6,465 3,139 4,522 4,535 APA16/H3 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 44 54 29 82 17 35 80 52 92 19 78 Nov 58. 3. 69. 68. 47. 35. 74. 80. 83. 37. 30. 73. ot 60 778. 59. 09 09 68 96 64 82 25 01 58 72 59 60 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 a1 Jan 40. 26. 30. 19; 23. 20. 30. 48. 335 20. is 353 30. 376. 28. 02 03 94 21 63 62 on 55 33 01 98 48 26 57 97 Feb Mar 28.94 20.01 16.24 16.02 25.28 26.03 14.97 16.02 18.41 19.83 18.07. 19.03 20.85 19.52 3%..20: 35.35 25.93 .:27.31 18.07 .. :20.'01 16.24 17.98 25.11. °:26:03 25.28 25.84 290.61 288.98 22: 00%, 22.20 The Average of 2,084,940 TABLE III-4 BUCKLAND RIVER ACRE-FEET X 1000 Apr 23. 18. 25; 22. 19. 17. 17. 31. 25. 21. 19. 25. 23. 290. 22. 23 41 19 45 72 40 40 96 30 56 36 48 34 80 37 May 78. 302. 100. Si, 342. 498. 420. 605. 189. 335. 213. 251. 260. 3,930. 300. 95 97 42 73 83 544. A 7183 598. Acre-Feet per year = annual average 52 327 223 -32 . 23 - 58 oad 54 -42 -89 “ol -89 -56 a7 32 Jul 344. 619. 368. 104. 143. 292. 2u2. 387. 261. 435. 221. 170. 324. 3,887. 299. 16 88 16 78 69 72 68 37 54 25 89 64 76 52 04 Aug 223. 479. 162. 250. 321, 162. 227. 795. 392. 195. 189. 134. 197. 3,733. 287. flow of 2880 cfs. 73 81 60 55 75 47 72 42 40 92 30 24 83 74 21 Sep 223. 239. 96. 116. 174. 146. 222. 424. 288. 384. 186. 268. 269. 3,040. 233. 28 32 17 01 99 60 10 47 92 02 46 61 38 33 87 Total 2,004. 3,142. 2,267. 1,375. 1,465. 2,168. 2,131. 3,507. 2,010. 2,064. 1,427. 1,715. 1,824. 27,104. 2,084. 69 25 31 98 64 28 30 84 18 15 35 12 10 19 94 AREA-ACRES x 1,000 25 20 5 10 5 AVE. EL. 136 ~ a dv Oz6 c6l 2 MIN. WS 118 — 4334—NOILVA313 °0 50 100 150 200 250 300 350 400 450 500 CAPACIT Y- ACRE-FEET x 10,000 BUCKLAND RIVER AREA-CAPACITY CURVE FIGURE IT - 6 Section III - Electric Energy Resources and Conversion Technologies b) qd) apal8/c Geology: The proposed damsite would be located in tertiary basalt which apparently covers cretaceous graywacke and conglomerate. Most of the proposed reservoir area is covered with quaternary unconsolidated sediments. Suitability of the basalt as basement rock for a water reservoir would have to be determined in a field investi- gation. 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 Eschholtz 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. Cost Estimate: The estimated cost of constructing the Project is given in Table III-5, which presents a summary of the direct construction cost and an estimate of the total capital investment, using recommended FERC account numbers. The estimate is based on the following criteria: e 1980 construction costs e It was assumed that construction would start in 1983, and continue through the three-year period 1983-1985, with power coming on line in January 1986. e Interest charges on cash disbursements during con- struction period are included. They are based on an interest rate of 9 per cent per year. e An allowance for inflation is included, based on an inflation rate of 9 per cent per year to 1984, 4% thereafter, and the construction period as stated above. III - 21 APA16/G1 TABLE III-5 BUCKLAND RIVER HYDROELECTRIC PROJECT COST ESTIMATE SUMMARY STAGE I: 2 x 10,000 kW FERC 1980 - $ x 1,000 Acct. First Year Second Year Third Year TOTAL HYDRAULIC PRODUCTION PLANT 331 Structures & Improvements .11 Powerhouse 1,200 1,200 2,400 .12 Tailrace 250 250 .13 Operator's Cottages 400 400 TOTAL ACCOUNT 331 3,050 332 Reservoirs, Dams and Waterways .11 Dam 8,287 8,287 16,574 .12 Intake Structure 150 150 .13 Penstock 1,350 1,350 2,700 .14 Spillway 3,600 3,600 TOTAL ACCOUNT 332 23,024 333 Waterwheels, Turbines, and Generators Turbines and Appurtenances 1,407 1,407 2,814 Generators and Accessories 1,719 1,719 3,438 TOTAL ACCOUNT 333 6,252 334 Accessory Electric Equipment 900 900 335 Miscellaneous Plant Equipment 250 250 336 Roads, Railroads and Bridges 2,600 2,600 Mob & Demob 2,000 2,000 2,000 6,000 Total Hydraulic Production Plant: 42,076 TRANSMISSION PLANT 350 Land and Land Rights - 98 miles 490 490 352 Structures and Improvements 500 500 353 Station Equipment 750 750 1,500 355 Poles and Fixtures - 98 miles 6,566 6,566 13,132 356 Overhead Conductor and Devices 3 x 98 miles 3,275 3,275 6,550 Mob and Demob 2,000 2,000 4,000 Total Transmission Plant: 26,172 DIRECT CONSTRUCTION COST 17,127 28 ,804 22,317 68,248 Contingency @ 15% 2,569 4,321 3,347 10,237 Engineering and Constr. Supervison @ 15% 2,954 4,969 3,850 T1703 TOTAL CONSTRUCTION COST 22,650 38 ,094 29,514 90,258 Allowance for inflation (8% to 1984, 4% thereafter) 5,882 13,732 12,246 31,860 Interest during construction 9% _ 2,568 7,232 10,990 20,790 TOTAL CAPITAL INVESTMENT 31,100 59,058 52,750 142,908 trr an Section III - Electric Energy Resources and Conversion Technologies f) g) apal8/c Power Production: The first stage of development with two 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. Estimated prime and secondary energy delivered at Kotzebue in Stage I development is 85,000 MWh and 52,000 MWh respectively. The second stage of development would deliver 137,000 MWh of prime energy. Environmental and Other Concerns: Preliminary investiga- tions indicate that the Buckland River supports salmon, char, pike, whitefish, burbot and grayling populations. The valley is also utilized by caribou and moose. The reservoir created by a dam at the proposed location would jinundate this area and destroy part of the mammal habitat as well as spawning and rearing grounds for the fish. (See Appendix E-1.) 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 indicates 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. Land Status: The damsite is located within a village withdrawal and most of the reservoir within state selec- ted 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. Lela ches Section III - Electric Energy Resources and Conversion Technologies h) apal8/c Alternate Development Plan: The cost estimates in Table III-5 show that approximately 38% of the total cost of construction are allocated to the transmission line. If single phase, low frequency generation and trans- mission would be considered, it is estimated that the transmission costs could be reduced to: 1980-$(1000s) Station Equipment $ 2,500 133 kV line, 795 kCM ACSR (from Appendix A) 8,330 Conversion Equipment - 10,000 kW terminal (from Appendix A) 4,000 Land rights, etc. 990 TOTAL 15,820 This represents only 23% of the total direct costs. It is assumed that the generating equipment costs approx- imately the same as three phase equipment. Preliminary investigations into the availability of a. low frequency, single phase equipment, and b. phase and frequency conversion equipment indicate that Jananese or European firms are building similar equipment and are interested in supplying it for the relatively small scale applications under investigation in Alaska. III - 24 Section III - Electric Energy Resources and Conversion Technologist D. COAL RESOURCES Coal is a very appealing near-future alternative resource for power generation in the Kotzebue area. Four known coal provinces within reasonable economic distance of Kotzebue are discussed in the following text, as well as consideration of the vast North Slope deposits. The four areas, in descending order of current economic importance to Kotzebue, are (1) the Kugruk River deposits, (2) the deposits near Corwin Bluff, (3) those of the Point Hope area, and (4) the Kobuk occurrences (See Figure III-12 and III-13 at the end of this section). me Chicago Creek (Kugruk River) Coals -1 General Description Considering the information that is known about the several potential sources of coal near Kotzebue, the Kugruk River coals hold the most promise for immediate development. Although they are of low heat and high moisture content, their relatively great thickness and close proximity to Kotzebue overshadow these disadvantages. The Kugruk River deoposits are lignitic coals of late Cretaceous age. They are exposed in seams dipping from 45 to 70 degrees and in widths to 80 feet near the tributaries of Chicago, Reindeer, Montana, Mina, and Independence Creeks. The coals were once mined in the early 1900's from workings near Chicago and Reindeer Creek. These coals range in heat content from 6,200 to 6,800 Btu/lb, and average 30-35% in moisture content. Although it required nearly twice as much volume as the higher-quality imported coals, the Kugruk coals were found adequate to fire boilers of numerous placer gold mining operations in the area. An analysis of the coal from the Chicago Creek area is as follows: % Fixed Carbon 1922 Volatile Hydrocarbons 39.0 Moisture 33.8 Ash qo Sulfur 0.9 Heating value: 6,825 Btu/1b At Chicago Creek, the main seam strikes about N9°W and dips 45° to 53° westward. Between 1902 and 1908, Between 60,000 and 100,000 tons of coal were mined from a slope and crosscuts apal6/m Ill => 25 Section III - Electric Energy Resources and Conversion Technologist which extended over 300 feet underground. A similar but smaller-scale mining venture occurred at the George Wallin mine about 4 miles up the Kugruk River near Reindeer Creek. Between these two mines scattered exposures of coal have been noted and exploration at the Chicago Creek claim block indicated that the main seam was continuous for at least *% mile, at which point it was about 70 feet below the surface. The coal beds dip more steeply upstream from Chicage Creek, reaching 70° at the George Wallin mine. With little other information available, it seems likely that the coal beds should be relatively continuous along the eastern banks of the Kugruk. Since the coal beds that were exposed are from 50 to 80 feet in width, the potential amount of coal in the area is substantial. The Chicago Creek area is located within a village land withdrawal. -2 Mining A coal-fired steam generation plant will require about 20,000 tons of 6,800 Btu/lb lignite annually. Assuming that energy needs in Kotzebue develop as assumed in the power requirements forecast and that the minimum lifetime of the mining operation at Chicago Creek should be 25 years, more than 2,500,000 tons of coal will need to be proven before coal mining can be justified. This is equivalent to a seam with a mineable width of 30 feet, a mineable slope-depth of 500 feet, and a strike distance of 5,000 feet. From what is known of the main Chicago Creek seam, quantities of this magnitude are very likely. Preliminary estimates of the costs involved in mining and transporting such coals to Kotzebue has been undertaken to enable comparison to other resources, as well as to other coals (Appendix A). Coals at Chicago Creek could be developed in the following fashion: a) Initially an exploration program would be necessary to determine the overall feasibility of the operation and the most likely areas to be mined. Following this, a serious drilling program would be necessary to prove that the reserves were indeed adequate, and to determine their nature and depth. These two phases of exploration could be accomplished in a single season. b) Following exploration, a docking facility would need to be built near the mouth of the Kugruk, construction equipment brought in, and a road built from the beach to the mine site, a distance of approximately 15 miles. Permanent camp facilities would then need to be established. apal6/m TT = 26 Section III - Electric Energy Resources and Conversion Technologist c) Development of the mine would overlap with establishment of the camp. The mine itself would involve an inclined shaft (down dip) of up to 45° with a conveyor system. Crosscuts and drifts would extend along strike and adequate pillars would be left between levels to support the hanging wall. Most equipment would operate from electricity provided by a coal-fired generator. The coal would be conveyed directly from the mine into a beneficiating system which would probably include crushing, screening, and drying. A second scenario involves an open pit mine. Although some drilling and blasting have been included in the estimated costs, it is assumed that ripping will be possible in most of the sandy shales enclosing the coal. Both a scraper and a combination rock buggy and loader are included in equipment costs. d) An efficient though complex transportation system would need to be established during final mine development Phases. The coal would be trucked to the beach using three 20-cubic-yard end dumps operating most of the year. Stockpiled at the beach, the coal would then be conveyed onto barges during summertime, transported across Kotzebue Sound, unloaded by conveyor and transported to the generation facility. e) Preparation of this coal (removal of non-combustible components etc.) will need to be considered carefully. Drying of the coals, which will be frozen, will undoubtedly be the most difficult part. Waste heat from the primary generation facility could be used either at the mine mouth or in Kotzebue. Other alternatives may also be feasible. The costing figures listed in Appendix A are based on new equipment quotes from various Alaska dealers, and inflated values for certain underground machinery as quoted in Bottge's 1977 report on coal mining costs near Wainwright. Freight and transporation costs were estimated from conversations with experienced Arctic marine operators. Road construction, camp and mining development were roughly estimated based on current in-house projects with input from several engineers and con- struction managers. Mining methods and effective costs are hypothetical, as the actual deposits are not known. In general, costing was done conservatively at each stage so no contingency is added at the end. Exploration and drilling costs estimated from direct experience and mining are considered to be low due to the contingency costs involved which are difficult to assess. The strip mining cost estimates include a well padded inventory of heavy equipment and are therefore considered somewhat on the high side. apal6/m III - 27 Section III - Electric Energy Resources and Conversion Technologist For a volume of 20,000 - 100,000 ton per year the following costs are estimated: Underground Mining Annual operating & fixed cost $47.44/ton Transportation 20.50/ton $67.94/7ton Open Pit Minin Annual operating & fixed cost $41.04/ton Transportation 20.50/ton $61.54/ton Winter transport across the frozen Kotzebue Sound has been briefly investigated. Transportation costs of $78/ton make this alternative uneconomical. Environmental aspects of open pit mining have not been considered here. With the land rights in the hands of the regional native corporation (NANA), any development will require their consent. 2. Corwin Bluff Area -1 General Description While normally considered as part of the North Slope fields, the Corwin field is a physically distinct unit lying south of the main fields and just east of Cape Lisburne. These coals could be more easily mined and transported to Kotzebue than could the coals of the North Slope. Despite the fact that they are a long distance from Kotzebue and would face diffi- cult transporation problems, they are of high quality, of a continuous nature, and in large quantities. The deposits could justify much larger operations than would be required by Kotzebue's present generation needs. Between the Utukok River and Corwin Bluff areas, mineable coal beds are confined almost entirely to the Cretaceous Corwin Formation. The formation is made up of over 15,000 feet of shales, sandstones, and conglomerates. Although beds of bituminous coal and coaly shale are present throughout the formation, the coal beds are thickest and most abundant in the upper section of the inland areas and in the upper middle part of the type section at Corwin Bluff. The actual area known to be underlain by commercial coal beds in the district is greater than 200 square miles (Brooks, 1910). In the Corwin Bluff Cape Beaufort area, at least 60 bituminous coal beds ranging from 14 inches to 9 feet in thickness are exposed along the apal6/m II] =-28 Section III - Electric Energy Resources and Conversion Technologist coast. The coal beds are greatest in number and in aggregate thickness in the seacliffs near Corwin Bluff itself. The old Corwin and Thetis mines were located 28 and 36 miles east of Cape Lisburne, respectively. These mines operated in the late 1800's to serve whaling ships and later during the gold rush shipments of coal were sent to Nome. More recently, occasional use has been made of the Corwin mine to supply Point Lay. Analysis of the coal from these two mine areas is as follows: Coal 1-3/8 miles W Thetis Mine Coal of Corwin Bluff (from highest seam) % % Fixed Carbon 40.80 46.27 Volatile Hydrocarbons 41.30 13°61 Moisture 13555) 35.60 Ash 4.33 4.52 Sulfur -40 i 100.00 100.00 Coke: none none Color of Ash: gray light brown Fuel Ratio: 0.96 1.30 Average heating value from these coals is about 13,600 Btu/1b. -2 Mining The mining of the Corwin Bluff coals would probably have to be underground. The coals occupy a synclinal basin. Near the central portion of the basin a shaft could be sunk to about 300 feet where the upper coals could be mined. From this point the seams could be mined along gently up-dipping slopes. Mining would be more expensive than at Chicago Creek for a small-scale mine, but could be considerably cheaper for a larger operation. Transportation of the coals would be a formidable task. The coastal waters are as shallow as 10 feet, 2 miles offshore, and there is no protection from strong northerly gales that blow in from the Arctic Ocean. If a barge and lighter system were used to transport the coals during the short ice-free season (July through mid-October), they would still be faced with these uncertain, potentially disastrous weather conditions. The estimated cost to transport 60,000 tons of coal to Kotzebue during a 76-day period would be about 1.5 million dollars, a cost of $25/ton. The cost of the project would not justify construction of over 200 miles of overland and/or ice road. apal6/m III - 29 Section III - Electric Energy Resources and Conversion Technologist 3. Point Hope Deposits The Point Hope deposits are another potential source of coal for Kotzebue. The Point Hope coal deposits are exposed along the foothills of the Lisburne Hills between Cape Dyer and Cape Thomp- son. Low-volatile bituminous coals (average 14,000 Btu/1b) occur in a highly deformed section of Mississippian-aged rocks, which are distinct and unassociated with the Corwin Bluff and North Slope provinces. The extent and distribution of the coals is not known, partly because prospecting has been discouraged by the highly folded and faulted nature of the rocks. Identified beds are gen- erally less than 4 feet in thickness and the coals are crumpled and broken. Analysis of coal collected 1 mile South of Cape Dyer gave the following results (in percentages): % Fixed Carbon 79.86 Volatile Hydrocarbons 15.62 Moisture een Ash 2.81 100.00 Coke: none Color of Ash: light brown Fuel Ratio: 00 Further exploration could turn up mineable areas in the Point Hope region, but in the interim these deposits are probably not an economic alternative for Kotzebue. 4. Kobuk River The Kobuk River area between Kiana and Shungnak is another unexplored area that may prove to have economic reserves in the future. Bituminous and subbituminous coal occurences have been noted at several localities exposed in the riverbanks of the Kobuk. Most of these occurrences are beds less that 2 feet in thickness with variable dips. Although further exploration may be warranted, the coals cannot be considered as an alternative resource for Kotzebue at this time. 5. Utilization of Coal Resources In this study, the use of coal for electrical generation is considered in two modes: direct boiler firing for steam electric generation and conversion to gas in a synthetic fuel facility for firing in a modified gas turbine unit. apal6/m III - 30 Section III - Electric Energy Resources and Conversion Technologist Steam plants account for the majority of electrical generation in the United States today. Although steam plants can accomodate a wide range of loads, U.S. economies of scale indicate that the cost per unit increases sharply in sizes below about 50 MWe. It should be noted that European coal-steam generation units are employed in the less than 10 MWe range. Figure III-7 is a simplified schematic of a coal steam plant. Current environmental regulations regarding sulfur dioxide emissions from conventional coal-steam plants generally require abatement processes which significantly increase the cost of such plants. An economic solution to this problem may be in waste heat capture or the cogeneration of steam (for heating and process purposes) and electrical power. Such heat could well be a saleable commodity. 1980 installed cost for a 5 MW coal steam plant is estimated in the Appendix as $2,200/kW. While coal could be gasified in a so-called synthetic fuel plant, the state of the art and associated economics make it appear doubtful that a fuel facility would be constructed solely for the purpose of providing fuel for limited electrical generation. (Reference Jobs and Power). The consequent evaluation is based on our own resource inventory and state of the art information. Further information will come from a demonstration project conducted by Marks and Galliett for the Alaska Village Electric Cooperative (AVEC) currently in process. So called low-Btu gas (100-200 Btu/cf) can be manufactured from coal and biomass in commercially available gasification equipment. Furthermore, some types of gasifiers produce more steam than they require for gasifying coal; use of this excess steam for heating and process operations obviously results in total fuel cost savings. Suitable low-Btu gasifiers are air blown units of the fixed bed type operating at atmospheric pressure. These units are "small": daily production is less than 2 billion Btu of hot, raw gas. Depending on the feedstock and application, this gas may or may not be cleaned prior to combustion. (Reference Schweiger). Figures III-8 and III-9 show the relative flow complexity of a clean fuel gas facility. (Ref. Energy Technology Handbook. ) Low-Btu gas is economically attractive only if produced near its usage - nominally, within a half mile. The cost of the gas in the "lower 48" typically ranges from about $2.50 to $4.00 per million Btu under most conditions. Actual cost at a specific location such as Kotzebue is influenced by the price of coal (about half the cost), the load factor, the gas cleanup requirements for specific process use, and clean air requirements. (Reference Schweiger). apal6/m TTIS==31; STEAM HEADER FEED pump (0) DIAGRAM OF RUDIMENTARY STEAM POWER PLANT FIGURE II -7 III - 32 TRUCK RAMP WOOD PILE HAMMERMILL SILO STORAGE WOOD GASIFICATION eee, —> FUEL GAS (TO BOILER OR GAS TURBINE) \J ASH DISPOSAL FIGURE IT-8 -1H(S) Generator SATURATOR COAL FEEDWATER ———_— at STEAM CLEAN FUEL GAS FROM COAL FOR POWER GENERATION | SS FIGURE II -9 III - 33 EXHAUST H2S GAS Section III - Electric Energy Resources and Conversion Technologist It should be noted that the problems associated with burning large volumes of low-Btu gas in gas turbines are more difficult to solve than burning this gas in boilers because of size limits on turbine combustion chambers. 1980 installed capital cost of a 5 MW gasifier turbine plant is estimated at $2,500/kW. (See Appendix A for detailed cost estimate). apal6/m III - 34 Section III - Electric Energy Resources and Conversion Technologist E. WOOD RESOURCE Wood is a potential fuel for either direct boiler firing for steam or for gasification. Although dry wood (at about 8000 Btu/pound) has about the same potential heat content as much of Alaska's coal, most wood is sufficiently moist to reduce this heat value by 40 to 50 percent. In addition to the moisture content, the relative volume to weight ratio of wood is disadvantageous as compared to coal, with consequent increased material handling requirements. Also, as compared to coal, the fuel gathering and transportation processes result in the expenditure of significantly greater amounts of energy. (Reference Jobs and Power). Wood, a relatively clean burning fuel, is suitable for smaller steam power plants than is coal. As these smaller sized plants are more suitable to much of Alaska's power development needs, this source of energy cannot be overlooked in the "big picture." Pres- ently demonstrated gasifiers also appear to be working better with wood than with coal Some bottomland spruce-poplar occurs along major rivers in the Kotzebue region and could be transported by water. Recent scien- tific studies ("ground plots") on wood availability were performed by the United States Forest Service near Ambler, Kiana, Kobuk, and Noatak. Many areas around Ambler indicated yields of 1,500 cubic feet (43,500 lbs dry!) of wood per acre, Kobuk had many areas at about 3,000 cubic feet (87,000 lbs dry) per acre, and Noatak had 800 to 1,200 cubic feet (23,200 to 34,800 lbs dry) per acre, although there were very large areas literally covered with trees. (Reference Mauneluk Report October 1979). The mass of wood required for a 5 MW plant is on the order of 60x10® pounds of dry wood per year ( 2.1x10® cubic feet or 1,700 to 2,600 acres) (Ref: Fogleman) and the projected difficulty in gathering and transporting such amounts has ruled out wood electric generation from further study for Kotzebue at this time. 1 Density of poplar is 29 lbs/ft® with 12% moisture content of resource: Marks). apal6/n III - 35 Section III - Electric Energy Resources and Conversion Technologist F. WIND Wind energy can make a significant contribution to Alaska's energy needs as it is theoretically possible to harness as much as 60 percent of the energy in the wind. Although wind energy has a long history of small scale use, extensive use in Alaska today is restricted by the following, among others: e Limitations in construction make existing systems relatively unsuitable for a climate such as Kotzebue, where windspeeds up to 107 m.p.h. and temperatures as low as -52°F have been recorded; e WECS are expensive and their relatively short life expectancy makes competition with other resources difficult; e Accurate site specific wind data are required to determine the type and size of wind turbine to be analyzed for feasibility; and e Energy storage equipment or firm generating equipment have to be provided for periods of little or no wind; Mean monthly wind speeds as well as potential power and energy output for three sizes of WECS for Kotzebue are contained in Table III-6 following. (Reference: Selkregg). ECS kwh 33,629 26 ,813 26 ,635 26 ,784 20,906 24,768 28 , 346 29.686 28 ,080 29 , 388 30,960 27,677 333,672 TABLE III-6 WECS POWER & ENERGY OUTPUT Wind Speed 1.5 kW WECS 15 kW WECS 100 kW W Month mi/hr kW ‘kWh kW kWh kW Jan 14.4 8 595 4.4 3,274 45.2 Feb 13.2 .65 437 3.7 2,486 39.9 Mar 12.3 «52 387 3.2 2,381 35.8 Apr 12.6 ~55 396 3.4 2,448 37.2 May 10.7 3 223 2.4 1,786 28.1 June 12 7 360 3 2,160 34.4 July 12.8 -58 432 3.5 2,604 38.1 Aug 13.2 .65 484 a7 2,753 39.9 Sept 13 =O 432 3.6 2,592 39 Oct 13e1 -63 469 3.6 2,678 39.5 Nov 13.9 75 540 4.1 2,952 43 Dec 12.6 .55 409 3.4 2,530 37:2 Annual Average 12.8 - 58 5,164 3.5 30,644 38.1 or Total apal6/n III - 36 Section III - Electric Energy Resources and Conversion Technologist The power output has been calculated as shown in Appendix B-2 for WECS mounted at the height the windspeeds have been recorded (assumed to be 20-30'). Power output for the 1.5 kW WECS has been taken from manufacturer's performance data. Busbar energy costs of wind energy conversion systems (WECS) depend on environmental and application parameters as well as the type of machine. Typical current forecasts run 40 to 80 mills/kWh for intermediate (100-600 kW) and large size (over 600 kW) units. However, energy costs for small (less than 100 kW) units can run two to three times the costs of intermediate and large scale units. Typical capital costs for these small commercial units ranges from $2 ,000-$5,000/rated kW (Reference Kilar); capital costs for Kotzebue are estimated to be $3 - 7,000/rated kW. (See Appendix A for details. ) Wind power generation suffers from the fluctuating nature of the wind itself and is best applied (as in the case of the Kotzebue region) in a fuel saver mode - the full instantaneous WECS output jis used to supply the load while displacing utility supplied power from other sources. A more meaningful comparison of wind energy usage can be made by estimating diesel fuel saved at 13 kWh/gallon generating effici- ency, if the WECS power output would replace energy otherwise generated in the Kotzebue power plant. Table III-7 summarizes these savings for the three WECS previously described. Table III-7 . FUEL SAVINGS WITH WECS Annual Annual Fuel WECS MWh Savings/Gallon rated kW (100% utiliz.) (13 _kWh/gal) 1.5 5.16 397 Se 30.64 Pane 100. 333.67 25,667 The following graph (Figure III-10) shows the annual $-amounts saved for various fuel unit costs and annual costs for various WECS, assuming 100% utilization, 15-year life expectancy and a 15-year loan with 7% or 9% interest. It should be noted that the stated life expectancy and utilization percentage are extremely optimistic at this time, and that none of the investigated machines have been in successful operation in Alaska for more than a few months (1.5 and 15 kW). A 100 kW system has not been operated in the state at all. apal6/n SSS 7 ANNUAL FUEL COSTS SAVINGS (9) 100 100 KW WECS 15 KW WECS oA 15 KW WECS B ANNUAL 1.5 KWWECS GS ANNUAL COSTS T% &I% 1.5 KW WECS ANNUAL FUEL COSTS SAVINGS USING WIND ENERGY 2.— 3.- 4.- FUEL COSTS $/GAL. III -- 38 5.- FIGURE I-10 Section III - Electric Energy Resources and Conversion Technologist G. GEOTHERMAL RESOURCE The possibility of utilizing geothermal energy for direct genera- tion of electric power is very remote for Kotzebue with presently known information. The possibility of using hot water for heating and other needs which would displace electrical power is much stronger. This viewpoint is based primarily on information obtained from a stratigraphic test well placed on Nimiuk Point about 15 miles south of Kotzebue. The well indicated a bottom hole temperature of 162°F (72°C) at 6,300 feet. This is an unusually high geothermal gradient and, depending on the size of the heat reservoir and the natural circulation of fluids within the reservoir, a well system might be developed which could deliver a substantial amount of hot water heat to Kotzebue. It seems worthwhile that a careful analysis be made of the possible heat content of basement rocks at Kotzebue, the heat losses involved in delivery, the potential markets, and the dollar cost of developing the system. An exploration well such as the one at Nimiuk Point would probably cost in the neighborhood of $600,000 to $800,000. Hot springs are known at several areas within 100 miles or so of Kotzebue, the closest being one near Kiana, approximtely 50 miles away. Serpentine Hot springs, Pilgrim Hot Springs, and the springs of the Purcell Mountains area are increasingly further distant. None of these areas show promise as far as direct electrical generation. Transmission of the heat itself is also out of the question. Their presence, however, does indicate the possibility of potential geothermal energy near Kotzebue. Geothermal hot water does offer the possibility of displacement of diesel for heating purposes in Kotzebue. Geothermal flows to displace diesel oi] are indicated in Table III-8 based on fuel oi] heating value of 138,000 Btu/gallon, conversion of diesel fuel to heat efficiency of 80 percent, and hot water heat content of 1 Btu/ pound/degree F at 8.33 pounds/gallon. Kotzebue's present annual residential heat load is estimated to be 91x10® Btu (See Section IV.B for details). This represents the use of 825,000 gallons of diesel fuel (138,000 Btu/gallon, 80% furnace efficiency). The expenditures for home heating of $1 per gallon amount then to $825,000 per year. If a geothermal well at a flow rate of 231 to 1,165 gallons per minute and a discharge temperature of 170°F can be found, the investment of $600,000 to $800,000 into a test well can be recovered within one year. Investments required for the heat distribution system and conversions in the individual houses are not accounted for in this rough comparison. There is not enough information available at this time to assess the probability of geothermal potential of this magnitude near Kotzebue. apal6/o PET 39 Section III - Electric Energy Resources and Conversion Technologist TABLE III-8 GEOTHERMAL EQUIVALENT OF FUEL OIL FOR HEATING Diesel Required Geothermal Flow, Average Annual Gallons/Minute* - Fluid Temperature Out, Annual Gallons 150 120 100 80 100 <1 <1 <1 <1 500 <1 <1 <1 <1 1,000 1.26 <1 <1 <1 5,000 6.30 2.52 1.80 1.40 10,000 12.60 5.04 3.60 2.80 50,000 63.0 25.2 18.0 14.0 100,000 126.0 50.4 36.0 28.0 * Based on 170°F fluid temperature in @ 100% availability. The nearest area of “prospectively valuable for geothermal steam" is nearly 70 miles away (Reference Conwell). The alternative of geothermal power generation for Kotzebue is apparently not viable at this time. Furthermore, while small (<100 kW) organic cycle geothermal generation is a small scale (as opposed to utility) possibility, the current state of the art for flashed steam plants (Figure III-11) indicates a minimum economic plant size of about 35 MW, far too big for Kotzebue. Consequently, the geothermal power alternative is not considered further in this study. H. OIL AND GAS Oil and gas can be converted to electricity by diesel generation, gas turbine generation, and firing in a boiler for steam-electric generation. These conversion processes have been discussed in previous sections. Kotzebue is straddled by two potential oi] bearing geologic struc- tures, Hope Province and Kotzebue Basin. Although some. exploratory efforts have proceeded at a relatively slow pace, it should be noted that the presence of such geologic structures does not mean that hydrocarbons are present in commercial quantities. Until a significant discovery of recoverable hydrocarbons is made, the construction, development, and production phases of oi] development cannot be assured. (Reference: Land Use Plan). Locally produced oi] and gas, then, are not considered further as viable energy resource alternatives for purposes of this study. apal6/o III - 40 TURBINE - GENERATOR DISTRIBUTION COOLING TOWER MAKEUP WATER FLASH VESSEL DIRECT CONTACT CONDENSER FROM PRODUCTION WELLS GEOTHERMAL POWER PRODUCTION BY THE FLASHED STEAM PROCESS FIGURE IT - |! Section III - Electric Energy Resources and Conversion Technologist I. OTHER RESOURCES For the purposes of this study, the following are classified as "other" resources: solar, waste conversion, peat, biogas genera- tion, waste heat capture, transmission interties, and conservation. aL Solar The economics of solar energy for electrical power production are typically not competitive with more conventional energy sources. In addition, the lack of sun during the winter months of peak energy demand is in itself a reason for dis- missing this option for purposes of this study. While the extent of potential solar use needs further site specific study, some direct (non-electric) applications appear to have local merit: passive solar heating of homes, solar water heating, and solar commercial use as, for example, in can- neries. Such use could result in diesel fuel savings in modes similar to those previously discussed. Generating electricity directly from the sun (with no inter- mediate thermal conversion) depends on the photovoltaic effect; this effect occurs when light impinges upon certain light sensitive materials and creates an electric current. So called solar cells are the basic units that accomplish this direct electrical generation. In practice, 14 percent of the incident solar energy is converted to electrical energy in the most efficient solar cells mass produced to date. (Reference DOE). A 20 by 30 foot panel of solar cells, operating to 10% effi- ciency and with a peak output of 5,000 watts at mid-day in the northeastern continental United States, for example, would produce an average of over 1 kW for the entire year. Despite the promise of photvoltaic cells, economics remain a serious barrier to widespread use. Based on a 1980 estimated cost of $10 to $20 per peak watt, the 1 kW average preduction system described above would cost $50,000 to $100,000. Such costs make direct solar conversion unattractive except in very remote applications of 10 to 100 watts. (Reference DOE). It should be noted that snow loading at a site like Kotzebue could render even a cost competitive solar cel] array unwork- able; climatic conditions pose dramatic freeze up problems for solar thermal collection and distribution systems. apal6/o III - 42 Section III - Electric Energy Resources and Conversion Technologist ee Waste Conversion While refuse (waste) can be used as an alternate fuel, large quantities are required on a continuous basis to justify the large capital investment for an economically sized facility. As only the Anchorage area approaches the production quanti- ties required, this option is also dismissed for Kotzebue. (Reference: Jobs and Power. ) 3; Peat Peat is an early stage in the transformation of vegetation to coal and results from the partial decomposition and disinte- gration of plant remains in the absence of air. Peat is generally formed in water bogs, swamps, and marsh lands. Generally, peat is low in nitrogen, sulfur, and ash. Although peat is used as fuel in many countries, use of higher heat content fuels in the United States has pretty much kept peat out of the energy market. Very little is known about existing peat deposits in Alaska. A study to estimate the Alaska resource potential is presently being performed for the State of Alaska, Division of Energy and Power Development. Undrained bog peat usually contains between 92 and 95 percent moisture, but moisture is reduced to about 25 to 50 percent when peat is harvested (by large earthmoving equipment) and air dried. At these reduced moisture levels, the bulk density of the resulting peat is about 15 to 25 pounds/cubic foot and its heat value is approximately 6,200 Btu/pound. If peat resources can be verified in the Kotzebue area and if utilization systems presently under development prove economical, peat could be an alternate fuel for Kotzebue. With the estimated heat contents of the peat, reserves in the order of magnitude of 330x10® Cu.Ft. (dry) would have to be verified to allow supply of the projected electric energy and heating requirements for the next 25 years!. Expenditures for fuel oi] used for heating and electric energy generation in 1980 are estimated 1 91x10° Btu/year heating in 1980 at 80% fuel efficiency plus 1.71x1011! Btu/year electric energy generation in 1980 at 20% fuel efficiency = 2.62x10!! Btu/year (net) or 2.85x101! Btu/year (gross) with an annual growth of 10% results in 3.1x10!% Btu or 330x10® Cu.Ft. for 25 years. apal6/o III - 43 Section III - Electric Energy Resources and Conversion Technologist at $1,804,000. If peat can be found at similar distances as the Chicago Creek coal and can be mined and transported at equivalent costs or less, utilization can be economically feasible. Reconnaissance level investigations to verify existence and availability appear to be warranted. Extensive investigations of the appropriate mining technique and its effect on permafrost areas have to be undertaken. 4. Biogas Biogas (two-thirds methane) can be produced from Kotzebue's sewage system waste. In a biogas generation system, heat is used to promote elevated temperature anaerobic bacterial digestive action of organic material. The decomposition of organic matter in the absence of oxygen is called anaerobic fermentation. Anaerobic fermentation of organic products results in methane, carbon dioxide, hydrogen, traces of other gases, and the production of some heat. The residue remaining is hygienic, rich in nutrients, and high in nitrogen. Potentially damaging germs are killed by the absence of oxygen during the fermentation process. (Reference: Singh). The biogas producing digestive activities are optimal in two temperature ranges: 85°-105° and 120°-140°F, although digestion will occur from freezing to 156°F. Fermentation, however, is less stable in the higher of these two ranges and, consequently, the biogas units should be designed to be maintained in the lower optimal range. (Reference: Singh) The key element in the biogas process is the heated, enclosed biomass digester tank. These tanks are sealed off from the atmosphere (particularly oxygen) and have provisions for raw material inflow, gas outflow, and organic residue outflow. Based on a population of 2,400, an average human waste of 3 pounds/day, 11% solids in that waste, 84% of solids being volatile (gas producing), production of 5 cubic feet of biogas at 600 Btu/cubic foot per pound of volatile solids, Kotzebue's theoretical biogas energy production is about 2 million Btu/day, equivalent to a heat content of 14.5 gallons of diesel per day. 5. Waste Heat Waste heat capture, while not a fuel for generation, can provide savings in overall fuel use. This subject will be discussed in Section IV in detail. apal6/o III - 44 Section III - Electric Energy Resources and Conversion Technologist 6. Transmission Interties Electrical interconnection of several small communities to form a larger system can be considered to be a form of conser- vation even when diesel generation is used throughout. This effect is due to the higher conversion efficiencies achieved in larger generating plants compared to small isolated systems: System Efficiency > 1000 kW 12-14 kWh/gal < 300 kW 8-10 kWh/gal < 10 kW 4- 5 kWh/gal Kotzebue's location on the Baldwin Peninsula, however, would require transmission lines of more than 80 miles in length to interconnect any small community to this larger system. In this case the line construction costs are far greater than possible fuel savings could afford. Interties have therefore been considered only for the case of the Buckland River Hydro- electric Power Development. The villages which are within a distance from the project or the transmission line to Kotzebue that would allow the intertie by Single Wire Ground Return Lines (See Appendix B-3 and B-4 for details) and the estimated construction cost are listed in the following Table III-9 and shown on Figure III-12 at the end of this section. Demonstration projects utilizing this type of transmission are presently under contract with the State of Alaska, Division of Energy and Power Development. If proven technically and economically feasible, this type of construction holds great promise for providing less costly electric energy to small communities, which have to rely on diesel generation at this time. apal6/o III - 45 Section III - Electric Energy Resources and Conversion Technologist TABLE III-9 SINGLE WIRE GROUND RETURN TRANSMISSION 1995- Distance Demand Line Voltage Line Cost Location (miles) (kW) (kV) (1980-$) Buckland River Plant to: Candle 31 144 40 511,500 Deering + 28 228 40 462,000 to: Buckland 8 228 14.4 132,000 Reindeer Station to: Selawik 41 361 40 676,500 TOTAL: 108 961 a 1,782,000 Summary Cost Estimate Total Line Cost (108 miles @ $16,500) 1,782,000 Terminals (7 @ $39,000) 273,000 Labor in difficult terrain (50 miles @ $4,500) 225,000 River Crossings, etc. (10 @ $10,300) 103,000 TOTAL COST (1980-$): $2,383,000 apal6/o III - 46 Section III - Electric Energy Resources and Conversion Technologist Te Conservation The average monthly electric energy use by a residential consumer (household) has been 430 kWh for the last two years. This usage indicates that the average residential consumer operates the common appliances such as refrigerators, freezers, radio, TV, clothes-washer, etc. in addition to lighting. Electric stoves, waterheaters and comfort heating do not appear to be used to any extent. For comparison, the average use for the same consumer category in Southcentral Alaska has been 1,284 kWh/month in 1978. This indicates that the electric energy use in Kotzebue is still at a rather low level and conservation of electric energy appears to be possible only in form of "no increase" rather than a reduction in individual use. With a population of approximately 2,500 people within the Kotzebue city limits and an average of 460 residential consumers, the population/consumer ratio is larger than 5, indicating relatively large family sizes, probably with more than one generation living together in one residence. As additional housing becomes available a separation of genera- tions is conceivable leading to more residential users but not necessarily to a reduction in individual energy use. apal6/o a7 LEGEND [H] HYDROELECTRIC POWER POTENTIAL @© GEOTHERMAL POTENTIAL (HOT OR WARM SPRINGS OR WELLS @D COAL RESOURCE ieee TRANSMISSION LINE (38 KV, 30 40 7 — TRANSMISSION LINE | 40KV MAX. swiKe,, & aT Awe te <o J eo ( See Espenberg te 3 of AD Camille Cones TAVA 2 2 b x-.Goslifg Cohe Sp cork Sa ee Pc g abi ‘ ; bn Point Chomisso Island ‘BL oS 10 Niel ORM gavin o Ts ges! KOTZEBUE ELECTRIC ENERGY RESOURCES FIGURE II - 12 TIT - 48 Wee KOTZEBUE ELECTRIC ENERGY RESOURCES FIGURE III - 13 BLUFFE]. “FCORWINGE “toe Cape Seppings ENTIAL (HOT OR WARM SPRINGS) OWER POTENTIAL f HYDROELECTRIC © GEOTHERMAL PO @D coAL RESOURCE POINT HOPE SECTION IV ANALYSIS OF MOST VIABLE ALTERNATE DEVELOPMENT PLANS SECTION IV ANALYSIS OF MOST VIABLE ALTERNATE DEVELOPMENT PLANS A. METHOD AND PARAMETERS Investigations of several resources (Section III) indicate that several of the alternative energy options under consideration in this study are either in an experimental/developmental stage or sufficient data are not available upon which to base positive recommendations for system development programs. In this study a somewhat general approach to future development was therefore taken. The methodology utilized to accomplish this approach included the following major activities: e Power and energy requirements were identified. e An inventory of resources for electrical energy generation was made, identifying and evaluating them on an order of magnitude scale, taking into account technical, economic, administrative, and environmental aspects. e From the energy resources identified hydroelectric and coal resources were selected for more detailed analysis in comparison to the baseline case of diesel generation. Available technology and perliminary cost estimates established for these resources indicate that development could be economically feasible. The option of waste heat recovery from diesel and coal resource generation was also selected for further analysis. ° A more detailed analysis of these selected alternatives was performed including economic evaluation through 1995 and discussion of environmental, land use, and safety aspects. e Recommendations are offered for future activities to more accurately identify the engineering and economic feasibility of the selected alternatives and to facilitate selection of the most promising alternative. B. ALTERNATES EVALUATED Based on technical and economic constraints described in previous sections, the following alternates were selected for detailed economic evaluation: the baseline case of diesel power generation; diesel generation with waste heat recovery; hydroelectric potential; coal utilization via steam electric generation and via gasification; transmission interties to smal] communities. apa2/e Iv-1 Section IV - Analysis of Most Viable Alternate Development Plans The development scenarios discussed following are necessarily speculative. They implicitly contain various assumptions regarding resource availabilities, development costs, market prices, and technology state of the art. They are based on the data available for this study and the engineering experience with other projects in Alaska. The scenarios have been presented in a way which allows easy adjustment of parameters used for the analyses as more specific data become available. 1. Diesel This scenario assumes continuation of diesel generation exclu- sively. Figure IV-1 following indicates the requirements for addition of diesel generating units in 1000 kW increments. As is shown, these new units are projected to go on line in 1984, 1987, 1988, 1990, 1992, and a 2000 kW unit 1993 to reach a total firm capacity of 10,800 kW by 1995. In reality the utility would add generation capacity in larger increments when the system demand increases above 3-5,000 kW. For the purpose of this evaluation the installations as shown are within the grade of accuracy required. 2 Diesel with Waste Heat Recovery Table IV-2, "Waste Heat Availability", following indicates _recoverable waste heat for various unit sizes and heat rates (Btu/kWh) assuming that one-third of the fuel heat is recoverable. Kotzebue's annual residential heat load is estimated to be about 91x10° Btu, based on: the heating degree days indicated in Table IV-1; a "standard" 30 x 30 x 12.5 foot building; R-11 insulation (U factor = 0.09) four walls of 2"x4" construction on 16" centers; unheated attic with 4 inches of U factor .09 insulation; two 24" x 40" windows; and 2 air changes per hour. As can be seen from Table IV-2, a 5 MW generation plant gener- ating 35,040 MWh annually at a heat rate of 10,000 Btu/kWh (equivalent to 13.8 kWh per gallon of diesel fuel) could theoretically provide the present annual residential heat load of Kotzebue. The present generation however, is closer to 10,000 MWh/year and the available waste heat between 23-46 trillion Btus per year. Assuming that 80 percent of diesel fuel heat value of 138,000 Btu/gallon is usable as heat, the annual diesel fuel savings for heating of approximately 35x10® yearly Btu amount to 317,000 gallons Waste heat utilization, however, is not free, even though there may not actually be a direct charge for the heat. The equipment for utilizing this heat requires a sizeable capital investment and is feasible only when the cost for associated equipment is less than the cost of the fuel saved. apa2/e IVe- 2 a |_| | [| A 1000 70 72 74. 76 78 80 82 84 86 88 90 92 94 96 98 2000 DIESEL GENERATION CAPACITY-DEMAND (KOTZEBUE ) FIGURE IZ-| Section IV - Analysis of Most Viable Alternate Development Plans TABLE IV-1 HEATING DEGREE DAYS Heating Month Degree Days January 2,130 February 1,940 March 2,031 April 1,560 May 1,060 June 645 July 375 August 443 September 717 October 1,283 November 1,719 December 2,136 Total 16,039 SOURCES: Selkregg. TABLE IV-2 WASTE HEAT AVAILABILITY 10° BTU/YEAR AVAILABLE AT GENERATING EFFICIENCY 10,000 12,500 15,000 17,500 20,000 MWh/YEAR BTU/KWh BTU/KWh BTU/KWh BTU/KWh BTU/KWh 1 7,008 23.36 29.20 35.04 40.88 46.72 2 14,016 46.72 58.40 70.08 81.76 93.44 5 35,040 116.80 146.00 175.20 204.40 233.60 10 70,080 233.60 292.00 350.40 408.80 467.20 * Assumes 1/3 of input Btus recoverable for heating. apa2/e Iv - 4 Section IV - Analysis of Most Viable Alternate Development Plans Some cost factors for the hot water distribution system only are discussed in Appendix A. (Reference Waste Heat Capture). Should these cost factors appear attractive, this does not mean that the system should be constructed, as the cost of conversion to district heating for individual consumers is an important contribution to the total system cost, particularly if present heating is by forced air instead of hot water baseboard units. The present fuel savings would be approximately 317,000 gallons/year - at $1/gallon this calculates to $317,000. This amount plus portions of future years' savings could then be used to install a district heating system or reduce the costs for electric energy. It should be noted however, that this amount represents only $528 per household. It is doubtful that heating systems can be converted for this amount. It should be noted that Kotzebue has a quite successful on-going waste heat utilization program. The Kotzebue Electric Association has installed exhaust silencer/waste heat boilers on four of its generators. Three of these units, combined with use of generator jacket water provide heat to the city water system and the KEA office. Figure IV-2 shows this heat recovery system. Such a system could be expanded into a district heating system. 3° Hydroelectric Potential With the technical, environmental, institutional and econom- ical problems associated with hydroelectric powerplants in arctic climates, the Buckland River potential appears to be the most promising project. A detailed description of the project has been provided in Section III. If detailed tech- nical and environmental studies prove the project feasible and low interest loans can be obtained for the construction, this alternate electric energy source could replace the presently used diesel generation in Kotzebue. Capacity and Demand balance are shown graphically in Figure IV-3. Operation of this plant by 1986 with 2x10 MW generators producing 87,600 Mwh firm energy would place the existing Kotzebue Diesel plant in standby operation. Firm capacity would have to be maintained here, since with only one transmission line connecting the hydroplant to the load center, failure of this line would cause loss of the hydo power plant. TRANSMISSION TIES TO SMALL COMMUNITIES The hydroplant capacity can easily supply more electric energy than presently projected for Kotzebue. It has therefore been investigated whether small communities could be connected to the plant by single wire ground return lines (SWGR). The method has been described in Section III and Appendix B. With the energy requirements established in Section II, Table IV-3 summarizes the hydro capacity and the projected loads. apa2/e IV 5 TYPICAL FLOW RATE = 295 GPM JACKET - WATER & EXHAUST WASTE HEAT RECOVERY SYSTEM FIGURE IZ-2 IV - 6 + ENE Z FE AVAILABLE Ie REQUIRED 20000 | —_ RH 9900 L. 4 |_| = et es ae 6p00 ri | | 5p00 y =] | 4900 4_|_| 3200) T COINCIDENT KW DEMAND | , | 2000 | + | + pool ZS Yh ee 72 74 76 78 80 82 84 86 88 90 x2 94 96 98 2000 YEAR BUCKLAND RIVER HYDROELECTRIC POWER CAPACIT Y—- DEMAND (KOTZEBUE & 4 VILLAGES) FIGURE IZ -3 IV -7 Section IV - Analysis of Most Viable Alternate Development Plans TABLE IV-3 BUCKLAND RIVER PROJECT POWER & ENERGY CAPACITY/REQUIREMENTS BALANCE kW Annual MWh Location 1986 1990 1995 , 20,000 20,000 20,000 Buckland Capacity 85,000 1 85,000 1 85,000 1 i A 4,500 6,400 10,200 Kotzebue Requirement 32-750 32-250 51,050 A 174 198 228 Buckland Requirement 6B 608 B16 . 90 114 144 Candle Requirement 321 46 534 Deering Requirement 174 198 228 613 698 816 . : 265 308 361 Selawik Requirement 374 Ti T3027 5203 2 7218 2 11161 2 | sition 25271 35193 54543 Surplus 14797 12782 8,839 Buckland 59,729 49,807 30,457 oo 2 Plant bus minus 3% losses. Noncoincident. apa2/e IV- 8 Section IV - Analysis of Most Viable Alternate Development Plans The economic evaluation assumes that the maintenance costs for the tie-lines are part of the village power costs and that diesel standby power has to be maintained. The initial costs for the tie-lines are included in the economic evaluation of the Buckland River Hydroelectric power project. It is realized that the per unit costs of electric energy in Kotzebue benefit from interconnecting the small villages, but the tie-line costs added into the hydro project reduce this benefit somewhat. The graph (Figure IV-4) illustrates the results of this investi- gation. (For details see Appendix C-4.1). 90 | 80 70 BUCKLAND RIVER eb HYDRO & SWGR INTERTIE = A 50 \ x 40 ss = 4 9°%> INTEREST ~ 2. 30 a 8 DIESEL GENERATION pei ONLY oO c w za w 204 1050 Be 84 86 gs 88 90 92. 94 96 YEAR BUSBAR COST OF POWER SMALL COMMUNITIES FIGURE IV -4 apa2/e Iv - 9 Section IV - Analysis of Most Viable Alternate Development Plans UTILIZATION OF ELECTRIC HEAT Since the capacity of the hydro project is relatively large com- pared to the initial demand of the supplied area, the cost per kWh is rather high since the large investment has to be paid for whether its capacity is used or not. Utilization of this surplus capacity in electric home heating (at a rate comparable to cost for heating with other systms) would be appropriate. The problem arises when -- at a later point in time -- the area demand (minus the electric heat) approaches the capacity of the hydroplant. At that time the electric heating load and its demand would require installation of additional capacity -- which if additional hydropotential cannot be found, would have to be a diesel or other fossil fuel burning plant. Another solution would be to ask all consumers with elec- tric heat to convert to some other heating system. The following scheme appears to allow for all the benefits and avoids most of the problems electric home heating can have for a utility and the homeowner: es The homes are built with a conventional heating system plus electric heat. 2. The utility pays for the installation of the electric heat and its control. 3. The utility sells the energy for the electric heat at a rate equal or lower than the other heat supply fuel cost. 4. The utility is allowed to control utilization of the electric heat -- e.g. turn it off during times of peak demand. During these times the "normal" heating system supplies comfort heating for the home. The existing alternate home heating system actually provides peaking capacity to the utility. Figure IV-5 graphically illustrates the utilization of the surplus hydroelectric capacity. The system and heating requirements shown include Kotzebue and the 4 small communities assumed connected to the project by SWGR tie-lines. The effect of electric heat utilization on the Buckland plant cost of power are shown in the following table, where busbar cost with and without electric heat are listed, for the Kotzebue market area only, for an interest rate of 7%. apa2/e IV - 10 100,000 MWH AVAILABLE HYDRO — SURPLUS HYDRO 7 "NORMAL" SYSTEM REQUIREMENTS { HEAT SUPPLIED BY OTHER MEANS 87 + HEATING REQUIREMENTS 88 89 90 gi 92 93 94 95 YEAR BUCKLAND RIVER ENERGY BALANCE WITH ELECTRIC HEAT UTILIZATION FIGURE IZ-5 Section IV - Analysis of Most Viable Alternate Development Plans TABLE IV-4 Buckland River Hydroelectric Project Cost of Power in ¢/kWh 1986 1990 1995 Kotzebue without heat 48.5 35.6 24.1 Kotzebue with heat 50.4 28.6 19.0 Essentially all receipts for heating kWh sales minus the equipment installation cost are benefits which can be used to lower the rates for electric energy from the hydroplant until full utilization is achieved. Break even in this case is calculated to be within 2 years. apa2/e IV.=) 12 COSTAL Section IV - Analysis of Most Viable Alternate Development Plans TABLE IV-5 EVALUATION OF ELECTRIC HEAT UTILIZATION FOR THE BUCKLAND RIVER HYDROELECTRIC POWER POTENTIAL Cost of Possible Possible Heating Benefits to "Normal" Surplus Marketable No. of Receipts + Install Hydro Busbar Hydro Marketable Hydro Heating Residential For Heating & Controls Power Cost Year MWh? Mwh> Mwh Mwh2 Consumers® § MWh($1000) ($1000) ($1000) 1986 85,000 25,271 59,729 31,700 597 1,805 2,287 (482) 1987 85,000 ZU 7o1: 57,248 32,650 615 of 69 1,902 1988 85,000 30,232 54,768 33,630 633 2,153 76 2,077 1989 85,000 32,012 52,287 34,642 652 2,350 82 2,268 1990 85,000 35;,193 49,807 35,681 672 2,566 87 2,479 1991 85,000 39,063 45,937 36,751 692 2,801 94 2,707 1992 85,000 42,933 42,067 37,854 713 3,058 100 2,958 1993 85,000 46 ,803 38,197 38,990 734 S520) 107 3,164 1994 85,000 50,673 34,327 40,144 756 3,116 115 3,001 1995 85,000 54,543 30,457 41,348 779 2,931 123 2,808 = Present Worth 1986 at 7% discount (Year end cash flow) 17,648 2,697 Net (transmission losses 3%) # of residential consumers x 59,000 kWh) -10% to account for fuel use during peaks Investment only, no O&M, inflated 8% to 1984, 4% thereafter. Fuel replacement equivalent $/gal x 3413 x kWh ; fuel cost escalated 2% above inflation rate, 138,000 x .7 1980 Base = $.98/gal. eon o Incl. system losses at 11%. Kotzebue in 1979 = 450 + 50 for small communities, growth 3% per year. a Section IV - Analysis of Most Viable Alternate Development Plans 4. Coal Utilization Utilization of the Chicago Creek coal has been investigated for a) A conventional coal fired steam plant located in Kotzebue; b) A coal gasifier plant located in Kotzebue; c) A coal fired steam plant at the mine mouth with a trans- mission line to Kotzebue. Earliest "in service" year has been assumed to be 1984 with one 2,500 kW unit serving as base load unit in Kotzebue for a) and b). The choice for a 2,500 kW unit rather than a 5,000 kW unit was made to keep the required reserve capacity low and phase the transition to a totally coal fired plant such as not to render the existing diesel plant obsolete at an early date. 5,000 kW installed capacity would be necessary for a mine mouth plant to provide power for the mining operation and surrounding communities. Diesel generation would be used during times of peak demand for the Kotzebue plant location. Additional units have been assumed in 2,500 kW steps in 1987 and 1994 based on energy requirements. This development is shown on Figure IV-6. The chosen scenarios do not take waste heat utilization for the steam plant or gas production for other than electric energy generation into account. This allows for a valid comparison between a “diesel only" case and coal utilization. The uncertainties involved in establishing the cost for coal extraction and delivery as well as for the gasification equip- ment (see Appendix A) should be kept in mind when the power cost analysis is compared with other scenarios. The relatively low heat content of the Chicago Creek Coal makes rather high quantities of the resource necessary for electric energy generation, and the "fuel" cost at $65/ton is calculated to be 8.36¢/kWh which compares to 7.54¢/kWh for diesel fuel at $.98/gallon in 1980. The capital investments required for either a steam or gasifi- cation plant are extremely high, with the gasification equip- ment still being in th development stage. The economic analysis shows either a steam or gasifier plant marginally feasible at the lower interest rates for a plant located in Kotzebue. The mine mouth plant with a transmission line would be too expensive for the energy required. A break- even for the energy costs (¢/kWh) related to the mine mouth plant is estimated to occur at an energy use rate of 8 times the present rate for even the lowest assumed interest rate. apa2/e Iv - 14 T al ENERGY AVAIL ABLE COAL CAPACITY COAL FIRED GENERATING PLANT CAPACITY—-DEMAND (KOTZEBUE) FIGURE IZ-6 Section IV - Analysis of Most Viable Alternate Development Plans Ce Other considerations necessary in the decision for a steam or gasifier plant are: Environmental Aspects: It is expected that a gasifier plant would operate with less damaging emissions than a steam plant. Ash disposal and the storage of a year's supply would pose problems for either method of utilization. Chemical treatment is considered necessary to prevent spontaneous combustion and freezing. Operation and Maintenance: The gasifier plant will require fewer operators of a lower skill level than a steam plant. Maintenance has not been assessed since the experience record of gasifier plants is still low. Cost of Power Based on the cost estimates in Section III and Appendix A as well as the detailed economic analysis in Appendix C, the costs of power for the alternates considered are summarized in Table IV-6. TABLE IV-6 COST OF POWER AT 7% INTEREST ON CAPITAL INVESTMENTS EARLIEST BUSBAR COST OF : YEAR OF ELECTRIC ENERGY IN ¢/kWh ALTERNATE PLAN OPERATION 1980 1985 1990 1995 Diesel Generation only 1980 10.9 15.6 20.9 (akae4 Buckland River Hydro? 1986 15.6 35.6 24.1 Buckland River Hydro? with Utilization of Electric Heat a aa 28.6 19.0 Coal - Steam Plant 1984 20.3 24.0 Ze Coal - Gasification Plant 1984 19.9 24.1 27.0 T Supply to Kotzebue plus 4 small villages. It should be noted that the above are busbar costs, not costs to the consumer. The following graphs (Figures IV-7 to IV-10) show power costs for the various interest rates and scenarios. apa2/e IV - 16 MILLS PER KWH 600 500} 400 300 Nn ° 100 80 8I 82 83 84 85 86 87 88 YEAR DIESEL GENERATION ONLY —— —— BUCKLAND RIVER HYDROELECTRIC PROJECT —-+-——-- COAL FIRED STEAM GENERATION srreeeeess COAL GASIFICATION GENERATION TV - 17 KOTZEBUE BUSBAR COST OF POWER AT 2% INTEREST RATE MILLS PER KWH 600 400 8 DIESEL GENERATION ONLY —— —— BUCKLAND RIVER HYDROELECTRIC PROJECT —:+-——--COAL FIRED STEAM GENERATION vreecesees COAL GASIFICATION GENERATION . KOTZEBUE BUSBAR COST OF POWER AT 5% INTEREST RATE MILLS PER KWH 600 500} 400 8 80 81 82 83 84 85 86 87 88 89 90 a 92. 93 94 «=—985 YEAR DIESEL GENERATION ONLY —— —— BUCKLAND RIVER HYDROELECTRIC PROJECT —-—--COAL FIRED STEAM GENERATION streesees+ COAL GASIFICATION GENERATION KOTZEBUE BUSBAR COST OF POWER AT 7% INTEREST RATE Iy_- MILLS PER KWH 600 500 400 8 | , 80 8 82 83 84 85 86 87 88 89 «8690 at 92 93 94 «(985 YEAR ——— DIESEL GENERATION ONLY —— — — BUCKLANO RIVER HYDROELECTRIC PROJECT —-——--COAL FIRED STEAM GENERATION sreeeese++ COAL GASIFICATION GENERATION KOTZEBUE BUSBAR COST OF POWER AT 9% INTEREST RATE tT on Section IV - Analysis of Most Viable Alternate Development Plans Accumulated present worths of annual costs and unit costs are presented in Table IV-7. TABLE IV-7 ACCUMULATED PRESENT WORTH OF ANNUAL COST IN $1000 AND EQUIVALENT UNIT COST IN ¢/kWh FOR KOTZEBUE FOR 1980-1995 at 7% DISCOUNT INTEREST RATE ALTERNATE me © £m % Diesel Equivalent Unit Cost 18.4 18.6 18.8 18.9 =PW Annual Cost 45,780 46,367 46,816 47,299 Buckland River? " wae ie 27.4 31.8 Coal (Steam) " Rib 20.7 21.4 iz. AL: Coal (Gasifier) " 19.5 20.5 21.4 2252 47,639 50,474 52,880 55,336 Cost ratios for the accumulated present worths if compared to diesel are as follows: Buckland River? 1.03 .77 -63 .54 Coal (Steam) .94 .91 .89 . 86 Coal (Gasifier) . 96 -92 .89 .85 1 Supply to Kotzebue and a small villages. The foregoing evaluation shows only the Buckland River Hydro Project feasible, but only at the lowest interest rate. When evaluating these alternate plans it has to be considered that the economic feasibility analysis is based on certain assumed inflation rates and project cost estimates which are at best of "magnitude of scale" accuracy. Sensitivity to changes in these parameters has not been investigated in this study, but changes in the costs of the various alternates are expected to be substantial. apa2/e IV - 21 SECTION V CONCLUSIONS AND RECOMMENDATIONS SECTION V CONCLUSIONS AND RECOMMENDATIONS A. INTRODUCTION Kotzebue, filling all its energy needs with diesel fuel, gasoline, etc., faces ever increasing costs for this energy. If suitable alternate sources cannot be found, better utilization of this fuel might help to reduce these costs. The people in the area have expressed the desire to utilize alternate resources -- even at the same or slightly higher cost as diesel fuel -- if the moneys paid remain in the local economy and additional jobs are created. The alternate resources found during the course of this study have been described and evaluated in previous sections as well as the infor- mation at hand allowed. Possible technical, environmental and administrative problems and benefits have been addressed and the economical aspects evaluated. With the resource and cost information available it has not been possible to recommend a clearly defined development plan. It appears that some field work will be required to allow full assess- ment of the coal and hydroelectric power potential. Equipment required for the utilization of other resources such as wind, direct solar, biogas, etc. is still in the research and development stage. Installation of this equipment at a location with Kotzebue's severe climatic conditions cannot be recommended at this time. The remoteness and climatic conditions require equip- ment that is reliable and easy to maintain. Recommendations are therefore primarily directed at in-depth investigations of the most promising resources found. The following sections outline the steps required for each potential plan which will eventually lead to the optimum development scenario for Kotzebue. B. BUCKLAND RIVER HYDROELECTRIC POWER PROJECT Further investigation of this potential appears to be warranted. The following steps are necessary to establish feasibility: Field reconnaissance has to be performed to verify assumptions made in regard to geology, reservoir size, dam location, transmission line routing, and environmental concerns. A stream gauge has to be installed to establish a flow record. The field evaluation has to determine technical feasibility and should be followed by an economic feasibility study, as well as conceptual design for the facilities. High importance has to be placed on the solutions to operational problems in arctic climates. apal6/q Ya Section V - Conclusions and Recommendations Administrative restraints such as land ownership and right-of- way of the reservoir site, damsite and transmission line corridor have to be addressed in greater detail. If technical and environmental feasibility can be established, a more detailed investigation of single phase, low frequency generation and transmission should also be performed, since approximate savings of 10% over the present investment are estimated to be possible. C. CHICAGO CREEK COAL Field investigations to determine the extent and recoverability of the field should have highest priority here. The most economical mining method can then be defined. Environmental impacts of the mining method will have to be addressed and land ownership as well as surface and subsurface rights have to be established. The possibilities of transporting the coal to Nome or other communities should be investigated after the resource availability has been established. The utilization of the coal for gasification appears to be less problematic than in a steam plant. Operations of a gasifier plant require less skilled personnel; maintenance is estimated to be lower, and emissions appear to be less harmful. A detailed analysis of availability, costs and complexity of the required equipment should be performed. If gasification is considered not only for the generation of electricity, but also for home heating, cooling, etc., the equipment modifications required have to be assessed. A steam generating plant, where the cooling water would be utilized for district heating, merits further investigation also. Again, if a mine mouth plant proves more economical, the single phase, low frequency generation and transmission is expected to lower the installed costs by at least 10% and should therefore be investigated. D. WIND ENERGY CONVERSION Wind energy is a resource which appears to be most useful, at this time, if used to replace fuel in electric energy generation Reliability and life expectancy of the available systems has so far proven rather low in Alaska. General positive recommendations for the installation of wind energy conversion systems can therefore not be made. It appears to be in the best interest of the commu- nity for experimental installations, financed by state or federal agencies, to be placed under the control of the existing electric utility, where performance can be closely monitored and an expe- rience record in regard to system compatibility can be established. apal6/q V-2 Section V - Conclusions and Recommendations E. GEOTHERMAL ENERGY To assess this energy potential a test well will have to be drilled as close as possible to Kotzebue. Temperature and flow rates have to be measured to determine the potential. Utilization of a low grade geothermal source for district heating is conceivable. With the possible benefits shown in Section III-G (annual diesel fuel savings of approximately $800,000) further investigation is recommended. A test well near Kotzebue would establish the data needed to assess this resource adequately. F. WASTE HEAT RECOVERY AND CONSERVATION The existing waste heat recovery system at the KTEA plant and utilization for heating the potable water of the community is considered to be a very economic use of the waste heat at this time. Additional application of recovery and utilization equip- ment, for district heat for example, will have to be evaluated on a highly detailed level to determine economic feasibility. If diesel generation and/or coal fired steam generation are considered, a district heating system should be further evaluated. If hydro- electric or coal gasification projects are pursued, such a system would have little use in future years or would have to be greatly modified in case of coal gasification. apal6/q Veqie3 APPENDIX A COST ESTIMATES Cost estimates for the alternates discussed in Section IV follow, based on most recent published data, manufacturers' budget estimates, recently completed projects, and engineering judgment. apa2/j Ay 2 Appendix A - Cost Estimates 1. DIESEL GENERATING PLANT Investment costs for plant additions of 1000 kW units Insurance cost Labor costs (from KTEA records) Maintenance cost (from KTEA records) Fuel cost (from KTEA records) Lube oi] costs Plant efficiency 2. HYDROELECTRIC PLANT Investment Insurance Maintenance Labor (1 operator @ $40,000 incl. benefits) 3. TRANSMISSION AND DISTRIBUTION a) Single Wire Ground Return Up To 40 kV 2 Pole Structures, 800' Spans Structures, 7 @ $200 (local timber) Conductor 7#8 Alumoweld 5300', $540/1000' Line hardware Survey Clearing 20%/mile @ $760/1000' Freight Local labor, 250 manhours @ $22 Engineering For conductor 4/0 ACSR add: 7 structures and hardware Conductor $270/1000' Labor For river crossings, bog shoes and additional guys, add For labor in difficult terrain, add NOTE: Right-of-way is not included. apa2/j A-2 1980 - $ 870 /kW 3 /kW $.98 /gal. 10% of fuel cost 13 kWh/gal. See Section III 40,000 Use: $ 16.500 Appendix A ~- Cost Estimates b) Terminal for Single Wire Ground Return Transmssion Up To 40 kV 4. COAL MINING AT CHICAGO CREEK a) apa2/j Ground Grid 20, 20' deep rods interconnected with about 1000' of wire Labor 50 manhours @ $22 Transformer, 18, up to 1 MVA including shipping and installation Switchgear and protection Engineering Use: - SUMMARIES Underground Mining - 90,000 Tons Per Year DEVELOPMENT COSTS: Initial exploration Drilling program to prove deposits Port development (dock at Deering, conveyor systems for coal handling at Deering and Kotzebue) Road construction, 15 miles @ $100,000/mile Initial site, camp and mine development CAPITAL COSTS: Mining equipment Construction, transporting & road maintenance equipment (new cost) Beneficiation & processing equipment Camp facilities, temporary and permanent Freight Capital recovery at 9% interest and 10 year equipment life (capital recovery factor .1558) (20 years .10955) $150,800 628,200 900 ,000 1,500,000 600 ,000 6,000,000 1,214,000 300 ,000 1,344,000 1,000,000 1980 $ $ 1,600 1,100 24,000 5,400 33,200 5,400 38,600 $ 3,779,000 9,858,000 $13 ,637,000 $2,124,644/year ($1,493 ,933/year) Appendix A - Cost Estimates ANNUAL OPERATING COST: Personnel (20 men) modified from Bottge '77 760,000 Supplies 600,000 Maintenance 600,000 Insurance 150,000 Fuel (excluding coal) 15,000 Exploration (continued) 20,000 2,125,000 at 10 year equipment life 4,270,000 at 20 year equipment life 3,618,933 Cost/ton calculated for 90,000 tons in first year; (10 years) 47.44 /ton (20 years) 40.21 TRANSPORTATION COST: Mine to beach 3.50 /ton Deering to Kotzebue 13.50 /ton Handling 2.00 /ton Beneficiating process, handling to plant 1.50 /ton 20.50 /ton at 20 years equipment life - Total 60.71 /ton Use; __$70 /ton b) Open Pit Mining - 90,000 Tons Per Year DEVELOPMENT COSTS: (As for underground) $3,779,000 CAPITAL COSTS: Construction and mining equipment 2,796,000 Beneficiation & processing 400,000 Camp facilities, temporary and permanent 1,344,000 Freight 500,000 5,040,000 8,819,000 Capital recovery at 9% interest and 10 year equipment life (capital recovery factor .1558) 1,374,177 /year 20 years . 10955 966,121 apa2/j A- 4 Appendix A - Cost Estimates c) d) Drilling Program to Prove Reserves apa2/j ANNUAL OPERATING COSTS (First Year Only) Labor (12 men) Supplies, including blasting Ripping Scraping Drilling/blasting Maintenance Insurance Fuel Exploration Capital recovery TRANSPORTATION COSTS (As for underground) DETAILS Exploration Cost 450,000 450,000 200 ,000 150 ,000 300 ,000 400,000 150,000 200 ,000 20,000 1,374,000 INITIAL GEOLOGIC RECONNAISSANCE PROGRAM TO OUTLINE TARGETS: Drillers, 2 men, limited drilling (60 days) 2,000 ft. drilling Project geologist, 80 days @ $280/day Geologist, 60 days @ $280/day Cook Camp rental Transportation Subsistence, 60 days, 4 men @ $40/day Miscellaneous costs Drilling, additional 12,000 ft. @ $40/ft (80 days camp, 4 drillers, 1 mechanic) Project Geologist, 120 days @ $280/day Assistant geologists (2), 120 days @ $100/day Cook Camp rental, $30/day/man Transportation Subsistence, 80 days, 8 men @ $40/day Miscellaneous costs 80,000 22,400 16 ,800 5,000 9,000 6,000 9,600 2,000 480,000 33,600 48,000 6,000 24,000 8,000 25,600 3,000 3,694,000 41.04 /ton 20.50 /ton 61.54 /ton Use: $65 /ton 150,800 628,200 Appendix A - Cost Estimates e) Camp Facilities, Both Temporary and Permanent For Up To 25 Men Mobile bunkhouse (6-8 men) Galley/shower Bunkhouse and cookhouse (3,000 sq. ft.) Office (20 x 20 ft.) Shop (60 x 60 ft.) Generator, 600 kW, and building Storage buildings, (2 @ $15,000) f) Mining Equipment For Underground Mi 26 ,000 48 ,000 500 ,000 40,000 300 ,000 400,000 30,000 nin 7) (inflated and modified from Bottge ‘77 Coal drills, cutting machines, scoop trams, supply vehicles, etc. Ventilation system and dust facility Conveyor system Safety equipment Fuel storage 3,000,000 500 ,000 1,800,000 500 ,000 __200;000 g) Construction, Transporting and Maintenance Equipment For Underground Mining Ripper, D-8 full cab End dumps, 20 cu. yd., 4 @ $80,000 Front loader, 988, 7 cu. yd. Front loader, 3 cu. yd., 2 @ $65,000 D-3 with backhoe Grader, 14-G Pickups, 4-wheel drive, 2 @ $12,000 Crew rig, 4-wheel drive apa2/j A- 6 252 ,000 320,000 267 ,000 130 ,000 57,000 152 ,000 24,000 12,000 1,344,000 6,000,000 1,214,000 Appendix A - Cost Estimates h) j) apa2/j Construction, Transporting and Mining Equipment Open-Pit Operation D-9 with ROPS/full cab, ripper 370,000 D-8 with ROPS/full cab, ripper 252,000 Motor scrapers, 2 @ $250,000 500 ,000 Front loader, 988, 7 cu. yd., 2 @ $267,000 534,000 Pit truck, 4-wheel drive, 33 cu. yd. 195,000 D-3, with backhoe 57,000 Grader, 14-G 152,000 Front loaders, 3 cu. yd., 2 @ $60,000 120,000 Pickups, 4-wheel drive, 2 @ $12,000 24,000 Crew rig, 4-wheel drive 12,000 End dump trucks, 20 ton, 3 @ $80,000 240 ,000 Fuel truck 25,000 Welding and shop truck 25,000 Track air drill, 2 @ $80,000 160 ,000 Compressors, 600 cfm, 2 @ $50,000 100,000 Explosives truck 30,000 2,796,000 Chicago Creek Coal - Transport to Kotzebue By Ice Road In Winter (i) Parameters used: Total distance: approx. 68 miles (15 mi. gravel road to beach) Duration: approx. Nov. 15 to May 15, or 100 days Coal: approx. 40 Ibs./cu. ft. Truck capacity: approx. 8 yards > 216 cu. ft. > 8640 Ibs. or 4.3 tons Use 4 tons/truck load Cost for ice road: $20,000 /mile first cost $10,000 /month/mile maintenance (per Bearfoot Eng. 2-1-80) Appendix A - Cost Estimates apa2/j Requirements at 6800 Btu/lbs and 17,500 Btu/kWh for 10,000 MWh /year for 20,000 MWh /year for 30,000 MWh /year for 50,000 MWh /year for 80,000 MWh /year 13,000 tons (3,250 truckloads) 26,000 tons (6,500 truckloads) 39,000 tons (9,750 truckloads) 65,000 tons (16,250 truckloads) 103,000 tons (25,750 truckloads) e With 100 days available and assumption of 2 trips per truck per shift (max. 2 shifts/day) Number of for for for for trucks required: 10,000 MWH/year 20,000 MWH/year 30,000 MWH/year 50,000 MWH/year for 80,000 MWH/year (iii) Total Ice road, 53 Annual Cost: For 13,000 tons mi. @ $20,000 Maintenance, 68 mi. @ $10,000/mo. /mi. Transport, @ $38/ton (13,000 tons) Handling, @ Ice road, 53 $2/ton (13,000 tons) # Trucks (8.13) .10 (16.26) 18 (24.38) 25 (40.63) 45 (64.38) 70 1980 $ in 1000 T, 060 2,720 494 26 4,300 for 100,000 tons mi. @ $20,000 Maintenance, 68 mi. @ $10,000/mo. /mi. Transport, Handling, or $331 /ton 1,060 2,720 3,800 200 7,780 or $77.80 /ton Appendix A - Cost Estimates Mine Mouth Powerplant: Plant investment (as for Kotzebue) Transmission Line 138 kV 120 miles @ $280,000 Substations Total Investment Coal at 6,800 Btu/lbs. and Annual Cost: Plant operations (as in Kotzebue) No coal yard equipment operators Maintenance - Material (as in Kotzebue) plus line maintenance 1% Insurance (as in Kotzebue) Generating efficiency Line losses approximately 3% 5. COAL FIRED STEAM PLANT 10,000,000 33,600 ,000 2,000,000 $45,600,000 $40 450,000 265,000 336 ,000 17,500 The bases of the capital cost estimates for a 5 MW coal fired steam plant at Kotzebue in 1980 dollars are given in Table A.5.1 following: SOURCE OF ITEM 1980 $ ESTIMATE NOTES Boiler 4,000,000 Manufacturer 1 Turbine-Generator 2,400,000 Manufacturer 2 Condenser 350,000 Manufacturer 3 Mechanical Auxiliaries 300,000 Engineer - Electrical Auxiliaries 200,000 Engineer 4 Civil Works 450,000 Engineer - Subtotal 8,100,000 = Engineering 1,100,000 14% of subtotal above Subtotal 9,200,000 ss Contingency 1,800,000 20% of subtotal above TOTAL 10,600,000 = 5 apa2/j /ton Btu/kWh Appendix A - Cost Estimates NOTES: apa2/j Includes intermediate material handling equipment, boiler feeders and stokers, air heater/economizer, induced draft fans, mechanical dust collector, all valves and controls. Lower 48 estimate has been multiplied by 2.8 for Kotzebue. Mased on manufacturer's estimate for 60,000 pounds of steam per hour at 250 psig and 500°F into turbine, 2" Hg condensing pressure. Includes turbine, generator, governor, and controls. Lower 48 estimate has been multiplied by 2.8 for Kotzebue. Manufacturer's estimate has been multiplied by 2.8 for Kotzebue. 2" Hg condensing pressure. Based on percentages of major equipment costs from expe- rience with similar power plants. This value is near the mean of eight estimates for similar plants in Alaska by others. LABOR: (in addition to existing diesel plant operators) Operators, (2 per shift, 3 shifts per day) @ 50,000 per operator per year including benefits 300,000 Coal yard equipment operators, 4 @ $37,500 per operator per year including benefits 150,000 450,000 MAINTENANCE: (2.5% of investment) 265,000 INSURANCE: $3/$1000 FUEL: (Coal) from Section III $65 /ton GENERATING EFFICIENCY: (Chicago Creek coal heat content: 6800 Btu/1b) 17,500 Btu/kWh For the case of the 2500 kW steam plant, scaling from the 5000 kW case is done using the so-called "six-tenths power law". (Ref. Comtois.) Application of this "law" results in a multiplier on capital, maintenance, and fuel costs of 0.66 with resulting 1980 costs of: $7 x 10® capital, and $175,000 maintenance. Labor costs for the 2500 kW case are assumed the same as for the 5000 kW case as the smaller and larger plants have the same operational complexity. Ar) 10 Appendix A - Cost Estimates 6. COAL GASIFICATION Gasifier estimates are subject to several qualifications: there was general reluctance on the part of manufacturers to estimate cost of gasification units (one refused outright) for Alaska; gas cleanup can result in substantially higher unit costs; application experience for commercial turbine firing of the case is severely limited and has been for larger units; and details on coal quality are sketchy. For a 5000 MW gasified coal gas turbine plant, the atmospheric pressure gasifier and associated coal handling equipment 1980 capital estimate for Northwest Alaska is $15.6 x 10® based on a manufacturer's "best guess". The installed cost of the gas turbine and appurtenant equipment is based on the latest in- stalled costs experienced by Kotzebue Electric Association in 1977/78 and escalated 10%/year to 1980. For a 5 MW plant the following costs are estimated: INVESTMENT: Gasifier 10,000,000 Turbine and auxiliaries 2,500,000 12,500,000 LABOR: (in addition to existing diesel plant operators) Operators, 1 per shift, 3 shifts per day, $50,000 per operator per year including benefits 150,000 Coal yard equipment operators, 4 @ $37,500 per operator per year including benefits 150,000 300,000 MAINTENANCE: (2% of investment) 250,000 INSURANCE: $3/$1000 FUEL: (Coal) from Section III $65 /ton GENERATING EFFICIENCY: (Chicago Creek coal heat content: 6800 Btu/1b) 17,500 Btu/kWh For a 2500 kW gasified coal plant, capital costs were estimated on the same kind of information as for 5000 kW; the gasification system totaled $6.6 x 10® and the turbine plant totaled 1.7 x 106 for a total capital cost of $8.3 x 106. Labor costs are assumed the same as for the 5000 kW case as operational requirements are similar. Maintenance calculates to $166,000. Note: Smaller, demonstration gasification power plants have been reported at significantly lower capital costs power installed kW. Such demonstration projects may result in lower cost plants, but require a high level of quality and operational control compared to commercial practice. To represent a realistic case the use of commercially available equipment estimates has been chosen for this study. apa2/j A- 11 Appendix A - Cost Estimates re WIND GENERATING EQUIPMENT a) b) apa2/j 1.5 kW Windplant with induction generator and control (Enertech 1500) Tower, including 60-3 pole, pole top adaptor guy wires and anchors (4) Control anemometer wire, 400' Freight, 4,000 Ibs @ $19/100 Ibs. Installation, 100 manhours @ $50 Annual maintenance and repairs 15 _ kW Windplant with induction-generator (Grumman WS-33) Tower, 40', steel Control anemometer wire, 400' Freight, 8,000 Ibs @ $19/100 lbs. Installation, 200 manhours @ $50 Annual maintenance and repairs 100 kW Windplant with induction generator (assume $2,000/kW) Tower, 100' steel Control anemometer and wire Freight, 45,000 Ibs. @ $19/100 lbs. Installation, 500 manhours @ $50 Annual maintenance and repairs A- 12 3,900 900 65 760 5,000 (10,625) Use: $12,000 2,000 35,000 2,000 65 1,570 10,000 (48,635) Use: $50,000 3,000 200,000 5,000 65 8,550 25,000 (238,615) Use: $250,000 10,000 Appendix A - Cost Estimates 8. FREQUENCY AND PHASE CONVERSION a) Single Wire Ground Return Low Frequenc Transmission 133 kV Per Mile Structures, 1000" spans 1980 $ Structures, 11 @ $1,500 (imported timber) 16,500 Conductor 795 ACSR, 5,300' @ 1100/11000' 5,830 Line hardware 12,000 Survey 2,160 Clearing 20%/mile @ $760/1000' 800 Freight 4,000 Labor, 400 manhours @ $50 (contract labor) 20,000 62,130 Engineering 14% 3,095 8,700 For river crossings, special foundations, etc. 10,000 80,830 Use: 85,000 b) Phase and Frequency Conversion Equipment 1980-$ Per kW Low frequency (25 Hz) to high frequency (60 Hz) and 18 to 3% for 1 to 2 MW per terminal (manufacturer's data: ASEA, Sweden) 220 Freight, Engineering, Contingencies 180 400 Phase conversion equipment 19 to 3@ estimate 150 150 9. WASTE HEAT RECOVERY Section IV discusses the cost factors that need to be determined to analyze the feasibility of recovering waste heat for a district heating system. The figures in Table IV can be used to determine diesel dollar savings using a 1980 diesel cost of $0.98 per gallon of 138,000 Btu of which 80 percent is assumed recoverable as heat. This works out to $8.88 per 10® Btu. Table A following gives some typical guideline costs for heating system distribution costs. apa2/j Aye 13 Appendix A - Cost Estimates TABLE A ESTIMATED INSTALLED COST PER FOOT* FOR PIPE IN RURAL ALASKA VARIOUS TYPES AND SIZES (1978) Interest Rate Pipe Size Material (Percent) 4 inch 6 inch 8 inch Asbestos 7 $ 36 $ 42 $ 52 9 44 50 63 12 56 64 80 Fiberglass 7 43 50 70 9 52 60 85 12 66 77 108 Ductile Iron 7 65 82 121 9 78 99 146 12 101 127 187 Carbon Steel iz 70 99 125 9 85 119 150 12 108 152 193 Insulated i 94 107 149 Fiberglass 9 113 134 179 12 145 171 230 Insulated 7 121 152 209 Ductile Iron 9 146 182 251 12 187 234 322 Insulated 7 127 168 216 Carbon Steel 9 153 202 260 12 196 259 334 * Median cost for coastal locations, using village labor from "Waste Heat Capture Study" prepared for State of Alaska, Department of Commerce, Division of Energy and Power Development, June 1978. apa2/j A- 14 Appendix A - Cost Estimates 10. GENERAL Table A indicates the production fuel costs only for electrical generation for various fuel supply costs and plant heat rates. TABLE B GENERALIZED FUEL COSTS FOR ELECTRICAL GENERATION COST_IN MILLS/kWh @ HEAT RATE IN Btu/kWh $/10®Btu 10,000 12,500 15,000 17,500 20,000 1.00 10.00 12.50 15.00 17.50 20.00 1.50 15.00 18.75 22.50 26.25 30.00 2.00 20.00 25.00 30.00 35.00 40.00 2.50 25.00 31.25 37.50 43.75 50.00 3.00 30.00 37.50 45.00 52.50 60.00 4.00 40.00 50.00 60.00 70.50 80.00 5.00 50.00 62.50 75.00 87.50 100.00 10.00 100.00 125.00 150.00 175.00 200.00 20.00 200.00 250.00 300.00 350.00 400.00 apa2/j A- 15 APPENDIX B TECHNICAL PERFORMANCE DATA AND DESCRIPTIONS apal8/al APPENDIX B-1 BIOMASS CONVERSION 1.1 GAS PRODUCER apal8/a2 Engineering and Construction Div., Koppers Company, Inc. Pittsburgh, PA 15219, Telephone 412-227-2000 recld } asleoc(Or KOPPERS Engineering and Construction January 22, 1980 Mr. Leonard Fisher Retherford Associates P. O. Box 6410 Anchorage, Alaska 99502 Dear Leonard: We are enclosing a brochure and a technical bulletin on the Koppers Gas Producer. They describe the system that we qiscussed. The gas from a producer can serve as an excellent fuel for the basic heating requirements of many industries. There are limiting charac- teristics on the use of the gas however. We refer you to the section on retrofitting on page 10 of the Technical Bulletin for a general discussion on the usability of the gas. We are also enclosing a brochure on the Koppers-Totzek (K-T) Process. The resultant gas from this process has a much wider range of usability. The size of the K-T gasifier is much larger than you require, however. This is why we suggest multiple users and therefore a-lesser unit cost for all. We hope this information will be of help to you. If you have any questions feel free to call. JEA/pme Enclosures pennical KOPPERS 3ulletin ana constrict ion Koppers Low Btu Fixed Bed Gas Producer Go 7° Table of Contents History 3 Producer Gas Technology 4 Feedstocks 6 Gas Compositions 7 Process Description 8 Retrofitting 10 Fuel Usage 10 Burners 10 Combustion Air 1 Products of Combustion 11 Ratio, Air to Gas 1 Flame Characteristics an} Combustion Characteristics 12 Environmental, Safety Aspects 13 Bibliography 14 Introduction This bulletin presents the story of low Btu gas as produced in the fixed bed producer. It includes a brief history, the basic chemistry, coal and gas data, process descrip- tion, retrofitting fundamentals anda discussion of environmental factors. History Producer gas is one of the oldest of the so-called manufactured heating gases. It is probably the basic manufactured gas since in its simplest form it is a mixture of carbon monoxide and nitrogen produced by proper control of the reaction, 2C+02+3.8N,+2CO+3.8N, The above reaction involves only carbon and air, yielding “true” producer gas or Siemen’s gas as it was sometimes called in Europe. However the composition of the commercial product is different and the reactions are not as simple as the foregoing. Producer gas was manufactured in the late 19th century in Europe for some industrial uses and toa small extent for residential heating. Its use for residential heating was never particularly practical because of its low heat content per unit volume and pipeline distribution problems. The advent of the by- product coke oven provided the stimulus for a surge in industrial gas producer installations. Low Btu producer gas (140 Btu/SCF) (5,500 x 10° J/m‘) could be substituted for coke oven gas (500 Btu/SCF) (20,000 x 10° J/m*) to underfire coke oven batteries and thus release the higher Btu coke oven gas suitable for pipeline distribution. One of the early producer designs was patented by Anton V. Kerpely of Austria-Hungary in 1906. This design was incorporated into the Koppers-Kerpely producer which was introduced into the U.S. in 1921 by Koppers. Hundreds of these producers were installed during the next twenty-five years. Then gradually, with the widespread availability of low priced natural gas, the gas producer became obsolete. Today itis undergoing arejuvenation as one of the integral parts of the energy supply scenario. Producer Gas Technology The basic chemistry of producer gas manufacture involves the con- trolled combustion of carbon to yield a gas with a carbon monoxide content as high as possible. The process is carried out in a fixed bed mode with fresh feed being added to the surface and essentially carbon- free ash being removed continuously from the bottom. Combustion and gasification are brought about by a countercurrent blast of air to which steam has been added. As previously stated, the desired ideal reaction is: (1) 2C+0,+2C0 It is generally believed that this reaction does not take place directly but rather is the thermo-chemical result of the following reactions: (2) C+O,-+CO, (3) C+CO,-2C0 The gas produced by the reac- tions above has a heating value of only 110 Btu/cu. ft. (4,300 x 10° J/m?) due to the dilution effect of nitrogen in the air. Also, since the overall reaction is exothermic, the heat generated tends to fuse the ash and resultant clinkers make continuous operation very difficult. Introduction of steam into the blast air holds temperatures in the bottom of the bed below the ash fusion point. Further, the heating value of the gas is enhanced since the steam reduces the nitrogen concentration to give producer gas with a heating value of about 140 Btu/SCF (5,500 x 10° J/m%) dry basis. The addition of steam to the blast air results in the following principal reactions within the reduction zone: (4) C+H,O+CO+H, (5) CO+H,O +CO,+H, The degrees to which these reactions (4 and 5) proceed area function of temperature and partial pressure of reactants, with higher temperatures favoring the formation of carbon monoxide via the steam- carbon reaction. All of the foregoing reactions are usually depicted schematically (Fig. 1) as taking place in horizontal strata within the fixed bed. This is a convenient simplistic method of illustration. However, research has shown that, because of variable heat losses and varying flow character- istics, the regions of equal gas composition vary with radial position in the producer. Regardless of the zone configurations there are four separate functions performed in the fixed bed: A. The ash bed which extends about 6 inches (150 mm) above the top grate section serves to protect the grate from excessive temperature and also helps to distribute and preheat the blast air stream. The maintenance of a uniform ash bed, free of clinkers and pockets of fine powdered ash, is essential for smooth operation. B. The oxidation section, where CO? formation (reaction 2) predominantly takes place, extends approximately 6 inches (150 mm) above the ash zone and operates at temperatures approaching, butnotexceeding, the ash fusion point of the coal (2100 to 2300°F or 1150 - 1260°C). C. The reducing section, where CO formation (reaction 3) predominates, extends verti- cally about 4 feet (1.2 m) above the oxidation section. Reaction (3) takes place much more slowly than reaction (2) as temperatures slowly decrease to about 1,200°F (650° C). Reactions (4) and (5) also take place in this zone. D. The devolatilizing and pre- heating section, which comprises the top layer, is about 8 inches (200 mm) thick, depending on the coal composi- tion and sizing. The temperature in this section (1100-1200°F) (590-650° C) depends primarily — on the coal moisture content. The single most important variable in gas producer operation is the steam addition to the air blast. Proper steam addition gives the required temperature control, particularly in the oxidation section. It prevents clinkering and promotes water gas reaction (4) for hydrogen generation. Saturation temperatures of the steam-air blast above 140°F (60° C) cause deterioration of gas quality since the increased steam/air ratio can result in lower bed Oxidation Zone C+0,--CO, 2100°F Ash Bed Air and Steam Ash to 1200°F to 1800°F to 2300°F Figure 1 temperatures and reaction (5) is favored at the expense of reaction (4). More air must be added to increase the bed temperature to promote reaction (2). Toolowsteam/ air ratios create higher bed tempera- tures and the potential for clinker formation is increased. Steam addition rates of 0.4 to 0.6 pounds per pound (0.4 to 0.6 kg per kg) carbon fed are typical. Depth of the fixed bed is also of importance with regard to gas yield and composition. The composition of the producer gas depends on temperature and time of contact of gaseous products with the layer of coke. Therefore, a sufficient depth of the fixed bed has to be maintained. Classical correlations have been made’ showing that producer gas constituents can be represented in an equilibrium condition vol (COz) (He) (HO) (CO) dependent on depth of the fixed bed. Data collected at varying bed depths show the value of K’ to be a linear function equal to 0.096 L where L is depth of fuel bed in feet, (H,O) is volume of total moisture per 100 volumes of dry gas and the other constituents are volume percent in the dry gas. Other empirical correlations have been made® which relate steam addition rates to the exit gas compositions for both coal and coke feed. For a given steam addition rate these correlations permit prediction of producer performance. Technology (Continued) Feedstocks Fixed bed gas producers can operate on a variety of feedstocks. In the past they were operated primarily with coke feed because they were integrated into coke plant opera- tions. Today's economics generally favor coal feeds. The table on the right shows data for typical coals: The output of producers is significantly affected by the screen size of the coal feed. It is also important that the sizing be uniform with particular emphasis on mini- mizing fines which tend to promote channeling and clinker formation. An industry custom is to state gasification rates in terms of pounds of coal feed per square foot of grate area per hour. In 10 foot (3 m/) diam- eter producers with anthracite feed, gasification rates can vary from 60 Ibs/sq ft/hr (300 kg/m?/hr) for egg (25/16" x 34") (60 x 80 mm) down to 10 Ibs/sq ft/hr (50 kg/m?/hr) for barley (°/16” x %/32") (5 x 3mm). The preferred sizes for good gasification rates are egg, stove, nut and pea with the less desirable being buck- wheat, rice and barley. Other feedstocks show similar gasification rates relative to size of the feed. Another important factor pertaining to feedstocks isthecaking Bituminous Anthracite (Ash and moisture free basis) Proximate Analysis Wt. % Volatile Matter Fixed Carbon Ultimate Analysis Carbon Hydrogen Nitrogen Oxygen Sulfur Gross Heating Value Btu/Lb. J/kg Ash Fusion Range ope ae 30.20 6.18 69.80 93.82 100.00 100.00 87.10 94.01 5.94 2.68 1.37 0.99 4.53 1.70 1.06 0.62 100.00 100.00 15,560 14,100 36 x 10% 33 x 10° 2350-2940 2730-3010 1290-1620 1500-1650 “Softening Temp. characteristics of bituminous coals. This agglomerating tendency causes an increase in pressure drop across the bed which promotes non- uniform gas flow and composition as well as channeling, clinker forma- tion and erratic ash descent. A measure of this property is the Free Swelling Index (FSI). Coals with indices greater than 3 exhibit caking which requires good agitation of the upper portion of the bed. Coals with indices above 6 are not recommended for producer feed. Gas Compositions Producer gas yields and compositions will vary depending on feed size, composition and operating conditions. The table on the right gives some typical values. Younger coals and lignites tend to produce gas with higher heating values because of increased amounts of methane generated in the top section of the coal bed. From From Bituminous Anthracite Coal Coal Gas Analysis, Vol. % (dry basis) co 26.0 H, 15.0 co 27.2 co, 5.0 He 15.5 CH, 2.0 Co? 5.0 Ilum. 0.6 CH* 0.4 Ne _51.4 N? 51.9 100.0 100.0 Higher Heating Value Btu/SCF, dry basis* 167 162 J/m$ 6600 x 10° 6400 x 10° Gas Yield SCF/Lb coal 65 80 m*/ kg coal 4 5 *Including sensible heat of gas at 1200°F (650° C), referenced to 60°F. Process Description The process description below relates to the production of hot, raw low-Btu gas from a Koppers gas producer. As feedstocks change, particularly in regard to increasing sulfur contents, additional cleaning and cooling will be required. The processing that may be required for delivery of clean gas is discussed at the end of this section. Also, the unloading, handling, and storage facilities for the coal or coke feed- stock will vary depending onexisting facilities at the proposed plant site and on coal delivery patterns in the area. Therefore, the process description begins with the receipt of coal at a bucket elevator located directly adjacent to the gas producer. A vertical bucket elevator delivers coal to a coal bin at a rate of about 20 tons/hour (18,000 kg/hr.). The bucket elevator is approximately 65 feet (20 m) high and will be operated about once per shift to fill the 20 ton (18,000 kg) capacity coal service bin located above the producer. The bin is equipped with low level and high level alarms. Coal is fed from the bin through a series of rotary valves and feeders that provide even distribution on top of the fuel bed in the producer. The Koppers gas producer isa cylindrical vessel 10 feet (3 m) inside diameter and 15 feet (5 m) high overall including the lower grate assembly support. Thetop freeboard section of the producer is refractory lined and extends about 6 feet (1.8 m) from the top of the producer to the beginning of a water jacketed zone. The water jacketed section extends 8 feet (2.4 m) to the bottom of the producer and completely encircles the fuel and ash beds. The water jacket serves to protect the sidewalls of the producer from thermal stress and chemical attack, helpsto prevent clinker formation, and provides a source of process steam by being connected to a steam drum located above the producer. The gas outlet nozzle is 36 inches (1 m) inside diameter and is located near the top and at the side of the producer. The fuel bed in the producer is supported and slowly rotated by an eccentrically mounted steel grate assembly. The grate is dome shaped and consists of stacked circular rings which increase in outside diameter from 20 inches (500 mm) at the top to about 7 feet (2.1 m) at the bottom. The overall height of the grate assembly is 2.75 feet (0.8 m). The air and steam blastis introduced at the bottom of the producer and directed to the interior of the grate assembly. The airand steam proceed to the fuel bed through circular holes that are drilled radially in each of the rings. The rotating eccentri- cally positioned grate serves to crush the ash against the wall of the vessel as it proceeds from the bottom of the fuel bed to the lower section of the producer. This feature tends to break up any ash clinkers that are formed in the bed. The ash accumulates in a circular ash pan located below the grate and is an integral part of the grate assembly and grate support. Theashpan, grate support, and grate assembly rotate together around the stationary gas producer. The drive mechanism consists of a totally-enclosed electric motor, variable speed reducer and a worm gear drive. A water seal separates the interior of the producer from the outer lip of the ash pan thereby preventing gases from either escaping or entering the producer. Two ash extractor paddles are positioned on the outer and opposite sides of the producer and function to scrape and lift the ash from the bottom of the water sealed ash pan out of the producer and into ash chutes. From the vertical ash chutes, the ash drops into containers or onto a conveyor belt for ultimate disposal. The gas producer is equipped with a bed agitator-leveler which serves both to distribute fuel at the surface of the bed and to stir the bed in order to inhibit channeling of gas. The agitator also serves to break the crust that could be formed with certain types of coal feedstocks. The agitator made of low alloy steel is water cooled and is positioned in the producer from the top viaa special structure which enables it to be easily positioned at various levels within the upper portion of the bed. Air required for gasification is provided by a motor driven centri- fugal type air blower. The blower delivers approximately 4,000 SCFM (107 m*/min) of air at a pressure of 90” H,O (1,100 mm H, O). Steam from the steam drum at 15 psig (103 kPa), saturated, is mixed with the blast air to achieve an air saturation temperature of about 140°F (60° C) and is then piped to the bottom of the producer for introduction into the grate assembly. An installed spare air blower should be con- sidered to minimize maintenance downtime if on-stream time is critical. The gas exiting the producer is directed toatangentialentry cyclone to separate particulate matter from the hot gas. The cyclone is con- structed of refractory lined carbon steel and is about 3.5 feet (7.1 m) in ww diameter with a4 foot (1.2 m)straight section and a 9 foot (2.7 m) cone bottom. Fines from the bottom of the cyclone are cooled and periodically dumped intoacontainer for disposal. Instrumentation and Controls The operation of a Koppers gas producer is straightforward and does not require the use of sophisticated instrumentation or control equip- ment. In a basic producer plant the only variable that is normally automatically controlled is the air blast saturation temperature. This is accomplished by a proportional controller on the steam line feeding the air saturator. The control valve operates on a signal generated from a temperature controller with its sensor located in the air blast line directly below the producer. All other variables are manually controlled by the operator based on various pressure, temperature, grate need and flow measurements. -ome of the important variables are the pressure and temperature of the gas exiting the producer and the flow rate of the blast air to the producer. The rate of gas production is controlled by a butterfly valve in the blast air line. Gas quality and ash quality are controlled by the amount of steam admitted with the blast air which is controlled automatically as noted above. The controlled ratio is held at approximately 0.08 Ib (0.04 Kg) steam/Ib air. The rate of ash removal is controlled primarily by the speed of rotation of the grate. It can be closely regulated by means of the variable speed drive which can be set such that the rate of removal of ash equals the rate of its formation in the fuel bed. Fuel feed is regulated by adjusting the variable speed drive on the rotary valve that feeds coal or coke into the producer. Depending on the final use of the fuel gas, particularly in regard to fluctuations in the demand for gas, an automatic control on the gas production rate may be incor- porated. This consists of a control or bleed-off valve on the air blast and acoal feed speed control operated by a signal from a pressure trans- mitter located near the outlet of the producer or cyclone. A Koppers gas producer can be turned down to about 25% of its maximum gas production rate and can be banked for extended periods if no gas production is required. Start-up from the banked or idling condition normally can be accomplished in about one hour. Gas Cleanup Producer gas can be supplied either as hot raw gas or cold clean gas with the following approximate characteristics: Hot Raw Thermal Efficiency, % 90-95 (1) Btu/SCF, HHV 165 J/m', HHV 6,500 x 10° Cold Clean Thermal Efficiency, % 70-85 (2) Btu/SCF, HHV 140 J/m', HAV 5,500 x 10° (1.) Based on higher heating value of the gas plus sensible heat divided by the higher heating value of the coal. (2.) No credit for tars, oil, sulfur, or by-product steam. The process description above is for the production of a hot, raw low Btu fuel gas. The gas exiting the cyclone is essentially free (0.05 grains/SCF) (120 mg/m*)of particu- late matter, is at a temperature of 1100-1200°F (590-650° C), and can be used directly in a number of industrial heating applications. However, with regard to current air quality regulations, many eastern and midwestern coals are non- compliance feedstocks because of their high sulfur contents. When these coals are gasified nearly all of the sulfur originally present in the coal is converted to gaseous hydrogen sulfide. Unless the hydro- gen sulfide is removed from the gas, the subsequent combustion of the fuel gas will result in the formation of sulfur dioxide in amounts exceed- ing environmental limits. For those applications where sulfur removal is required, Koppers will provide a system to remove first the tar and then the hydrogen sulfide from the fuel gas. There are many commercially proven methods avail- able for H,S removal, ranging from solid absorbents, that can either be discarded or regenerated, to liquid systems utilizing chemical absorbents that remove hydrogen sulfide, HCN, CS,, COS from the gas stream. Theselection ofasystem depends on local environmental regulations, operating considera- tions, plant size, and the final application for the desulfurized fuel gas. Tar removal can be accom- plished by a system of traps, scrubbers, electrostatic precipi- tators and decanters and the tar may be a useful by-product. Process (Continued) Operator Expertise Notwithstanding the fact that fixed bed producers are relatively simple it is necessary to havea competent, experienced operator to maintain a steady consistent output of gas. The “condition” of the bed is critical and the functioning of the various zones outlined in the Technology section must be closely monitored by the operator. In the past this was accomplished by visual observation through inspec- tion ports and probing the bed with rods and pokers to check tempera- tures and prevent caking, clinkering and channeling. Koppers prior experience verifies the importance of the operator and his personalized techniques and even with present day technological advances he remains a significant factor in good steady operation. Retrofitting Retrofitting is a major economic consideration in the feasibility analysis of any producer installation in an existing plant using natural gas or oil. The magnitude of this varies greatly depending on the process or equipment involved. Some of the factors which affect retrofitting are: 1 — Fuel gas usage 2 — Burner design 3 — Combustion air 4 — Combustion gas 5 — Ratio of air to gas 6 — Flame characteristics Table 1 compares general combustion characteristics of methane (the major constituent of natural gas) and saturated producer gas for equivalent calorific content of the two fuels. Data presented in the table serve to illustrate the fol- lowing major retrofit considerations. Fuel Usage In comparison to natural gas, about six to eight times the volume of producer gas is required for the same heat output. This necessitates installation of a relatively large fuel supply line to the combustion equip- ment. Sizing of the fuel line involves economic compromise between capital cost of the pipeline versus the cost for delivering the gas at higher pressures or reduced temperatures. Normally an existing fuel supply line would be retained for “back up” purposes. If this is not the case, it may be possible to use an existing fuel supply line by transmitting the producer gas at higher velocity. This is a more feasible possibility where natural gas may already be supplied from the gas company’s header through an oversized line, as is often the case for small capacity units. Due consideration must be given of course to design pressure of existing lines as well as protection against leaks in view of toxic carbon monox- ide contained in the producer gas. The pipeline conveying the producer gas must be equipped with all necessary condensate traps unless the gas is delivered hot over a short distance. These traps must be protected from freezing. Weather protection as well as insulation ofthe pipe may also be necessary to minimize condensation or heat loss. Extensive drying of the producer gas is ordinarily too costly to consider. Burners Conversion from natural gas to producer gas usually will necessitate installation of new burners because of the increased volume of gas. In addition, specific flame character- istics of producer gas, such as flashback gradient and heat release, differ from conventional fuels. Many low Btu gas burners have been used successfully throughout industry. These burners have also been designed for multifuel capabilities, including low Btu gas, pulverized coal, oil, and natural gas. Ordinarily the cost of new burner hardware is relatively minor com- pared to other retrofitting costs. Most retrofit costs are incurred in pipeline distribution, manifolding and controls. Burner heat release (reflective of combustion rate and flame emissivity) is an important flame characteristic to consider in retrofit applications. Generally, producer 10 gas burns with a slower, colder flame than natural gas, but yields more emissive combustion gas constituents. Small combustion units, characterized by a high ratio of heat transfer surface to furnace volume, present less difficulty in retrofitting. In general, processes which are simplest to retrofit are those which employ a relatively small number of large burners, and those using general-purpose burners for heat applications wherein specific flame characteristics are not critical. Such processes include sintering, incineration, afterburning, reheat and reverberatory furnaces, soaking pits, air preheating, calcining, kiln operation, direct fired heaters, smelters, forging furnaces, andsome heat treating applications. Other processes may demand more sophisticated burner design upon retrofitting. Such processes include -lass tanks, indirectly fixed furnaces, :nished ceramic or metal treating, pulp and paper drying, and those processes which presently employ flat flame, partial premix, or radiant tube burners. Combustion Air Producer gas utilizes about 80% of the air required for combustion of natural gas for the same calorific heat input. For natural draft burners this feature is of little consequence. For processes which presently employ a forced draft air fan, care must be taken to assure that the reduced air flow does not place the fan outside of its stable operating range. If necessary a damper, or other resistor, can be installed or adjusted on the fan discharge to increase the developed head to a stable value. Alternatively, a portion of the compressed air can be bled to the atmosphere. Products of Combustion Producer gas yields about 25% more products of combustion gas than that obtained from natural gas. This is a very important retrofit consideration, since the combustion unit must be able to accommodate this increased flue gas flow to avoid derating. Determining the effect of pressure drop demands detailed analysis of specific cases. Processes with relatively large combustion chambers and stacks can usually accommodate the increased stack gas flow without significant effects on pressure drops. This is likely to be the case for small capacity units, especially natural draft furnaces. In cases where induced draft fans are used, it is likely that some derating will occur unless the fan is replaced or already designed for the increased flow and power requirements. The increased gas flow might be accommodated by operating the combustion unit at higher pressure, if the unit is designed to permit such performance. When forced draft air fans are employed, the reduced quantity of combustion air would permit delivery of the air to the furnace at higher pressure. A favorable effect of the increased combustion gas flow is that heat transfer coefficients are improved within any convective sections of the combustion equipment. Ratio of Combustion Air to Flue Gas Producer gas results ina ratio of combustion air to flue gas which is about 60-65% of the corresponding ratio for natural gas combustion. This consideration is important for combustion units equipped with air preheaters or recuperators. A lower proportion of combus- tion air implies that there can be insufficient air available to cool the combustion products to the flue gas temperature already being experi- enced. As flue gas temperature rises the unit overall efficiency is somewhat decreased. Although a higher flue gas temperature can impair efficiency, a favorable advantage to the higher temperature is that it increases the natural stack draft. This can offset somewhat the unfavorable effects of accommodating the increased flow of flue gas. Flame Characteristics As illustrated in Table 1, producer gas generally yields alower flame temperature than natural gas. This is an important consideration for high temperature combustion processes or for processes where high heat transfer rates are desirable in the combustion furnace. If hot producer gas is supplied, or if the producer gas and/or the combustion air are preheated, the flame temperature can be improved and efficiency of the combustion unit would be improved. As an example, increasing the fuel gas temperature by 500° F (260° C) will raise the flame temperature 250- 300°F (120-150° C). 11 Table I: Comparison of Combustion Characteristics of Methane and Producer Gas Bases: One Million Btu of Gross Calorific Value [Air Supplied @ 14.7 psia, (100 x 10° Pa) 50°F Producer Gas With (10° C) Wet Bulb] Methane 11.5 Vol. % Moisture Fuel Heating Value, Wet Basis Btu/ft?, (J/m* x 10%) 1013 (39,000) 152 (6,000) Fuel Usage: cubic feet (Nm*) 987 (26) 6553 (175) pounds (kg) 41 (19) 410 (186) Ib-moles (kg-moles) 26 (1.2) 17.3 (7.9) Combustion Air Required, Lb. (kg) @ 0% excess air 720 (327) 601 (272) @ 15% excess air 828 (375) 691 (313) Products of Combustion, Lb. (kg) @ 0% excess air 762 (346) 1012 (459) @ 15% excess air 870 (395) 1102 (500) Weight Ratio of Air to Combustion Gas @ 0% excess air 0.95 0.59 @ 15% excess air 0.95 0.63 ~ Flame Temperature, °F, (° C) 0% Excess Air and Fuel @ 120°F (49° C) Air @ 77°F (25° C) 3575 (1968) 2980 (1638) Air @ 600°F (316° C) 3990 (2199) 3195 (1757) Flame Temperature, °F, (°C) 15% Excess Air and Fuel @ 120°F (49° C) Air @ 77°F (25° C) 3305 (1818) 2855 (1568) Air @ 600° F (316° C) 3645 (2007) 3085 (1696) Vol. % CO, in Gas @ 15% Excess Air 8.2 13.7 Dewpoint of Combustion Gas °F (° C) @ 15% excess air (no adjustment for effect of sulfur) 136 (58) 128 (53) 1 12 Environmental And Safety Aspects Because of the abundance of oil and gas inthe U.S. in the past several decades, very few gas producers have been built or have remained in operation. The last Koppers gas producer in the country was shut down in the late 1940's. The old designs were based on priorenviron- mental and safety concerns that were neither as comprehensive nor as stringent as the ones that exist today. The new Koppers gas pro- ducer will of course incorporate all the necessary changes required such that the machine will comply with current EPA, OSHA, and local regulations. It is not anticipated that the modifications will be unduly exten- sive; however, current regulations regarding gas producers are alsoina stage of development and evolution and therefore designs will have to be made with this consideration in mind. The basic changes that are presently evident are in conjunction with various raw gas vents that exist in the coal feed mechanism, the gas producer vessel, and downstream piping. Previously, gases from these vents were exhausted directly to the atmosphere. New designs will either (1) recycle these gases to the air blast blower, (2) incinerate them inan environmentally acceptable manner, or (3) incorporate them with the product fuel gas. Also, the liquid effluents produced when bituminous coals are gasified will be contained in closed systems and will either be combusted or directed to appropri- ate treatment facilities. The actual methods employed will depend primarily on location and plant size. Koppers gas producers are also designed to meet the requirements of OSHA safety regulations. Princi- ple concern is with the possible escape of small quantities of producer gas into the surrounding atmosphere. Because of carbon monoxide contained in the producer gas, leakage from seals, flanges, or coal feeders could create hazardous conditions for operating personnel. Careful design and assembly of the equipment will serve to eliminate gas leakage. However, since the possibility exists, carbon monoxide monitors and alarms are provided to warn personnel of the presence of carbon monoxide in the air before dangerous concentrations are reached. Koppers pastexperiencein the design, engineering, construc- tion and operation of producers, coke ovens and blast furnaces is invaluable in the safe and efficient design of the present day Koppers gas producer. 13 Bibliography 1. R. F. Bacon & W. A. Hamer: American Fuels Vol. II, McGraw-Hill, 1st Ed., (1922). 2. N. E. Rambush: Modern Gas Producers, Van Nostrand Co., New York, NY (1923). 3. R. T. Haslam & R. P. Russell: Fuels and Their Combustion, McGraw-Hill, (1926). 4. Fred Denig: “Carbonization Committee Report” A.G.A. (1927) Convention. 5. J. S. Haug, Chairman: Report of Subcommittee on Producer Gas, American Gas Association, Inc., (1930). 6. G. V. Slottman: “Factors Influencing Gas Producer Operation”, A.G.A. Proceedings (1930). 7. J. J. Morgan: American Gas Practice, Vol 1, “Production of Manufactured Gas”, J. J. Morgan, Maplewood, NJ (1931). 8. Walker, et al: Principles of Chemical Engineering, McGraw-Hill (1937). 9. “Producer Gas Plant for Industrial Purposes”, National 10. 11. 12. 13. 14. 15. Federation of Gas Coke Associations, 1 Grosvenor Place, London S.W. 1 (1942). The Efficient Use of Fuels, H.M. Stationery Office, London (1944). B. J. C. van der Hoeven: “Producers and Producer Gas” Chemistry of Coal Utilization, John Wiley & Sons, Inc., New York, (1945), Vol. 2, pp. 1586-1672. B. J. C. van der Hoeven: Chemistry of Coal Utilization, John Wiley & Sons, Inc., New York, (1945), Vol. 2, pp. 1629-1635. R. F. Mitchell: “Oxygen Steam Producer Blast” Can. Chemistry & Process Ind., Aug. (1946). C. C. Wright and L. L. Newman: “Oxygen Gasification of Anthracite in the Wellman- Galusha Producer”, A.G.A. Proceedings (1947). K. F. Bray: “Details in the Operation of Gas Producers”, Iron & Coal Trades Review, (April 4, 1947). 16. 17. 18. 19. 20. 21. 22. C. C. Wright and L. L. Newman: A.G.A. Proceedings, (1947), pp. 701-712. C. C. Wright, K. M. Barclay, and R. F. Mitchell: /nd. Eng. Chem. 40, pp. 562-600 (1948). P. J. Wilson & H. J. Wells: Coal, Coke and Coal Chemicals, McGraw-Hill, (1950). William Gumz: Gas Producers and Blast Furnaces, John Wiley & Sons, New York, NY, Chapman & Hall Ltd., London (1950). W. H. Fulweiler: “Manufactured Gas,” R. E. Kirk, & D. F. Othmer eds., Encyclopedia of Chemical Technology, 1st ed., The Interscience Encyclopedia, Inc., New York, 1951, Vol 8, pp. 765-800. R. E. Kirk & D. F. Othmer: Encyclopedia of Chemical Technology, 1st ed., Vol. 10, pp. 353-442 (1951). “Fixed Bed Coal Gasification for Production of Industrial Fuel Gas”, Oct. (1977). U.S. Dept. of Energy, Contract No. EX-76-C- 01-2220, Task No. GFPMB-12. 14 15 Koppers Company Inc. Engineering & Construction Group 1150 Koppers Building Pittsburgh, PA 15219 Phone: 412/227-2532 KOPPERS 2 Engineering and Construction 2/79-1500 APPENDIX B-1 BIOMASS CONVERSION 1.2 STEAM TURBINE GENERATORS apal8/a3 i GENERAL QB ELECTRIC =|, (wouerarar _ 1 GENERAL ELECTRIC COMPANY, 55 HAWTHORNE STREET, P. O. BOX 3736 ALES 1 iwisiow-—— SAN FRANCISCO, CALIF. 94119, Phone (415) 546-4211 / “January 30, 1980 Dora Gropp c/o Repherford Associates PO Box 6410 Anchorage, Alaska 99502 Subject: Dear Ms. Steam Turbine Generator Sets Gropp: As requested by Leonard Fisher last week, I am pleased to provide the following information on steam turbine generator sets: 1 - 2500 KW geared steam turbine generator designed for inlet steam conditions of 250 Psig, 500° FIT and exhausting at 2" Hga. The turbine will drive through a reduction gear a generator rated 3125 KVA, .8 power factor, 4160 V, 60 hertz, 1200 rpm. The turbine generator set will be mounted on an integral steel base with rotating brushless excitation system, lube oil system, gland condenser, and stop valve. An electronic governor will be provided for remote mounting. Estimated price for this unit, f.o.b. Fitchburg, Massachusetts, with no freight allowed is ----------------------- $800,000 Estimated steam flow to generate 2500 KW is 34,356#/hour. 5000 KW geared steam turbine generator designed for inlet steam conditions of 250 Psig, 500° FIT and exhausting at 2" HgA. The turbine will drive through a reduction gear a generator rated 6250 KVA, .8 power factor, 4160 V, 60 hertz, 1200 rpm. The turbine generator set will be mounted on an integral steel base with rotating brushless excitation system, lube oil system, gland condenser, and stop valve. An electronic governor will be provided for remote mounting. Estimated price for this unit, f.o.b. Fitchburg, Massachusetts, with no freight allowed is ---------------------- $850,000 Estimated steam flow to generate 5000 KW is 64,800#/hour. GENERAL @@ ELECTRIC D. Gropp Repherford Associates Page 2 January 30, 1980 I am attaching some bulletins which give the features of our units. Unfortunately the full color brochure on these turbine generator sets will not be available until next month, for which I apologize. However, as soon as it is received I will forward you a copy. It has been our experience that most customers cannot justify installing two half-size steam turbine generator sets since the overall reliability of these units is in the order of 99+% and because of the additional cost. Most customers, for reliability, install extra boiler capacity since this is where most outages occur in a power plant. We appreciate your request for information and if we can be of any further help please advise. Yours very truly, R. J. Hofvath Industrial Turbine Sales Phone: (415) 546-4428 RJH/gr Encl. cc: Leonard Fisher 3841 - 25th St. San Francisco, CA 94114 o> TURSIE- EEA TOR SEIS FOR RELIABLE, EFFICIENT POWER GENERATION GENERAL @D ELECTRIC ipayen General Electric turbine reliability, aficiency, and low mainisnance are lacked by quaiiiy features | Stainless steel steam path minimizes effects of cor- osion and erosion. ! Spring-backed metallic labyrinth interstage packing irovides effective long-life seal against steam leakage tong the shaft. More complete details of turbines are included in bul- « Centerline support of turbine casings, bearings, and letin GEA-6232A. diaphragms insure equal expansion and maintain clear- ances through all transient conditions. @ Two-piece casing simplifies maintenance and elim- inates steam leakage associated with four-way joints. Typical non-condensing turbine, also available in condensing-type, automatic extraction, and extraction admission. | brushes generator eliminaiss most mainisnance General Electric’s brushless generator and static voltage regulator eliminate most maintenance with these im- portant features, to give you better generator service: @ No brushes, slip rings, or commutators; spare parts re- quirements are greatly reduced. @ Reliability of generator is backed by the use of proven components. Silicon diodes are not thermal-aging and can withstand high centrifugal forces. Critical reliability and performance requirements of diodes have been dem- onstrated in missile applications. @ The silicon-controlled rectifier-regulator and the gen- erator system are designed and fully tested as a unit. ™ Brushless generator is available in totally enclosed configuration (below) or in open, drip-proof design. Typical totally enclosed generator, also available in open, drip-proof design. 2 HOW DPushisss encilaiion works The brushless generator uses hermetically sealed silicon rectifiers to replace the conventional brush and commu- tator mechanical rectifier. This allows the d-c output of the exciter to be connected directly to the generator field. The exciter is an a-c generator of the stationary-field, rotating-armature type. The stationary field consists of salient poles located on the exciter frame. The rotating armature is mounted on a shaft extension of the main generator rotor and generates a-c voltages as it revolves in the magnetic field produced by the stationary poles. The silicon rectifiers are mounted on a heat-dissipating assembly which is attached to, but isolated from, the ro- tating shaft. The a-c output of the exciter armature is fed to the rectifier assembly and converted to d-c. Leads connect the output of the rectifiers to the main gener- ator field and thus the excitation power is delivered directly. The amount of excitation is controlled by a voltage regu- lator which senses the generator output and varies the power to the stationary field of the exciter. This regu- lator employs highly reliable static components to pro- duce a compact, reliable package. 3 General Electric geared automatic extraction unit installed General Electric direct-connected non-condensing unit in- in paper mill. stalled in an industrial power plant. SMALL STEAM TURBINE DEPARTMENT GENERAL Go) ELECTRIC FITCHBURG, MASSACHUSETTS APPENDIX B-2 WIND ENERGY CONVERSION APPENDIX B-2 WIND ENERGY CONVERSION BY Dr. Tunis Wentink, Jr. University of Alaska Basic Definitions and Methodology The primary criterion for determining the feasibility of Wind energy Conversion Systems (WECS) use is the average wind speed V at the rotor hub height h of a WECS. An annual V of 12 MPH is desirable, but lower V may still be useful in energy-deficient areas. The principal equations below will be used, always leading toward the calculation of the average power Pu produced by a wind machine. Thus, monthly and annual V for each community are sought. (1) Power in the Wind (no WECS involved here) A wind with instantaneous speed V will have an instantaneous power density or flux P/A (for a vertical or "sheet of wind" area A) of PA = C, Wie QQ) C, depends on the units of A and V, and the air density. apal5/i B-2 - 1 Appendix B-2 - Wind Energy Conversion apal5/i The average power flux PY/A in a wind regime (the collection of V values over a long period, say a month or year) is not P/A =1Ge Vee (2) . _ but is P./A = f(k) C, V8. (3) The value of f(k) depends on the speed distribution of the winds, i.e., the shape of the so-called frequency distribution curve. For Alaskan winds f(k) = 2.14 isa good value for estimation purposes, and it is used herein when actual f(k) are not known. Then, for A in square meters, V in miles per hour (MPH), Cy is 0.05472 if ce is in watts (w) and equation (3) becomes P/A (w/m?) = 2.14(0.05472) v3 (MPH*) or PLA = 0.1171 V5. (4) So, a rough "rule-of-thumb" is that the average power flux of a wind regime is 1/8 of the cube of the average wind speed, for the units given above. However, see the caution under "Power Output of a WECS" regarding use of equation (4). Beez Appendix B-2 - Wind Energy Conversion (2) apal5/i It is important to remember that the above refers to the power (or energy content) of the wind. Now the question of the energy extraction by a WECS must be considered. In the following this is done, in terms of average power delivered at the output of the wind-driven turbine (generator), with no further losses such as those due to transmission lines, inverters, etc., being considered. Power Output of a WECS: The average power produced by a specific (model, size, etc.) WECS is defined as Pur One can define an analog to the wind flux PSA by Pu/As where in the windmill case A is the disc area swept out by the blades. There is no theoretical simple relationship between cS and Pu except that, of course, the larger the a the larger the expected Pus Detailed calculations of the coupling of a windmill with a given power characteristic (Py vs. V) and the actual full wind distribution curve for a given location lead to a set of values Pus V. This is displayed in Figure I with the associated computational procedure given later. One must be careful in applying equation (4) to engineering situations. While the mean wind power flux is useful as a guide to determining the wind power potential of a site, the PAA is appreciably greater than Piy/A- First, only 59.3% of PA at most can be extracted by an ideal single unshrouded disc WECS, and then only if the WECS operates at all V in the wind spectrum. This is a fundamental limitation (like the Carnot Law). In practice cut-in and cut-out V of a WECS make some of the wind B-2 - 3 Appendix B-2 - Wind Energy Conversion (3) apal5/i spectrum unusable. Second, for a rotor the efficiency or power coefficient at various V is variable, ranging from zero to some maximum value (0.3 to 0.45 at best) and then back to zero, for increasing V. This power coefficient depends on the ratio of the wind V/rotational speed of the blade tips. There are additional inefficiencies, as in any geared rotating system. Thus, in practice the Py/A of contemporary wind machines will be of the order of 1/5 to 1/10 of PAA. Computation Method: Given the assumption of a specific WECS installed at a hub height h; (above ground) where the average wind speed is Vi, the mean average power Pu from the WECS can be predicted from simple empirical equations. These are of the polynomial form 4 2 3 Pag kW) a, + ay V5 + a, Vi + a3 V3 (5) The a; depend, of course, on the machine selected. Table I gives the a; for two contemporary machines; one is rated (maximum power) at 15 kW, the other at 100 kW. For most locations the h; of installation will be different from the he of anemometers yielding the measured Va: The key relationship here is . Pp VV, = (hj /h,)" (6) where a good approximation is p = 0.2. B-2 - 4 Appendix B-2 - Wind Energy Conversion apal5/i Equations (5) and (6) are the most important equations used herein. Justification of these, especially in determination of the ai, is outlined here. The first step in getting the a; of equation (5) requires that the frequency statistics (% of the time the wind blows at a specific V) are summed in a way to yield the V and also the so-called wind speed V duration curve. The latter gives the fraction or percentage of the time of the measurement period that the wind blew at V or greater than V. The duration curve is then coupled with the WECS power characteristic Pu vs. V to provide a third curve giving the percentage of time the WECS delivers a given P. See Figure I. The area under this last curve is then the total energy extracted by the WECS, since the product of power and time is energy. Thus this total energy divided by the absolute time (e.g. in hours) of the V measurement period gives the average power Pu for the period involved. In this way a large number of V statistics from the wind regime are boiled down to a single Pus V point characterizing the behavior of a given WECS at a specific location for a selected period. Then a large number of such points can be used to obtain plots and curve fitting computer routines yield fits (give the a;) corresponding to the plotted points. For example, several hundred duration curves from 50 Alaskan sites have been treated to arrive at the constants of Table I. B-2= 5 <— FURLING LIMITING WwECS CHARACTERISTIC DURATION CURVE % t VZV 100 COMBINATION OF A WIND SPEED DURATION CURVE AND WECS POWER CHARACTERISTIC TO OBTAIN THE WECS TOTAL ENERGY PRODUCTION For the WECS, V, = limiting V; ee = cut-out or furling V The average power P is obtained from the total energy produced (shaded area) divided by the total absolute time of the measurement period of the duration curve (taking into account that the curves above express time as a percentage of the period involved). FIGURE IL =.9..8 100 %t, v2v Appendix B-2 - Wind Energy Conversion TABLE I AVERAGE POWER OUTPUT POLYNOMIAL COEFFICIENTS FOR CONTEMPORARY WECS P (kW) = a, +a, V+ a, V2 + a, V3; V in MPH Max. P (Rated P) a, ay : a» a3 15 kW -0.247 -0.1169 4.333) \|E-2 -9.041 E-4 100 kW -19.59 35222 0.1935 -7.280 E-3 apal5/i Bead, APPENDIX B-3 SINGLE WIRE GROUND RETURN TRANSMISSION APPENDIX B-3 SINGLE WIRE GROUND RETURN TRANSMISSION GENERAL CONCEPT MINIMUM COST TRANSMISSION SYSTEM Single Wire Ground Return Transmission of Electricity The Single Wire Ground Return (SWGR) transmission concept described in this proposal has evolved from a recognition of certain basic facts-of-life concerning electric energy in remote western and interior Alaska, which facts are: 1. Small electric loads and the geographic distribution of villages presently limit electric energy supply to small, inefficient fossil-fueled generating plants. 2. Fuel prices in the western and interior regions, already uniquely high, face the probability of continued escalation. 3. Conventional three-phase electric transmission/distribution systems to intertie the outlying communities to more efficient generating plants are mostly impractical because high initial costs penalize the transmitted energy rates. 4. A transmission system using a Single Wire Ground Return (SWGR) line promises good electrical performance [1] [4] [7] [8] [10] and a substantially lower initial capital cost and therefore a lower transmitted energy cost than conventional transmission. 5. The SWGR line can be constructed using a high percentage of local labor and local resources in areas that need gainful employment as well as lower cost electricity. 6. The incentive to develop new, alternative energy sources (such as appropriate scale hydroelectric power in the area) is dependent on an economically viable electric transmission scheme that can feasibly deliver such energy to the villages. The SWGR transmission concept is one which proposes to deal with these realities. While the use of a single energized wire and earth return circuit is unconventional in the sense that applications are not common, it is an accepted system of proven use in several areas of the world {7] [8] [9] [10] [11]. Three phase equipment can also be successfully operated from this system by using phase converters [6]. apal7/n Bashan Appendix B-3 - Single Wire Ground Return Transmission The fifth edition of the National Electrical Safety Code (NESC) allowed the use of the ground as a conductor for a power circuit in rural areas; however, the most recent edition does not. It is the opinion of this writer that the SWGR system proposed here would in no way create an operating system with a lesser safety than the "conventional" system now in use throughout Alaska. Robert W. Retherford Associates has applied to the State of Alaska for an exception to the NESC to allow construction of a SWGR system. Verbal approval has been received, with final approval to be on a case by case basis, to construct demonstration projects using this principle. A project to supply central station electricity to isolated villages using the SWGR system is proposed. Such a project would provide a demonstration of the technical and cost feasibility of the system. The following pages provide a listing of objectives and a description of three alternate projects of increasing size and cost that will contribute valuable data for use in considering further extensions of such systems. apal7/n B-3);-7 2 Appendix B-3 - Single Wire Ground Return Transmission PHYSICAL DESIGN AND CONSTRUCTION CONSIDERATIONS Lack of a road system, permafrost, and limited or no accomodations for constructon crews throughout most of the region being studied establish some limitations that must be dealt with to find appropriate solutions. Conventional construction techniques and line designs might be used - but at premium costs. A design believed most adaptable to these limitations is based on the use of an A-frame structure shown in the following sketch labeled Figure I. The arrangement is well suited to the SWGR design. It is believed that the design has certain features that will provide unique opportunities for its use over the terrain of this region, as follows: ae The structure can be built using maximum local products and manpower. The legs of the A-frame can be made from local spruce that grows along the major river systems of the region and can be transported by these rivers. With this being done, 75% of the total line construction dollars could stay within the region. Ze The structure has transverse stability from gravity and need not penetrate the earth (permafrost in this region). Longitudinal stability is obtained through the strength and normal tension of the line conductor. This allows for use of the shortest lengths for legs to provide the ground clearances needed for safety. Additional longitudinal stability would be provided by fore and aft guying at suitable intervals. 3 The Single Wire configuration can be designed for minimum cost by utilizing high-strength conductors that require a minimum number of structures and still retail the standards for high reliability. For example: A single wire line constructed using 7#8 Alumoweld High Strength (approx. 16,000 1b. breaking strength) wire, electrically equivalent to a #4 ACSR conductor will require one half as many structures per mile as the #4 ACSR under the same Heavy Loading Design Conditions. (The line could also be converted to 36 at a future date by adding another structure in each span, and adding the new conductors. ) apal7/n B-3 - 3 20'FT., 4"X 4"X 1/4" ANGLE IRON "A'-FRAME STRUCTURE, HAIRPIN CONNECTOR SUSPENSION INSULATORS FIG. I B-3-4 Appendix B-3 - Single Wire Ground Return Transmission 4. The A-frame, gravity stabilized design form allows the use of a unique, engineering/construction technique that will sub- stantially reduce both engineering and construction effort as follows: The high strength conductor is laid out on the ground between anchor points (at typical intervals of 1 to 2 miles) and tensioned while on the ground to the approximate stringing tension. An engineer and assistant locate structure points by using the tensioned conductor as a template (lifting it above the ground to observe clearances from the natural contour). This could be done in winter time by using snow machines rigged with a small "jig" to underrun the conductor and lift it to predetermined heights for observation. At points selected by the engineer, a crew assembles a structure completely and fastens it permanently to the conductor (all lying on the ground). The crew lifts the structure at the point of attachement while the stress in the conductor is being maintained at the appropriate stringing tension. (A typical structure with conductors in an 800 foot span might weigh 900 lbs. complete. ) 5s Long river crossings (typically 2000 feet or less in length) can be accomplished using the same high strength conductor. Several such crossings have been in successful operation in Alaska using this same 7#8 Alumoweld wire as follows: Naknek River (S. Naknek to Naknek) 2000 ft. Talkeetna River (near Sunshine) 1894 ft. Along Kachemak Bay, Tutka Bay 1835 ft. Sadie Cove 4135 ft. Halibut Cove 2070 ft. 6. Costs for an SWGR line constructed using the A-frame design and high strength conductor is estimated to be about one-third (1/3) the cost of an equivalent 38, 4 wire line of similar capacity. apal7/n Basia Appendix B-3 - Single Wire Ground Return Transmission The gravity stabilized A-frame line design using long span construction will provide excellent flexibility to adapt to the freezing - thawing cycles of the tundra and shallow lakes of the region. Experience in this kind of terrain has clearly demonstrated the need to "live with" these seasonal cycles and avoid designs that cannot tolerate movement of the structure footings. Gravel backfill around and under poles that are set in the earth using more conventional line designs has proven seccessful but usually expensive and in many areas of this region highly impractical because of lack of gravel. Hinged structures supporting large transmission line conductors (Drake, 795 MCM, ACSR, 31,700 1b. strength, 1.094 lbs. weight/ft. ) across shallow and deep muskeg swamps and permafrost have been performing excellent service on the lines from Beluga across the Susitna River and its adjacent flat lands. Some of this route has severe freeze - thaw action that has dramatically demonstrated the need for flexibility. These flexible systems have performed as intended during severe differential frost action. The basic structural philosophy and performance of this transmission line is reflected in the proposed A-frame arrangement described here. The experience with such existing lines provides the strong basis for confidence in the structural performance of this new design. apal7/n B-3 - 6 Appendix B-3 - Single Wire Ground Return Transmission ELECTRICAL CHARACTERISTICS Series impedances and shunt capacitive reactance for selected conductor sizes have been calculated using the following formulas [12]: Series Impedance 2160 f Zg =r, + 0.00158 f + j0.004657F logio GM ree resistance of conductor per mile f = frequence in Hz p = earth resistivity in ohm meters GMR = geometric mean radius of conductor Shunt Capacitive Reactance = ! ' + ; Kee Kale 1/3 X @ in Megohms per mile x" = 0683 go 1og10 i (Capacitive Reactance at 1 ft. spacing) xia = a 10gi9 2h (Zero Sequence Shunt Capacitive Reactance Factor) h = height above ground in ft. f = frequency in Hz r = conductor radius in ft. apal7/n Basho Appendix B-3 - Single Wire Ground Return Transmission The line data have been calculated with the following assumptions: Frequency: Height above ground: Earth Resistivity: Ground Electrode Resistance: 60 Hz, 25 Hz 30 ft. 100 Ohm-m (swamp), 1000 Ohm-m (dry earth) R Ohms of each end 60 Hz IMPEDANCES AND SHUNT CAPACITIVE REACTANCES Z_ (ohm per mile) R GMR(Ft) (Ofim Diam. p= 100 p = 1000 Conductor Size Per Mile) Cinch) Ohm-m Ohm-m 7#8 Alumoweld 2.354 .0116 2.449 + 2.449 + 385 j 1.504 j 1.643 266.8 MCM .35 .0217 -445 + -445 + ACSR . 642 j 1.428 j 1.567 397.5 MCM - 235 .0278 .33 + .33 + ACSR . 806 j 1.397 j 1.537 556.5 MCM . 168 .0313 .263 + . 263 + ACSR 927 j 1.383 j 1.523 795 MCM .117 .0375 .212 + .212 + 1.108 j 1.361 j 1.501 apal7/n B-3 - 8 X (Meg Shm Per Mile) - 244 «eed -222 -218 -213 Appendix B-3 - Single Wire Ground Return Transmission 25 Hz Conductor Size 7#8 Alumoweld 266.8 MCM ACSR 397.5 MCM ACSR 556.5 MCM ACSR 795 MCM apal7/n IMPEDANCES AND SHUNT CAPACITIVE REACTANCES R (Ofim Per Mile) 2.354 00) 2235 - 168 on GMR(Ft) Diam. Cinch) -0116 - 385 .0375 1.108 B-3 - 9 Z_ (ohm per mile) Ohm-m 2.394 + j .649 .390 + j .617 L275 + j 604 -207 + j .598 .157 + j .589 Ohm-m 2.394 + j .707 .390 + j 675 .275 + j .663 .207 + j .657 .157 j .647 X (Meg ohm Per Mile) - 586 - 549 099 2023 Oud: Appendix B-3 - Single Wire Ground Return Transmission [1] [2] [3] [4] [5] [6] [7] LIST OF REFERENCES "A Regional Electric Power System for the Lower Kuskokwim Vicinity, A Preliminary Feasibility Assessment" prepared for the United States Department of the Interior - Alaska Power Administration, by Robert W. Retherford Associates, Anchorage, Alaska, July 1975. Reconnaissance Study of the Kisaralik River Hydroelectric Power Potential and Alternate Energy Resources in the Bethel Area, Alaska Power Authority, by R. W. Retherford Associates February 1980. "Grounding Electric Circuits in Permafrost", a paper by J. R. Eaton, P.E., West Lafayette, Indiana (formerly Professor of Electrical Engineering, Purdue University and visiting Professor of Electrical Engineering, University of Alaska) consultant to Alyeska Pipeline Service Co.; P.O. Klueber, P.E., Senior Operations Engineer, Alyeska Pipeline Service Co., Anchorage, Alaska and Robert W. Retherford, P.E£. of Robert W. Retherford Associates, Anchorage, Alaska. January 1976. "Single-Wire Ground -Return Transmission Line Electrical Performance", a paper prepared for Robert W. Retherford Associates by J. R. Eaton, visiting Professor of Electrical Engineering, University of Alaska, Fairbanks, Alaska, April 1974. "Ground Electrode Systems", by J. R. Eaton, Professor of Electrical Engineering, Purdue University, Lafayette, Indiana, sponsored by Commonwealth Edison Company, Chicago, Illinois, June 1969. "Performance Characteristics of Motors Operating from Rotary- Phase Converters", prepared by Leon Charity, Professor Agricultural Engineering, Iowa State University, Ames, Iowa, and Leo Soderholm, Agricultural Engineer, Farm Electrification Res. Br. AERD, ARS, USDA, Ames, Iowa. This paper was presented at the IEEE Rural Electrification Conference held at Cedar Rapids, Iowa May 1-2, 1967. Paper No. 34CP, 67-268. "Rural Electrification by Means of High Voltage Earth Return Power Lines", by My E. Robertson, Paper No. 1933 presented before a General Meeting of the Electrical and Communication Engineering Branch of the Sydney Division on 27 August 1964. The author is the Design Engineer for the Electricity Authority of New South Wales, Australia. apal7/n B-3 - 10 Appendix B-3 - Single Wire Ground Return Transmission [8] [9] [10] (11) [12] [13] [14] [15] "Wire Shielding 230 kV Line Carries Power to Isolated Area" - an article which appeared in the July 15, 1960 issue of Electric Light and Power, written by D. L. Andrews, Distribution Studies Engineer and P.A. Oakes, System Analysis Engineer, Idaho Power Company. This article describes a 40 kV single-phase transmission line using earth return. "Single-Phase, Single-Wire Transmission for Rural Electrifi- cation", Conference Paper No. CP 60-883, presented at the AIEE Summer General Meeting, Atlantic City, New Jersey, June 19-24, 1960 by R. W. Atkinson, Fellow AIEE and R.K. Garg, Associate Member AIEE, both of Bihar Institute of Technology, P.O. Sindri Institute, Dhanbad (Bihar) - India. "Single Wire Earth Return High Voltage Distribution for Victorian Rural Areas", by J.L.W. Harvey, B.C.E., B.E.E., H.K. Richardson, B.E.£., B. Com., and I.B. Montgomery, B.E., B.E.E., Messrs. Harvey and Richardson are with the Electricity Supply Department, State Electricity Commission of Victoria, Australia and Mr. Montgomery is Director and General Manager, Warburton Franki (Melbourne) Ltd. This paper No. 1373 was presented at the Engineering Conference in Hobart, Australia, 6 to 21 March, 1959. The paper recalls that "...... the system was first developed by Lloyd Mandeno of Aukland, New Zealand, who introduced it in the Bay of Islands area in the North Island of New Zealand in 1941. Since that time ....... thousands of consumers are connected to hundreds of miles of single-wire MANOS okie In September 1951, the State Electricity Commission of Victoria erected a small experimental system at Stanley... . following the success of the experimental installations the single-wire earth-return system has been very extensively used in Victoria... ." "Using Ground Return for Power Lines", by R.K. Garg (see [9] above) of the Bihar Institute of Technology - an article published in the Indian Construction News, June 1957. Electrical Transmission Distribution Reference Book, 4th Edition, 1950, copyrighted and published by the Westinghouse Electric Corporation, East Pittsburg, Pa. "A regional Electric Power System for the Lower Kuskokwim Vicinity", Alaska Power Administration, prepared by R. W. Retherford Associates, July 1975. Rural Electrification Administration Bulletin 62-1, Trans- mission Line Manual, September 1972. Alaska Regional Profiles, Southwest Region published by The University of Alaska Arctic Environment and Data Center. apal7/n B-3 - 11 APPENDIX B-4 DISTRIBUTION AND TRANSMISSION LINE LOAD LIMITATIONS APPENDIX B-4 DISTRIBUTION AND TRANSMISSION LINE LOAD LIMITATIONS The amount of power that can be transmitted over a distribution or transmission line is limited by: e current carrying capacity of the conductor e tolerable voltage drop e electrical system stability. System stability considerations have to be determined for individual cases and current carrying capacity depends strictly on conductor material and size. Voltage drop, however, is a limiting factor dictated by line length, operating voltage, load, and conductor size and configuration. Voltage Drop (%) = Voltage Weltage cee X 100 Maximum tolerable voltage drops are for: Distribution Lines (up to 24.9 kV)? 6.67% Transmission Lines (from 34.5 kV up to 138 kV)? 5-7% The following tables show load limitations in form of Megawatt Miles for various distribution and transmission lines. For distribution lines calculations where performed in accordance with REA Bulletin 45-1 where: (vo) (kV?) (cos 8} P cos 80 + X sin ® 0 Megawatt - Miles Where VD = Allowable voltage drop in % kv = Line to ground voltage 8 = Phase angle between voltage and current P = # of phases R = Resistance in ohms per phase per mile of line X = Reactance in ohms per phase per mile of line 1 REA Bulletin 169-27, January 1973 2 Standard Handbook for Electrical Engineers. Fink & Carroll. 10th Edition. apal7/o B-4-1 Appendix B-4 - Distribution and Transmission Line Load Limitations For transmission lines tables published in REA Bulletin 65-2 have been utilized and for Single Wire Ground Return Lines the following formula! is considered to render adequate results for preliminary investigations: evi iz XIV, I? - R24X2 Receiving End Voltage = ee ee Where Vy, #= Sending end voltage in kV R = Resistance in ohms per phase per mile X = Reactance in ohms per phase per mile 6 = Phase Angle between the two bus voltages . P R2 + X2 6 = at TENT re | eg eer Neat et roca Where Pig = total real power (MW) The reactive power Qi = Q? + Q Loss - Ye V,? Where Qe = Receiving end reactive power (MVAr) Q loss = Line loss reactive power (MVAr) Yc = Shunt capacitive admittance in Meg mhos per mile It should be understood that this formula can only be used for "short" line models (up to 50 miles) and that the following assumptions have been made: TORUS LAST, 2. 6 and Vz are calculated by solving for each alternatively, assuming 6 < 10° 3. Vy and Vo differ less than 10% 4. Line length 1 mile The load limitation given in Table B-2 can be used for preliminary feasibility investigations. For actual line design more accurate calculations are mandatory. 1 From: Electric Energy Systems Theory by Olle I. Elgerd. Published by McGraw-Hill, Inc. apal7/o B-4° = 2 Appendix A-2 - Dillingham APAO12/H1 DISTRIBUTION LINES (6.67% Voltage Drop) TABLE A-2.1 LINE LOADING LIMITS IN MEGAWATT MILES IN REGARD TO ALLOWABLE VOLTAGE DROP FOR SELECTED CONDUCTOR SIZES Stee saws Re eg I (ACSK/AAC) 95 1.0 9 95 1.0 9 95 1.0 9 95 1.0 . Ma 1.2 wy 3.9 4 4.6 4.3 4.7 5.6 15.5 16.7 18.9 1/0 19) 2.2 Bel 8.3 8.9 1.7 7.4 8.4 12 33.3 36.7 46.7 4/0 2.8 3:3 5.4 13.3 15.5 23.3 i 13 2 51 60 2 397.5 - - : 19 23 44 : - : 14 2 173 Based on lines of Standard REA Design Conductor Size - AWG (ACSR) 95 1.0 54" equiv. spacing) PF. PF 115_kV_(13.48' equiv. spacing) P.F. PF. P.F 9 95 1.0" P. 9 138 kV (19.53' equiv. spacing) PF. P.F Lz 95 1.0 Partridge 266.8 307 362 IBIS 397.5 370 450 Dove 556.5 423 526 Drake 795 476 603 Single Wire Ground Keturn Lines Conductor Size - AWG (ACSR unless otherwise noted) 748 Alumoweld Partridge 266.8 IBIS 397.5 Dove 556.5 Drake 795 Ground resistivity = 100 ohm-m (characterizes swampy wetlands). account. Calculated using A,B,C,D constants. 573 788 997 1228 40 P kV Fe 9 25 70 75 80 85 819 973 1871 980 1197 2142 112 1389 2685 1243 1581 3271 (5% Voltage Drop) come 65 180 200 215 225 B-4-3 1359 1535 1706 ~S ome 95 265 290 315 335 1668 1924 2178 3030 3770 4556 133 720 800 860 910 Voltage drop at the ground electrodes has not been taken into APPENDIX B-5 PHASE AND FREQUENCY CONVERSION IN POWER TRANSMISSION APPENDIX B-5 PHASE AND FREQUENCY CONVERSION IN POWER TRANSMISSION Power transmission lines are limited in their capacity to transport energy by conductor sizes and voltage levels. Theoretically higher operating voltages and larger conductors will allow transmission of higher loads over greater distances. Load and distance of trans- mission will cause the voltage to drop. If this drop exceeds 5-7% of the nominal voltage either load or distance have to be decreased or a higher voltage level and/or larger conductor have to be chosen. Construction and operating cost will limit operating voltages and conductor sizes however to the most economical level for any particular case. In Alaska, where small communities with low energy demands are separated by great distances, conventional transmission lines will - in many cases - have to be designed for voltage levels that are too high to allow economical installation. The Single Wire Ground Return transmission scheme is an attempt to make tie lines possible where conventional 3-phase lines would be too expensive to be built (see Appendix B-1). If this scheme is utilized at a lower operating frequency the load or transmission distance could be increased by an amount that is proportional to the new value for the frequency. Railroad electrification in the U.S. as well as in Europe has utilized reduced frequencies (25 and 16 2/3 Hz respectively) to Maintain adequate voltage levels over great distances. Generating plants, transmission lines and substations have been built exclusively to supply the railroad distribution network with single phase, low frequency power. Interconnections between three phase, 50 or 60 Hz systems and single phase, 16 2/3 or 25 Hz systems have been made via rotating converter sets up to 45 MVA1°°. Static frequency/phase conversion equipment is available, but presently not an “off the shelf" item for small (1-2 MW) applications. It is however conceivable that this type of power transmission and conversion can be economically feasible where conventional transmission lines would be too expensive. In case of a remote hydroelectric plant for example the power can be generated single phase at low frequency, the voltage stepped up to transmission level and transported to the point of utilization where, after voltage step down, phase and frequency can be converted to the required system levels. Since accurate cost estimates for conversion equipment could not be obtained in time to be used for this study, the potential benefits are shown for a hypothetical case. apal7/p B=onoL Appendix B-5 - Phase and Frequency Conversion in Power Transmission Transmission line capacity is shown here in terms of Megawatt miles at 5% voltage drop, .9 power factor for: TABLE A-3.1 THREE PHASE TRANSMISSION, 60 Hz SINGLE WIRE GROUND RETURN, 60 Hz and 25 Hz CONDUCTOR THREE PHASE SIZE 60 Hz (AWG) 34.5 kV 69 k 138 kV 266.8 ACSR 78 295 nae 397.5 ACSR 94 353 1359 556.5 ACSR 108 401 1535 SWGR 60 Hz 40 kV 66 kV 0 kV 133_kV 266.8 ACSR 70 180 265 720 397.5 ACSR 75 200 290 800 556.5 ACSR 80 215 315 860 SWGR 25 Hz 40 kV 66 kV 80 kV 133 _kV 266.8 ACSR 110 300 440 1200 397.5 ACSR 135 360 540 1440 556.5 ACSR 150 410 600 1640 See Appendix A-1 and A-2 for method of calculation. The construction cost of SWGR transmission are estimated at approx- imately 30-40% of a three phase transmission line. For a rough comparison the following cost can be used: 34.5 kV 39 $ 80,000/mile (conductor to 556.5 ACSR) 69 kV 39 $100,000/mile (conductor to 556.5 ACSR) 138 «kV 38 $125,000/mile (conductor to 556.5 ACSR) apal7/p B-5 - 2 Appendix B-5 - Phase and Frequency Conversion in Power Transmission Transmission line cost for the following assumptions are then: Power to be transmitted 6 MW Distance 50 Miles 36 - 69 kV, 397.5 ACSR $5,000,000 SWGR (60 Hz) - 80 kV, 266.8 ACSR $2,500,000 SWGR (25 Hz) - 66 kV, 266.8 ACSR $2,000,000 The achievable cost savings if SWGR transmission is employed are: $2,500,00 to $3,000,000 which would allow an expenditure of $416 to $500 per kW for phase and frequency conversion equipment. A rotating converter set of this size (6 MW) with controls is estimated to cost approximately $300/kW. Preliminary cost estimates for static converters received from a manufacturer indicate $200/kW per terminal. Conversion losses are estimated at 6% at each terminal. Generating equipment for single phase, reduced frequency operation are anticipated to be between 10 and 20% more expensive for an equivalent power output than for three phase equipment. To demonstrate the benefits of reduced frequency operation for power transmission systems more clearly, investigations in regard to the availability of conversion equipment as well as the capacity and cost are necessary. The evaluation of a particular project installed with conventional and low frequency, single phase equipment will then show the possible savings. apal7/p B=5 = 3 Appendix B-5 - Phase and Frequency Conversion in Power Transmission 100 101 102 103 BIBLIOGRAPHY "The Largest Rotating Converters for Interconnecting the Railway Power Supply with the Public Electricity System in Kerzers and Seebach, Switzerland" Brown Boveri Review, November 1978. "Electrical Transmission and Distribution Reference Book", Westinghouse, 1964. "Standard Handbook for Electrical Engineers", Fink and Carroll, 10th Edition. "Electrical Engineers' Handbook", Pender, Delmar, 4th Edition Electric Power. apal7/p B-5 - 4 APPENDIX C ECONOMIC ANALYSIS - DETAILS APPENDIX C ECONOMIC ANALYSIS - DETAILS List of Alternatives A - Diesel only -- for Kotzebue B - Buckland River Hydro -- for Kotzebue, Candle, Deering, Buckland and Selawik C - Coal (steam) -- for Kotzebue D- Coal (gasified) -- for Kotzebue apal2/v (Hal APPENDIX C-1 PARAMETERS USED FOR ECONOMIC EVALUATION APPENDIX C-1 PARAMETERS USED FOR ECONOMIC EVALUATION A. POWER DEMAND AND ENERGY REQUIREMENTS A system loss rate of 10% has been added to energy sold. The listed demands have been used as coincident demand, although it is expected that an intertied system would have a coincident demand of 98 or 99 percent of the listed demand. B. ENERGY SOURCES AND SUPPLIES System firm capacity is assured by assuming the largest unit in the system in non-operational. In the Buckland River hydro case it is assumed that if there is a failure at the dam or in the transmission lines, the four communities (Candle, Deering, Buckland and Selawik) which were served by the dam would have to rely upon their own diesel backup power sources. They would not be supplied by Kotzebue. C. LINE LOSSES Line losses for the Buckland transmission line have been assumed at 3%. Line losses for the village interconnections have been ignored as they represent less than one percent of the system's annual energy requirements. D. BASE YEAR All cost data ar for the base year 1980. E. EXISTING PLANT VALUES Existing plant values are taken from the Kotzebue Electric 1978 financial and statistical report. The value of the existing pro- duction plant is $1,876,000. Debt service for the existing plant is based upon 35 year loans at 2 percent. apal2/t CoA Appendix C-1 - Parameters Used for Economic Evaluation Fi ADDITIONAL PLANT VALUES Diesel -- $870/kilowatt Buckland River Dam -- $101,002,000 for Phase 1 oS $ 2,383,000 for additional incurred trans- mission line costs Gasified Coal Turbine Plant -- $ 8,300,000 for 2500 kW ia $ 12,000,000 for 5000 kW Coal Fired Steam Plant -- $ 7,000,000 for 2500 kW a $ 10,600,000 for 5000 kW For the mine mouth operation which would use 5,000 kW coal fired steam plants, $33,600,000 was used for the transmission line additions and another, $2,000,000 was used for a single wire ground return transmission line. . G. DEBT SERVICE Debt service on new investments has been calculated using 2, 5, 7 and 9 percent cost of money. An amortization period of 35 years is used in all alternatives. H. INFLATION AND ESCALATION RATES An inflation rate of 8 percent per year is used through 1984 for all costs (i.e. labor, construction, maintenance, etc.). The rate is then decreased to 4 percent per year for the remainder of the study. Diesel fuel costs were escalated to 2 percent above the general inflation rate. This means that diesel fuel is inflated at 10 percent through 1984 and 6 percent thereafter. I. INSURANCE Insurance costs were calculated using the following base rates Hydro: one dollar per thousand dollars invested; Diesel: three dollars per thousand dollars invested; Coal: three dollars per thousand dollars invested. apal2/t Cla 2 Appendix C-1 - Parameters Used for Economic Evaluation J. OPERATION AND MAINTENANCE Maintenance costs were based on utility records and the following relationships: Diesel: $7.00 per MWh generated by diesel. Hydro: $.60 per MWh generated by hydro. Coal Fired Steam Plan: 2.5 percent of investment in the plant Gasified Coal Turbine Plant: 2 percent of invest- ment in the plant inflated as noted before. Operation or labor costs were based on the following: Diesel: Present records plus an additional two operators hired by 1995. Hydro: One operator, plus one operator to be retained for the diesel back-ups. Coal Fired Steam Plant: 2500 kW, 2 operators x 3 shifts plus 3 workers at the coal yard; 5000 kW, 3 operators x 3 shifts plus 3 workers at the coal yard. Gasified Coal Turbine Plant: 2500 kW, 1 operator x 3 shifts plus 3 workers at the coal yard; 5000 kW, 2 operators x 3 shifts plus 3 workers at the coal yard. General, $50,000 annual costs are used per worker. This includes salary and benefits. K. FUEL AND LUBE OIL COSTS Fuel and lube oi] costs are calculated using the following bases: 98¢/gallon of diesel fuel in 1980 plus 10 percent for lube oi] costs. It is assumed that one gallon of diesel fuel has a generating efficiency of 13 kWh, and a heat content of 138,000 Btu/gallon. apal2/t CaS Appendix C-1 - Parameters Used for Economic Evaluation For coal generators located in Kotzebue, the following figures were used: (Coal mined at Chicago Creek) Heat content: 6800 Btu/1b Cost in 1980: $65/ton Generating efficiency: 17,500 Btu/kWh The costs for coal have been inflated at the "normal" inflation rate used in this study. L. DISCOUNT RATE Present worth was calculated using discount rate of 7 percent per year. apal2/t C-1- 4 APPENDIX C-2 EXPLANATION OF COMPUTER PRINTOUTS APPENDIX C-2 EXPLANATION OF COMPUTER PRINTOUTS The following is a line by line explanation of the enclosed computer printouts. DESCRIPTION bs Load Demand Demand - kW Energy - MWh Ze Sources - kW A. Existing Diesel Location or Unit 1-12 B. Additional Diesel Unit 1-6 C. Existing Hydro or Alternate Unit 1-6 D. Additional Hydro or Alternate Unit 1-3 Total Capacity - kW Largest Unit Firm Capacity Surplus or (Deficit) - kW Net Hydro Capacity - MWh Net Alternate Capacity - apal2/u EXPLANATION Projected peak load in kW Projected Energy Requirement in MWh Existing diesel units in kW Diesel Additions in kW and year added Existing Hydro or coal units in kW Hydro or coal additions in kW and year added Sum of lines A, B, C, D above Largest installed unit (See page C-2 for definition) Total capacity less largest unit Surplus or deficit in existing generation capacity Net annual MWh available from hydro generation Net annual MWh available from coal generators equals installed coal generation in kW times 8760 hours/yr. Ca2re lal Appendix C-2 - Explanation of C DESCRIPTION omputer Printouts EXPLANATION Net Diesel Capacity - MWh Diesel Generation - MWh Surplus or (Deficit) - MWh 7 Investment Cost ($1000) 1980 Dollars * A. Existing Diesel B. Additional Diesel Units 1-6 C. Existing Hydro or alternate D. Additional Hydro or alternate Units 1-B E. Transmission Plant Unit 1-2 Total ($1000) 1980 Dollars Inflated values 4. Fixed cost ($1,000) Inflated values A. Debt Service 1. Existing 2. Additions Subtotal 2%-9% apal2/u Net annual MWh available from diesel generation and is calculated by multiplying firm capacity in MW by 8760 hrs./yr. Diesel Generation in MWh required to supply load enegy. Calculated as Load energy (MWh) less net hydro or alternate capacity (MWh), with diesel providing peaking energy where required. Surplus or deficit in existing diesel energy capacity. Cost of existing diesel units in 1980 dollars. Cost of additional diesel units in 1980 dollars Cost of existing hydro units in 1980 dollars Cost of additional hydro units in 1980 dollars Cost of transmission plant additions in 1980 dollars Sum of lines A through E above Sum of Lines A through E above adjusted for inflation Existing debt service on investments Debt service calculated on inflated new additions using 2, 5, 7, and 9% cost of money. C-2;- 2 DESCRIPTION B. Insurance Total Fixed Cost ($1000) 2% - 9% Productions Cost ($1000) Inflated value A. Operation and Maint. 1. Diesel 2. Hydro 3. Alternate B. Fuel Oi] and Lube Total Production Cost ($1000) Total Annual Cost ($1000) 2% - 9% Energy Requirements - MWH Mil1s/kWh 2%- 9% C. Present Worth Annual Costs ($1000) 2%- 9% apal2/u Appendix C-2 - Explanation of Computer Printouts EXPLANATION Calculated as a percentage of invest- ment and then inflated. Sum of Debt Service Existing, Debt Service Additions, Insurance and Taxes Production Plant Sum of yearly labor cost related to diesel generation and diesel main- tenance cost. Sum of yearly labor cost related to hydro generation and hydro mainten- ance cost. Sum of yearly labor cost related to coal generation and coal plant investment cost. Sum of fuel oi] and lube oil cost. Lube 011 cost is assumed as 10% of fuel oi] cost for diesel. Fuel oi] cost is calculated by dividing Diesel Generation (MWh) by fuel efficiency in kWh/gal. and multiplying result by the fuel oi] cost in $/gal. Alternate fuel oil cost is calculated using cost per ton of coal, Btus per pound and Btus per kWh. Sum of Diesel and Hydro Operation and Maint. , and Fuel and Lube 0i1 cost Sum of total fixed cost and total production cost Project energy requirements in MWh same as line 1, load energy - MWh Obtained by dividing total annual cost by energy requirements in MWh and multiplying by 1000 Present worth of total annual cost 2%- 9% Co2nen3 Appendix C-2 - Explanation of Computer Printouts DESCRIPTION EXPLANATION D. Accumulated Annual Accumulated total of annual cost Costs ($1000) 2%-9% 2%- 9% * Accumulated Present Accumulated total of the present worth Worth Annual Costs of annual costs. 2%-9% ($1000) 2%-9% re Accumulated Present Accumulated total of the present Worth of Energy worth of annual energy cost in Mills/kWh 2%-9% mills/kWh. 2%-9% apal2/u C-2 - 4 APPENDIX C-3 COMPUTER PRINTOUTS apal8/a4 T-€-9 1920 1. LOAD DEMAND DEMAND - KW 2,450 ENERGY - MWH 11,800 2. SOURCES - KW A. EXISTING DIESEL LOCATION OR UNIT 1 S00 2 s00 a 1,025 4 1.000 S 200 & 200 Zz _ 3 = ° = 10 * 1. ? 12 = B. ADDITIONAL DIESEL WNIT 1 = 2 & 3 = 4 - 5 S 6 = C. EXISTING HYDRO UNIT 1 - OQ. ADDITIONAL HYDRO UNIT 1 = 2 = 3 a TOTAL CAPACITY - KW 4.325 LARGEST UNIT 1-025 FIRM CAPACITY 3,390 SURPLUS OR (DEFICIT) - KW 1.350 NET HYDRO CAPACITY - MWH - NET DIESEL CAPACITY — MWH 33.283 DIESEL GENERATION - MWH 11,3800 SURPLUS OR (DEFICIT) - MWH 21.493 POWER COST STUDY DIESEL GENERATION 1931 1932 1923 2.790 3,000 3200 13,000 14,400 15,700 soo soo S00 = 500 soo soo 1,025 1,025 1,025 1,900 1.900 1,000 200 200 200 200 - 200 3200 4.32 4.325 1,025 1,925 3,200 3.200 1,100 300 33,239 33,2383 33,2338 13,000 14,600 13.700 20,238 13,488 17,533 1934 3,750 13,950 500 soo 1,025 1,900 200 200 $.9325 1.925 4,300 1,950 42,043 13,950 23,093 1935 4,100 20,750 500 500 1,025 1,000 300 300 1934 4,500 22.750 500 _ 500 1,925 1,900 3900 900 42,0493 22,750 19,293 1987 4,900 24,750 soo 300 1,025 1,000 200 300 4,325 1,025 5.300 200 50,308 24,750 26,058 ALTERNATE A e-€-9 1. LOAD DEMAND DEMAND - FW ENERGY - MWH 2. SOURCES - KW A. EXISTING DIESEL LOCATION OR UNIT 1 eee OWN FUE WN neo B. ADDITIONAL DIESEL UNIT 1 euUaWn C. EXISTING HYDRO UNIT 1 2 D. ADDITIONAL HYDRO WNIT 1 ca 3 TOTAL CAPACITY - KW LARGEST UNIT FIRM CAPACITY SURPLUS OR (DEFICIT) - kW NET HYDRO CAPACITY - MWH NET DIESEL CAPACITY - MWH DIESEL GENERATION - MWH SURPLUS OR (DEFICIT) — MWH 1933 S.350 27-950 500 soo 1,025 1,000 200 200 1,000 1,000 1,000 7.825 1,025 6-800 1.450 5?,548 27,950 32,518 1939 1290 5.850 6-400 29,750 32.250 500 S500 1,025 1,000 200 200 1,000 1,000 1,000 1,000 1,000 1,000 - 1,000 7,825 3.325 1,025 1,025 4,300 7,300 950 1,400 42,323 32,250 36,078 500 500 1,025 1,000 200 200 1,000 1,000 1,000 1,000 3,825 1,025 7,300 300 68,328 35,350 32,973 1.000 1,000 1,000 1,000 1,000 9,825 1,025 8,300 1.100 77,083 33,750 33,333 1993 3,500 42,250 9-325 1,025 3,300 300 77,083 42,250 34,3833 1994 9.300 46. 500 500 1,025 1,000 200 200 1,000 1,000 1,000 1,000 1,000 2,000 11,325 1,025 10,300 1,500 94,608 46,450 43,153 500 590 1,025 1,000 200 200 1,000 1,000 1,000 1,000 1,000 2,000 11,325 1,025 10,300 400 94.603 51,050 43,553 C=6=9 3. INVESTMENT COSTS ($1000) 1980 DOLLARS A. EXISTING DIESEL B. ADDITIONAL DIESEL UNIT 1 rMPan ©. EXISTING HYDRO D. ADDITIONAL HYDRO WNIT 1 3 €. TRANSMISSION PLANT ADDITIONS WNIT 1 2 F. MISCELLANEOUS ADDITIONS UNIT 1 > 2 TOTAL £$1000) 1980 DOLLARS INFLATED VALUES 4. FIXED COST ($1000) INFLATED VALUES A. DEBT SERVICE 1. EXISTING 2. ADDITIONS SUBTOTAL 2% s% 7% % B. INSURANCE 1930 1,876 1,376 104 1981 1.376 1,376 1,874 104 1982 1,376 1,874 104 1983 1.376 1,376 1,376 104 1984 1.374 2.7446 3,060 104 47 72 71. 112 at 1985 1,876 2,746 3.060 194 a7 72 a 112 1936 1.376 2,746 3.060 104 47 72 1 112 1937 1,376 3,616 4,371 104 100 153 194 233 17 F=C-0 TOTAL FIXED COST ($1000) 2% 3% 7% % S. PRODUCTION COST ($1000) INFLATED VALUES A. OPERATION AND MAINT 1. DIESEL 2. HYDRO B. FUEL AND LUBE OIL TOTAL PRODUCTION COST ($1000) TOTAL ANNUAL COST ($1000) 2% Ss” 7% % ENERGY REQUIREMENTS - MWH MILLS/KWH 2% S% 7% 9% C. PRESENT WORTH ANNUAL COST ($1000) 2% S% 7 om D. ACCUMUL. ANN. COST ($1000) 2% % 7% 2% E. ACCUMULATED PRESENT WORTH ANNUAL COST ($1000) 2% S% 7% Ou: 1930 110 110 110 110 193 279 1,172 1,282 +282 1,282 1,282 11,800 109 109 109 109 1,232 1,282 1,232 1,282 1,232 1,232 1,282 1,232 1,232 1,232 1,282 +282 1981 119 110 110 110 1,513 1.513 1,513 1,513 13,000 116 116 116 116 1,414 1,414 1,414 1,414 2,795 2.795 2.795 2.798 2-496 21695 2169 25696 1982 iit lit tit tit 247 1,445 1,712 1,823 1,323 1,323 1,323 14,400 125 125 25 125 1,592 1,592 1,592 1,592 4,613 4,613 4-619 4.4613 4.233 4.233 7238 4.2393 1983 dit iii tit iit 277 1,733 2,010 2,121 2121 2/121 2-121 15,700 135 135 135 135 1,731 1,731 1,731 1,731 6.739 6.739 5,739 4.739 6,019 5,017 6.019 S019 1934 162 137 206 227 331 Nn y 5 n a wo n 2,319 2,338 2,359 13,950 147 149 150 151 2,132 2-151 2,165 2,181 2,533 9.553 9.577 9,593 8.151 3,170 3,194 3.200 1985 163 133 207 223 361 2.470 3,031 3,194 3,219 3-233 35259 20,750 154 iss 156 157 2,277 2+295 2,309 2,324 12,727 12.777 12,3815 12,357. 19.423 19,465 10,493 10,524" 19846 163 133 207 223 396 3-103 3,499 31662 3,487 3,706 3,727 22,750 161 162 163 164 2,440 2.457 2,469 2,483 46,389 16,444 14.521 16,584 12,363 12.922 12.942 13,007 1987 274 3s 359 433 3579 4,012 4,233 4,236 4,327 4,371 24,750 171 173 175 ie 25635 25469 2,695 2.722 20,422 20,750 20,343 20,955 15,504 13,591 15,457 15,729 S-€-9 F. ACCUM PRES WORTH OF ENERGY MILLS/KWH 2% s% 7% o% 1930 109 109 109 109 1991 217 217 217 217 - 1932 326 326 326 326 1933 426 426 436 436 1984 $43 sso sso ssi 1935 6538 661 661 663 1936 76S 769 770 Tie 1987 871 377 379? 332 os Feo es ces ore vor Set 99e%L Ord‘t OL OL OL oLe oLe 9L8'T Seel ev oe ers cv? ott vor Bel‘Tt TIEtL Ov‘t OLE OLe ole OLE OL 94E4T veel 9 199 crs Sir 08st vor v6s's 9rI*> oLe os ole OLe OLE 924E°1 €oot se v7 crs Sit ost vor ves‘s 92> 9281 coet mts dle ot siz vot wlLZ*£ 9SE*S 048 OL OL OL 926+1 Tool Tis ile oct sic vor LT *lL 9SE‘S VLEST ool zc est Toe BET sst vor 9LL‘°S 980 ‘ty 92e°T oSel TZ 69 TOE Bez sst vor 9L4L‘S 930 ¢ 926°1 BBeT BINVYENSNI “a he KL “Ss “co Wwi01LEns SNOILIGdy °Z ONILSIXS *T BI1Akd3aS 1830 “vv S310" d3a1v14NI (O0OT$) 1S03 G3X13 *e Sawa G3LYISNI _ SuvT10d oget (OOOTS$) Wi0L c TO LING SNOILIGGY SNOSNYTISZISIW “3 z T LING SNOILIGGY LNW1d NOISSIWSNYYL “3 & T 4INn OYGAH WWNOILIddv *d O¥GAH ONIASIX3 *o amen TO AINA 138310 WNOlilddv “6 T3S310 ONILSIX3S *v SyvT0d FET (O00TS$) SLS0I LNBWIS3ANI *S C-3-6 L-i-d TOTAL FIXED COST ($1900) 2% 3% ™% 2% S. PRODUCTION COST ($1000) INFLATED VALUES A. OPERATION AND MAINT 1. DIESEL 2. HYDRO B. FUEL AND LUBE OIL TOTAL PRODUCTION COST ¢$1000) TOTAL ANNUAL COST ($1000) 2% s% 7% ”7 ENERGY REQUIREMENTS - MWH MILLS/KWH 2% s% 7% % ©. PRESENT WORTH ANNUAL COST ($1000) 2% 3% 7m % D. ACCUMUL. ANN. COST ($1000) 2% sx 7% o% €. ACCUMULATED PRESENT WORTH ANNUAL COST ($1000) 2% s% ™ % 1983, 230 363 426 404 476 4,146 4,622 4.902 4,985 5,043 S,116 27-050 131 184 187 139 2,353 2,901 2,938 2,978 25,524 25.725 253,396 26-071 13,357 18,492 18,595 13,707 1°89 281 364 427 495 S93 4,234 3,427 5.703 5,791 5,354 $,922 29,750 192 195 197 199 3,105 3,150 3.184 3.22 31,232 31,526 31,750 31,993 21,462 21,642 21,779 21,9238 1990 347 441 54° 643 647 5.554 6.201 6.548 61562 4,750 6,344 32-250 203 207 209 212 3+329 3.387 3.431 3.479 37.780 33,138 23,500 33,337 24,791 23,029 25-210 25,407 1991 348 462 sso 544 Tir 6,454 7165 7,513 7,627 7,715 7,809 35,350 213 216 2138 221 3,569 3,624 3.665 3,710 45,293 45.315 46,215 44,484 23.340 +653 23.375 29,117 1992 41? 67 431 303 734 7,493 2 n a Nn 3.701 3,949 8.963 2,085 33,750 22 223 231 234 35843 3,922 3,930 4,034 53,204 34,644 55.173 S5.731 32,223 32.532 32,355 33.152 1993 420 363 632 304 B64 3446466 9,530 2,950 10,093 10,212 10,334 42,250 236 239 242 245 4,129 4,190 4,238 238 53,9484 64.742 6S. 390 55.065 34,352 34,772 37.093 37,439 1994 572 794 265 1,148 1,037 10,100 11,137 11,709 11,931 12,102 12,235 46,450 252 2357 261 264 4,541 4,627 4,693 4,764 75.453 76.692 77.492 73,350 40,393 41,399 41,736 42,203 1935 s74 79% 967 1,150 11,764 12.919 12,434 13.706 13,877 14,040 51,050 264 263 272 275 4,387 4,968 5.030 5,096 39.137 20, 399 91,369 92,410 45,730 46.367 46,316 47,299 8-€-9 F. ACCUM PRES WORTH OF ENERGY MILLS/KWH 2% S% 7% % 1933 27% 234 oa8 992 1989 1,080 1,090 1,095 1,100 1999 1,133 1,195 1-201 1,208 1991 1,294 +298 1,305 1,313 1992 1993 1,482 1,493 1,508 1,519 1294 1995 1,580 1,676 1,593 1,695 1,609 1,703 1,621 1,721 6-€-9 POWER COST STUDY BUCKLAND RIVER HYDROELECTRIC PROJECT ALTERNATE B 1930 1931 1932 1983 1934 1935 1986 1237 1. LOAD DEMAND DEMAND - KW 2.450 2,700 3,000 3,200 3.750 4,100 5,204 5.432 ENERGY - MWH 11-300 13,000 14,600 15,700 18,950 20,750 25,253 27,363 2. SOURCES - KW A. EXISTING DIESEL LOCATION OR WNIT 1 500 500 500 500 S00 500 500 2 500 S00 S00 S00 S00 S00 500 3 1,025 1-025 1,025 1,025 1.025 1,025 1,025 4 1,000 1,000 1,000 1,000 1,000 1,000 1,000 s 200 200 900 700 200 200 200 6 200 200 200 200 200 200 200 7 — a _ Bs = % eS a a : - - ae = - = 2 2 - - = = - = = 10 - - - - - - - - 11 - - - - - - - 12 - - - - - - - - B. ADDITIONAL DIESEL UNIT 1 - - - - 1,000 1,000 1,000 1,000 2 a a - - _ = S =~ 3 = = = a = x - _ 4 = = - - = B S - s - - - - -- - - -, 6 = S = a - = = = ©. EXISTING HYDRO UNIT 1 - - - - - - - - D. ADDITIONAL HYDRO UNIT 1 - - - > - - 20,000 20,000 = i = x 5 - z 5 = = TOTAL CAPACITY - KW $.323 25,825 LARGEST UNIT 1,925 20,000 FIRM CAPACITY 4,300 $.325 SURPLUS OR (DEFICIT) - kW 700 193 NET HYDRO CAPACITY - MWH - NET DIESEL CAPACITY - MWH 33.283 DIESEL GENERATION - MWH 11,800 SURPLUS OR (DEFICIT) - MWH 21,483 = 35.000 35,000 42,043 31,02 51,027 20,750 _ - 21,298 $1,027 51,027 ) tse 1. LOAD DEMAND DEMAND - KW ENERGY - MWH 2. SOURCES - KW A. EXISTING DIESEL LOCATION OR UNIT 1 Ree CON PUR WED neo B. ADDITIONAL DIESEL UNIT 1 euUaun C. EXISTING HYDRO UNIT 1 me D. ADDITIONAL HYDRO UNIT 1 a TOTAL CAPACITY — kW LARGEST WNIT FIRM CAPACITY SURPLUS OR (DEFICIT) kW NET HYDRO CAPACITY - MWH NET DIESEL CAPACITY - MWH DIESEL GENERATION — MWH — MWH SURPLUS OR (DEFICIT) 20,000 27,225 20-000 7,325 1-714 35,000 63.547 63,547 1939 6639 32,533 27,825 20.000 7,825 1,136 35,000 $8,547 63.547 1990 7,212 355193 20,000 27.825 20,000 7,325 607 5,000 48,547 468,547 1991 7,845 38,403 290,000 35,000 36,067 36,0467~ 1992 4.575 41,913 S00 500 1,025 1,000 200 200 1,000 2,000 2,000 29,325 20.000 9,325 1.250 35.000 34,067 86,067 1993 2,404 45,523 1,000 2,000 2,900 2,000 20,900 71.325 20,000 11,32 2.421 35,000 103,537 103,587 1994 10,232 49,333 1,000 2,000 2,000 2,000 31.325 20.900 11,325 1,592 35.000 103,537 103,537 1995 11.161 54,543 500 soo 1,025 1,000 200 200 1,000 2,000 2.0.0 2-900 20,000 35.000 103,537 103,587 EL-€-9 3. INVESTMENT COSTS ($1000) 1930 DOLLARS A. EXISTING OLESEL B. ADDITIONAL DIESEL WNIT 2 MeO C. EXISTING HYDRO QO. ADDITIONAL HYDRO WNIT 1 3 €. TRANSMISSION PLANT ADDITIONS UNIT 1 F. MISCELLANEOUS ADDITIONS WNIT t TOTAL (s$1ON0) 1920 DOLLARS INFLATED VALUES 4. FIXED COST ($1000) INFLATED VALUES A. DEBT SERVICE 1. EXISTING 2. ADDITIONS SUBTOTAL 2% 3% 7 % B. INSURANCE 19890 1,376 1,374 1,376 104 1981 1,376 1,375 1,374 104 1982 1.376 1,376 1,874 104 1933 1.875 1,376 1,376 1934 1,376 2,746 3,060 104 _a7 72 71 iz At 1985, 1,876 2,746 3,060 104 a7 72 1 112 1926 1-376 87 i 101,002 106,131 185,192 104 e132 9,229 11.340 14,503 1937 1.376 370 101,00 pin 1 w a wo 106,131 155,192 104 +132 9,229 11,940 14,503 TUTAL FIXED COST ($1000) 2% s% 7% % S. PRODUCTION COST (810005 INFLATED VALUES A. OPERATION AND MAINT 1. DIESEL 2. HYDRO B. FUEL AND LURE OIL TOTAL PRODUCTION COST ($1000) TOTAL ANNUAL COST ($1000) 2% s% 7% 7% ENERGY REQUIREMENTS — MWH MILLS/KWH 2% s% 7% ox C. PRESENT WORTH ANNUAL COST ($1000) 2% 3% ™% % OQ. ACCUMUL. ANN. COST ($1900) 2% s% 7% % E. ACCUMULATED PRESENT WORTH ANNUAL COST ($1000) 2% sn 7% 9% 1930 110 110 1190 110 193 379 1,172 +282 1,232 1,282 +232 11,300 109 109 109 109 2232 1,282 1,292 +232 1,232 1.232 1,232 1.282 1,292 1,282 1.2982 1-232 1981 110 110 110 110 cls 1,136 1,403 1,513 1,513 1,513 1,513 13,000 116 116 116 116 1,414 1,414 1,414 1,414 2.795 2179S 2.795 2.795 25696 25696 2,696 25696 1932 lit it tit lit 1,465 1,712 1,323 1,323 1,323 1,323 14,600 125 125 125 1235 1.592 1,592 1,592 1.592 4,413 4,619 4-612 4,613 +233 4.283 4,233 4,223 1983 ait ti lit itt 277 1,733 2,010 2-121 2,121 2-121 25121 15,700 135 135 135 135 1,731 1,731 1,731 1,731 4.739 +739 6.739 6.739 6,019 4,019 6,019 6,019 1984 142 157 206 331 2-301 25632 2.794 2,319 2,333 2,359 13,950 147 149 150 ist 132 1S1 165 1a 9.533 2.553 2,577 9,593 3,151 3,170 3,184 3.200 1985 143 133 207 228 341 2,670 3,031 3,194 3+219 3,233 3-259 20,750 154 153 156 157 2.277 2935 2,309 2-324 12.727 12,777 12,315 2,357 10,423 10,445 0,493 10.524 1934 4.397 9,494 12.105 14,773 s9 31 140 6,537 9.634 12,245 14,913 25,253 2s9 331 43s S91 14,784 146,335 13.4652 20. 1987 6,403 9,500 12,221 14,779 61 36 147 4,550 9,647 12,258 14,926 27-3463 239 353 443 345 4,079 6,003 7+634 9,295 25,314 32,053 37,313 2596 13,863 22,393 245,286 27.756 €T-€-0 1930 1981 19382 1923 1934 1935, 1936 1937 F. ACCUM PRES WORTH CF ENERGY MILLS/KWH 2% 109 217 2 436 343 453 931 3% 109 217 326 426 sso 461 915 7% 109 217 326 4346 sso 661 734 1,243 o% 109 2tZ, 326 436 ssi 663 1,057 1.396 WT-€-9 3. INVESTMENT COSTS ($1000) 1930 DOLLARS A. EXISTING DIESEL . B. ADDITIONAL OIESEL UNIT 1 Oo. TUbWN EXISTING HYDRO ADDITIONAL HYDRO WNIT 1 €. 3 TRANSMISSION PLANT ADDITIONS UNIT 1 es F. MISCELLANEOUS ADDITIONS UNIT 1 2 TOTAL ($1000) 19380 DOLLARS INFLATED VALUES 4. FIXED COST ($1000) A. INFLATED VALUES DEBT SERVICE 1. EXISTING 2. ADDITIONS SUBTOTAL 2% 3% ™ 9% INSURANCE 1.3745 101,002 107.371 157,961 104 4-243 9,393 12.054 14,770 1,376 101,002 107,871 157,941 104 +243 2,393 12,054 14,770 139 1990 1.3746 101,002 107,871 157.961 104 6,243 9,393 12,054 14,770 197 1991 1,374 109,611 161,974 104 65343 9,533 12,295 15,065 1992 1,376 370 1,740 1,740 101,002 109,411 161,074 104 6+ 363 9,533 12,295 15,065 ty ny o 1993 370 1,740 1,740 1,740 101,002 111,351 164,445 104 6.503 9,794 12.555 5.334 1994 1,874 370 1,740 1.740 1,740 101,002 111,351 164,445 104 4.503 9,798 12,555 15,334 2s2 1995 1,376 370 1,740 1,740 1,740 101,002 111,351 144,445 TOTAL FIXED COST ($1000) 2% 5% 7% % S. PRODUCTION COST ($1000) INFLATED VALUES A. OPERATION AND MAINT 1. DIESEL 2. HYDRO B. FUEL AND LUBE OIL TOTAL PRODUCTION COST ($1000) TOTAL ANNUAL COST ($1000) 2% S% 7% on ENERGY REQUIREMENTS - MWH MILLS/KWH 2% s% 7% 2% C. PRESENT WORTH ANNUAL COST ($1000) s% 7% 1 on D. ACCUMUL. ANN, COST ($1000) 2% E. ACCUMULATED PRESENT WORTH ANNIIAL COST ($1000) oy 3% 7% om 1933 6,529 2,634 12,340 15,056 61685 9,340 12,496 15,212 29,773 22! 331 420 S11 3,891 S727 7.273 3,354 32.429 41,299 42.314 57,203 1929 61536 9,691 12,347 15,063 46 29 165 6,701 9,356 12,512 15,228 32,583 206 302 334 467 3,645 5-361 6,306 3,283 39.200 S1,754 62,326 734136 24, 209 33,931 40,268 46,393 1990 +544 2,699 12.355 15,071 49 105 174 6,713 9,373 12,529 15,245 35,193 191 281 356 433 3,415 5,019 6,369 7+750 45,9128 1,627 74,355 83.381 1991 $1436 9,906 12,613 15,333 72 113 6,371 10,091 12,798 15,563 38,403 179 243 333 305 3,264 4,794 6,080 73% $2,739 71,713 37,653 103.949 33.073 43,794 52,314 62,032 1992 S695 FAS 1254622 15,392 74 121 195 41390 10,110 12,317 15,587 41,913 164 241 306 372 3,059 4,489 S491 45,921 59.479 31,222 109,470 119,534 34.137 43.233 53,505 43,260 1993 6.349 10,140 12,901 15.730 77 130 207 7.056 10,347 13,1038 15,937 45,523 155 227 233 350 2.928 4,294 §,439 4613 $46,735 92,175 113.573 135.472 75,573 1994 10, 150 12,911 15,740 a1 141 222 7,081 10,372 13,133 15,962 49,333 142 2038 264 320 1995, 51349 10.160 12,921 15,7590 130 191 241 293 2.574 3.763 4,769 5,794 30,922 12.244 139.269 167,422 44,397 9T-€-0 F. ACCUM PRES WORTH OF ENERGY MILLS/KWH 2% s% 7% o% 19383 1,211 1,323 1,507 1,693 1939 1990 1-320 1,535 1,397 2,167 1991 1,405 1,760 2.055 2.359 1992 1.473 1,847 ayiot 2.524 1993 1,542 1,961 2-311 22549 1994 1,597 2,042 2,413 2.793 1993 1,644 2-111 2,500 2-899 LT-€-9 1. LOAD DEMAND DEMAND - KW - ENERGY — MWH 2. SOURCES - KW A. EXISTING DIESEL LOCATION OR UNIT 1 3 4 5 6 7 8 9 10 11 12 B. ADDITIONAL DIESEL UNIT 1 2 3 4 s 6 C. EXISTING ALTERNATE UNIT 1 = 2 QO. ADDITIONAL ALTERNATE UNIT 1 2 3 TOTAL CAPACITY - KW LARGEST UNIT FIRM CAPACITY SURPLUS OR (DEFICIT) - kW GROSS ALTRNT CAPACITY - MWH GROSS DIESEL CAP —- MWH DIESEL GENERATION - MWH POWER COST STUDY COAL FIRED STEAM RLANT 1980 2.450 11,800 4,825 1.025 3,300 1,350 33,283 11,300 1981 2,700 13,000 4,325 1,025 3,300 1,100 33,2388 13,000 1982 3-000 14,400 4-32! 1,025 3,300 300 33,283 14,600 1933 3,200 15,700 4,325 1,025 3,300 4600 33,233 15,700 1984 3.750 13,950 2,500 7.32" 2,500 4,325 1.075 21,900 42,267 631 1985 4,100 20-750 2-500 7,325 2.500 4,325 725 21,900 42,267 948 19346 4,500 22.750 2,500 7,325 2,500 4,325 325 21,9700 42,267 1,347 1937 4,700 24,750 43,300 54,167 ALTERNATE C 8T-€-9 1. LOAD DEMAND DEMAND - KW ENERGY - MWH 2. SOURCES - KW A. EXISTING DIESEL LOCATION OR UNIT 1 2 3 4 s 6 7 3 9 10 11 12 B. ADDITIONAL DIESEL WNIT 1 2 .3 4 5 6 C. EXISTING ALTERNATE UNIT 1 a D. ADDITIONAL ALTERNATE UNIT 1 i 3 TOTAL CAPACITY — KW LARGEST UNIT FIRM CAPACITY SURPLUS OR (DEFICIT) - KW GROSS ALTRNT CAPACITY — MWH GROSS DIESEL CAP - MWH DIESEL GENERATICIN - MWH 1983 5,350 27,050. 2,500 2,500 9,825 2,500 7,325 1,975 43,300 54,167 35 1939 5,350 29,750 2,500 2,500 9,325 2,500 7,328 1,475 43,300 44,157 187 1990 6,400 32,250 soo S00 1,025 1,000 900 200 2,500 2,500 9,925 2,500 7.328 925 43,800 64167 464 199% 7,000 35,350 9,325 2,500 7+325 325 43,300 64,167 B66 1992 1993 7+700 3,500 38,750 42,250 soo 1,025 1,900 900 200 2,500 2,500 2,500 2.500 9,825 ?,e25 2.500 2,500 7,328 7,325 (375) (15175) 43,300 43,300 64,167 64,167 1,430 2.151 1994 9,300 46,450 2,500 2,500 2,500 12,325 2,500 9,325 S25 65,700 36,067 520 1993 10,200 51,050 2,500 2,500 2,500 12,325 2,500 9,825 (375) 45,700 36,067 1,072 61T-€-9 3. INVESTMENT COSTS ($1900) 1939 DOLLARS A. EXISTING DIESEL B. ADDITIONAL DIESEL UNIT 1 a or Newe . EXISTING ALTERNATE OD. ADDITIONAL ALTERNATE WNIT 1 zs 3 €. TRANSMISSION PLANT ADDITIONS WNIT 1 = F. MISCELLANEOUS ADDITIONS WNIT ft TOTAL ($1000) 1930 DOLLARS INFLATED VALUES 4. FIXED COST ($1000) INFLATED VALUES @. DEBT SERVICE 1. EXISTING 2. ADDITIONS SUBTOTAL 2% s% 7% % B. INSURANCE 1930 1,375 1,376 1.876 104 1991 1,376 1,876 1,376 104 1982 1,376 1,876 1,376 1933 1,876 1,375 1,376 104 1934 1,876 3,876 11,399 331 S73 735 201 36 1935 1,374 8,376 11,399 104 331 573 733 201 33 1934 1,376 3.876 11,399 104 381 573 735 901 30 1937 1,374 7,900 7,000 15,376 22.112 104 310 1-218 1,562 1.918 73 0¢-€-9 TOTAL FIXED COST ($1000) 2% s% 7% on S. PRODUCTION COST ($1000) INFLATED VALUES A. OPERATION AND MAINT 1. DIESEL 2. ALTERNATE B. FIVEL AND LUBE OIL TOTAL PRODUCTION COST ($1000) TOTAL ANNUAL COST ($1000) 2% s% 7% on ENERGY REQUIREMENTS - MWH MILLS/KWH 2% 3% 7% % (. PRESENT WORTH ANNUAL COST ($1000) 2% s% ™” 7 D. ACCUMUL. ANN. COST ($1900) 2% s% 7% ” E. ACCUMULATED PRESENT WORTH ANNUAL COST ($1000) 2% 3% 7% % 1980 110 110 110 110 1.232 1,282 1,282 1,282 11,300 109 109 109 109 1,282 1,282 1,282 1,232 1,282 1.282 1,232 1,232 1,282 1.282 1,282 +232 1931 110 110 110 110 1,186 1,403 1,513 1,513 1,513 1,513 13,000 116 116 116 116 1,414 1,414 1,414 1,414 2.795 2.798 27 eS: 2.795 21696 26% 256% 244% 1932 aii tit lit ai. 247 1,465 1,712 1.322 1,223 1,323 1,823 14,600 125 125 125 125 1,592 1,592 1,592 1,592 4-613 4,613 4,413 4,613 4,283 4,288 4.239 4,283 1933 111 iit lit 111 2,121 2,121 2-121 2,121 15,700 135 1235 135 135 1,731 1,731 1,731 1,731 6.739 6+739 6,739 4.739 6,019 O19 6,019 6-019 1934 S21 713 375 1,041 350 2,147 3,002 35523 3,715 4,043 13,950 186 196 205 213 2,683 2.834 2,958 3.084 10,2462 10,454 19,616 10.782 3,707 3.353 3,977 9,103 19385 S23 715 377 1,043 186 195 203 211 2.755 2-892 3,007 34126 14,126 14,510 14,334 15,144 11,462 11,745 11.994 12,229 1936 S24 716 373 1,044 13 920 2.799 3.732 4,256 4,448 4,610 4,776 22,750 137 196 203 210 2-336 2.964 3,072 35182 18,332 13,953 19,484 19,942 14,299 14,709 15,056 15.411 1937 937 395 1,739 2,092 3.145 4.349 5,356 5.744 $103 6,461 24,750 17,533 13,299 13.2460 19.435 Té-€-9 Ff. ACCUM PRES WORTH OF ENERGY MILLS/KWH 2% 3% 7% % 1930 109 109 109 109 19381 217 217 217 ane 1932 3246 326 326 326 1933 436 436 436 436 1984 573° 5386 592 5938 19385 711 Tas 737 743 19846 836 356 372 333 1987 971 1,001 1,026 1,051 ¢@?-€-9 19383 3. INVESTMENT COSTS ($1000) 19380 DOLLARS A. EXISTING DIESEL 1,376 B. ADDITIONAL DIESEL UNIT 1 . ‘« 2 S 3 - 4 - 5 - ie = C. EXISTING ALTERNATE = D. ADDITICNAL ALTERNATE WNIT 2 7,000 2 7,000 3 z= E. TRANSMISSION PLANT ADDITIONS UNIT 1 ~ 2 = F. MISCELLANEOUS ADDITIONS UNIT 1 ~ 2 S TOTAL ($1000) 1980 DOLLARS 15,876 INFLATED VALUES 22,112 4. FIXED COST ($1000) INFLATED VALUES A. DEBT SERVICE 1. EXISTING 104 2. ADDITIONS SUBTOTAL 2% 810 sn 1,218 7% 1.562 9% 1.915 B. INSURANCE 7 1989 1,875 15,376 22,112 104 310 +2138 1.562 1.915 72 1990 15,876 22,112 104 810 1,213 155462 1,915 1991 1,376 7,000 7,000 15,876 22.112 104 310 1,213 1,562 1,915 35 1992 1,376 7,000 7,000 15.8746 22, tt2 104 310 1,213 1,562 1,915 1993 1,376 7,000 7,000 15,374 22,112 194 310 +213 1,562 1,%18 1994 1,376 7,000 7.900 7,000 22,876 36,209 194 1,374 2,066 2,451 3.249 132 1993 1,376 7,000 7,000 7,000 22,876 36,209 1,374 2,066 2,651 3,249 144 CL-t Vv TOTAL FIXED COST ($1000) 2% st 7% % 5S. PRODUCTION COST ($1900) INFLATED VALUES A. OPERATION AND MAINT 1. DIESEL 2. ALTERNATE B. FUEL AND LUBE OIL TOTAL PRODUCTION COST ($1000) TOTAL ANNUAL COST ($1000) 2% s% 7% 9% ENERGY REQUIREMENTS - MWH MILLS/KWH 2% ”% 7% 2% C. PRESENT WORTH ANNUAL COST ($1000) 2% s% 7% % D. ACCUMUL. ANN. COST ($1000) 2% s% 7% o% E. ACCUMULATED PRESENT WORTH ANNUAL COST ($1000) 2% s% 7% % 1933 990 1,393 1,742 2.095, »273 3-574 4,349 5,339 4,247 6,591 61944 27,950 216 231 244 257 3.398 3+436 3,336 4,041 29,577 30,969 32.143 33,347 21,031 21,935 22,696 23.476 1989 203 1,401 1,745 2,098 5,413 6,411 6.319 7+163 7+S16 29,750 215 229 241 233 3,487 3,709 315396 4,088 35,288 37,738 39. 306 40,363 24.512 25.544 26,592 27,564 1990 296 1,404 1,748 2,101 s 1,377 4,623 6,005 7,001 7,409 7.753 3,106 32,250 217 230 240 231 3.559 3,766 3,941 4.121 42,939 45,197 47,059 43,969 23.077 27,410 30,533 31,635 1991 299 1,407 1.751 2,104 1. 1-432 5.233 61726 7.725 3,132 3,477 3-330 35,350 219 230 240 250 3,470 3,864 4,027 4195 50,714 53,330 55,536 37,799 31,747 33,274 34,540 35,320 1992 1,003 1,411 1,755 2,108 19 1,490 6,045 7,554 3.557 3.965 9,309 91662 383,750 221 231 240 249 3,799 3,981 4,133 4,290 $9,271 62,295 64,345 67,461 35.546 37,255 38,493 40.170 1993 1,006 1.414 1,753 2111 29 1,549 6,337 3,465 9,471 9,379 10,223 10,576 42,250 224 234 242 250 3.930 4,099 +242 4,339 $3,742 72.174 75,063 78,037 39,474 41,354 42,935 44,559 1994 1,614 2,303 2,393 3,491 1,964 7,721 9,763 11,379 12,071 12,656 13,254 46,450 245 260 272 235 4,413 4,631 4,903 5,140 80,121 34,245 37,724 21,291 43,339 46,035 47,342 49,699 1995 1.622 2-314 2,399 3,497 17 2,042 3.937 10,996 12.413 13-310 13,895 14,493 S1L.050 247 261 272 234 4,373 4,324 5.036 3.253 92.739 27,555 101,419 105,734 43,442 50,359 $2,379 54,252 Ot F. ACCUM PRES WORTH OF ENERGY MILLS/KWH 2% s% 7% o% 1938 1,097 1,135 1.1463 1,201 19389 1,214 1,260 1,299 1,339 1990 1,324 1,377 1,421 1,467 1991 1,423 1,486 1,535 1,536 1992 1.5526 1,589 1,642 1,697 1993 1,619 1,686 1,742 1,801 1994 1,714 1,787 1,347 1,912 1993 1,304 1,382 1,946 2,015 S@-€-9 1. LOAD DEMAND DEMAND - KW ENERGY - MWH 2. SOURCES - KW A. EXISTING OIESEL LOCATION OR UNIT 1 CONE WaWE B. ADDITIONAL DIESEL UNIT 1 MPN C. EXISTING ALTERNATE WNIT 1 D. ADDITIONAL ALTERNATE WNIT 1 3 TOTAL CAPACITY - kW LARGEST UNIT FIRM CAPACITY SURPLUS OR (DEFICIT) - KW GROSS ALTRNT CAPACITY = MWH GROSS DIESEL CAP - MWH ‘ DIESEL GENERATION - MWH POWER COST STUDY COAL GASIFIER GENERATING PLANT 1930 2,450 11,300 4-325 1,025 3,200 1.350 33,288 11,300 1931 2,700 13,900 soo soo 1,025 1,000 900 200 4,325 1,925 3,300 1,100 33,283 13,000 1932 3,000 14.4600 500 soo 1,028 1,000 200 900 1933 34200 790 4.325 1.025 34200 600 33,298 15,700 1934 3,750 13,950 2.500 7.325 2,500 4,325 1,075 21,900 42-267 631 1935, 4,100 20,750 500 S00 1,025 1,000 900 900 21,2900 42,247 9438 1986 4,500 22,750 1937 4,200 24,750 ALTERNATE D 9@-€-9 1938 1. LOAD DEMAND DEMAND - KW 5,350 ENERGY - MWH 27,050 2. SOURCES - KW A. EXISTING DIESEL LOCATION OR UNIT 1 soo 2 500 3 1,025 4 +000 s 200 6 200 7 = 2 - 2 = 10 - 11 - 12 - B. ADDITIONAL DIESEL UNIT 1 - 3 a 4 - s = a = C. EXISTING ALTERNATE UNIT 1 - 2 a D. ADDITIONAL ALTERNATE UNIT 1 2,500 2 2,500 3 a TOTAL CAPACITY - KW 9,825 LARGEST UNIT 2,500 FIRM CAPACITY 7.325 SURPLUS OR (DEFICIT) - kW 1,975 GROSS ALTRNT CAPACITY - MWH 43,300 GROSS DIESEL CAP - MWH 64.167 DIESEL GENERATICN - MWH 35. 1989 5.350 27,750 soo soo 1,025 1,000 2.500 2,500 2.325 2.500 7.325 1,475 43,300 64,147 137 1990 6,400 32.250 2,500 2-500 2,325 2.500 75325 925 43,300 64,167 464 1991 7,000 35,350 500 soo 1,025 1,000 300 300 2,500 2,500 9,825 2,500 7,325 325 43,900 64.167 866 1992 7,700 38,750 S00 S00 1,025 1,000 300 300 2,500 2,500 9,325 2,300 7,328 (375) 43,300 44,167 14430 1993 1994 3,500 9,300 42,250 46,450 500 500 soo soo 1,025 1,025 1,000 1,000 300 900 200 200 2,500 2,500 2,500 2,500 i” 2,500 9,325 12,325 2,500 2,500 7325 9,325 (1,175). s2s 43,300 65,700 64,157 346,067 2151 520 1995 10,200 51,050 2,500 2,500 2.500 12,32 2,500 9,825 (375) 65,700 34,067 1,072 Le-€-9 3. INVESTMENT COSTS ($1000) 1980 DOLLARS A. EXISTING DIESEL B. ADDITIONAL DIESEL UNIT 1 a \« o> WBWh C. EXISTING ALTERNATE D. ADDITIONAL ALTERNATE UNIT 1 2 3 E. TRANSMISSION PLANT ADDITIONS UNIT 1 2 F. MISCELLANEOUS ADDITIONS UNIT 1 TOTAL ($1000) 1980 DOLLARS INFLATED VALUES 4. FIXED COST ($1000) INFLATED VALUES A. DEBT SERVICE 1. EXISTING 2. ADDITIONS SUBTOTAL 2% 3% 7% oz: B. INSURANCE 1980 1,376 1,376 1,376 104 1981 1,374 1,876 1,376 104 1982 1,376 1,876 1,876 104 1933 1,876 1,376 1,876 1984 1,876 10,176 13,168 104 452 472 372 1,069 1985 1,376 10,176 13,163 104 4as2 67? 372 1,069 43 1986 1,374 8,300 10,176 13,168 104 452 679 $72 1,069 45 1987 1,876 3,300 3.300 13,476 25,370 104 960 1,443 1,853 2.271 3s 82-€-9 TOTAL FIXED CAST ($1000) S. PRODUCTION COST ($1900) INFLATED VALUES A. OPERATION AND MAINT 1. DIESEL 2. ALTERNATE B. FUEL AND LUBE OIL TOTAL PRODUCTION COST ($1000) TOTAL ANNUAL COST ($1000) 2% 3% 7% on ENERGY REQUIREMENTS - MWH MILLS/KWH 2% s% 7% on C. PRESENT WORTH ANNUAL COST ($1000) 2% % 7% % D. ACCUMUL. ANN. COST ($1000) 2% Ss% 7% o% E. ACCUMULATED PRESENT WORTH ANNUAL COST ($1000) 2% S% 7% o% 1980 110 110 110 110 193 979 1,172 1,282 1,232 1,282 1,232 11,800 109 109 109 109 1981 110 110 110 110 1,136 1,403 1,513 1,513 1,513 1,513 13,000 116 116 116 116 1,414 1,414 1,414 1,414 2,795 2,795 2,795 2.795 2,696 25696 2,696 2496 1982 111 iit 11. 111 1,592 1,592 1,592 1,592 4,613 4,613 4,613 4,613 4,233 4,233 4,283 4,233 1933 iit tit 111 lit 1,733 2,010 2-121 2121 2,121 2,121 15,700 135 135 135 135 1,731 1,731 1,731 1,731 4,739 6,739 6,739 6739 6,019 6,019 6,019 6,019 1934 sos 325 1,013 1,215 434 2,147 2,784 3,384 3-611 3,304 4,001 18,950 179 191 201 2ut 2,582 2.755 2,902 3,052 10,123 10,350 10,543 10,740 8,601 3,774 8,921 9.071 1935, so? 326 1,019 1,216 10 659 2,447 3,116 3,715 3,942 4.135 4,332 20,750 179 190 199 209 2,649 2,811 2,948 3,089 13.338 14,292 14,673 15,072 11,250 11,585 11,969 12,160 1936 601 323 1-021 1,213 13 686 2.799 3,493 4,099 4,326 4,519 4,716 22,750 1380 190 199 207 2,731 2,833 3,011 3,142 17,937 13,613 19,197 19,738 13,931 14,443 14,330 15,302 1987 1,149 1,632 2,042 2,460 967 35145 4,112 5,241 5,744 6154 4,572 24,750 213 232 249 266 +276 3.577 3,932 4,993 23,193 24,342 25,351 26,360 17,257 18,045 18,712 19,395 67-€-9 F. ACCUM PRES WORTH OF ENERGY MILLS/KWH 2% 3% ™ % 1980 109 109 109 109 1931 217 217 217 aay 1982 326 326 326 326 1983 436 436 436 436 1934 S73 s32 539 S97 1985 7O1L 717 731 746 1936 321 344 264 334 1937 954 1,019 1,050 o€-€-9 1983 2. INVESTMENT COSTS ($1000) 1980 DOLLARS ~ A. EXISTING DIESEL 15876 B. ADDITIONAL DIESEL UNIT 1 - 2a - 3 2 4 = s S 6 - C. EXISTING ALTERNATE - D. ADDITIONAL ALTERNATE UNIT 1 8,300 2 3,300 3 - E. TRANSMISSION PLANT ADDITIONS UNIT 1 s 2 - F. MISCELLANEOUS ADDITIONS UNIT 1 - 2 = TOTAL ($1000) 1980 DOLLARS 18,476 INFLATED VALUES 25,370 4. FIXED COST ($1000) INFLATED VALUES A. DEBT SERVICE 1. EXISTING 104 2. ADDITIONS SUBTOTAL 2% 260 3% . 1,443 % 1,853 2% 2.271 B. INSURANCE . 33 1989 1,376 8,300 3,300 18,476 25,370 104 960 1,443 1,853 2,271 1990 1,876 8,300 3,300 18,476 25,870 104 960 1,442 1,353 271 and 1991 1,876 3,300 8,300 18,476 25,370 104 960 1,443 1,353 2,271 1992 1,375 3,300 3, 300 13,476 25,370 104 960 1,443 1,353 2.271 103 1993 1,876 3,300 8,300 18,476 25,870 104 960 1,443 1,353 2,271 107 1994 1.376 8,300 3,300 3,300 26.776 42,585 104 1,622 2,449 3.144 3,353 162 1995 1,876 3,300 3,300 8,300 26,776 42,585 104 15629 2,449 3-144 3.853 163 T€-€-0 TOTAL FIXED COST ($1000) 2% sn 7% o% S. PRODUCTION COST ($1000) INFLATED VALUES A. OPERATION AND MAINT 1. DIESEL 2. ALTERNATE B. FUEL AND LUBE OIL TOTAL PRODUCTION COST ($1000) TOTAL ANNUAL COST ($1000) 2% S% 7% % ENERGY REQUIREMENTS - MWH MILLS/KWH C. PRESENT WORTH ANNUAL COST ($1000) 2% 3% 7™% 9% D. ACCUMUL. ANN. COST ($1000) 2% S% 7% % E. ACCUMULATED PRESENT WORTH ANNUAL COST ($1000) 2% - S% 7% om” 1983 1,152 1,635 2,045 2.463 1,006 3.5746 4,582 5,734 S217 61627 7,045 27,050 212 230 245 260 3,337 3,618 3-357 4-100 23,932 30,579 31,978 33,405 20,594 21.663 22,569 23.495 1989 1,156 1.5639 2,049 2.467 1,044 4,092 5.140 61295 6.772 72139 7+607 29,750 212 223 242 256 +425 $1687 3,910 4,138 335,223 37,358 39,1467 31,012 24,019 25,350 25.479 27-633 1990 1,159 1,642 2,052 2,470 1,083 4,623 5,716 6,875 7,353 7+763 83,186 32,250 213 22! 241 254 35495 3,740 3,949 4,161 42,103 44,716 46,935 49,198 27.514 29,090 30.428 31,794 19971 15163 1,646 2,056 2.474 11 1,131 5S, 283 6,425 7,588 8,071 3.431. 3,399 35,350 215 22! 240 252 3,605 3,334 4,029 4,223 49,691 52,787 55,416 58,097 31,119 22 924 34,457 346.022 3 1,147 14650 2,060 2,478 3,408 3,391 9,301 9.719 33,750 a7 229 240 251 3,733 3,943 4,130 4.315 53,099 61,673 64,717 67,316 34,352 36.372 38,587 40,337 1993 1,171 1,654 2,064 2,432 =e 1,22 6,337 3,140 9.3L 9794 10,204 10,622 42,250 220 232 242 231 34864 4,064 4,234 4,408 67+410 71,472 74,921 78,433 38.716 40,936 42,321 44,745 1994 1,395 2.715 3,410 45119 3 1,607 757AL 9,406 11,301 12,121 12,314 13,525 46,450 243 261 276 291 4,383 4,701 4,970 5,245 73,711 33,593 37,737 91,963 43,099 45.4537 47.791 47,290 1995, 1,901 2.721 35416 4,125 17 1,671 8,937 10,625 12,526 13,346 14,041 14.750 31,050 245 261 * 275 239 4,540 4,337 5,089 5,346 91,237 96,939 101,778 106,713 47,639 50,474 $2,330 SS. 334 ze-E-9 F. ACCUM PRES WORTH OF ENERGY MILLS/KWH 2% Sn 7% % 1938 1,077 1,122 1,162 1,201 1989 1,192 1,246 1,294 1,340 1990 1,300 1,362 1,417 1,469 1991 1,402 1,470 1,531 1,589 1992 1,493 1,572 1,638 1,700 1993 1,589 1,663 1,738 1,304 1994 1,683 1,769 1,345 1,917 1995, 1,7 1.3 1,9 72 64 45 22 APPENDIX C-4 OTHER DETAILS APPENDIX C-4 OTHER DETAILS 1. SWGR_INTERTIES TO SMALL COMMUNITIES Parameters used: a) Buckland Hydro from C-3 in ¢/kWh b) Inflation: ? Fuel & lube oi] 10% to 1984, 6% thereafter O&M cost 8% to 1984, 4% thereafter c) Diesel generation at 8 kWh/gal d) Fuel Cost $1.20/gallon (1980-Base) Lube 011 10% of fuel e) SWGR tie lines: 1980-$ Construction $2,383,000 (from Section III) 1985-$ Construction $3,371,727 Annual Costs: Maintenance at 1% of investment (1985) $ 33,720 TABLE C-4.1 UNIT COST OF POWER FOR SMALL COMMUNITIES Energy Diesel Generation Required Fuel Buckland & SWGR Annual /Lube O&M Total Lines ¢/kWh Year Mwh ¢/kWh ¢/kWh ¢/kWh at 9% Interest 1986 2521 26.4 4.4 30.8 59.1 + .01 = 59.11 1987 2626 27.2 4.6 31.8 54.5 + .01 = 54.51 1988 2732 28 4.8 32.8 51.1 + .01 = 51.11 1989 2837 28.8 5 33.8 46.7 + .01 = 46.71 1990 2943 29.7 5.2 34.9 43.3 + .01 = 43.31 1991 3053 30.6 5.4 36 40.5 + .01 = 40.51 1992 3163 31.5 5.6 37-1. 37.2 + .01 = 37.21 1993 3273 32.4 5.8 38.2 35.0 + .01 = 35.01 1994 3383 33.4 6 39.4 32.0 + .01 = 32.01 1995 3493 34.4 6.2 40.6 29.8 + .01 = 29.81 1 from KTEA, Dec. '79 record. apal2/b C-4- 1 Appendix C-4 - Other Details ELECTRIC HEAT FOR KOTZEBUE Parameters used: a) Residential consumers only b) Average heating load per residence based on 16039 heating degree days. Insulation level of R-11 and 2 Airchanges per hour building size 30'x30' 202 x 10® Btu/year at 70% furnace efficiency and 138 Btu/gallon 2,100 gallon of fuel or 59,000 kWh electric energy c) Resistance heat installed 1980-$ 20 kW @ $120/kW 2,400 /residence Control equipment 120 /residence 2,520 /residence d) Central station control equipment (Sangamo System 5) 50,000 Note: Potential need for larger distribution transformers, service drops and service entrance equipment has not been taken into account. apal2/b C=4-72 APPENDIX D BIBLIOGRAPHY Alaska State Housing Authority; Kotzebue, Alaska, Comprehensive Development Plan; Anchorage; March 1971. Alaska, State of, Department of Commerce and Economic Development; Jobs and Power for Alaskans; July 1978. Alaska, State of, Department of Commerce and Economic Development, Division of Energy and Power Development; 1979 Community Energy Survey; 1979. Alaska, State of, Power Authority and Robert W. Retherford Associates; Service Contract; Anchorage; October 24, 1979. Alaska Consultants, Inc., Land Use Plan: Kotzebue, Anchorage; July 1976. Ashrae, Handbook of Fundamentals; American Society of Heating, Refrigerating, and Air-Conditioning Engineers, Inc.; New York; 1972. Author Unknown, "Advanced Thermomechanical Cycles"; EPRI Journal; October 1979. Author Unknown, "Cogeneration"; Power Engineering; March 1978. Author Unknown, Kotzebue: An Alaskan Community Profile; City of Kotzebue and State of Alaska, Division of Economic Enterprise; March 1978. Averitt, Paul, and Lopez, Lorreda, 1972, Bibliography and Index of U.S. Geological Survey Publications Relating to Coal, 1882-1970: U.S. Geol. Survey Bull. 1377. Averitt, Paul, 1974, Coal Resources of the United States: U.S. Barnes, F.F., 1967, Coal Resources of the Cape Lisburne-Colville River Region, Alaska: U.S. Geol. Survey Bull. 1242-E. Barnes, Farrell F., 1967, Coal Resources of Alaska: U.S. Geol. Survey Bull. 1242-B. Baumeister, Theodore, Avallone, Eugene A., and Baumeister III, Theodore, Editors; Marks' Standard Handbook for Mechanical Engineers; Eighth Edition; McGraw-Hill Book Company; New York; 1978. apal4/p D-1 Appendix D - Bibliography Bos, Peter G. and Williams, James H.; "Cogeneration's Future in the CPI"; Chemical Engineering; February 26, 1979. Bottge, Robert G., 1977, Coal as an Energy Source for Barrow —_- =< ——age ee ogee Alaska: U.S. Dept. of the Interior, Bureau of Mines, Situation Report. Brooks, Alfred H., and others 1905, Mineral Resources of Alaska 1904: U.S. Geol. Survey Bull. 259. Brooks, Alfred H., and others, 1906, Report on Progress of Investi- gations of Mineral Resources of Alaska in 1905: U.S. Geol. Survey Bull. 284. Brooks, Alfred H., and others, 1907, Report on Progress of Investi- gations of Mineral Resources of Alaska in 1906: U.S. Geol. Survey Bull. 314. Brooks, Alfred H., and others, 1909, Mineral Resources of 1908: U.S. Geol. Survey Bull. 379. Alaska, Brooks, Alfred H., and others, 1910, Mineral Resources of Alaska, Report of Progress of Investigations In 1909: U.S. Geol. Survey Bull. 442. Clark, Paul R., 1973, Transportation Economics of Coal Resources of Northern Slope Coal Fields, Alaska: Mineral Industry Research laboratory, University of Alaska, Fairbanks. Collier, Arthur J., 1906, Geology and Coal Resources of the Cape Lisburne Region, Alaska: U.S. Geol. Survey Bull. 278. Comtois, Wilfred H.; "Economy of Scale in Power Plants"; Power Engineering; August 1977. Considine, Douglas M., Editor-in-Chief; Energy Technology Handbook; McGraw-Hill Book Company, New York; C. 1977. Conwell, C. N. and Schell, L. C.; Energy Resources Map of Alaska; Alaska Department of Natural Resources, Division of Geological and Geophysical Surveys; 1977. Crane Co., Flow of Fluids through Valves, Fittings, and Pipes; Technical Paper No. 410; New York; 1974. Eisenson, Marc; "On-Site Power Generation for CII Facilities"; Specifying Engineer; November 1978. Fogleman, S. F.; Biomass Conversion Process for Energy Uses in Alaska; International Engineering Company, Inc.; San Francisco, 1979. apal4/p D=2 Appendix D - Bibliography Godfrey, Robert Sturgis, Editor-in-Chief; Building Construction Cost Data 1980; Robert Snow Means Company, Inc. ; 1979. Gruy Management Service Co., A Study of Alternate Fuel Sources for Barrow, Alaska; for U.S. Geological Survey; Dallas, Texas; january 1979. International Engineering Company, Inc., Hybrid Geothermal Wood Residue Power Plant; San Francisco; 1979. International Engineering Company, Inc., Power Generation Cost with Alternative Energy Sources; San Francisco; January 1978. Kilar, L.A.; "Wind Blows Anew"; Power; May 1979. Kotzebue Electric Association, Inc., Power Requirements Study: Alaska 13 Kotzebue; Kotzebue; April 1978. Lyle, William M., and Bragg, Nola J., 1974, Coal Bibliography for Alaska: State of Alaska, Division of Natural Re Resources, Div. of. Geological and Geophysical Surveys, Alaska Open-File Rept. 41. McGee, D.L., and O'Connor, Kristina M., 1976, Mineral Resources of Alaska and the Impact of Federal Land Policies on Their Avail- ability - Coal: State of Alaska DNR, Div. of Geological and Geophysical Surveys, Open-File Rept. 51. Moffitt, Fred H., 1905, The Fairhaven Gold Placers, Seward Penin- sula, Alaska: U.S. Geol. Survey Bull. 247. Muffler, L.J.P. Editor; Assessment of Geothermal Raveurces of the ton, VA; 1979. Neal, Gordon W.; "Advantages of Combined Power/Process Generating Plants"; Power Engineering; February 1977. Oliker, I., "Cogeneration Power Plants Serve District Heating Systems"; Mechanical Engineering; July 1978. Othmer, Donald F.; "“Energy-Fluid Fuels from Solids"; Mechanical Engineeing; November 1977. Rao, P. Dharma, and Wolff, Ernest N., eds., 1975, Focus On Alaska's Coal md Proceedings of Conference. Fairbnaks, Ala Alaska, MIRL Rept. 37. Retherford, Robert W., Associates and Arthur Young and Company; Alaska Village Electric Cooperative Cost of Service Study; for State of Alaska Public Utilities Commission; November 1977. apal4/p D- 3 Appendix D - Bibliography Retherford, Robert W., Associates; Bristol Bay Energy and Electric Power Potential (Draft); for U.S. Department of Energy; A Anchorage; October 1979. Retherford, Robert W., Associates; Construction Work Plan, 1978-1980, Kotzebue Electric Association, Ine. ; Anchorage; August 19 1978. Retherford, Robert W., Associates; Economical Evaluation of a 4.5 Electric Association, Inc.; Anchorage; July 1978. Retherford, Robert W., Associates; Feasibility Study for the Conversion of System Voltage; for Kotzebue Electric Association, Inc.; Anchorage; ipriy 37 1979. Retherford, Robert W., Associates; Power Requirements Forecast 1979-1990; for North Slope Borough; Anchorage; August 1979. Retherford, Robert W., Associates; Project Closeout Documents, 1977 Power Plant Addition, Kotzebue Units 7&8, 2000 kVA; Anchorage; July 1978. Retherford, Robert W., Associates; Waste Heat Capture Study for State of Alaska; Anchorage, Alaska; June 1978. Retherford, Robert W., Associates; 1976 Power Cost Study for Kotzebue Electric Association, "Ine. ; Anchorage, November 1976. Schweiger, Robert G.; "Burning Tomorrow's Fuels"; Power; February 1979. Selkregg, Lidia L.; Alaska Regional Profiles: Northwest Region; University of Alaska, Arctic Environmental Information and Data Center; California 1976. Singh, Ram Bux; Bio - Gas Plant; Mother's Print Shop; Henderson- ville, NC; 1975. Solar Energy Resource Institute, Wind: An Energy Alternative; Golden Co.; August 1979. Solt, J. C.; "Cogeneration for Industrial Plants"; Specifying Engineer; August 1978. Tailleur, I.L., 1965, Low-volatile Bituminous Coal of Mississippian Age on the Lisburne Peninsula, Northwestern Alaska: U.S. Geol. Survey Prof. Paper 525-B. Tetra Tech, Inc., Energy From Coal; U.S. Energy Research and Develop- ment Administration; Washington, D.C.; ca. 1976. apal4/p D- 4 Appendix D - Bibliography Toenges, Albert L., and Jolley, Theodore R., 1947, Investigations of Coal Gaposits for Local Use in the Arctic Regions of Alaska and Proposed Mine Development: “U.S. Bureau of Mines, Rept. Inv. 4150. U.S. Department of the Interior, 1916, Regulations Governing Coal-Land Lease in the Territory of Alaska. United States Department of Energy; Solar Energy from Photovoltaic Conversion; Washington, D.C.; March 1978. Young, Arthur and Company; A Discussion of Considerations Pertaining to Rural Energy Policy Option ; State of Alaska Department of Commerce and Economic Development, Division of Energy and Power Development; April 1979. apal4/p D- 5 APPENDIX E LETTERS & COMMENTS apal8/a5 APPENDIX E-1 LETTER FROM STATE OF ALASKA DEPARTMENT OF FISH AND GAME apal8/a6 DEPARTMENT OF FISH AND GAME -; 1300 COLLEGE ROAD FAIRBANKS, ALASKA 99701 February 1, 1980 Dora L. Gropp, P.E. Robert W. Retherford Associates P.O. Box 6410 Anchorage, Alaska 99502 Dear Ms. Gropp: Re: Kotzebue Area Hydroelectric The Alaska Department of Fish and Game has reviewed your reconnaissance study for hydroelectric potential in the Kotzebue area. While we have no objection to the reconnaissance level study, we feel that your proposal is premature. We know that chum, pink and King salmon, char, pike, whitefish, burbot and grayling are present in the Buckland River and most utilize the Buckland River for spawning and rearing. In addition, caribou and moose utilize the 25,000 acre projected impoundment area for feeding and migration routes. This Department recognizes the need for work toward alternate energy sources, but we insist on orderly and appropriate organization of activities toward development of these sources for the greatest beneficial yield with the least detrimental impact. Thank you. Sincerely, (MawK Sonabc2 Alan H. Townsend Habitat Biologist III Habitat Protection Section cc: W. Copeland - ADL Fairbanks D. Lowery - ADEC Fairbanks C. Johnson - BLM Fairbanks APPENDIX E-2 LETTER FROM ALASKA POWER ADMINISTRATION DEPARTMENT OF ENERGY apal8/a7 Department Of Energy Alaska Power Administration P.O. Box 50 Juneau, Alaska 99802 Ms. Dora L. Gropp Robert W. Retherford Associates P.O. Box 6410 Anchorage, AK 99502 Dear Ms. Gropp: We are interested in your assessment of hydroelectric power generation alternatives in the Kotzebue area and have some information on the hydroelectric potential in the area that may be useful. Our inventory of potential hydroelectric sites in Alaska identified seven sites near Kotzebue 2,500 kW or larger. They are marked on the enclosed list as sites 4 through 10. Three of the sites are on the Noatak River, two on the Kobuk, one on a tributary to the Kobuk, and one on the Buckland River. Rough inventory grade calculations were made on all the sites and more detailed information on a few of these is avail- able in our office. The only site that we have done fairly thorough studies on is the Agashashok site on the Noatak River. The dam site is in the Noatak Canyon 25 miles north of Kotzebue and was field surveyed in 1967. At the same time a surface geology study was prepared which included river soundings and shallow geophysical measurements. There are several problems with development of the Agashashok powersite. First, it would block the mainstem of the Noatak fiver For Rigratory sheefish and salmon and flood a considerable area of wildlife nesting area. Secondly, the installed capacity of full development would be roughly 186 MW, which is considerably larger than the 5- to 10-MW power potential needed in the Kotzebue area. Thirdly, the land status of the Agashashok dam and reservoir site is still unsettled and under proposed legislation, would become, as a minimum, a National ecological preserve. The upstream sites on the Noatak River, Misheguk and Nimiuktuk, face similar legis- lative land classifications which could preclude their development. The Kobuk River site and the Upper Kobuk River site, number 7 and 9 on the enclosed list, face some of the same mainstem river problems for development as the Noatak River. In addition, any transmission lines along the Kobuk River would have to cross the existing Kobuk National Monument. 2 The Kogoluktuk River, number 8 on the enclosed list, was recently exam- ined by Alaska Power Administration in a flight over the area in con- junction with another study, and we have pictures of the dam site and waterfalls immediately downstream from the potential dam site. The U.S. Geological Survey is currently doing intermittent streamflow measure- ments as part of a research project on the Kogoluktuk River, A stream flow of 2,500 cubic feet per second was measured last August, and a March 1980 streamflow measurement is scheduled to obtain a low winter flow. This site appears to have promise but would be roughly 150 miles east of Kotzebue and encounter the same transmission line difficulties of permafrost and crossing the Kobuk National Monument that the other Kobuk River dam sites would have. We feel wind generation may have a potential for at least supplemental energy in the Kotzebue area. Two wind generators in the Kotzebue area were noted during our recent visit to the area on a hydropower inventory for the Alaska Village Electric Cooperative. One wind generator is near the Senior Citizen Center in Kotzebue and the other is on the bank of the Ambler River, roughly one-half mile northeast of Ambler. Both machines appeared to be in the 2-kilowatt to 10-kilowatt size range. Neither one was turning the days we observed them. The owners of these wind machines may have useful data about the wind duration and applica- bility of wind generation to meet local needs. If you should care to examine our inventory site plans, maps, calcula- tions, or other reports, feel free to contact us. Sincerely, Robert J. Cross Administrator Enclosures