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Home My WebLink AboutBristol Bay Regional Power Plan Interim Feasibility Assessment Volume 2 - Appendices 1982_·· __ ........ ______ ........ _. __ .'.~._ .. _'_.'M_'. ___ .. ,_ ..... ,"_,,_._,, .• ,,~ ..... _,_." __ .. _ ---------_. --- CONTRft CT No_ CC .. 08 -2108 B R.II S "lr () L ~I~ JI~ 'li~1' It E GilD N ,~~ L ~:~ () \J\lIE I;;:: If"l. ~t\ Irl~II'1 11]1 E'·r)\ I LEI) F IE A:S m 181 LifT l' Jl!~ lr~ ,~\.Il" "11' S :~~':il r ."." . ; '" '''''', J ! " i I I i :' I' : \ I ; ) . ! ,.., '. ! I ~ I ,; \ • I " I ,'! I. i, . ., • • u .. ,.. I·..,,,, •. " .. , & Stone & Webslll!l En~gin4~(:~ring Corp{ratiol1 -----,~~ ILASli A I~'f,,~~r gi~11 J\.I_r,rtlI1411'llt 1"llr'l( ,-. -.-.-------_._--'-'",' .... ~ .... -,-,.,--- VOLUME 1 -REPORT GENERAL OUTLINE BRISTOL BAY REGIONAL POWER PLAN DETAILED FEASIBILITY ANALYSIS INTERIM FEASIBILITY ASSESSMENT VOLUME 2 -APPENDICES APPENDIX A -ENGINEERING/TECHNICAL CONSIDERATIONS A.I A.2 A.3 A.4 A.5 A.6 A.7 A.8 A.9 A.I0 ENERGY NEEDS HYDROELECTRIC POWER PROJECTS DIESEL POWER WASTE HEAT RECOVERY ENERGY CONSERVATION WIND ENERGY POWER TRANSMISSION FOSSIL-FUEL ALTERNATIVES ORGANIC RANKINE CYCLE LOAD MANAGEMENT ANALYSIS APPENDIX B ENERGY SUPPLY TECHNOLOGY EVALUATION APPENDIX C -ENERGY DEMAND FORCAST VOLUME 3 -APPENDICES APPENDIX D -WIND ENERGY ANALYSIS APPENDIX E -GEOTECHNICAL STUDIES -TAZIMINA RIVER APPENDIX F -GEOTECHNICAL STUDY -NEWHALEN RIVER VOLUME 4 -APPENDICES APPENDIX G -ENVIRONMENTAL REPORT APPENDIX H -NEWHALEN SMOLT AND FRY STUDIES APPENDIX I -HYDROLOGIC EVALUATIONS -TAZIMINA RIVER ... .... - - - APPENDIX A ENGINEERING/TECHNICAL CONSIDERA TIONS A.l.l Introduction APPENDIX A. 1 ENERGY NEEDS The energy needs of the Bristol Bay study region have been evaluated and are being reported in the final report by the Institute of Social and Economic Research (ISER) of the University of Alaska. These needs address varying conditions within the study area such as baseline situations, historical data, prospects for economic and energy growth, and other parameters relating to and affecting the energy needs of the ~egion. Village profiles of energy needs and use developed and reported in the final ISER report address distinguishing features of household stock such as baseline data, energy movements, energy growth, and energy use aspects. Data from this report will be used in the detailed feasibility analysis efforts to be performed during Phase II of the study. From past studies of the region and of other rural areas it is recognized that the two predominant energy forms affecting the study area are electrical energy needs and space heating needs, including energy needs for hot water heating. These major energy needs have been determined by ISER. They are discussed in detail in Appendix C, which is ISER I S preliminary report on energy demand forecast for the study region. A copy of this report was made available in mid-January 1982 for our use in the continued study efforts under Phase I. The energy forecast data given by Appendix C had to be further analyzed in order to develop data that could be used for the alternative plan studies and evaluation. The approach and methodology for performing these analyses is described in this appendix. A. 1.2 Electric Energy Needs The end-use application of electrical energy relates to two predominant areas: appliance end-use and space heating end-use, including the heating of hot water. A.l-l The electrical energy and power (demand) requirements of the study region were previously studied by Retherford (Ref land 2) and are as shown in Tables A.l-l and A.1-2. These data have been interpreted to reflect the results of evaluations and assumptions taken for the development of a band of possible electrical energy needs which is contained between the given "Low Load Growth" scenario and the "High Load Growth" scenario. Although it is believed that these referenced forecasts address the appliance end-use of electrical energy, it is not clear whether they also include some energy-power needs which relate to electrical space heating and/or electric hot water end use. Because of this uncertainty, it is assumed that they only reflect an "appliance" end-use. These data are referenced because of their use in development of power needs as these power needs pertain to preliminary electrical energy forecast by ISER. Under its preliminary electrical energy-power forecast needs, ISER has developed only the regional energy (MWh) needs as given in Tables A.1-3 and A.I-4. The electrical energy needs shown respond only to appliance end-use. Electric space heating and hot-water usage is assumed not to occur under this forecast. Data on electrical power (kW) has been made available in the final ISER report and will be used in Phase II studies. The reference energy needs from the low load and high load growth Retherford scenarios and the energy needs, as developed by ISER under its preliminary forecast report, are graphically shown on Figure A.I-l. As can be seen from this figure, the ISER energy projection tends to parallel the low load growth band. This is principally because the ISER projection was made to be consistent with the original interpretation of the base plan study scenario. This scenario reflects the primary dependence on diesel power generators for electricity. It assumes that electricity prices escalated at 2.6 percent above inflation and that the effect of state intervention to lower electricity prices continues throughout the projection period, consistant with levels experienced in 1980 and 1981; the projections also assume no dramatic changes in electricity end-use patterns from those observed in the recent past. Electricity space heating is assumed not to occur in this forecast scenario by ISER. Data on energy A.1-2 .. --- .... ---- -.. .. -- .. • • -• • ... -.. • .. .. (MWh) needs by sector by village community were made available by ISER for only the years 1980 and 2002. Similar energy data for intermediate years were calculated on the basis of parameters, growth assumptions, rates of changes, and appliance saturation and other factors developed by ISER and presented in Appendix C. Data on electrical power (kW) needs were not made available by ISER at the same time as the energy (MWh) demand data that is contained in its preliminary report (Appendix C). Power data were therefore calculated using both the energy-power data as developed by Retherford, ISER's energy data, and the following procedure: a. For each of the five-year intervals (1980 to 2000) of both the low and high electrical energy and power requirements forecast by Retherford and for each of the villages, the average yearly power (kW) required was calculated from the energy (MWh) stated by the forecast for that year. Ratios of the "peak demand" (kW) power values given by the Retherford forecast to these average yearly power (kW) values were made. These ratios, which varied for each of the villages and for each of the five-year intervals, are graphically shown by Figures A.1-2 through A.1-14. b. The yearly energy needs of each village for the intermediate years were calculated using energy (MWh) data made available by ISER for each village and for the years 1980 and 2002, and the parameters, assumptions, rates of change, and other criteria established by ISER in its preliminary forecast report. c. For each of the years (1980 to 2002) and for each village the average yearly power (kW) was calculated as required to give the calculated energy (MWh) needed by the village. d. A comparison of the ISER village energy forecast was made to the Retherford energy forecast for that village. A ratio curve of peak demand to average demand was then evaluated on the basis of this energy comparison and plotted on Figures A.1-2 through A.1-14 as the A.1-3 "ISER"curve. This curve was used to calculate the peak demand of power (kW) that would apply to each village for each year of data. The results of this methodology and approach are summarized, on the basis of five-year forecast periods, by Table A.I-S. These five-year energy and power forecasts, as well as the forcasts for the intermediate years, were used in the sizing of electrical energy/power installations, whether these may be diesel, wind, hydroelectric, or some other identified suitable energy resource. Because several of the interim phase power plan study scenarios consider the regional energy and power needs, it was necessary to determine the monthly load demand requirements that would be representative of a regional power system. In calculating these monthly needs, use was made of energy and capacity (power) load curves representative of load data conditions existing within the region. The two main energy areas within the region are those served by Nuskagak Electric Co-operative, Inc., namely, the Dillingham grid, and by Naknek Electric Association, namely, the Naknek-King Salmon grid. Energy/capacity data available from these electrical energy suppliers were used to develop typical energy and capacity load curves for each of these areas. These curves are shown by Figures A.I-IS through A.I-IB. Similarly, energy/capacity data was obtained from the Alaska Village Electric Cooperative relating to the New Stuyahok village. These data were used to develop typical energy/capacity curves for the rural villages, that is, villages whose energy needs are not predominantly dependent on or affected by the fish processing industry. The load curves for these rural villages are shown by Figures A.I-19 and A.I-ZO. Data relating to fish processing villages were not readily available; as such, load curves based on data and assumptions given by Retherford were developed, and these are shown by Figures A.I-ZI and A.I-Z2. The developed energy/capacity curves were used to calculate monthly energy/power values for villages individually, in groups, or on a regional A.I-4 • .. -- ., .. • .. • - • • II' • • ., • .. .. • -.. .. -.. basis, depending on the interest and needs for responding to particular study scenarios; these curves were also used to determine transmission line needs such as preliminary design criteria and cost. The resulting data are too voluminous to include in this interim report; however, the monthly energy and power data developed for the forecast year 2002 are included. These data are given in Table A.1-6. From these data, the average monthly energy need is 5,646 MWh/month. The average monthly power (kW) need is 7,734 kW. The peak power (kW) need is shown to occur in July and has a forecast value of 13,614 kW. Assuming that a 10 percent loss factor would occur as a result of power plant generating needs, transmission line losses, and distribution and other losses, the gross energy and peak power needs on a regional basis are about 74,500 MWh/year and 15,000 kW, respectively. In general, in the conceptual development of electric energy and power generating facilities, the application of a 10 percent loss factor has been assumed, and the forecasted energy and power needs have been increased accordingly. However, because of the remoteness of identified hydroelectric power projects to major load centers and the need for extensive transmission lines, the installed capacity (kW) as these regional development was increased from 15,000 kW to 16,000 kW. This is a conservative approach and does result in some additional increase in investment cost for these power plans. A similar approach was applied to singular fossil-fueled regional power plans, except for diesel installations, where the 10 percent criteria was retained. A.l.3 Space Heating Energy Needs Space heating energy needs of the region are presently being met by the use of wood, to a certain extent, and by some electric space heating, but predominantly by the use of fuel oil. The analysis of space heating energy demand, based exclusively on heating oil consumption has been developed by ISER in a preliminary forecast which addresses the residential, commercial/government, industrial, and military sectors of the Bristol Bay study region. Also, the analysis implicitly assumes that conservation A.1-5 measures are not performed on either residentail or commercial/government structures. Initial data on space heating demand forecasts by ISER and used in the interim phase of the study, given by village and sector, are summarized in Table A.1-7. The impressive fact relating to the forecast values of space heating needs is their magnitude. This is five times or more that of the electrical energy-power forecast previously described. The space heating requirements of the total region, reflecting specific sector needs, are shown by the pie diagram in Figure A.1-23; these sector projections are graphically represented in Figure A.1-24. As can be seen from these figures, the greatest needs for space heating relate to the commercial/government and residential sectors. As previously stated, these spacing heating values also include an energy need for cooking or water heating by the residential, commercial/government, military, and industrial sectors. It is estimated that this component of the total fuel needs is about 7 to 12 percent in the residential sector and possibly twice that amount in the remaining sectors. Applying these estimates to the appropriate sectors, energy needs are determined to be as given in Table A.1-8. The results from this table, can be summarized as follows: Energy Needs Energy Needs For Hot Water For Space Year and Others (MWh) Heating (MWh) Total (MWh) 1980 20,536 119,019 139,535 1982 23,316 134,941 158,257 1987 30,261 174,746 205,007 1992 37,208 214,553 251,761 1997 44,153 254,358 298,510 2002 51) 100 294,163 345,263 A.1-6 .. -... .. - 0-. .. ., .. -.. .. .. ., • II' • .., .. • .. ., - .... -- Figure A.1-25 can be used to determine the monthly space heating needs, for any form of energy. This figure relates the percentage of monthly degree days to the total yearly degree day value for the Bristol Bay study, where this value is taken at the average of 11,500 degree days. As an example: a. Space heating needs for the year 2002 are shown as 294,163 MWh. b. It is assumed that these needs are to be met by electrical energy. • From Figure A.1-25, the maximum space heating demand occurs in January and is 14.68 percent of the total yearly. Therefore, (0.1468) (294,163 MWh) = 43,183 MWh/of energy must be supplied in January of year 2002. • To supply 43,183 MWh/of energy, the average generated monthly power need is estimated as: 43, 183 MWh x 1 month x 1 day = 58 MW month 31 days 24 hours This relates to an approximate total regional electrical peaking demand capacity of some 58 MW for space heating and 16 MW for electrical energy, or 74 MW total. It is doubtful that firm electrical energy would be cost effective for use in meeting space heating energy needs, unless it were being provided by a low cost, renewable generating resource such as hydroelectric power. As an example, assume. the cost of fuel oil for heating at the Dillingham-Naknek area is approximately $1.46/gal. This source of fuel is equivalent to about assuming about 138,000 Btu/gallon and an heating system of approximately 73 percent. 100,000 Btu of net energy, effective efficiency of the In order to supply 100,000 Btu of net energy using electric heat (with baseboard heating assumed at 100 percent efficiency), 29.3 kWh of electrical energy would be needed. This A.1-7 energy would have to cost to the consumer $1.46/29.3 kWh = $O.OS/kWh, or less, to be equivalent to present fuel oil energy. Similarly, for areas where the fuel oil cost $2.80/gal, the equivalent electrical energy cost for heating would have to be about $O.lO/kWh. These costs do not reflect the costs as may be required for converting to electrical space heating; therefore, an even lower unit cost of electrical energy must be attained in order to realize a conversion to electric heating. A.l.4 Effect of Low-Cost Energy on Electrical Demands It should be recognized that if electrical energy costs to the consumer in the range of $0. OS/kWh to $O.lO/kWh occur, there is a good potential for some switching to the use of electricity for cooking, hot water heating, and particularly for additional "appliances" end-use. The sensitivity to the electrical energy end-use for appliances, space heating, water heating, and other needs resulting from low cost energy have been evaluated by ISER in its final report and will be used during Phase II studies. A.l-8 III! -.. .. • -.. - .. • • • • .. • -., .. -.. -• References for Appendix A.l 1. R. W. Retherford Associates, "Bristol Bay Energy and Electric Power Potential -Phase I", prepared for the Alaska Power Administration, December 1979. 2. R. W. Retherford Associates, "Reconnaissance Study of the Lake Elva and other hydroelectric power potentials in the Dillingham area", prepared for the Alaska Power Authority, February 1980. A.I-9 TABLE A.1-1 DEMAND FORECAST BY R. W. RETHERFORD ELECTRIC ENERGY AND POWER REQUIREMENTS LOW LOAD GROWTH Location 1977 1980 1985 1990 1995 Dillingham Energy (MWh/year) 4769 5930 8500 11070 13521 Demand (kW) 1200 1500 2040 2580 3115 Naknek/King Salmon Energy (MWh/year) 11691 12526 15648 18770 20923 Demand (kW2 2700 2550 3190 3830 4265 Subtotal Dillingham/ Naknek Energy (MWh/year) 16460 18456 25148 29840 34444 Demand (kW2* 3600 4050 5230 6410 7380 Clark's Point Energy (MWh/year) 152.7 160 175 191 537 Demand (kW) 45 46 51 55 153 Egegik Energy (MWh/year) 101. 9 413 966 1517 1600 Demand (kW) 40 600 645 690 730 Ekuk Energy (MWh/year) 21.3 188 195 203 290 Demand (kW) 6 214 224 233 260 Ekwok Energy (MWh/year) 167.4 178 198 218 257 Demand (kW) 50 51 57 62 65 Igiugig Energy (MWh/year) 79.1 145 155 166 199 Demand (kW) 25 41 45 48 51 Koliganek Energy (MWh/year) 160.1 170 188 206 296 Demand (kW) 50 50 54 58 73 Levelock Energy (MWh/year) 171. 7 183 205 228 343 Demand (kW) 50 52 58 65 85 Manokotak Energy (MWh/year) 197.8 257 264 271 398 Demand (kW) 58 73 77 80 100 New Stuyahok Energy (MWh/year) 203.1 232 256 280 384 Demand (kW) 100 115 100 100 100 Portage Creek Energy (MWh/year) 83.3 110 134 156 190 Demand (kW2 24 31 38 45 48 2000 15972 3650 23076 4700 39048 8350 883 250 1683 770 378 287 297 68 232 53 386 88 458 105 120 120 480 110 224 50 " .. ~ ... Location TABLE A.1-1 (cant) DEMAND FORECAST BY R.W. RETHERFORD ELECTRIC ENERGY AND POWER REQUIREMENTS LOW LOAD GROWTH 1977 1980 1985 1990 Subtotal -10 villages Energy (MWh/year) 13384 2036 2736 3436 Demand (kW2* 448 1273 1349 1436 Iliamna/Newhalen Energy (MWh/year) 1000 1382 1571 1761 Demand (kW2* 285 315 357 400 Total 1995 4494 1665 1955 445 Energy (MWh/year) 18798.4 21874 28455 35037 40893 Demand (kW)* 4333 5638 6936 8246 9490 ""Noncoincident Note: System losses not included. REF: Report by R.W. Retherford Associates, Dated February, 1980 2000 5552 1901 2149 90 46759 10741 Location Dillingham Energy (MWh/year) Demand (kW) Naknek/King Salmon Energy (MWh/year) Demand (kW2 TABLE A.1-2 DEMAND FORECAST BY R.W. RETHERFORD ELECTRIC ENERGY AND POWER REQUIREMENTS HIGH LOAD GROWTH 1977 1980 1985 1990 4969 6574 12827 19080 1200 1500 2730 3960 11691 14086 22044 30002 2400 "2870 4495 6120 Subtotal Dillingham/ Naknek Energy (MWh/year) 16460 20660 24871 49082 Demand (kW)* 3600 4370 7225 10080 Clark's Point Energy (MWh/year) 152.7 184 879 1574 Demand (kW) 45 52 326 600 Egegik Energy (MWh/year) 101. 9 1040 2316 3591 Demand (kW) 40 600 980 1350 Ekuk Energy (MWh/year) 21.3 198 233 269 Demand (kW) 6 226 267 308 Ekwok Energy (MWh/year) 167.4 203 330 457 Demand (kW) 50 58 94 130 Igiugig Energy (MWh/year) 79.1 158 225 292 Demand (kW) 25 45 65 85 Koliganek Energy (MWh/year) 160.1 190 356 523 Demand (kW) 50 54 102 150 Levelock Energy (MWh/year) 171. 7 209 419 629 Demand (kW) 50 60 120 180 Manokotak Energy (MWh/year) 197.8 338 678 1018 Demand (kW) 58 97 194 290 New Stuyahok Energy (MWh/year) 203.1 267 460 653 Demand (kW) 100 100 143 186 Portage Creek Energy (MWh/year) 83.3 120 198 275 Demand (kW2 24 34 57 80 1995 2000 32298 45516 6310 8660 40591 51180 7930 9740 72889 96696 14240 18400 1894 2215 725 850 3642 3692 1380 1400 948 1628 619 930 982 1507 238 345 410 528 103 120 1014 1505 248 345 948 1467 235 290 1728 2439 425 560 118.3 1713 288 390 372 468 94 107 Location TABLE A.1-2 (cant) DEMAND FORECAST BY R.W. RETHERFORD ELECTRIC ENERGY AND POWER REQUIREMENTS HIGH LOAD GROWTH 1977 1980 1985 1990 Subtotal -10 villages Energy (MWh/year) 1338.4 2907.0 6094 9281 Demand (kW2* 448 1326 2348 3369 Iliamna/Newhalen Energy (MWh/year) 1000 1543 2215 2887 Demand (kW2* 285 352 506 660 Total Energy (MWh/year) 18798.4 25110 43180 61250 Demand (kW)* 4333 6648 10079 14109 *Noncoincident Note: System losses not included. 1995 13121 4355 5578 1190 91588 19785 REF: Report by R.W. Retherford Associates, Dated February, 1980 2000 16982 5337 8270 1720 121948 25457 Year 1980 1982 1987 1992 1997 2002 TABLE A.I-3 BRISTOL BAY POWER PLAN OVERALL ELECTRIC ENERGY DEMAND PROJECTIONS (MEGAWATT HOURS/YEAR) Residential CommercialLGov't Industrial Militar~ % of % of % of % of Total Total Total Total Total Total Total Total 4,459 16 9,629 34 8,248 30 5,600 20 4,936 16 10,957 36 8,879 29 5,600 19 6,249 17 15,083 42 8,952 25 5,600 16 7,937 18 20,789 48 9,025 21 5,600 13 10,060 19 28,642 54 9,098 17 5,600 10 12,743 19 39,632 59 9,098 14 5,600 8 1980-2002 Overall Average Annual Rate of Growth -Percent (%) (%) 4.89% 6.64% 0.45% 0% 4.06% SOURCE: ISER Report, Appendix C Region Total 27,936 30,372 35,884 43,351 53,400 67,073 TABLE A.1-4 BRISTOL BAY REGIONAL POWER PLAN ELECTRICAL ENERGY DEMAND PROJECTIONS BY CUSTOMER Number of Customers Elect. Consum~. ~er Customer (KWH) Total Electricit:£ Consum~tion (MWH) Seasonal Non-Seasonal Non-Seasonal Non- Residential Central Central Central Total Central Central Central Central Central Central Total 1980 810 68 82 960 5,152 1,308 2,401 4,113 89 191 4,459 1982 859 11 90 1,020 5,115 3,021 3,062' 4,445 215 216 4,936 1981 996 81 114 1,191 5,585 3,413 3,591 5,563 216 410 6,249 1992 1,154 91 145 1,390 6,046 3,829 4,222 6,911 348 612 1,931 1991 1,338 103 184 1,625 6,501 4,214 4,965 8,106 440 914 10,060 2002 1,551 111 234 1,902 6,969 4,808 5,851 10,809 563 1,311 12,143 Commercial/Government 1980 355 19 69 443 22,413 13,092 20,322 1,918 249 1,402 9,629 1982 386 20 14 480 23,598 13,104 21,212 9,109 214 1,514 10,951 1981 416 22 88 586 26,569 15,362 23,845 12,641 338 2,098 15,083 1992 581 23 106 116 29,914 11,220 25,129 11,560 396 2,833 20,189 1991 124 25 126 815 33,680 19,303 29,963 24,384 483 3,115 28,642 2002 896 21 151 1,014 31,920 21,638 33,581 33,916 584 5,012 39,632 Industriala Processors Processors Processors can/ Fish Camps & Can/ Fish Camps & Can/ Fish Camps & Can Onl:£ Freeze BU:£ Stations Total can Onl:£ Freeze Bu:£ Stations Can onl:£ Freeze Bu:£ Stations Total 1980 3 10 40 53 486,000 583,000 24,000 1,458 5,830 960 8,248 1982 3 11 42 56 486,000 583,000 24,000 1,458 6,413 1,008 8,819 1981 2 -12 41 55 486,000 583,000 24,000 912 6,996 984 8,952 1992 1 13 40 54 486,000 583,000 24,000 486 1,519 960 9,025 1991 0 14 39 53 0 583,000 24,000 0 8,162 936 9,098 2002 0 14 39 53 0 583,000 24,000 0 8,162 936 9,098 aDoes not correspond to village groups for residential and commercial/government. SOURCE: ISER Report, Appendix C TABLE A.1-5 PRELIMINARY PROJECT FORECAST ELECTRICAL ENERGY AND POWER REQUIREMENTS BASED ON BASE PLAN SCENARIO BY ISER YEAR 1982 1987 1992 Location Dillingham Energy (MWh/year) 8,740 11,550 15,800 Power(kW) 2,045 2,571 3,445 Naknek/King Salmon Energy (MWh/year) 14,700 16,370 18,650 Power (kW2 2!987 3!327 3!370 Subtotal Dillingham/Naknek Energy (MWh/year) 23,440 27,920 34,450 Power (kW)* 4!032 5!898 7,235 Clarks Point Energy (MWh/year) 620 700 775 Power (kW) 184 216 243 Egegik Energy (MWh/year) 1,300 1,400 1,500 Power (kW) 683 639 599 Ekuk Energy (MWh/year) 800 800 800 Power (kW) 913 913 767 Ekwok Energy (MWh/year) 155 210 245 Power (kW) 44 60 68 Igiugig Energy (MWh/year) 185 255 385 Power (kW) 54 74 108 Koliganek Energy (MWh/year) 245 310 390 Power (kW) 71 90 107 Levelock Energy (MWh/year) 190 245 340 Power (kW) 44 70 91 Manokotak Energy (MWh/year) 430 560 720 Power (kW) 124 162 197 New Stuyahok Energy (MWh/year) 550 720 930 Power (kW) 217 234 260 Portage Creek Energy (MWh/year) 90 120 140 Power (kW2 26 35 39 1997 2002 21,000 28,100 4,555 6,095 21,650 25,800 4!400 5!242 42,650 53,900 8!955 11! 337 880 1,030 276 323 1,620 1,790 647 715 800 800 593 457 285 370 70 80 500 700 131 149 465 580 115 127 470 670 115 145 930 1,220 230 258 1,210 1,625 297 347 180 215 41 44 TABLE A.1-5 (cont) PRELIMINARY PROJECT FORECAST ELECTRICAL ENERGY AND POWER REQUIREMENTS BASED ON BASE PLAN SCENARIO BY ISER YEAR 1982 1987 1992 Location Subtotal -10 villages Energy (MWh/year) 4,565 5,320 6,225 Power (kW2* 2 z360 2 z493 2 z479 Iliamna/Newhalen/Nondalton Energy (MWh/year) 1,420 1,935 2,615 Power (kW2 324 442 597 Total Energy (MWh/year) 29,425 35,175 43,290 Power (kW)* 6,716 8,833 10,311 * Noncoincident power loads Note: System losses not included 1997 2002 7,340 9,000 2 z515 2 z645 3,570 4,840 795 1 z055 53,560 67,740 12,265 15,037 Month January February March April May June July August September October November December Total TABLE A.1-6 FORECAST ELECTRIC ENERGY AND POWER NEEDS BRISTOL BAY STUDY AREA -YEAR 2002 Average Energy Needs (MWh/mo)* 5,662 5,159 4,866 4,993 5,461 6,663 7,547 6,067 4,892 5,077 5,366 6,000 67,753 MWh/year Peak Power Needs (kW)* 10,340 10,256 9,167 9,326 9,889 12,447 13 ,614 11,806 8,633 9,117 9,710 11,370 * Value represent system coincident values but do not include system losses, as may apply due to power plant needs, transmission lines, distribution, and other factors. LOCATION AND SECTOR Dillingham/Aleknagik Residential Comm/Gov. Industrial Total Naknek/King Salmon/So Residential Comm/Gov. Military Industrial Total Egegik Residential Comm/Gov. Industrial Total Manokotak Residential Comm/Gov Total New Stuyahok Residential Comm/Gov Total Portage Creek Residential Comm/Gov. Total Ekwok Residential Comm/Gov. Total TABLE A.1-7 SPACE HEATING DEMAND FORECAST BY VILLAGE BY SECTOR BRISTOL BAY STUDY REGION (All values given are in MWh) YEAR 1980 1982 1987 1992 15,655 17,669 22,704 27,740 42,763 51,001 71 ,596 92,191 96 100 111 122 58,514 68,770 94,411 120,053 Naknek 8,118 9,188 11 ,862 14,537 29,978 35,751 50,182 64,613 13,381 13,381 13,381 13,381 5,287 5 /287 5 /287 5 /287 56,764 63,607 80,712 97,818 828 937 1,209 1,481 906 926 975 1,025 1 /349 1 /349 1 /349 1 /349 3,083 3,212 3,533 3,855 1,767 2,003 2,595 3,186 1,827 1,867 1 /966 2,066 3,594 3,870 4,561 5,252 1,820 2,062 2,666 3,271 1 /230 1 /257 1 /324 1 /391 3,050 3,319 3,990 4,662 377 415 509 603 304 311 327 344 681 726 836 947 620 681 834 987 321 328 346 363 941 1,009 1,180 1,1350 1997 2002 32,775 37,810 112,786 133,381 133 144 145,694 171,335 17,211 19,885 79,045 93,476 13,381 13,381 5 /287 5 /287 114,924 132,029 1,753 2,025 1,074 1,124 1 /349 1 /349 4,176 4,498 3,777 4,368 2 /165 2 /265 5,942 6,633 3,875 4,480 1 /459 1 /520 5,334 6,006 698 792 360 377 1,058 1,169 1,139 1,292 381 398 1,520 1,690 LOCATION AND SECTOR Koliganek Residential Comm/Gov. Total TABLE A.1-7 (cont) SPACE HEATING DEMAND FORECAST BY VILLAGE BY SECTOR BRISTOL BAY STUDY REGION (All values given are in MWh) YEAR 1980 1982 1987 1,040 1,152 1,434 534 546 575 1,574 1,698 2,009 1992 1,715 604 2,319 Iliamna/Newhalen/Nondalton Residential 2,775 3,038 3,746 4,453 Newhalen Comm/Gov. 534 546 575 604 Iliamna Comm/Gov. 2,070 2,115 2,228 2,341 Nondalton Comm/Gov. 838 856 902 948 Total 6,197 6,555 7,451 8,346 Clarks Point Residential 858 946 1,165 1,385 Comm/Gov. 356 364 383 402 Industrial 674 674 674 674 Total 1,888 1,984 2,222 2,461 Ekuk Residential & Comm/Gov. 51 58 75 92 Industrial 85 85 85 85 Total 136 143 160 177 Levelock Residential 1,596 1,756 2,157 2,558 Comm/Gov. 640 654 689 724 Total 2,236 2,410 2,846 3,282 Igiugig Residential 465 513 631 750 Comm/Gov. 432 441 465 489 Total 987 954 1,096 1,239 Regional Total (MWh) 139,555 158,257 205,007 251,761 1997 2002 1,996 2,277 633 662 2,629 2,939 5,161 5,868 633 662 2,454 2,567 993 1 z039 9,241 10,136 1,604 1,824 422 441 674 674 2,700 2,939 109 126 85 85 194 211 2,959 3,360 759 794 3,718 4,154 869 988 512 536 1,381 1,524 298,511 345,263 The above residential needs include fuel for water heating and some cooling. SECTOR & ENERGY NEED Residential Hot Water/Cooking* Space Heating Commercial/Government Hot Water/Others** Space Heating Military Hot Water/Others** Space Heating Industrial Hot Water/Others** Space Heating TABLE A.1-8 SEGREGATION OF SPACE HEATING ENERGY NEEDS AND HOT-WATER & OTHER ENERGY NEEDS -BY SECTOR BRISTOL BAY STUDY REGION (All values in MWh) YEAR 1980 1982 1987 1992 3,266 3,672 4,687 5,702 32,664 36,723 46,872 57,020 13,7892 16,164 22,094 28,024 68,962 80,821 110,468 140,116 1,248 1,250 1,250 1,252 6,242 6,246 6,255 6,266 2,230 2,230 2,230 2,230 11,151 11,151 11,151 11,151 * Assumes 10 percent of total forecast for sector ** Assumes 20 percent of total forecast for sector 1997 2002 6,717 7,732. 67,169 77,317 33,952 39,882 169,765 199,413 1,254 1,256 6,273 6,282 2,230 2,230 11,151 11,151 r---------------------------------------------------------------~: o 0 0 0 ... )( ~ ~ ~ I (I) C w w Z > C!' a:: w z w 140~----------~----------~----------~----------__ • RETHERFORD "HIGH" LOAD GROWTH ISER'S FORECAST RETHERFORD "LOW" LOAD GROWTH 120~----------~----------_+----------~----------~ 100 80 60 40~------~~_r--------~~~----~~~ __ --------~ 20,-----------~----------_+----------~----------~ O~----------_r----------_;------------~--------~ 1980 1~5 1~0 1~5 2000 FORECASTS OF ENERGY NEEDS FORECASTS OF ENERGY NEEDS ""'----------FIGURE A.1-1 N ... 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II j Iii I i RETHERFORD ,tTl ~ 1.00 ' 11 ., 'I i I :, HIGH LOAD GROWTH' I . i .... I : i:: I! I:: I illl! .: I III 1'1' I 11"',:::: !ili: I !: a: " " II i I I , II ' II I 1+4 ' +t 1 I, ,,' o~I:·:~:It::II~,::~,::~::~*=t:~=IH~!:~_=t:~.~I:~t::~":':~~:~~::~~I~~=I-lli~lm~:j~ll,~t~~I:!I~II!~II~:~t~I~~4i~~f1~rt~~mm YEAR 1980 1985 1990 1995 2000 2005 ELECTRICITY DEMAND RATIO V ARIA TION NAKNEK GROUP 2010 YEAR '----------------FIGURE A.1-3--..1 I· ~ I i 1 I i 1 I ! I I , :! 1 11 Ii ~ I Ii ill -r i lIT II ' 1 t t I: ~t J-~it t. ft Hi , , Itr 1 i j , 'I , , I i 't ,~ rtt , , ~ ,t i : i I: ! ; I ~ n ! III ' t!, 111 til [ I I; I : iii i ; II ; Ill! I i I::: !:':!!: i ~ iii ! : : ! rr: ! i : iii: ([ Ii i i ! 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CD -o <I: r---------------------------------------------------------------------------------.... --1--- -- 14 r--------1--- ;::==:-._- 13 -- ~-=~--= -- ---:-~~-------:-~---- ---- -- t------ 1---.---- --_. --. --f-->--- 12 c- 1-- 11 10 c Z <9 :E w C ..J <8 ::> Z Z < ..J7 < ~ o ~ ~6 ~ Z w (.) a:: 5 w CI. ------::==::f-____ :_ ~_~~ .::..-c----~ ---1--- -------- .------I--1--------c---- ~- ------ -. ----------I---~-= 1----1----- ._. -- ---r===:----. --:---:-==------._- .-t-----.~ _-=..::... __ .-1--- -~----::::~---.:-~-. --:--:--::I-:~--.. --~.---- -- ..... 1"--- ~-r==------I---~f=-- ---+I--_-_-_-_+r--_-_ .. -=- -1_---r----::- -.. -----~----=-=~----------= . t------c---- ---~--:-I--------::-- t-----1-. ~ _~ 1----_._- -1----~----1--- -~ .... _-1----. -I--:-__ . ___ --=-:.. __ ----- ---1------_ . __ ---- ---- ._-- ._- ---- -------- ----- 1---_~~---:-.::.=:::= r=-----~--= - 4 t-----_ _. --------1----=-- 1------c-------:-:.--:=----. __ ._~=t_:_._ --~-=...::--:-f=-- --r=--::----~-.----- 3 I--=1----~ -_.-------_. .. .:.. --:-.:-.- ---~ ----~----.- 2 ~f--=-.-=. =-==_=If-~_=._=_=+_=====-=_-_:j=I---:-.=-=---_. -------~--------=--_=-1--:. --- -- -- 1------ o f==-t--. _ .. :~-. t----.-I-----~"":':=I-----=-t----.--+----+-----+---f=--. ...:.... ----- I-------::- ~= 1----- 1-----c-. -=--:-- 1-----.---~--__ -:-_:~==r__.:..:__-_ --.. -r---_C-_____ --::::-:: --~--.--:-~ ~---~= . ----_r---:--= ::_-::- -- ... _.:- ---c------- JAN FEB MAR APR MAY JUNE JULY AUG SEPT OCT NOV ENERGY DEMAND DISTRIBUTION NAKNEK ELECTRIC ASSOCIATION (NAKNEK) -- -- .- DEC FIGURE A.1-17 '" • -.. c( ~------------------------------------------~M - 140 130 120 110 100 90 ::.:: 80 <t w c.. ..J ~ 70 Z Z <t ~ Z w u a:: 50 w c.. 40 30 20 10 o JAN - - --r------1--- -,---------- -- ----_ .. - FEB MAR APR MAY JUNE JULY AUG SEPT OCT CAPACITY DEMAND DISTRIBUTION NAKNEK ELECTRIC ASSOCIATION (NAKNEK) NOV DEC ~-------FIGURE A.1-18 -.. • -o c( ~ -N • -0 c( 14 13 12 11 10 C ~9 ~ w C ...I ct 8 :::I Z Z -- ct t--- ...17 ct ----- I-e I-... - "-6 e -- I- Z w Us a: w D. 4 3 2 1 0 JAN FEB MAR APR MAY JUNE JULY AUG SEPT OCT NOV DEC ENERGY DEMAND DISTRIBUTION RURAL VILLAGES -FIGURE A. 1 19 - ~-----------------------------------------------------.~ '" III 14 0 13 0 120 110 100 90 ~ c:s:: 80 w c.. -oJ c:s:: :> z 70 Z c:s:: u.. o ~ 60 Z w (.) a: ~50 40 30 20 10 o JAN - --- --~-- -.. ---._" -- ---~ FEB MAR APR MAY JUNE JULY AUG SEPT OCT CAPACITY DEMAND DISTRIBUTION RURAL VILLAGES NOV DEC ~------FIGURE A.1-20 o c( ~--------------------------------------------~= .. 130 120 110 100 Q 2 « :E90 w Q ..J « ::I 80 2 2 « ..J « 70 l-e I- u. e 60 I- 2 w (.) ffi50 a.. 40 30 20 10 0 '-------'-_F_EB_~ JULY AUG SEPT OCT NOV DEC JAN ENERGY DEMAND DISTRIBUTION FISH PROCESS VILLAGES FIGURE A. 1-21 - N • .. co 0( ~------------------------------------------~. - 140 130 120 110 100 90 ::.:: 80 <t w 0.. ..J ~ 70 Z Z <t e;60 ... Z w ~50 w 0.. 40 30 20 10 o JAN -~ ---t------- -- - ~ F~APR MAY JUNE JULY AUG SEPT OCT CAPACITY DEMAND DISTRIBUTION FISH PROCESS-VILLAGES' ~ ~ NOV DEC ------------FIGURE A.1-22 -N • ~ .-----------------------------------------------------------~~ <II 59.3 C/G 69,3 C/G C/G == COMMERCIAL/GOVERNMENT R = RESIDENTIAL M == MILITARY I = INDUSTRIAL YEAR 1982 158,257 MWh YEAR 2002 345,263 MWh SPACE HEATING NEEDS C '" • '" c c( ------------..... IGURE A.1-2:-l-.... 4oo~----------~---------+----------4-----------~--------~ ~ 300;-----------~--------_+----------;_~ __ ~----r_--------_; i I > c::I a: ~ ~~----------~--~-----+------~ w I-w Z I- Z w ... g ~ 1°OL=r=~=p=f1 W RESIDENTIAL 1985 1990 1995 2000 2005 YEAR REGIONAL SPACE HEATING NEEDS : o ... • N ~ '--------------FIGURE A.1-24----' r-------------------------------------------------------------------------------~~ 15 11 __ _ 14 -" --~--~- 13 12 11 4 3 2 o JUNE JU OCT NOV A VERAGE MONTHLY DISTRIBUTION OF DEGREE DAYS DEC FIGURE A.1-25 • c .... • .... APPENDIX A. 2 HYDROELECTRIC POWER PROJECTS A. 2.1 Tazimina River Power Proj ects A.2.l.l Introduction The Tazimina River drains the Upper and Lower Tazimina Lakes into the Newhalen River, which discharges into I liamna Lake in the northeastern portion of the Bristol Bay region. There is a 100-ft waterfall on the Tazimina River approximately halfway between the mouth of the river and the outlet of Lower Tazimina Lake. The hydroelectric development of the Tazimina River centers on utilizing the energy available in the flow and fall of the river at Tazimina Falls. The regional energy and power needs of the year 2002 require that the flow of the river must be regulated, as the natural river flow varies greatly with the seasons and at times would be insufficient to meet the demand. This regulation would be provided by a storage reservoir located at the only suitable damsite identified on the river. As the location of the storage reservoir is several miles upstream of the falls, a low forebay dam would be placed above the falls to divert the water released from storage for power generation. The Tazimina River could also be developed as a run-of-river project with sufficient capacity installed to meet the regional power demand at times when the river flow is available. Another source of power would be required in conjunction with the regional run-of-river concept to meet the year-round regional energy needs. Local development of the Tazimina River could be pursued on the subregional level, where the storage reservoir and generating facilities are scaled down to meet only a portion of the region I s ultimate energy and power demands. Similarly, a local run-of-river concept could be developed to meet the energy and power demands of the villages in the immediate vicinity of the site. A.2-l A. 2.1. 2 Geology A discussion of the geology in the Tazimina River basin appears in Appendix E. The proposed damsite offers bedrock outcrops in both abutments with a continuous bedrock surface covered by up to 170 ft of pervious sands and gravels in the valley. There is evidence of sufficient rock in the immediate area suitable for a rockfill dam; however, the impervious materials for the core zone may have to be brought from borrow areas a few mil~s away. The powerhouse location offers good rock for foundations but will require some slope protection, as the slopes in this vicinity are actively raveling. A.2.l.3 Tazimina Regional Power Project The generating capaci ty installed in the Tazimina regional power development would be 16 MW, with the storage reservoir sized to provide sufficient flow to meet the predicted regional energy needs in the year 2002. The important features of the Tazimina River regional power development are shown on Figures A.2-l through A.2-5. A summary of descriptive data pertaining to the Tazimina River Regional Hydroelectric Project is given in Table A.2-1. The project will consist of the following: a. Storage Dam and Reservoir A 65 -ft high rockfill dam would be constructed at river mile 12.9. This site is the only suitable location identified by the geologic surveys of the river between the falls and the outlet of Lower Tazimina Lake. Damsites previously identified by the USGS (Ref 1) and other engineers and consultants (Ref 2) were found to be unsatisfactory after preliminary geologic investigations. The storage dam would have a crest elevation of 705 ft with a core of glacial till and zones of sand and gravel filter material, crushed rock, rockfill, and riprap. A rockfill dam was selected A.2-2 .. --.. .. .. a • • .. • .. -.. • .. • .. -• • .. • .. -- -.. - for the purposes of this study to make use of the rock excavated from the sidechannel spillway. A detailed cost comparison of the alternate types of dams will be made during the feasibility study phase. The valley floor materials are quite pervious and the dam would require a full cutoff to the underlying rock to prevent excessive water loss. A 10-ft diameter steel regulating pipe outlet would be provided in the storage dam branching into four steel pipes, each 4 ft in diameter, and one pipe, 2 1/2 ft in diameter. Each outlet pipe would be provided with a valve and a concrete energy-dissipating structure on the downstream side. The valves would be opened on demand to release the necessary flows for generation. A concrete energy-dissipating structure was selected over energy-dissipating type valves because of the potential of the valves freezing in position during cold weather. The storage required to provide sufficient water for generation was determined by comparing the monthly generating flow requirements with monthly river flows as developed in Appendix I. A mass balance of the monthly river flow with an 80 percent chance of being exceeded and the year 2002 generating flow demand was used to determine the required storage of 200,000 acre-ft. The monthly river flows are given in Table A.2-2 along with the average monthly river flows and the peak and average generating flows. The minimum allowable reservoir water level was assumed to be at elevation 655, the present elevation of Lower Tazimina Lake. To obtain the required 200,000 acre-ft of storage, the reservoir normal maximum water level was set at elevation 690. The area-capacity curves for the reservoir are shown on Figure A. 2-6. In a hypothetical year where each monthly river flow is equal to the 80 percent exceedence flow for that month, the reservoir would be drawn down to elevation 655. In a year with average runoff, the reservoir would be drawn down to elevation 667. The month-by-month regulated river flow and reservoir level for average runoff conditions and year 2002 generating flow requirements are given in Table A.2-3. A.2-3 b. Storage Reservoir Spillway The storage reservoir spillway would be of the ungated sidechannel type located in rock on the right abutment of the storage reservoir dam. The overflow section would consist of a concrete ogee with a crest elevation of 691 ft. The probable maximum flood inflow of 225,000 cfs determined in Appendix I is essentially the same as determined by R.W. Retherford Associates (Ref 2) and is expected to require a similar discharge capacity of 75,000 cfs. The 625-ft wide spillway overflow section would pass the estimated 75,000 cfs peak discharge with a 10-ft reservoir surcharge. The forebay dam and intake is used in lieu of running the penstock an addi tional 2.2 miles to the storage reservoir, where a generating intake structure would be installed. The longer penstock would reduce the volume of storage required due to the greater head available. If the Tazimina River is selected for development as a regional power project, the alternative of a longer penstock versus a forebay dam will require study in greater detail before a selection being made. c. Forebay Dam and Intake The concrete forebay dam would be located at river mile 10.1 and founded on exposed rock. The dam would provide essentially no storage and would serve only as an intake structure and aid in turbine-generator operation. The central 200 ft of the dam would be formed as an overflow section to pass river flows in the range of the annual spring flood; the remainder of the dam would be designed to allow the passing of higher floods by overtopping the dam. A gated intake structure would be provided in the left side of the dam to admit water to the penstock. An 18 ft x 18 ft trashrack would be set in vertical slots to preclude large trash from entering the penstock and generating units. A.2-4 • • • • -• • • • -• • • • • • • • • • • • • • • - • -- - • III d. Penstock The 8-ft diameter steel penstock will gradually emerge from the ground and run a total of 6,700 ft on the surf ace to the powerhouse. The penstock will bifurcate into two 5-ft diameter sections before entering the powerhouse. The penstock and access road to the forebay dam will follow a parallel, adjacent alignment to the extent possible to facilitate construction and inspection of the penstock. e. Powerhouse and Generating Units The powerhouse would consist of a prefabricated insulated building on a reinforced concrete substructure approximately 47 ft wide x 70 ft long. It would house two 8 MW turbine-generators of the vertical Francis-type operating at 450 rpm and 160 ft net head, and necessary auxiliary equipment. An indoor service bay would be provided for equipment assembly and maintenance. The powerhouse would contain a 30-ton bridge crane to handle the heavy equipment in the building. f. Access roads Approximately 11 miles of new access roads would be required to connect the project facilities with the existing road from Newhalen. The existing road would be upgraded to be suitable for permanent access to the project. g. Constructibility The Tazimina regional power project could be constructed over a period of 3 to 3 1/2 years with a construction labor force peaking at about 200 people. An additional 50 administrative and management personnel are also probable, bringing the peak force number to 250 people. Construction would proceed during the warm weather months on the two dams and appurtenant structures. The closing of the dams and diversion of the river would occur during the early spring months of the second construction season when the river flow is low. The powerhouse would be enclosed during this period so A.2-5 that work could continue indoors over the winter months. A.2.l.4 Tazimina Sub-Regional Power Project The development of the Tazimina River to meet approximately one-half the regional energy and power demand involves the same aspects as the regional installation on a smaller scale. There would be 8 MW of generating capacity installed, served by a 6-ft diameter penstock from the forebay dam. The storage reservoir would be constructed at the same location as previously described with an active storage volume of 30,000 acre-ft. This requires a 30-ft high dam with the crest at elevation 675 ft. The spillway required would be approximately the same as described for the regional development of this site. A.2.l.S Tazimina Run-of-River Power Project The Tazimina River could also be developed as a run-of-river project. As a run-of-river installation, the plant would generate power according to the availability of flow in the river without the benefit of storage or regulation. Two run-of-river power projects were considered: a 16 MW installation designed to meet a portion of the regional energy and power needs with the balance supplied from another source and a 1.2 MW installation designed to meet the year 2002 energy and power demands of the villages of Iliamna, Newhalen, and Nondalton. a. Regional Run-of-River Installation The 16 MW installation, shown on Figure A.2-7, would be identical to the project facilities described earlier in Section A.2.l and shown on Figures A.2-2 through A.2-S for the Tazimina Regional Power Project, with the exception that a storage reservoir would not be provided. The forebay dam, penstock, and powerhouse would remain unchanged. Since there is no storage reservoir required with this concept, approximately 2.2 miles of access roads would be eliminated. A.2-6 .. .. .. .. III .. .. .. .. .. .. .. .. .. • .. .. .. .. .. .. -.. -.. - A monthly accounting of average river flows and the average percentage of regional energy available from the 16 MW run-of-river installation is given in Table A.2-4. A flow-duration curve with the operating range of the project outlined is shown on Figure A.2-S. An analysis of the average monthly flow-duration curve with regard to the energy which could be captured indicates that 32 million kWh/yr could be generated. The actual contribution of this project to the regional energy needs would be somewhat less than indicated above, as the average river flow would not be sufficient to meet the daily variation in generating load for the months November through April. Analysis of a flow-duration curve constructed from daily flows, if available, would confirm that the actual contribution of the project is less than that indicated by monthly flow-duration curve. Due to the shortfalls projected above for the year 2002, the Tazimina 16 MW run-of-river project can only be considered as a dependable source of regional power and energy during the months of May through October; the balance of the energy and power requirements for the months November through April would need to be supplied from another source. b. Local 1.2 MW Run-of-River Installation The generating facilities proposed to serve only the villages of Iliamna, Newhalen, and Nondalton would consist of a gated intake structure above Tazimina Falls, a 1,400 ft penstock, and a powerhouse containing two 600 KW turbine-generator units. The features of the local run-of-river project are shown on Figures A.2-9 and A.2-10. The intake structure would be located 700 ft. upstream of the falls and consist of a shoreline drop inlet with 6 1/2 ft x 6 1/2 ft trashrack and a similar size gate. No forebay dam would be required. The 3 1/2 ft diameter penstock would exit the intake structure and be buried in the channel until the river bottom drops enough for it to emerge and be supported from the rock on the side of the canyon. The powerhouse would be located approximately 700 ft downstream of the falls and would be a 62 ft x 23 ft prefabricated, insulated building on a reinforced concrete substructure. The powerhouse would contain two 600 KW generating units operating at 115 ft maximum gross head. Cross flow-type turbines are proposed for this A.2-7 installation because of their superior performance over a wide operating range as would be expected over the life of this installation. The average and peak generating flows to meet the year 2002 loads of the three villages are compared with the average and 80 percent exceedence river flows on Table A. 2-5. Based upon these river flow estimates, which were obtained from data in Appendix I, there is a possibility that the river flow will be insufficient at times during the months of January, February, and March as the generating load reaches the year 2002 estimates. The actual amount of energy and power shortfall which may occur is subject to the variation in river flows and the actual growth in the. generating load. The estimates presently available for river flow and year 2002 loads do not permit a determination of the generating shortfall with a great degree of confidence. The extent to which supplementary generating facilities are needed may not be known until sometime after the development would be in operation; however, they appear to be minimal and only necessary during the months of the February, March, and April in later years of the study period. The local Tazimina power project could be constructed over a period of approximately 2 to 2 1/2 years with a construction labor force of about 100 people. An additional 30 administrative and management people would bring the peak force to about 130. Construction would proceed on the shoreline diversion structure during the low flow months of the early spring. The powerhouse would be enclosed during the warm weather months so that installation of the turbine-generators could continue throughout the winter months. A.2.2 Kontrashibuna Lake Hydroelectric Project A.2.2.1 Introduction Kontrashibuna Lake is drained by the Tanalian River, which discharges into Lake Clark in the northeastern portion of the Bristol Bay region. There is a 281 ft elevation difference between Kontrashibuna Lake and Lake Clark which could be utilized to develop the Kontrashibuna Lake hydroelectric A.2-8 -.. .. • ., • • .. .. .. .. - • • • .. .. -.. .. .. .. .. .. - - -.. project. Considering the average flow of the Tanalian River and the elevation difference between the two lakes, a hydroelectric capacity of 16 MW installed at this location would provide the energy and peak power demand required by the Bristol Bay region in the year 2002. Development of the Kontrashibuna Lake Hydroelectric Project would require the construction of a dam at the outlet of Kontrashibuna Lake with a tunnel constructed to divert the generating flows to a powerhouse on the shore of Lake Clark. A.2.2.2 Geology Geologic conditions appear favorable Kontrashibuna Lake Hydroelectric Project. for the There construction appears to be of the a good damsite with shallow bedrock and rock abutments opposite one another in the narrow valley. Impervious materials will need to be hauled several miles from the shore of Lake Clark to construct the core of the dam, while there is an ample supply of rockfill material nearby. A.2.2.3 Description of Project The significant aspects of the Kontrashibuna Lake hydroelectric development are shown on Figures A.2-11 through A.2-14. A summary of descriptive data pertaining to the project is given in Table A.2-6. The project will consist of the following: a. Storage Dam and Reservoir A 90-ft high rockfill dam would be constructed at the outlet of Kontrashibuna Lake at a damsite previously identified by the USGS (Ref 3). The storage dam would have a crest elevation of 545 ft with a core of glacial till and zones of sand and gravel filter material, crushed rock, rockfill, and riprap. A large amount of the rockfill material would be made available through the construction of the spillway. There is no A.2-9 information available to allow for an evaluation of the permeability of the soils underlying the damsite and thus determine the need for a cutoff. Lacking any site-specific data, it is assumed that the dam foundation materials are similar to, but shallower than, those found in the Tazimina River basin and that a full cutoff to the underlying rock would be required. An outlet would be provided in the dam to permit controlled releases to the Tanalian River. This outlet would consist of a gated lO-ft diameter pipe with a concrete energy-dissipating structure. The reservoir is also provided with an ungated overflow spillway to discharge any excess inflow when the reservoir is full. The reservoir storage capacity was determined by preparing a mass curve of inflows to the reservoir from the five years of recorded flow data on the Tanalian River. A reservoir capacity of 380,000 acre-ft was selected to allow the year 2002 generating demand to be met if a similar five-year sequence of flows were to occur. The storage volume was provided above the present level of Kontrashibuna Lake. Should the Kontrashibuna Lake hydroelectric development be selected for further study, it is quite possible that a more detailed evaluation of reservoir storage requirements and an investigation of the feasibility of allowing active storage below the present lake level would permit a reduction in the size of the dam required. Reservoir levels would vary between the maximum drawdown, the present lake level of elevation 456 ft, and the normal maximum water level of elevation 520. The area and capacity curves of the reservoir are shown on Figure A. 2-15. b. Storage Reservoir Spillway The spillway for the storage reservoir would be an ungated overflow spillway cut into the bank around the left abutment of the dam. A 220-ft wide spillway with a 15-ft reservoir surcharge to elevation 535 would be provided to pass the estimated probable maximum flood discharge of 50,000 A.2-10 .. lilt .. lilt .. .. .. .. .. .. • .. -.. .. .. • .. .. .. -.. .. .. -.. - ., .. .. cfs. The overflow section and spillway channel would be lined with concrete for a distance of approximately 280 ft. c. Power Tunne I A l3-ft diameter concrete-lined tunnel would be constructed for a distance of 11,500 ft to the powerhouse location on Lake Clark. A 20 ft x 20 ft trashrack would be provided at the intake portal at Kontrashibuna Lake with a gate structure provided at the tunnel, 550 ft downstream of the portal. A surge shaft would be constructed from the tunnel to the ground surface located 2,600 ft upstream o! the powerhouse to relieve pressure transients and facilitate turbine-generator response to load changes. The final 200 ft of the tunnel would be lined with steel. The flow line then reduces to an 8-ft diameter buried penstock, which divides into two 4 l/2-ft diameter penstocks connecting to the inlets to the turbine scroll cases. d. Powerhouse and Generating Units The powerhouse would consist of a prefabricated insulated building on a reinforced concrete substructure approximately 45 ft wide x 66 ft long. Enclosed in the powerhouse would be two 8 MW turbine-generators of the vertical Francis type, operating at 450 rpm and 220 ft net head. An indoor service bay would be provided for assembly and maintenance of the equipment along with a 25-ton bridge crane. e. Access Roads and Facilities A 2 l/4-mile access road would be constructed from the powerhouse location on Lake Clark to the storage reservoir and intake on Kontrashibuna Lake. A dock would be constructed on the shore of Lake Clark to receive material and equipment brought in over water or on the ice. The project facilities would not be accessible by road from the Iliamna Lake area. f. Constructibility The Kontrashibuna power project could be constructed over a period of A.2-11 approximately 3 to 3 1/2 years with a labor force of about 250 people. An additional 50 people for administrative and management needs would bring the project labor force peak to about 300 persons. The dam would be closed during the low flow period in the early spring of the second warm weather construct ion period. Work on the power tunnel would proceed cont inuous ly on a year-round basis after establishing operations in the warm weather months. Installation of the turbine-generators would continue through the winter in the powerhouse which will be enclosed during the preceeding construction season. A.2.3 Chikuminuk Lake Power Projects A. 2.3. I Introduction The Chikuminuk Lake power projects consider the development of hydroelectric power by utilizing the flow and head resources found on the Allen River near the outlet of Chikuminuk Lake. These resources can be used to develop a power project which is capable of meeting the energy and power needs of the Bristol Bay study region or a power project suitable for serving the local needs of only those villages within the Nushugak River drainage basin. The Chikuminuk Lake and Allen River form a part of the Tikchik River drainage basin and are located in the northern section of the Wood-Tikchik State Park. Chikuminuk Lake is an east-west trending lake, having an elevation 598 ft above mean sea level. At this elevation, the lake has a surface area of about 24,000 acres. Water flows from the lake into Allen River. The Allen River flows in a south-southeast direction and discharges into Chauekuktuli Lake directly south of Chikuminuk Lake. The river has a total length of about 10.8 miles. Several rapids exist within the river's course, particularly near the outlet of Chikuminuk Lake. These rapids are severe enough to preclude migration of anadramous fish into the lake. However, a small number of anadramous fish do reach the lower section of A.2-12 • .. .. 111 • .. - • • .. • • .. • .. .. • • • -.. -.. - ". ... the river. Because of the rapids near the lake outlet, the river level drops 98 ft to elevation 500 within a two-mile distance from the lake. This is the section of the river being considered for the development of a hydroelectric power project, both on a regional or local basis. For both regional and local power developments, all the proposed power project structures and other required construction such as roads and an airport would be located on state lands. The power project structures and a portion of the accees road and transmission line would be located within the existing Wood-Tikchik State Park boundary, on the eastern side. A.2.3.2 Geology The geology of the area is obtained from literature, research and examination of aerial photographs. Several attempts to visit the site were unsuccessful due to adverse weather. Site bedrock is primarily interbedded siltstone and massive volcanics, with some sandstone and conglomerate. Overburden has been mapped as till. From aerial photographs, the landforms appear to be typical of a series of receeding terminal moraines, and very steep valley walls along the Allen River. Valley walls, in the section immediately below the lake outlet, are clearly not rock but strong evidence indicates that the overburden is a till. Glacial outwash sand and gravel appear limited. However, falls and rapids in the Allen River suggest that the riverbed is bedrock. The inner valley of the Allen River, formed from till overburden, should provide adequate and sound abutment material that is moderately to highly impervious. This till material would be suitable for compacted impervious fills. Granular fill material appear evident about 11.5 miles to the east of the dam site. On a preliminary evaluation, the site can be considered fair to good. The degree of permeability of the till comprising dam abutments would be the major influencing factor on future evaluations. A.2-13 A.2.3.3 The Regional Chikuminuk Power Project The flows of Allen River must be regulated to provide the regional electric energy and power needs forecast for the year 2002. This is because the natural flows vary widely with the seasons and. at times, would not be sufficient to meet the power demands. The flows would be regulated by the construction of a dam near the lake I s outlet. This dam would allow for the full storage of flows as well as for the raising of the lake level, resulting in additional generating head. The installed generating capacity for the regional development would be 16 MW. This value was selected to meet the peak power demand forcast for the year 2002. and includes an allowance for plant anticipated power needs, transmission line losses, and other minor contingencies. The important features of the Regional Chikuminuk Power Project are shown on Figures A.2-l6 through A.2-18. Summary descriptive data on the proposed development are given in Table A.2-7 and briefly described below. a. Storage Dam and Reservoir A 100-ft high rockfill dam having a central impervious core would be constructed at the location shown on Figure A.2-l7. The dam would have its crest at elevation 640. This type of dam was selected in order to utilize natural dam building material believed to be available in the vicinity of the project site. A subsurface cutoff system would be provided under the dam and adjoining abutments to. minimize seepage. It is assumed that this cutoff would extend to a depth of about 70 ft. This could be considerably reduced if the river is running on rock and the abutment tills are highly impermeable. The reservoir required to fully store the natural flows was determined by comparing the monthly average generating flow needs with estimated monthly river flows equivalent to the 80 percent exceedence flows of the Allen River. The average natural monthly flows and 80 percent exceedence flows A.2-l4 .. .. .. .. .. • .. • .. .. ., • • .. • -• .. .. .. .,. ., - - - - of Allen River as well as the average monthly flows required for generating the year 2002 energy demands are given in Table A.2-8. Based on these flow data, an active storage of about 570,000 acre-ft was calculated for the development. The minimum operating water surface of the storage reservoir is assumed to be at elevation 598, the natural elevation of Chikuminuk Lake. To obtain the required active storage of 570,000 acre-ft, the reservoir maximum normal operating water level is set at elevation 619. The area volume curves for the reservoir are shown on Figure A.2-l9. b. Storage Reservoir Spillway The storage reservoir spillway consists of an ungated overflow concrete ogee and an unlined, rock spillway channel located adjacent to the proposed dam. The ogee would have a crest at elevation 620. The probable maximum flood of this development would be in the range of that developed for the Tazimina River regional power plan. As such, it is assumed that for the Phase I study effort, the probable maximum flood condition would be regulated through storage and free discharge to a peak outflow of 75,000 cfs. c. The Diversion and Low Level Outlet A l6-ft horseshoe-shaped, concrete-lined tunnel would be utilized to divert the Allen River flows as may be required during the construction of the dam. This tunnel would be provided with an intake structure at its inlet and a flip-bucket type energy-dissipating structure at its outlet. The diversion tunnel system is designed to flow with a free surface. Subsequent to dam construction and termination of diversion needs, the tunnel would be plugged at about midpoint and its upstream section used as part of the pressure power tunnel. Similarly, the downstream section of the diversion tunnel would serve to accommodate the installation of 3-ft diameter steel pipe for use as a low level outlet. The outlet pipe would be set on concrete saddles and would be double-valved for safety and for protection against freezing. A.2-l5 d. The Power Tunnel A power tunnel, similar in construction to the diversion tunnel, was selected for minimizing hydraulic losses and for maximizing the utilization of construction equipment. The 16-ft horseshoe-shaped concrete lined tunnel would be about 2,800 ft long. The tunnel would branch off near its downstream into two 9-ft diameter concrete and steel-lined tunnel sections. Each of these sections would average about 110 ft long and would connect to the steel inlets of the turbine scroll cases. e. Powerhouse and Generating Units The powerhouse would consist of a concrete substructure with prefabricated insulated superstructure. a The plant would house two generating units and would also have an indoor service bay area for assembly and maintenance of the plant equipment. A powerhouse bridge crane of 40-ton capacity would be provided to handle the heavy equipment during erection and for maintenance. The overall plan dimensions of the plant would be 47 ft x 96 ft. The two turbine-generator units would each consist of a 12,000 hp turbine designed for a 100 ft net head and coupled to a 8,900 kVA, 0.90 pf, 60 Hz, three-phase, 13.8 kV generator unit. f. Access Roads and Airport Approximately 11.8 miles of gravel surface access road. would be required to connect the project facilities to a proposed airfield. Approximately 7 miles of this road are within the boundary of the Wood-Tikchik State Park. The remote location of this site and its inaccessibility by roads and/or navigable waters require that an airfield be constructed to accommodate large load-carrying planes. The planes would be used to transport material, equipment, and personnel for the project. The airfield would be located outside the state park boundary and would consist of a single A.2-16 • III ., • -. • • • .. • • ., 'lit • JIll ,. -.. .. .. ... -.. runway about 300 ft wide x 4,000 to 5,000 ft long. The airfield would continue to serve the plant after its construction. g. Constructibility The Chickiminuk regional project would be constructed over a period of approximate ly 3 to 3 1/2 years with a labor force peaking at about 175 persons. An additional 40 people are assumed for administrative and management needs, making the total peak force 215 people. Construction would start with the airfield and access road development. River diversion and spillway excavation would be followed with dam construction and the development of the powerhouse and its water conveyance system. A.2.3.4 The Local Chikuminuk Power Project The electrical energy and power needs forecast for the year 2002 for those villages within the Nushagak River drainage basin can be met by the development of a hydroelectric power plan at the outlet of Chikuminuk Lake. This development would require some minor regulation of the Allen River flows. This regulation would be achieved by the construction of a small dam near the lake outlet. The primary reason for the need of the dam is to create a headwater pool at essentially the present lake level and to provide for the submergence necessary at the power tunnel's intake structure. This also would result in an increased generating head condition and decreasing the water conduit length. The installed capacity of the local development has been established at 8 MW. This value was selected to meet the peak power demand forecast for the year 2002, and includes an allowance for plant anticipated power needs, transmission line losses, and other minor contingencies. There are certain conditions and engineering concepts of the local power development which are similar to those previously described for the regional Chikuminuk Lake development. These similarities relate to geology, the storage reservoir spillway, the diversion and low level outlet systems, and to the access roads and airport structures. As such, these A.2-17 items will be only briefly described herein to show areas or points pertinent to the local power development. The geologic aspects of the local Chikuminuk Lake power development are the same as those of the regional project previously described. The important features of the local Chikuminuk Power Project are similar to those shown on Figures A.2-20 through A.2-22 A summary of descriptive data pertaining to this development are given in Table A.2-9 and briefly described below. a. Storage Dam and Reservoir The dam required across the Allen River for impoundment of storage, for the development of additional generating head, and for providing the submergence needed over the power intake structure is similar to the dam described for the regional power plan. For the local development, however, the dam is to be located about 2,700 ft upstream of the location shown for the regional plan. The dam would have a crest at elevation 625, resulting at dam height of about 40 ft. The dam would impound only that quantity of water needed to supplement the natural river flows for power generation. Because of the increased generating head and reduced local energy and power requirements, only a small amount of storage is required for this concept. This storage can be adequately provide by retaining water within Chikuminuk Lake to elevation 602. This would provide an active storage volume of about 98,000 acre-ft. A 30-ft deep grouted cut-off curtain would be provided under the dam and in the adjoining abutments to control seepage. The average natural monthly flows, the 80 percent exceedance flow of Allen River, and the average monthly flow required for generating the year 2002 local energy demands are given in Table A.2-l0. Based on these data, an active storage of about 60,000 acre-ft was calculated for the development. The minimum operating water surface of the A.2-l8 • .' -• .. II • • - -.. • • - storage reservoir is assumed to be at elevation 598, the natural elevation of Chikuminuk lake. To obtain the required active storage of 60,000 acre-ft, the reservoir maximum normal water surface would be approximately elevation 600.5. The area volume curves for the reservoir are shown on Figure A.2-19. b. Storage Reservoir Spillway The storage reservoir spillway would be of the same size and type as described for the regional power project except that the ogee crest would be at elevation 603 ft. c. Diversion and Low Level Outlet Similar diversion and low level outlet works would be developed for the local plant as are envisioned for the regional power project. d. Power Tunnel The concept of a concete-lined power tunnel joining the diversion tunnel is also used in the local plant. The power tunnel is a 12 ft horseshoe-shaped tunnel branching to two 7-ft diameter circular steel liners. The tunnel length is 2,800 ft and each steel liner branch line averages about 110 ft in length. e. Powerhouse and Generating Units The pow.erhouse of the local plant would be located at the same area as for the regional plant (Figure A. 2-22). The powerhouse would consist of a concrete substructure with a prefabricated insulated building superstructure. The plant would house two generating units and would also have an indoor service bay area for unit assembly and maintenance. A powerhouse bridge type crane of 25 -ton capacity is being provided to handle the heavy equipment during erection and maintenance. The overall plan dimensions of the plant would be 45 ft x 73 ft. A.2-19 The two turbine-generator units would each consist of a 5,550 hp, 300 rpm turbine, designed for an 85 ft net head, and coupled to a 4,500 kVA, 0.90 pf, 60 Hz, three-phase, 13.8 kV generator unit. f. Access Roads and Airport The needs for access roads and an airport are the same as for the regional power plan. g. Constructibility Essentially the same concept pattern of construction would be followed for this project as for the regional project. However, the total peak labor force, including administrative and management personnel, is estimated at about 200. A.2.4 Newhalen River Power Projects A. 2.4.1 Introduction The Newhalen River power projects consider the development of hydroelectric power by utilizing the flow and head resources found to exist in the Newhalen River near Lake Iliamna. These resources can be used to develop a power project which is capable of meeting the energy and power needs of the Bristol Bay study region as forecast for the year 2002, or a power project suitable for responding to the needs of only the villages of Iliamna, Newhalen, and Nondalton. Both projects would be located within the Newhalen River section, near Iliamna Lake, which exhibits numerous rapids and a narrow winding channel. The location of these proposed projects is south and west of the present Iliamna airfield, from between river mile 1. 0 and river mile 7.0. This section of the Newhalen River had been previously identified and withdrawn as a potential hydroelectric power site under Power Site Reserve No. 485, dated on April 1, 1975, by the Federal Power Commission. A.2-20 .. - • ., .. ...., • -.. .. • --• .. .. --.. .. -- The combination of the rapids, a narrow channel, a winding character, and high river flows have been known to create conditions within this section of the river that produce high velocities, sometimes precluding the upstream migration of anadromous fish. These conditions have occurred within recent history, resulting in major kills near the mouth of the Newhalen River. It has been reported that such fish kill conditions result when river flows reach about 20,000 cfs or higher. Because of the above described situation, a plan was considered which in addition to developing power would allow for river diversion that could reduce the high flow velocities in the existing river channel. This type of development could be considered as a regional power project, suitable for supplying the energy and power needs of the Bristol Bay region as forecast for the year 2002. A smaller river flow diversion concept could also be developed for providing the forecasted energy and power needs of only the Iliamna, Newhalen, and Nondalton villages through the year 2002. A.2.4.2 Geology The reconnaissance on the Newhalen sites was conducted by both overflights and a ground visit from Iliamna. Data have also been derived from research of available literature and by field exploration along the proposed diversion canal alignment. A discussion of the geology for the Newhalen River concepts is given in Appendix F. Bedrock outcrops in the bed and walls of the Newhalen River for about 13 miles from the outlet of Sixmile Lake into Iliamna Lake. The rock is primarily basalt and andesite, with tuff and assorted volcanic rubble, including breccias and agglomerates. Overburden is primarily glacial tills with lesser amounts of glacial outwash sand and gravel. Overburden is estimated to be about 12 ft. thick near the canal intake and about 65 ft. near the outlet of the canal in the vicinity of the river. Sand and gravel material are fairly common in the immediate vicinity of the site. The basalt and andesite rock should provide fair to good tunneling conditions A.2-21 and stable slopes for large open cut excavations. Development of a canal, suitable for diverting water flows, within the geologic material encountered in the area of investigation is believed technically feasible. A.2.4.3 Regional Newhalen Power Projects Two types of projects are being considered for regional power development from the Newhalen River. These are: • • A canal concept that would divert only those flows required for power generation. A canal concept that would divert flows for both power generation and for reducing river flow conditions within the natural river channel. The latter concept would have the ability to bypass large quantities of water from the upper, most severe group of rapids near river mile 7 to a point near river mile 2, where the natural channel of the Newhalen River is about 1,500 to 2,000 ft. wide. Figure A.2-23A shows the general concept. Both concepts would have an installed capacity of l6MW for meeting the year 2002 peak demand. This power value includes an allowance for anticipated plant power needs, transmission line losses, and other minor contingencies. The important features of the diversion concept for power only are shown on Figures A.2-23 and A.2-24. The important features of the diversion concept for both power and river diversion are shown on Figures A.2-25, A.2-26, and A.2-26A. Figure A.2-27 shows the powerhouse applicable to both diversion concepts. A summary of descriptive data pertinent to the diversion for power only concept are given in Table A.2-11A. Similiar descriptive data applicable to the power and river diversion concept are given in Table A.2-11B. A brief description of key project features for these two concepts are given in the subsequent paragraphs. A.2-22 -.. ... • - .. .. .. -.. .. ---- -- a. Diversion Canals For the power only concept, a diversion canal about 2.5 miles long and of varying width would be developed in the plateau found north and northeast of the Newhalen River, between river mile 2 and 7. The canal would be designed to carry a flow as high as 2,100 cfs. The water depth in the canal is expected to vary from 15 ft. near the canal intake to about 30 ft. near the canal terminus. Water would enter the canal under a concrete baffle wall and through a system of deflector trashracks. The flow velocity through these deflector trash racks would be about 5.3 fps with a canal flow of 2,100 cfs. Flow control would be by the two generating units, at the powerhouse, and would depend on plant load requirements. The low velocity intake of the canal would be provided with suitable fish deflection racks and would be excavated in rock. The intermediate portion of the canal would be partially in rock (invert and lower sides) and partially in granular overburden material (upper sides). The lower downstream section of the canal would be located entirely in the granular overburden material and would be of trapezoidal cross section, having a 20 ft. wide invert and 2H:lV side slopes. The canal would be lined with roller compacted concrete, over its portion located on granular material. The lining would be 12 in. for the invert slab and 18 in. for the side slopes. The top sloped area of the lining would be reinforced for freeze-thaw protection. Lining of the canal would be done so as to prevent leakage losses and prevent erosion by the flowing water and ice. A forebay area would be developed for this concept to reduce the possibility of leakage from the canal to the overburden near the last 300 ft. above the scarp. The forebay would be developed by an enlargement of the canal area ending at a semicircular closed and concrete lined basin. Located within this basing would be the intake structure for the power penstock. The concept developed for both power generation and river flow diversion would have a canal that is about 2.5 miles long and of varying width, depending on the cross sectional configuration used. designed to carry a flow as high as 21,000 cfs. The canal would be This flow could be diverted from river mile 7 to just below river mile 2, in the Newhalen A.2-23 River. The water depth in the canal is expected to vary from about 15 ft. near the intake to about 30 ft. near the canal terminus. Water would enter the canal through a system of deflector trashracks. The flow velocity through these deflector racks would be about 2 fps with a canal flow of 21,000 cfs. The flow control would be a concrete spillway structure near the downstream end of the canal. Discharges from this spillway structure would be to the Newhalen River by means of a "stepped" discharge channel. Final discharge velocities into the river would be sufficiently high to form a velocity barrier for preventing upstream migrant fish from swimming up the discharge channel. A small bypass sluice would be provided adjacent to the spi llway. This bypass would be des igned to pass smo 1 ts and fry which may have entered the canal, in the event flows are not discharged through the spillway. At the inlet, the canal would be excavated in rock and would have an invert width of about 85 ft. For the intermediate portion, the canal would be excavated partially in rock (invert and lower sides) and partially in granular overburden material (upper sides). The downstream portion of the canal would be located entirely in the granular overburden material and would be of trapezoidal cross section, having a 30 ft. wide invert and 2H:IV side slopes. The portion of the canal excavated in granular material, including the invert founded on these material, would be lined with roller compacted concrete. The lining would be 12 in. for the invert s lab and 18 in. for the side slopes. Lining the canal is done for the same reasons, as previously described. The forebay area developed under this concept would extend some 300 ft. above the scarp. It would be formed on two sides by gravity type concrete retaining structures and on the third side by the spillway structure, thus forming the "U" shaped forebay. The concrete gravity structures would be of roller compacted concrete. The spillway would be of structural concrete. The gravity sections along with suitable retaining concrete walls would support backfill material placed against these structures. Canal flows through the spillway would be carried to the Newhalen River by a channel excavated in rock. b. Power Intake and Penstock The intake structure, for the power only concept, is a submerged morning A.2-24 • - -.. • • • .. • • • • .. • - .. - -- .. --• glory-type intake with a vortex shedding cap. This structure is located at the terminus of the canal. Supported on rock, the structure connects the canal and powerhouse through a 12 ft. diameter steel penstock. The penstock passes through a concrete gate house, located downstream of the canal terminus. The gate house is provided with two slots, one for the emergency gate and the other for emergency stop logs. These are used also for dewatering the penstock for maintenance. The intake structure, for the power and river diversion concept, is located adjacent to the spillway and forms a part of the "u" shaped forebay. The structural concrete low-level intake is separated from the canal-spillway by a deep set barrier baffle wall and a system of deflector trashracks. The intake structure is connected to the powerhouse by a 12 ft. diameter steel penstock. A steel gate is provided at the intake structure for use as an emergency closure and for dewatering the penstock during maintenance. c. Powerhouse and Generating Units The powerhouse would consist of a concrete substructure with a prefabricated insulated building structure for both concepts. The plant would house the two generating units and would also have an indoor service bay area for the assembly and maintenance of the plant equipment. A power house bridge crane of 40-ton capacity would be provided to handle the heavy equipment during erection and for maintenance. The overall plan dimensions of the plant would be 47 ft x 96 ft. The two turbine-generator units would each be of a 12, 000 hp, 257 rpm turbines designed for a 100 ft net head and coupled to a 8,900 kVA, 0.90 pf, 60 Hz, three-phase, 13.8 kV generator unit. Average generating flows anticipated during the operation of these units in meeting the year 2002 energy demands as well as the natural average and 80 percent exceedence flows of the Newhalen River are given in Table A.2-12 for comparison. A.2-25 d. Access Roads For both concepts, the plant and canal are located on the left bank of Newhalen River. This makes the plant readily accessible from the existing Iliamna Airport or from Iliamna Lake for construction and operation. Existing roads from the airfield to Newhalen River would be upgraded and supplemented with an additional new road section leading to the power plant. Material excavated from the canal would be placed at one or both sides of the canal to create a roadway to the canal intake area. e. Constructibility It is estimated that about 3 to 3 1/2 years would be needed for the construction of the plant under either concept. The main construction effort would be the bypass canal. Access/construction roads would need to be extended into the project area. Canal construction would probably occur from one heading. Excavation would be from the downstream towards upstream, with concrete lining construction followed in the reverse order. Other major construction efforts are the spillway and its discharge channel, and the powerhouse and its water conveyance system. It is estimated that construction labor would peak at about 250 persons. This, coupled with about 50 administrative and management personnel, would give a total peak labor force of 300 persons. A.2.4.5 Local Newhalen River Power Project The electrical energy and power needs as forecast for the year 2002 for the Newhalen-Iliamna-Nondalton villages can be met by the development of a hydroelectric power plant that uses a flow diversion system. The main features of this plant are shown on Figures A.2-28 through A.2-30. A summary of descriptive data pertinent to the project is given in Table A.2-l3 and briefly described below. This plant is located on the west side of Newhalen River, and would involve the section of river between river miles 2 and 5. The rapids existing through this section of the river form a "stepped" river channel resulting A.2-26 - .. • .. • ---.. .. .. • • • .. -.. - --. in about 50 ft head differential for use in power generation. This concept, diversion to conditions. however, is not assist upstream a. Intake System expected to fish migration create a during sufficient high river flow flow An intake channel, excavated in rock, would divert some of the Newhalen River flow at a point upstream of the rapids found near river mile 4.5 and would convey this flow to the power intake structure. A barrier dam constructed of large rock material would be placed near the channel inlet. This barrier dam would act as a screen and allow the passage of water, but keep fish from entering the channel. Caution must be taken in the design of this barrier dam to ensure that it does not silt-up over the years and does not freeze during winter, thus completely blocking off flow. The channel would have an invert width of about 20 ft; the flow velocity at maximum generating conditions is estimated to be less than 1.0 fps. The total length of the channel would be about 2,500 ft. A concrete intake structure would be provided at the downstream end of the intake channel. This structure would have steel trashracks and a steel gate. The gate would be used for emergency closure. The invert of the intake is at elevation 80, while its top is at about elevation 125. The top would be accessible from the powerhouse by an access service road. b. Power Tunnel A 12-ft, horseshoe-shaped unlined tunnel about 5,800 ft long would be constructed for the power tunnel. The power tunnel would be enlarged at its downstream portal, embedment of two 4-ft in a horizontal plane, to provide space for the diameter steel penstocks. The penstocks would be connected to the two power units. A.2-27 c. Powerhouse and Generating Units The powerhouse would be a concrete substructure with a prefabricated insulated building for a superstructure. The plant would house two generating units and would also have an indoor service bay area for assembly and maintenance of the plant equipment. A powerhouse bridge crane of 5-ton capacity would be provided to handle the equipment during erection and for maintenance. The overall plan dimensions of the plant would be about 42 ft x 50 ft. The two turbine-generator units would each consist of a 830 hp, 600 rpm turbine coupled to a 667 kVA, 0.90 pf, three-phase, 60 Hz, 4,170 kV generator. Average generating flows anticipated during plant operation toward meeting the year 2002 energy demands of the three villages and the natural average and 80 percent exceedence flows of the Newhalen River are given in Table A.2-l4 for comparison. d. Access Roads The plant and its waterways would be located on the west side of the Newhalen River. This makes the plant inaccessible from Iliamna airfield and reqUires that a bridge be constructed across the river for access. The existing road from the airfield to the Newhalen River would be upgraded and supplemented with a new road which would connect to the new bridge and then to the power plant. An access service road would also be constructed from the power plant to the concrete intake structure. e. Constructibility It is anticipated that construction of the project would require from 2 to 2 1/2 years. The major construction efforts are the water conveyance systems and the power plant. Construction labor is expected to peak at about 150 people. Administrative and management personnel would be about A.2-28 1If' .. -... .. • .-.. • .. - --.. .. .. .. .. .. • .. -.. • .. • .. .. .. SO people, resulting in a total work force peaking at about 200 people. A.2.S Kukaklek Lake Power Projects A. 2.5.1 Introduction The Kukaklek Lake power projects consider the development of hydroelectric power by utilizing the flow and head resources found between Kukaklek Lake and Iliamna Lake, or between Kukakalek Lake and two unnamed lakes near Kukaklek. The former source can be used to develop a power project which is capable of meeting the energy and power needs of the Bristol Bay study area and is called a regional power project. The second source would be capable of meeting the needs of those villages found along the Kvichak River and Kvichak Bay area and is considered a local project. Each project can be developed to meet the electrical energy and power needs of their respective regions as forecast for the year 2002. Immediately prior to the initiation of the study, the Kukaklek Lake was incorporated in a preserve area of Mt. Katmai National Park and Reserve. This action placed Kukaklek Lake in a restrictive category, one requiring possible congressional approval for development as part of a hydroelectric power project. Also, during the later part of the Phase I, a definite opposition to the development of a project relating to Kukaklek Lake was presented by the community of Igiugig. Despite these two restrictive conditions, however, and at the instructions of Alaska Power Authority, the regional and local concepts were carried on for study and are reported herein. A.2.S.2 Geology Field reconnaissance at the Kukaklek Lake area consisted of several overflights by fixed-wing helicopter. The area is aircraft and spot generally covered A.2-29 ground visits by glacial utilizing a tills, with occasional outwash deposits of sand and gravel. No rock outcrops were seen in the immediate area of the sites; however, scattered exposures in the vicinity of the area indicate that bedrock is primarily tuff and assorted volcanic rubble, including agglomerate. The depth of bedrock through the glacial overburden material is not known. Sand and gravels from glacial outwash deposits as well as material for impervious fills from glacial till should both be readily available in the immediate area. Rock for riprap and other uses may only be available at the east end of Kukaklek Lake. No significantly adverse geotechnical conditions are presently identified at the Kukaklek sites. A. 2.5.3 Kukaklek Lake Regional Power Pro j ect The Kukaklek Lake regional power project would use some of the flow from Kukaklek Lake and the head found between this lake and Iliamna Lake. In general, the project would divert regulated lake flows northward from the northwestern portion of Kukaklek Lake through a water conduit system to a powerhouse located at the south shore of I liamna Lake. The important features of the regional Kukaklek Lake project are shown on Figures A.2-31 through A.2-34. A summary of descriptive data pertinent to the project is given in Table A.2-1S and briefly described below. a. Flow Regulating Structure A 120-ft wide concrete structure would be constructed at the outlet of Kukaklek Lake. This structure would be developed such as to have two folding-type, hydraulic operated, overflow weir gates as shown on Figure A.2-34. The gates would be automatically controlled to continuously discharge lake water into the Alagnak River. Only the water needed for power generation would be stored in the lake. The influence of this regulating structure on the natural conditions of both the Kukaklek Lake and Alagnak River would be small in the early years after power development. This influence would continue to increase until the year 2002, when the design period energy and power loads are realized. At that A.2-30 .. -.. .. .. a • • -.. -- • .. • 'II • .. • • -.. • • • .. • • -- ", ... time, the flow regulating structure could be operated to reflect the conditions given by Table A. 2-16. This table shows the effect of flow regulation on both the Kukaklek Lake outflow and the Alagnak River flow near its confluence with the Kvichak River. Similarly, Table A.2-17 shows the effect of water regulation to the Kukaklek Lake water surface elevation. b. Intake Channel A 3,SOO-ft long trapezoidal channel excavated in the morainal material would convey some of the regulated Kukaklek Lake flow to the intake of the water conduit system. The channel is des igned for low velocity flow conditions, with the velocity under a peak generating flow, about 280 cfs, estimated to be about 0.30 fps. c. Barrier Dike A rockfill barrier dike is being contemplated for the inlet at the intake channel. The dike would be constructed of large rocks. The purpose of the dike is to hinder the passage of fish into the intake channel, but to allow flow passage. The design would need to consider the prevention of silt and ice blockage of this barrier. d. Intake Structure The intake structure would be a concrete gravity dam located at the downstream end of the intake channel as shown on Figure A. 2-33. The structure would contain the inlet to the pressure penstock, a closure head gate, and other pertinent equipment. The concrete structure would be formed in place. Backfill material would be placed downstream to form an approach level and to assist in supporting the concrete intake against hydrostatic loads. e. The Power Pens tock A buried steel penstock would connect the intake to the power plant. The penstock would be about 8 ft in diameter and about 46,000 ft long. Near A.2-31 the powerhouse, this penstock would branch into two steel pipelines for connecting with the turbine-generating units in the power plant. The penstock would be buried approximately eight feet in the ground. Suitable manholes would need to be provided along the penstock route for ready access for inspection and maintenance. f. Powerhouse and Generating Units The power house would consist of a concrete structure. The plant would house two units and would also have an indoor service bay area for the assembly and maintenance of the plant equipment. A powerhouse bridge crane of 40 ton capacity is being provided to handle the main generating equipment, and other heavy components, during erection and maintenance. The overall plan dimensions of the plant would be about 40 ft wide by 50 ft long. The two turbine-generator units would each consist of a 12,000 hp 900 rpm turbine designed for a net head of about 700 ft, coupled to a 8,900 kVA, 0.90 8f, 60 Hz, three-phase, 13.8 kV generator unit. g. Access Roads The only access roads suggested for the project would be those connecting the proposed unloading dock facility to the storage/camp site area and this area to the powerhouse plant. This is a total road length of about two miles. h. Storage Area and Camp Site A storage area for equipment and material used in the project construction would be provided near the shore of I liamna Lake. This area would also serve the project needs for the constructon of a personnel camp. i. Unloading Dock An unloading dock would be constructed at the shore of I lianma Lake. The dock would be about 50 ft deep by about 200 ft wide. This dock would serve the project during the phase when materials and equipment are being barged A.2-32 -.. ... .. WI .. • • • .. • .. .. .. • • • • WI .. • • -.. .. .. • .. ... .. ... to the site. j. Constructibility In considering the construction aspect of the project, it appears that the total plant can be on-line within 3 to 3 1/2 years from start of construction. Construction would need to be started essentially simultaneously in several areas. The first area would relate to the need for constructing the unloading dock and storage/camp area. The next critical area would relate to the penstock line, powerhouse, and transmission line construction. It is believed that construction efforts would require a work labor force that would peak at about 150 persons; administrative and management personnel would require an additional 50 personnel, resulting in a work total force peaking at about 200 people. A. 2.5.4 Kukaklek Lake Local Power Project The Kukaklek Lake local power project would use some of the flow of Kukaklek Lake and the head found to exist between this lake and two unnamed lakes, approximately two miles northwest of Kukaklek Lake. The project would be similar to the regional Kukaklek Lake project previous ly described in many respects. The general plan for the local power project is shown on Figures A.2-35 and A.2-36. Other features relating to this development are shown on Figures A.2-33 and A.2-34. The important features of the local development are summarized in Table A.2-18 and briefly described below: a. Flow Regulating Structure The flow regulating structure of this local development is the same as that described for the regional project, and is shown on Figure A.2-34. Operation of the folding-type steel gates for flow storage and regulation, required for the operation of the power plant, could result in the conditions for Kukaklek Lake outflow and Alagnak River flows, near its A.2-33 confluence with the Kvickak River. given in Table A.2-19. Similarly. Table A.2-20 shows the effect of water regulation to the Kukaklek Lake water surface elevation. b. Intake Channel The intake channel for the local project would be the same as that of the regional project. The channel would be designed for low velocity flow conditions, with the velocity under a peak generating flow, about 310 cfs, expected to be approximately 0.35 fps. c. Barrier Dike This is a passage fish prevention structure and would be the same for the local concept as for the regional, previously described. d. Intake Structure The intake structure of the local concept would be the same type as for the regional concept previously described. e. Power Penstock A buried steel penstock would connect the intake to the power plant. The pens tock would be about 7.0 ft in diameter and about 11,000 ft long. Near the powerhouse, this penstock would branch into two steel pipelines for connecting with the turbine generating units in the power plant. The penstock would be buried approximately 8 ft into the ground. Suitable manholes would be provided along its length for ready access for inspection and maintenance. f. Powerhouse and Generating Units The powerhouse would consists of concrete structure with a steel prefabricated superstructure. The plant would house two horizontal axis Francis-type units. Sufficient room would be provided within the plant for A.2-34 .. .. ., • - • ., • .. ., .. ., • .. .. .. -- • • .. erection and required unit assembly. A bridge crane of 15-ton capacity would be used to handle the completely assembled turbine, generator, and other heavy component parts of the plant. The overall plan dimensions of the plant would be about 45 ft wide by 70 ft long. The two turbine generators would each consist of a 4,700 hp, 720 rpm turbine designed for a net head of 300 ft, coupled to a 4,000 kVA, 13.8 kV generator. g. Access Roads Because the plant for the local concept is located farther inland, it becomes necessary to provide an access road to the powerhouse. This access road would be about 5 miles long and would connect with storage/camp site near the shore of Iliamna Lake. The 2-mile access road connecting the proposed unloading dock and storage/camp site area would also be provided as part of the local concept. h. Storage Area and Camp Site The storage area and camp site, as previously described for the regional concept, would also be used in the local concept. i. Unloading Dock These facilities would be the same as those for the regional concept. j. Constructibility In considering the construction aspects of the project, it appears that the total plant could be on-line within 2 1/2 to 3 years from start of construction. Construction would necessarily begin with the unloading dock and service/camp area. The access road would be built to bring equipment to the powerhouse area for construction of the powerhouse and penstock system. Equipment and construction material would be brought to the intake channel area and to the regulating structure area for work on the associated structures. It is believed that the construction efforts would require a work labor force that would peak at about 125 persons. A.2-35 Administrative and management personnel would require an additional 50 personnel, resulting in a total work force peaking at about 155 people for the job. k. Downstream Regulation It may be desirable, as part of this local project development, to regulate generating flow discharges. This re-regulation would be done to divide the generating flow proportionately between Ole Creek and Pecks Creek. Topographic maps indicate that the natural flow from the two unnamed lakes (the tailrace lakes for the local plant) is into Pecks Creek. If no regulation is made to the generating flow, it would drain naturally into Pecks Creek. Should re-regulation of generating flow be considered desirable, this could be accomplished by the construction of a ponding dike in the valley downstream of the unnamed lakes and by the installation of two flow regulating structures. One structure would discharge into the Ole Creek drainage area and the other would discharge into Pecks Creek drainage area (Figure A.2-35). Since the desirability of flow re-regulation is not known at this time, the technical and economic aspects of this issue have not been investigated. The environmental aspects of such re-regulation, however, have been considered and are discussed in the main report. A.2.6 Ice Conditions Relating to Hydroelectric Power Plants A.2. 6.1 Introduction The formation of ice on reservoirs and rivers should be considered during the evaluation and design of a hydroelectric power project. Ice conditions may require the implementation of protective measures or the adoption of concepts less sensitive to ice-related problems. A. 2.6.2 Ice Formations to be Considered There are several types of ice that can form in nature. The most common A.2-36 -• .-.. • .. ., .. - - --., -.. .. • .. • • • • • .. - .. type is call "sheet ice". This type of ice forms mostly in stagnant bodies of water and low-velocity streams; it originates with ice plates or border ice and gradually propagates across the surface of the water until a continuous covering is formed. Sheet ice development by itself is not usually considered harmful, and in fact may be beneficial in that it forms an insulating sheet over the flowing water. Another form of ice relates to the mass of ice that is formed at the surface of a water body and which results from the sucessive freezing of sheets of water that seep or flow over existing ice layers. This type of icing condition is known as "river icing" or "aufies". Sheet ice and river ice result in difficulties relating to ice pressure, ice jamming, and ice pile-ups and are often the cause of freezing gages, valves, and other exposed structures. The form of ice that is perhaps most difficult to deal with in hydroelectric power plant operations is that commonly known as "frazil . " 1ce . This type of ice consists of small particles or crystals of ice floating in the water at any depth when and where turbulent water approaches freezing temperature. The temperature range within which frazil ice tends to form is very narrow and may extend only tenths to thousands of degrees Celsius above and below freezing. Prevention of trouble and service interruptions as a result of frazil ice has to start with proper plant design. In addition to possible frazil ice build-up at plant structures, this ice has a tendency to adhere to river bottom in fast flowing streams, thus forming" anchor ice." 2.6.3 Safeguarding Against Ice Problems The recognition that ice problems can develop and that corrective or preventive measures are needed is by itself the first safeguard. Successfully operating hydroelectric power plants have been constructed throughout those areas of the world where severe ice conditions develop. The adaptation of proper engineering and design techniques coupled with certain proven corrective measures usually results in minimizing ice- related problems. For example, a long and deep pond, high head, good and permanent ice cover (sheet ice), and deeply submerged intakes are some positive approachs. The use of underground (tunnel) water conveyance A.2-37 systems also decreases the instance of ice-related problems. Supplementing such safeguards are several designs and special approaches that can also be used; some of these measures might be the application of heat to stuctures and/or equipment, the circulation of warmer water either by submerged pumps or an air bubbler system, special coating and insulation, mechanical ice removers, and the removal of the ice-sensitive equipment from the water during the winter season. 2.6.4 Ice and the Study Plants Special consideration will be given in Phase II of the study to possible ice problems if a hydroelectric power project is considered as part of the regional power plan. For the hydroelectic power projects previously discussed, the formation of ice is inevitable. The formation of sheet or river ice would not be considered a major problem for the Kontrashibuna Lake, Kukaklek Lake, and Chikuminuk Lake projects. Sheet or river ice may present some difficulties and could require some precautionary measures for the Newhalen River regional development. The possible difficulties from these two ice forms would most likely affect the Tazimina River regulating dam projects, in that section of the river between the regulating dam and the forebay dam, and would also probably affect all of the small (local) run-of-river projects. Frazil ice would most likely have minimum impact on the Kontrashibuna Lake, Kukaklek Lake, and Chikuminuk Lake projects. These projects relate to long, deep reservoirs, with possible deep intakes, high heads, and use of underground water conveyance systems. Frazil ice may also have a minimum impact on the Newhalen River regional power project. This is because the by-pass canal system relates to low velocity flows which are conducive to the build-up of a good insulating sheet ice cover, and the depth of the canal which could have a beneficial temperature effect on the water as well as toward the submergence of the intake structure. Also, for this concept, it is easy to remove those structures that would be most adversely affected by frazil ice (trash racks on deflector racks). It is unlikely that anchor A.2-38 ., .. .. • .. • .. .. - - -.. • • • • • • -.. • .. .. • • .. - • - ice will form in the by-pass canal system; this is because during the winter, the maximum probable flow velocity of the water in the canal would be less than 1.0 fps. Frazil ice and/or anchor ice problems would likely be more acute for the other run-of-river plants studied, particularly for the small (1,200 kW) Tazimina River concept. Should any of these run-of-river plants be considered as part of the regional power plan, special attention must be given to probable ice problems. A. 2.7 Expanded Hydroelectric Regional Proj ects The previously described regional projects have been "tailored" from a capacity and energy standpoint to meet the year 2002 electrical power needs forecast for the study regions. These are an installed capacity of 16 MW and a total yearly energy capability of about 74,500 MWh/yr. However, some of the regional hydroelectric sites may be technically suitable for higher capacity and energy development. Such potential would permit power to be supplied to areas beyond what was defined in this study as the limits of the Bristol Bay Regional Power Plan. The benefits which might result from such a Ifmulti-regionallt development are: (1) the ability to supply electrical power to areas adjacent to Bristol Bay, that is, Bethel and Togiak, (2) the economies of scale that can be realized from a larger single installation, and (3) a small differential increased impact on the environment. The most likely candidates for multi-regional developments, based on known technical and environmental considerations, appear to be: a. A Newhalen River Project b. A Chikuminuk Lake Project As a further consideration, there exists the possibility of developing Ifmulti-subregional" projects. An example may include: A Newhalen River project for serving only the Lake Clark/Iliamna Lake regions and the villages along the Kvichak River; coupled with a Chikuminuk Lake project designed to serve the Nushagak River villages, as well as the Bethel and A.2-39 Togiak areas. While "multi-subregional" developments may be possible, assessment of their feasibility is beyond the scope of the Phase I study. However, such an investigation may be part of the Phase II efforts, if desired by the Power Authority. A.2-40 .. .. .. - • .. .. ., • .. • -.. .. • ., .. .. .,. .. ., ., ... .. .. .. ... .. • .. References for Appendix A.2 1. U.S. Geological Survey, Tazimina Lake Dams and Reservoir Sites, Alaska, two sheets, 1966. 2. R. W. Retherford Associates, Reconnaissance Study of the Lake Elva and other Hydroelectric Power Potentials in the Dillingham Area, prepared for the Alaska Power Authority, 1980. 3. U. S. Geological. Survey, Kontrashibuna Lake and Tanalian River Dam and Reservoir Site, Alaska, two sheets, 1966. A.2-41 TABLE A.2-1 SUMMARY DATA TAZIMINA RIVER REGIONAL HYDROELECTRIC POWER PROJECT Reservoir Design Maximum Water Surface Elevation Normal Maximum Water Surface Elevation Design Minimum Water Surface Elevation Surface Area -Maximum WSL Surface Area -Minimum WSL Active Storage Total Storage Storage Dam Type Height Crest Elevation Outlet Facilities Spillway Type Crest Elevation Crest Length Design Discharge Forebay Dam Type Height Crest Elevation Penstock Diameter Thickness and Material Length Turbine-Generators Number and Capacity Turbine Type Maximum Gross Head Design Head Operating Speed Generator Voltage 701 ft 690 ft 655 ft 8,200 acres 4,100 acres 200,000 acre-ft 220,000 acre-ft Rockfill 65 ft 705 ft Four 4-ft diameter pipes One 2 l/2-ft diameter pipes Ungated sidechannel 691 ft 625 ft 75,000 cfs Concrete Gravity with overflow Section 20 ft 595 ft non-overflow 590 ft overflow 8 ft 3/8-in steel 6,700 ft Two units, each @ 8,000 kW Vertical Francis-type 180 ft 160 ft 450 rpm 13.8 kV TABLE A.2-2 RIVER AND GENERATING FLOWS TAZIMINA RIVER REGIONAL HYDROELECTRIC POWER PROJECT Month Tazimina River Flow Generating Flow Average (cfs) 80% Exceedence (cfs) Average (cfs) Peak (ds) Jan 197 133 663 901 Feb 115 97 669 893 Mar 113 93 570 799 Apr 110 94 597 812 May 761 340 639 861 Jun 2,889 1,751 806 1,084 Jul 3,254 2,709 884 1,186 Aug 2,560 2,159 710 1,028 Sep 1,844 1,428 592 752 Oct 1,388 678 594 794 Nov 350 245 649 846 Dec 350 231 726 990 TABLE A.2-3 AVERAGE RESERVOIR RELEASE AND LEVEL TAZIMINA RIVER REGIONAL HYDROELECTRIC POWER PROJECT Generating Reservoir Regulated Reservoir Release Spillage River Flow Level Month (ds) (cfs) (cfs) (ft) Jan 663 663 681 Feb 669 669 677 Mar 570 570 671 Apr 597 597 667 May 639 639 668 Jun 806 806 687 Jul 884 1,947 2,831 690 Aug 710 2,026 2,560 690 Sep 592 1,252 1,844 690 Oct 594 794 1,388 690 Nov 649 649 688 Dec 726 726 685 Month Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Month Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 16 TABLE A.2-4 MONTHLY ENERGY CONTRIBUTION TAZIMINA RIVER MW REGIONAL RUN-OF-RIVER POWER PROJECT Tazimina River Flow, Generating Flow (cfs) (cfs) 197 197 115 115 113 113 110 110 761 639 2,889 806 3,254 884 2,560 710 1,844 592 1,388 594 350 350 350 350 TABLE A.2-5 RIVER AND GENERATING FLOWS TAZIMINA RIVER LOCAL RUN-OF-RIVER POWER PROJECT Percentage of Regional Energy -2002 30 17 20 18 100 100 100 100 100 100 54 48 Tazimina River Flow Generating Flow 80% Exceedence (ds) Average (ds) Peak (cfs) 197 133 105 139 115 97 111 139 113 93 89 132 110 94 83 111 761 340 74 111 2,889 1,751 65 69 3,254 2,709 58 76 2,560 2,159 72 138 1,844 1,428 87 125 1,388 678 94 139 350 245 105 145 350 231 105 166 TABLE A.2-6 SUMMARY DATA KONTRASHIBUNA LAKE REGIONAL HYDROELECTRIC POWER PROJECT Reservoir Design Maximum Water Surface Elevation Normal Maximum Water Surface Elevation Design Minimum Water Surface Elevation Surface Area -Maximum WSL Surface Area -Minimum WWL Active Storage Storage Dam Type Height Crest Elevation Outlet Facilities Spillway Type Crest Elevation Crest Length Design Discharge Power Tunnel Diameter Lining Length Turbine-Generators Number and Capacity Turbine Type Maximum Gross Head Design Head Operating Speed Generator Voltage 535 ft 520 ft 456.5 ft 7,000 acres 5,032 acres 380,000 acre-ft Rockfill 90 ft 545 ft One 10-ft diameter pipe Ungated overflow 520 ft 220 ft 50,000 cfs 13 ft Concrete 11 ,500 ft Two units, each @ 8,000 kW Vertical Francis-type 281 ft 220 ft 450 rpm 13.8 kV TABLE A.2-7 SUMMARY DATA CHIKUMINUK LAKE REGIONAL HYDROELECTRIC POWER PROJECT Reservoir Data Maximum Surcharge Water Surface Elevation Normal Maximum Water Surface Elevation Normal Minimum Water Surface Elevation Surface Area at El. 619 Surface Area at El. 598 Active Storage (approximate) Storage Dam Type Height Crest Elevation Outlet Facilities Spillway Type Crest Elevation Crest Width Design Discharge Diversion Works Type and size Tunnel Length Design Discharge Flow Power Tunnel Type and size Tunnel Length Steel-Lined Section 636 ft 619 ft 598 ft 27,900 acres 24,320 acres 570,000 acre-ft Rockfill with central impervious core 100 ft 640 ft. One 3-ft diameter steel pipe with control valves Ungated concrete ogee 620 ft 320 ft 75,000 cfs 16-ft horseshoe, concrete-lined tunnel with concrete flip-bucket energy dissipator 930 ft 7000 cfs 16 ft horseshoe, concrete lined tunnel, reducing to two 9-ft diameter circular steel-lined tunnels 2,800 ft One each 120 ft and 100 ft liners, 3/8 in thick Turbine-Generator Number and Capacity Turbine Type Maximum Gross head Design Head Operating Speed Generator Voltage TABLE A.2-7 (cont) Two each @ 8,000 kW Vertical Francis -type 120 ft 100 ft 257 rpm 13.8 kV - • .. .. .. • .. .. • • • .. • • • .. • .. lilt • lilt .. .. .. .. -.. ., .. -., -.. TABLE A.2-8 FLOW DATA CHIKUMINUK LAKE REGIONAL HYDROELECTRIC POWER PROJECT Allen River Flows Required Average Average 80% Exceedence Generating Flow Month (ds) (ds) (ds) Jan 577 482 1,110 Feb 489 410 1,115 Mar 379 317 955 Apr 285 239 1,024 May 700 585 1,098 Jun 4,361 3,647 1,413 Jul 3,295 2,756 1,562 Aug 2,112 1,766 1,230 Sep 2,119 1,771 998 Oct 1,163 973 995 Nov 624 521 1,085 Dec 606 507 1,183 TABLE A.2-9 SUMMARY DATA CHIKUMINUK LAKE LOCAL HYDROELECTRIC POWER PROJECT Reservoir Data Maximum Surcharge Water Surface Elevation Normal Maximum Water Surface Elevation Normal Minimum Water Surface Elevation Surface Area at El. 602 Surface Area at El. 598 Active Storage (approximate) Storage Dam Type Height Crest Elevation Outlet Facilities Spillway Type Crest Elevation Crest Width Design Discharge Diversion Works Type and size Tunnel Length Design Flow Discharge Power Tunnel Type and size Tunnel Length Steel-Lined Sections 619 ft 602 ft 598 ft 25,800 acres 24,320 acres 60,000 acre-ft Rockfill with central impervious core 40 ft 625 ft one 3-ft diameter steel pipe with control valves Ungated concrete ogee 603 ft 320 ft 75,000 cfs 16 ft horseshoe, concrete, lined tunnel with concrete flip-bucket energy dissipator 2,260 ft 7,000 cfs 12 ft diameter horseshoe type concrete-lined, reducing to two 7 ft diameter circular steel-lined tunnels 2,800 ft One each 120 ft and 100 ft liners, 3/8 inch thick Turbine-Generator Number and Capacity Turbine Type Maximum Gross Head Design Head Operating Speed Generator Voltage TABLE A.2-9 (cant) Two each @ 4,000 kW Vertical Francis-type 102 ft 85 ft 300 rpm 13.8 kV .. -.. lit, • lit. .. .. .. .. .. .. .. .. .. -.. . ' .. .. .. - -.' .. -• TABLE A.2-10 FLOW DATA CHIKUMINUK LAKE LOCAL HYDROELECTRIC POWER PROJECT Allen River Flows Required Average Average 80% Exceedence Generating Flow Month (cfs) (cfs) (cfs) Jan 577 482 593 Feb 489 410 633 Mar 379 317 488 Apr 285 239 539 May 700 585 528 Jun 4,361 3,647 622 Jul 3,295 2,756 627 Aug 2,112 1,766 599 Sep 2,119 1,771 534 Oct 1,163 973 530 Nov 624 521 595 Dec 607 507 632 TABLE A.2-11A SUMMARY DATA NEWHALEN RIVER DIVERSION POWER ONLY REGIONAL HYDROELECTRIC POWER PROJECT Reservior The concept considers a "diversion" of some flow from the Newhalen River, by the use of a canal. As such the reservior is the natural stream of the Newhalen River. Normal Maximum Water Surface Elevation Normal Minimum Water Surface Elevation Active Storage Not applicable. This is run-of-river plant. Storage Dam Not applicable. This is run-of-river plant. Spillway Not required. Diversion Canal Type Size Natural river channel unchanged. Length, approximate Cross Sectional Area Maximum Design flow in Canal, approximately Canal flow velocity at maximum flow Average Generating Flow (Year 2002) Canal flow velocity at ave. generating flow Max. flow at Peak generation (16 MW) Canal flow velocity at peak generation Penstock Size and type Length, approximate Steel Branch Lines 165 ft 153 ft Trapezoidal Section, open cut excavation in rock, concrete lined in gravels. Top width and Invert width vary. 14,000 ft 2,600 sq ft @30 ft depth, approximate 2,100 cfs 0.9 ft/sec 1,033 cfs 0.40 ft/sec 2,100 cfs 0.9 ft/sec 12 ft diameter, steel pipe on saddle supports 1,300 ft Two each 9 ft diameter, 125 ft long TABLE A.2-11A (cant) Canal Flow Control Spillway Not required -canal terminates at intake for power plant. Powerhouse Type Size, overall plan Turbine-Generators Number and Capacity Turbine Type Maximum Gross Head Design Head Operating Speed Generator Voltage Concrete substructure with prefabricated steel super- structure 47 ft. wide by 96 ft. long, including service bay area Two each @ 8,000 kW Vertical Francis -type 125 ft 100 ft 257 rpm 13.8 kV • .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. • .. .. .. .. .. .. .. .. .. j" TABLE A.2-11B SUMMARY DATA NEWHALEN RIVER DIVERSION POWER & RIVER DIVERSION REGIONAL HYDROELECTRIC POWER PROJECT Reservoir The concept considers a "diversion" of some flow from the Newhalen River, by the use of a by-pass canal. As such the reservoir is the Newhalen River and the canal. Normal Maximum Water Surface Elevation Normal Minimum Water Surface Elevater Active Storage Not applicable. This is run-of-river plant. Stor,flge Dam Not applicable. This is run-of-river plant. Spillway Not required. Diversion Canal Type Size Natural river channel unchanged. Length, Approximate Cross Sectional Area Maximum Design flow in Canal, approximately Canal flow velocity at maximum flow Average Generating Flow (Year 2002) Canal flow velocity at ave. generating flow Max. flow at Peak generation (16 MW) Canal flow velocity at peak generation Penstock Size and type Length, approximate Steel Branch Lines 165 ft. 153 ft. Trapezoidal Section, open cut excavation in rock concrete lined in gravels. Top width and invert width vary 14,000 ft. 2,700 sq. ft. @30 ft. depth, approximate 21,000 cfs 7.9 ft/sec 1,033 cfs 0.40 ft/sec 2,100 cfs O.B ft/sec 12 ft diameter, steel pipe on saddle supports 1,300 ft Two each 9 ft. diameter, 125 ft long Canal Flow Control Spillway Type Crest Elevation Gates Gate Hoists Powerhouse Type Size, overall plan Turbine-Generators Number and Capacity Turbine Type Maximum Gross Head Design Head Operating Speed Generator Voltage TABLE A.2-11B (cont) Concrete gravity, structure with three 36 ft wide flow bays 138 ft. Three each vertical lift wheel-type gates Three each, 40-ton capacity fixed drum hoists Concrete substructure with prefabricated steel super- structure 47 ft. wide by 96 ft. long, including service bay area Two each @ 8,000 kW Vertical Francis -type 125 ft. 100 ft. 257 rpm 13.8 kV - - - III' • .. .. .. .. .. .. • .. .. .. • .. .. .. .. • .. .. .. • --.. ---- II!' Month Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec TABLE A.2-12 FLOW DATA NEWHALEN RIVER DIVERSION REGIONAL HYDROELECTRIC POWER PROJECT (Applies to both Concepts) Newhalen River Flows Average 80% Exceedence (cfs) (cfs) 2,700 2,100 1,900 1,900 4,700 14,000 21,000 22,000 18,000 11 ,000 6,300 3,600 2,050 1,600 1,500 1,500 2,400 9,800 18,000 19,000 16,000 8,600 4,000 2,500 Required Average Generating Flow (ds) 1,017 1,026 874 927 981 1,237 1,356 1,089 908 912 996 1,078 TABLE A.2-13 SUMMARY DATA NEWHALEN RIVER DIVERSION LOCAL HYDROELECTRIC POWER PROJECT Reservior The concept considers a "diversion" of some flow from the Newhalen River by the use of a channel/tunnel water conveyance system. As such the reservoir is the Newhalen River. Normal Maximum Water Surface Elevation, estimated 106 ft 106 ft Normal Minimum Water Surface Elevation, estimated Active Storage Not applicable. This is a run-of-river plant. Storage Dam Not applicable. This is a run-of-river plant. Spillway (for PMF) Not required. Natural river channel unchanged. Diversion Channel Type Size Length, approximately Cross Sectional Area @ 20 ft. depth of water Power Tunnel and Penstock Size and type of tunnel Penstock Trapezoidal section, open cut excavation in rock 20 ft wide at invert. Top width varies 2,500 ft 450 sq ft 13 ft horseshoe shaped, unlined tunnel 2 each 4 ft diameter steel pipes, 40 ft long Powerhouse Type Size, overall plan Turbine -Generators Number and Capacity Turbine Type Maximum Gross Head Design Head Operating Speed Genreating Voltage TABLE A.2-13 (cont) Concrete substructure with prefabricated steel superstructure 42 ft wide by 50 ft long, including service bay area Two each @ 600 kW Vertical axis, propeller 66 ft 50 ft (Depends on design) 4.17kV • ., • • • ., .. • • • It • • • ., • - - -.1 • WI! • Month Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec TABLE A.2-14 FLOW DATA NEWHALEN RIVER DIVERSION LOCAL HYDROELECTRIC POWER PROJECT Newhalen River Flows Average (cfs) 2,700 2,100 1,900 1,900 4,700 14,000 21,000 22,000 18,000 11,000 6,300 3,600 80% Exceedence (cfs) 2,050 1,600 1,500 1,500 2,400 9,800 18,000 19,000 16,000 8,600 4,000 2,500 Required Average Generating Flow (cfs) 165 174 140 130 116 101 91 114 136 148 164 164 TABLE A.2-15 SUMMARY DATA KUKAKLEK LAKE REGIONAL HYDROELECTRIC POWER PROJECT Reservoir Data Normal Maximum Water Surface Elevation Normal Minimum Water Surface Elevation Surface Area of Present lake Active Storage (approximate) Storage Dam None Required Regulating Structure Type and Size Gates Gate Operators Spillway and Diversion Work None required Intake Channel and Structure Approximate length of channel Channel Shape Channel Invert Elevation Intake Structure Power Water Conduit 815.5 ft (call 816.0 ft) 811. 0 ft 43,000 acres 194,00 acre-ft Open Flume Concrete, 120 ft long by 40 ft wide Steel Folding leaf type two each 55 ft long Hydraulic cylinders 3,500 ft Trapezoidal 800 ft Concrete Gravity Type Type and Size 8 ft diameter steel penstock Length, approximate Construction Turbine -Generator Number and Capacity Turbine Type Maximum Gross Head Design Head Operating Speed Generator Voltage 46,000 ft Buried Two each @ 8,000 kW Vertical Francis -type 776 ft 700 ft 900 rpm 13.8 kV TABLE A.2-16 KUKAKLEK LAKE NATURAL-REGULATED-GENERATING FLOWS REGIONAL HYDROELECTRIC POWER PROJECT Kukaklak Lake Alagnak River Outflow Flow Average Average Average Average Average Natural Regulated Natural Regulated Generating Month (cfs) (ds) (ds) (ds) Jan 220 220 660 660 146 Feb 250 250 660 660 147 Mar 250 250 660 660 125 Apr 260 260 680 680 135 May 1,420 1,230 3,170 2,970 144 Jun 3,770 3,430 8,350 8,030 186 Jul 5,290 4,870 12,010 11 ,590 205 Aug 5,240 4,870 12,390 12,020 162 Sep 3,720 3,440 9,840 9,200 131 Oct 1,620 1,430 4,750 4,560 131 Nov 510 510 1,860 1,860 143 Dec 250 250 660 660 155 Note: Average natural flow data were derived and not measured. Data based on historic streamflow and drainage basin information available from the Newhalen, Tanalian, and Kvickak Rivers. Month Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec TABLE A.2-17 KUKAKLEK LAKE WATER SURFACE ELEVATIONS REGIONAL HYDROELECTRIC POWER PROJECT Kukaklek Lake Elevation Natural (ft) 810.0 810.0 810.0 810.0 811. 6 813.5 814.6 814.6 813.6 811. 8 810.5 810.0 Water Surface* Regulated (ft) 810.6 810.4 810.2 810.0 811 . .7 813.8 815.2 815.5 814.7 813.0 811.5 810.8 * This assumes that the natural water surface elevation of Kukaklek Lake is at 810. At this level, the depth of water at the lake outlet is assumed to be 1.0 ft. TABLE A.2-18 SUMMARY DATA KUKAKLEK LAKE LOCAL HYDROELECTRIC POWER PROJECT Reservoir Data Normal Maximum Water Surface Elevation Normal Minimum Water Surface Elevation Surface Area of Present Lake Active Storage (approximate) Storage Dam None Required Regulating Structure Type and Size Gates Gate Operators Spillway and Diversion Work None Required Intake Channel & Structure Approximate Length of Channel Channel Shape Channel Invent Elevation Intake Structure Type and Size Length, approximate Construction Turbines -Generators Number and Capacity Turbine Type Maximum Gross Head Design Head Operating Speed Generating Voltage 815.5 ft (call 816.0 ft) 811. 0 ft 43,000 acres 194,000 acre-ft Open Flume concrete 120 ft long by 40 ft wide Steel Folding leaf type, two each 55 ft long Hydraulic Cylinder 3,500 ft Trapezoidal 800 ft Concrete, gravity type 7 ft. diameter, steel penstock 11 ,000 ft Buried Two each @ 3,500 kW Vertical Francis -type 341 ft 300 ft 720 rpm 13.8 kV TABLE A.2-19 KUKAKLEK LAKE NATURAL-REGULATED-GENERATING FLOW LOCAL HYDROELECTRIC POWER PROJECT Kukaklek Lake Alagnak River Outflow Flow Average Average Average Average Average Natural Regulated Natural Regulated Generating Flow Month (ds) Cds) (cfs) Cds) (ds) Jan 220 220 660 660 144 Feb 250 250 660 660 133 Mar 260 250 660 660 131 Apr 260 260 680 680 136 May 1420 1200 3,170 2,950 162 Jun 3,770 3,390 8,350 7,990 228 Jul 5,290 4,810 12,010 11 ,530 272 Aug 5,240 4,860 12,390 12,010 182 Sep 3,720 3,440 9,840 9,200 130 Oct 1,620 1,430 4,750 4,560 130 Nov 510 510 1,860 1,860 136 Dec 250 250 660 660 154 Note: Average natural flow data were derived and not measured. Data based on historic stream flow and basin information from the Newhalen, Tanalian, and Kvickak Rivers. Month Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec TABLE A.2-20 KUKAKLEK LAKE WATER SURFACE ELEVATIONS LOCAL HYDROELECTRIC POWER PROJECT Kukaklek Lake Water Surface Elevation* Natural (ft) Regulated (ft) 810.0 810.0 810.0 810.0 811.6 813.5 814.6 814.6 813.6 811. 8 810.5 810.0 810.5 810.4 810.2 810.0 811.7 813.8 815.2 815.5 814.7 813.0 811.5 810.7 * Assumed natural water surface elevation of Kukaklek Lake is El. 810. At this level. the depth of water at the lake outlet is assumed to be 1. 0 ft. ~~lJFIGURE A.2-1 NORMAL MAX ws. EL S5>O' 30' CONCRETE j CUT-OFF WI\l.L TOP CF ROCK IN'-\,lSi),'';'M.,.E,...i.._!!tiiIl!!QIlICZ!!IIi!J!, ~LIII!!i!l!ll""'_ A-A SCALE' 1'-20' 20.0020 GENERAL PlAN SCALE: f.~ Mt< OPERATNG ws. EL 6:::J __ 30' 20 10 0 20 \ , \~ TAZIMINA RIVER DEVELOPMENT REGIONAL POWER PROJECT BRISTOL BAY REGIONAL POWER PLAN ALASKA POWER AUTHORITY STONE &. wt:BSTER ENGINEERING CORPORATION J. 0. 14007 OENVER. COLO. -IAN. !982 -------------------------FIGURE A.2-2----- EL9oo--------------------------------------------------------------------------------------------------------------------El~ El 800------------------------------------------------EXISTING -------- EL700-----------------------~~~~~--------------------------------------EL 655' ____ _ --------EL 700 ----------- El600------+------···········-------····-------~----------------------------+--------------------~---------Eleoo 600" 1: 200 st.OPE 625' OVERFLOW SECTION SECTION (j ~ SPILLWAY OVERFLOW SECTION & CHANNEL (AT STORAGE RESERVOIR) SCALE: ,'.m loo!)() 0 100 200 CROSS-SECTION @ SPILLWAY SCAi.£: 1'.100' ,00~!)()~-;:O:"""'''"""!,~00~!!!!!!!!!2oo TAZIMINA RIVER DEVELOPMENT REGIONAl. POWER PROJECT BRISTOl BAy REGIONAL POWER PLAN ALASKA POWER AUTHORITY STONE & WEBSTER ENGINEERING CORPORATION ..1.0. 14007 DENVER, COLO . & FIGURE A.2-3-------- TAZIMINA RIVER ________ 640-------------------------~ 645--~ I VALVE I I I II I I I II II I OUTLET II I I , PIPES~ I: I I I 'I I II I, I I I II , I I , I I I I '0' _ PIPE TO SPILLWAY 'I II II I CHANNEL FOR TEMPORAR I I I RIVER D<VERSION"'. ____ --+ _________ -IJB C ------1+./-Uill-L..:r-------...L----UtJ I:..Llj ~ -------->.... IAlVE HOUSE ACC~ 650----------~~~~~~~~----------~ NCRETE HEADWALL PLAN -RESERVOIR OUTLET INTAKE STRUCTURE SCALE, 1'· 20' 20 10 0 20 /~LMAX W S. EL 690' 40 GATE STRUCTlRE PLAN -RESERVOIR OUTLET GATE STRUCTURE SCALE: 1·. 20' 20 10 0 20 J OAM CREST ----...fi~~~!SZ~~~~~----"'" EL 705' ;>cCESS BRIDGE ---------------------- OUTLET PlPES""",~~,,=::--~ 650 ___ _ PLAN -RESERVOIR OUTLET DISCHARGE STRUCTURE SCALE, 'I' • 20' 20 10 0 20 •• >~ _-::;~",,_STLLNG BASINS -H---tt-----Cl ti _ PIPE EL635'---------- A - A B - B SCALE: 1'· 20' SCALE: l' • 20' 20 10 0 20 40 20 10 0 20 D 650'--..,---------------i ----------------..,--650' 2«)' OGEE SECTON 55d---------------'=::.::...--------------------------550' FOREBAY DAM ELEVAnON LOOKING DOWNSTEAM SCAlE:'" 50' 50 ZI 0 50 100 40 t GATE OPIERATOR SECTION @ <i PENSTOCK ~TAKE STRUCTURE SCALE: '1'. 2d 20 10 0 20 40 "-OUTLET PlPlES EL 6451 C - C SCALE, '1'. 20' BUTTERFLY VALVE wI OPERATOR 20 10 0 20 40 [EL595' r-------,-r ~~R!.Si ~L590' 20 10 D-D SCALE: ('·20' o 20 RIVER BOTTOM .----------------------1 EL575', 40 TAZ IMINA RIVER DEVELOPMENT REGIONAL POWEB PROJECT BRISTOL BAY REGIONAL POWER PLAN ALASKA POWER AUTHORITY STONE & WEBSTER ENGINEERING CORPORATION .1.0. 14007 DENVER, COlO. FEB. 1982 FIGURE A.2-4 PARKING ARE A EL 425' 4, 1 SLOPE !-+-....,-l---.;----+------t-'r--___1 EL 388' DOWN I------~~~------~ 20' 47' PLAN -EL 425' SCALE; ,'.10' 10 5 0 10 ~-----------------4_1A 20 / BUTTERFLY VALVE wi A-A SCALE: I' -10' 10 ~ 0 10 20 TAZIMINA RIVER DEVELOPMENT REGIONAL POWER PROJECT BRISTOl BAY REGIONAL POWER PLAN ALASKA POWER AUTHORITY STONE & WEBSTER ENGINEERING CORPORATION J.n 14007 DE NVER, COLO. JAN. 1962 FIGURE A.2-S , SURFACE AREA -ACRES xl03 8 7 6 5 4 :; 2 1 o 600~------~--------+_------_+--------~~----~------~--------+-------~ 680~--~~~--------+_----~~--------r_------~------~--------+-------~ t-= LL • ~ RESERVOIR AREA ~ VOLUME CURVE w ~ 670-l----_f__~~_f__--_+_--__+_-T AZIMINA LAK E -+-------1 w ~ LL a: ::J U) a: w ooO~----~~r_------~----~~--------~------_r------~r_------;_------~ i OOO~~----~--------+_------_+--------r_------~------~--------~~----~ MO~------~--------+_------_+--------r_------~------~--------+_------~ 50 100 1 0 200 250 300 350 400 CUMULATIVE VOLUME -ACRE FT xl03 I, , I I I , ." , , , 'f. j FIGURE A.2-6 __._.J r-----------------------------------------------------~N COl 4.000-----....--_-__ ---.---..,----,,...--_-__ ----. 3.500-+---tY---+---+----+---+----+----iI---+---+----I 3.000-+--+--+---+----+---+----+----iI---+---+----I 2.500-t--+-tr---f---I---+---+----II---+--+--+-----t ... b ~ 2.000-l---I--t--+--....f---+---+---;I---+---+---I----t o ...I U. 1,500 ...... -+--~r__-I---+----;----I--1---+--+----! o 10 20 30 40 50 60 70 80 90 100 PERCENT OF TIME EQUALLED OR EXCEEDED T AZIMINA RIVER FLOW -DURATION AVERAGE MONTHLY FLOW BASED ON DAMES & MOORE ESTIMATED FLOW S "'---------FIGURE A.2-8--- o N • N o C FIGURE A.2-9 NORMAL WSE!.!en . /- 560 PLAN-GATED INTAKE STRUCT\..RE seAL£:,1"·'O' 10 5 0 10 20 -1-1 , I G4TE {l.P POSITIO"O t : ~ ...... -- I I I I t:5-- GENERAL PLAN SCALE, ,'.500' PLAN -FONERrousE SCALE ,1'.10 10 ~ 0 10 ~ 0 10 550~ L?© -~f7= ___ ... _",/'r--- 600~ TAZII' .. llNA RIVER DEVELOPMENT LOCAL POWER PROJECT BAY REGIONAL POWER PLAN ALASKA PONER AUTHORITY STONE & WEBSTER ENGI\EERNG CORPORATION .1.0. 14007 DENVER, ro.o, JAN. 1982 L-__ '~O 5~~C_!'~~'~: ~2O:""'-_________________ FIGURE A.2-10 A LAKE CLARK w. s. EL 254' / / GENERAL PLAN SCALE, f. 500' !IOO 250 0 1000 800 __ -- } I <JYJ ~)------------------.......... ----------------------------------------~ ............. -----~----·--------------------------------------------900 ~--------------------------------------------800 700-----------------------------------------------~~~---------------------.~OL~~~----------------------------700 600 -------------------------------------7tl~-------------------------------------.. -.----------------- /"GATE HOIST STRUCTURE KONTRASHIBUNA LAKE 600 NORMAL MAX 500-------------------------~~~~----~--------------------------------------.. ---_________ ~ __ . _____________________ ~~~;:==~~~W~.S~.~E~L=5~20~'==~ ... 500 MIN Ws. SURGE SHAFT EL456' 4oo~~:t::::::~~~~4oo POWERHOUSE 13';1 CONC LlNED TUNNEL -------------------------------------------------------------------------------~O 2oo~~~~ ____ -=~S~T~EE~L~LI:NE~D~PE~N~S~T~OC~K~ _________________________ ----------------------------------------------------------------------------------200 PROFILE THROUGH FLOWLINE HORIZONTAL SC ALL f. 500' /"" "'--'" 1cP c/~ / ,# ( KONTRASHIBUNA LAKE DEVELOPMENT REGIONAL POWER PROJECT 8RISTOL BAY REGIONAL POWER PLAN ALASKA POWER AUTHORITY STONE ~ WEBSTER ENGINEERING CORPORATION J.O.14oo7 DENVER, COLO, JAN. 1962 ~ ________________ !IOO:=.2!SO~O=.!IOO:E.~lOOO _________ FIGURE A.2-12----- sHORE LINE PLAN -LOW LEVEL OUTLET INTAKE STRUCTURE SCALE: 1t1" 2d 20 '0 0 20 40 INTAKE STRUCTURE"\ A-A SCALE, 1'. 2d 20 10 0 20 40 I J --10', PIPE TYPICAL DAM SECTION SCALE' 1". 2d 20 £AXW.S. ~L520' Il/I.M CREST EL 545' PLAN -LOW LEVEL OUTLET GATE STRUCTURE SCALE, 1". 20' 20 40 PLAN • LOW LEVEL OUTLET OUTLET STRUCTURE SCALE' ,".20' 20 10 0 20 EL 4SO' ------10' ¢ PIPE ---- B-B SCALE, '('.20' 20 40 " I C-C SCA:...E f ~ 20' 2~f----1h 0 20 40 G 600" APPRCACH CHANNE.L I 260', SPILLWAY , 300" DISCHARGE CHANNEL. I, CREST EL 521' I ! : ~,--r-) ~ """ ~.,~ .. (*._".,~. ~ '~I -"-" ~ e:,Jiif,$ SECTION @ <k SPILLWAY SCALE, (.100' ,00"10 0 100 200 KONTRASHIBUNA LAKE DEVELOPMENT REGIONAL POWER PROJECT BRISTOL BAY REGIONAL POWER PL AN ALASKA POWER AUTHORITY STONE a. WEBSTER ENGINEERING CORPORATION J. 0. 14001 DENVER, COLO. JAN. 1962 1& FIGURE A.2-13------ (J:j\ \ KONTRASHIBUNA LAKE \ \ .. ., o I + -t i -t PLAN -INTAKE & GATE STRUCTURES SCALE:; 1~ .. 20' 20 '0 0 20 40 I -13' ¢ TUNNEL~ A - A SCALE: ,. = 201 20 '0 0 20 40 EL 570' PLAN -POWERHOUSE FL EL 261' B-B SCALE; ,. '" 101 '0 ~ 0 TO 20 -.JB LEL LAKE CLARK KONTRASHIBUNA LAKE DEVELOPMENT REGIONAL POWER PROJECT BRISTOL BAy REGIONAL P(hYEq PLAN ALASKA POWER AUTHORITY STO'lE a, WEBS TEf< E '<G''<EE RiNG CORPORATION J. 0, '4007 :)ENVEC(. COW. JAN. 1982 FIGURE A.2-14 A r-----------------------------------------~~~~~~--------------------------------.... AREA -ACRES ~ N 7,000 6,000 5,000 : 520 __ ------r-----~ __ ----~------_+------__ ------~------~--__ ~ 510~------+-----~~~r_~------_+------~------~~~--+_----~ ..: u. Z o ~ 490~------+-------r-----~~~~~-------+-------r------~------; c( > w ~ w K ONTRASHIBUNA STORAGE RESERVOIR qO~------+-----~~--~~~----~-------+------~------~----~ 470;-------+-~~~~----~------_+--~r_~------~------+_----~ ~1-~~--+_----~~----~------_+------_r~~--~------+_------1 456.5 ...... ------t------~r------+------~----1--------::I1II-----+------' 100 150 200 250 300 350 CUMULATIVE VOLUME -ACRE FT x 10 3 ---------------FIGURE A.2-1 ~ o <C j CHIKUMINUK LAKE ~ -< /1 ?G o LAKE \ \' i ® I 24 19 ~ CHAUEKUKTULI ~~~~~FIGURE A.2-1,6 24 25 25 36 K LAKE CHIKUMINU ECTION SEE TYP tlVERSION POWER & TUNNELS RAL PLAN GENE E 1",500' ~~S~C~A~L~~~~==~~~ ~~ 0 470" 25 30 36 31 320', "JII 1/ /III t..o EUIARIES) EL640 ROCKFILL 20 10 0 40 EL 615-f ..... _':-t-' --4-----.- 20 10 0 20 DEVELOPMENT CHIKUMINUK L~~~ER PROJECT REGIONAL POWER PLAN BRISTOL BAY REGIONAL AUTHORITY A LASKA POWER CORPORATION ENGINEERING l!1S1 STOlE & WEBSTE"oe:NVER COLO DE!: J 0 14007 & FIGURE A.2-17 700 - 650- 600- MMWSELIl19) MINWSEL59S" -- ALLEN RiVE R E:L::5=7=5::!::;:~~ 550 - 16' n TUNNEL I"<M'ER TUNNEL TAKE-OfF VALVE LON LEVEL OUTLET PIPE EL.520 ALLEN RNER ---4c--"'-- -700 -650 -600 -550 ---------------------------------------------------------------=----~~-----------------------------------------------------------------------------------------------500 650- 630 610- 590- 570 550- 600- 590 - 580- 570- 540- 530- 520- 510- 500- 490- 460- 60 20' 35' SECTION ® <l. INTAKE STRUCTURE SCALE 1".20' o 20 EMERGENCY GATES SECTION® 50 2!l 0 100 <L INTAKE I 30' 40' 30' N ;.. " I ID ~ 20' .1· 20' ~cl ~ . ;., 60' r : N C-C SCALE 1"a20' 3 20 10 0 20 40 , It. OISTRIBlfIOR EL,5oo 10 5 17' ,..1, I " I " I r"8: I 96' tUN !T2 34' I " --\~ '" / \ " / { \ \ \ \ \- tN\~~ '41 26' -r IT I STA10R & ROTOR ERECTION RAMP -UP It. UNITS <£~CESS a!aii~l 5f _lei I 14'MAJOOIOR ~ \ --L:r:r-----..------.Jx,f--_...J ~~L---~~----~L-----~~----~F_~---------~ \ EL490 8-B SCALE 1-'10' o 10 20 SERVICE AREA EL,520 PLAN TURBINE GENERATOR FLOOR @ EL.523 SCAL.E 1",10' 10 5 0 10 20 ALLEN RIVER CHIKUMINUK LAKE DEVELOPMENT REGIONAL POWER PROJECT BRISTOl BAY REGIONAL POWER PLAN ALASKA POWER AUTHORITY STONE & WEBSTER ENGINEERING CORPORATION J.O. 14007 DENVER, COLO. DEC 1981 FIGURE A.2-18 SURFACE AREA -ACRES x10 .. N 800 780 760 740 ...: u. z 0 720 j: <[ ::> w ..J 700 w w U <[ u. 680 a: ::l fI) a: w 660 I-~ 640 629 600 80 70 60 50 40 3[) :1[) 10 0 " ./ ~ " ~ ~ \ / ~ \ ~ X" uv' ~ /~ \ RESERVOIR AREA VOLUME CURVE /' , CHIKUMINUK LAKE ~ /' / I' \ / \. LAKE W.S. EL598 - 0 N 800 • N 0 « 780 760 740 720 700 680 660 640 620 600 580 580 o 1 2 3 4 5 6 7 8 CUMULATIVE VOLUME ACRE -FT. x10 6 -----------------t-IGURE A.2-19'---' j~ CHIKUMINUK LAKE j 1 ! POWE RH9USE---.;--II .... J'>J .' l . j _f ~"'.k /,r, M~J"t..I" / ' ~~--~~ i" / I ,w .~ , , j ! .. LAKE CHAUEKUKTULI J I --I ~"'S" .~-"~ o .11 . 24 i - I~ ( 19 J :1 \ ~ ( I ,' . .,.... - '. { I>t- ·i: .. "t 11 . ,. .- \ .:.. 18 17 19 CHIKUMINUK LAKE 24 25 GENERAL PLAN SCALE 1". ~OO· CHIKUMINUK LAKE DEVELOPMENT LOCAL POWER PROJECT CORPORATIO"l DEC 1981 ~ ~ ~;~C====--___ ---2;~~~;~~ __________ ......:.!~_~~ __ ---.;;;""'-'iio~"""~ FIGURE A.2-21-.... , 700- 650- 600- 550- MAX W S EL 602). MIN WS EL 59B)' .... ...:. 16'.n TUNNEL LOW LEVEL OUTLET PIPE INVEL 520 FLOW CONT fIOL VALVE 700 -650 -600 -550 ~-------------------------------------------------------------------------------------~~---------- 630 610 590- ALLEN RIVER WS EL595 570- 560- 550- 540- 530- 520- 510- 500- 490- 4BO- t..s SECTION @ <:f.INTAKE STRUCTURE SCALE 1" 20' == 20 10 0 20 40 EMERGENCY GATES SECTION@ <:f. POWER & DIVERSION TUNNELS 700 650 600- 550 SCALE r· 50' 5~0~~~-0~~~50~~~'OO --= 20 10 B-B SCALE 1"1: 20' o 20 40 DAM ELEVATION-LOOKING UPSTREAM SCALE 1"·50' 50 ~ 0 100 DISTRIBUTOR EL505 OIlAFT TUBE GATE EL493!: A-A SCALE 1'.10' '0 5 0 10 20 ill 'Of " N , \ -----1f,-~ " \ 5TATOR/!.ROTOR ERECTION AREA YARD AREA EL.523 I I " / '---~--T-\----,--tt. UNITS }' / \ \ \ I' I SERVICE BAY f'~r" ..! 1 4 'MANDOOR 'r ,,--t -+--, ~' ~r% II!IIIII;J a;;;:]I I L --r EL 525 1-----1 f-,,-----,---~ TAILRACE CHANNEL EL493' !...,.A PLAN TURBINE GENERATOR FLOOR ® EL.525 SCALE 1". '0' 10 5 0 20 CHIKUMINUK LAKE DEVELOPMENT LOCAL POWER PROJECT BRISTOL BAY REGIONAL POWER PLAN ALASKA POWER AUTHORITY STONE /!. WEBSTER ENGINEERING CORPORATION J o. '4007 DENVER, COLO L----------------------FIGURE A.2-22- STA 0.00 INV EL '''~' TOP OF ROAO EL 205' / ... C··· ... ( ,)L-,. 2) PIKE LAKE 177 IN GRAVELS SEE CANAL SECTION BY PASS~_--,~~ CANAL / / NEW BRIDGE c.:5 -NEW ROAD NEW V CULVERT 00 GENERAL P~AN SCALE"'500 ~~~;;;"~500~!!!!!!!!!Tol000 500 z:;o 0 CANAL DIVERSION NEWHALEN RIV~ER PROJECT (ONLY) REGIONAL PO GIONAL POWER PLAN BRISTOL BA~~~ER AUTHORITY ALASKA RNG CORPORATION STONE 8. WEBSTER ENE<!'N~~~ JUNE 1982 DENY ". J.O '4007 ~ URE A.2-23 FIGURE A.2-23A cL ~ 12f7/ PARKING AREA INTAKE DEFLECTOR STRUCTURE ACCESS ROlD CANAL PLAN CANAL INTAKE SCALE' (.,00'-0" o 100 200 CANAL SECTION IN ROCK SCALE d-2d-Cf 20 10 0 20 40 PLAN POWER INTAKE SCALE :f·1O-0' 10 5 0 10 20 C-C SCALE :1".IO-Cf 10 5 0 10 20 B r RACK GUIOE SLOT MAX. ws. EL'2 MIN. WS.EL.,~ 10 5 10' 20' 4' 2d t--~=----~-'-i---,(-iTY"'P")---t--'-i_4' (TYP) BAITLE WALL DEFLECTOR RACK I,-A SCALE : '"~lC1-o' o EL 112' 10 20 ToP OF CONCRETE EL 1751 CONCRETE TRANSITIONAL CANAL SECTION SCALE. ,',20'-0' 20 10 0 20 EL 175' GATE HOUSE TOP OF GROUNOl c·AMW-. ~~~~~5==T~~~~~ SACKFILL -;1. .\'< 9~. OJ; .~~ .' SECTION -GATE HOUSE SCALE' '"·10-0' 10 5 0 '0 20 BACKFILL PART ELEV. B-B SCALE: '".10'-0' 10 5 o 20 40 12' .. PENSTOCK RACK GUIOE BEDLOIID DEFLECTION WIER PLAN CANAL OUTLET SCALE: (·100'-0' ,F5 TOP OF EL 175' o 20 ROLLER COMPACTED CONCRETE TYP. ON SIDES 1'-6" THiCK VARIES CANAL SECTION IN GRAVELS SCALE ,,", 20'0' 20 10 0 20 40 NEWHALEN RIVER CANAL DIVERSION REGIONAL POWER PROJECT (ONLY) BRISTOL BAY REGIONAL POWER PLAN ALASKA POWER AUTHORITY STONE I\. WEBSTER ENGINEERING CORPORATION J. 0 14007 DENVER, COLO. JUNE 1982 FIGURE A.2-24 C:~225 ) ( ( .J PIKE LAKE 177 CANAL SECTION IN GRAVELS BY PASS ___ ~\.,C"" CANAL GENERAL PLAN SCALE. 1'0 ~OO· ~~2~50~O~~~~~To1000 NEw BRIDGE eJ NEWV CULVERT 00 .-NEw ROAD SPILLWAY CONT ROL STRUCTURE 8. POWERHOUSE INTAKE STRUCTURE NEWHALEN RIVER CANAL DIVERSION RIVER DIVERSION 8. REGIONAL POWER PROJ. BRISTOL BAY REGIONAL POWER PLAN ALASKA POWER AUTHORITY srONt 8. WEBSTER ENGINEERING CORPORATION J.O 14007 DENVER. COLO JUNE 1982 Iv~~ ~ ~'v~~~ ~ FIGURE A.2-25 BEDLC\I\D DEFLECTION WEIR o· ~ INTAKE DEFLECTOR STRUCTURES U> -+I-J'--'7"'~r*--"'~--r+'-Tfi ~ I=:::::;I--~~ STA 0+00 PLAN -INTAKE CANAL SCALE , 1'-100' 1&5"?O 0 50 100 200 DL1==~E +--- 308' END OF CANAL :;IStE CANAL SECTION IN GRAVELS EL 130' \ EL 175' , , r£L 107 ';t I--f-~--STA '+20 228' L PENSTOCK ---------------- PLAN DISCHARGE CHANNEL SCALE,,".,Oo'-O' 100 50 0 '00 200 EL (VARIES) D D SCALE, f'_100'-0' '00 50 0 100 200 ~ TOP OF PARAPET WALL EL '7B.5' ~--------------------------~ I" __ ~EL175' 10 5 PART ELEV B-B SCALE' f.10'-0· o 10 20 BEDLC\I\D DEFLECTION WEIR r- '0 SHORE LINE VARIES NEWHALEN RIVER MAX ws.EL7 5 RACK GUIDE PIER (HP) DEFLECTOR RACK (TYPI MAX WS. MIN W.S. EL A-A SCALE r-1C1-Cf' o 10 20 8 ROLLER COMPACTED CONCRETE r-l I I I I I I I I I I I I L __ 'i PIER <l PIER PART PLAN DEFLECTOR STRUCTURE SCALE' ,'. 'CI-d' DEFLECTOR RACK 8 i C o 10 20 17!;' WALL INTAKE: CANAL INVERT 1EL 130' ~~~~------~~~~ l B CANAL SECTION IN ROCK (INTAKE) SCALE, ,'. 20Cr! --20 10 0 20 40 CANAL SECTION IN GRAVELS SCALE' ,'. 2d-c/' 20 10 0 20 40 C-C SCALE, f'. 'O'-d' o '0 20 TRANSITIONAL CANAL SECTION SCALE :1"4"20'--0" 20 10 0 20 40 NEWHALEN RIVER CANAL DIVERSION RIVER DIVERSION & REGIONAL POWER PROJ. BRISTOL SAy REGIONAL POWER PLAN ALASKA POWER AUTHORITY STONE & WEBSTER ENGINEERING CORPORATION .1.014007 DENVER, COLO JUNE 19B2 -------------------------FIGURE A.2-26 #.'>-"'l';Ec"" ., .4f"/1' '1iV~," ~i EL 130'" SLOPE. if C","NAL ROLL ER COMPACT EO CONCRETE """\ \ EL ,e7 \ 1 ~ GRAVITY SECTION 8-8 SCALE' ':'20'-0' 20 10 0 20 40 c ~ ~PEFLECTOR POWERHOUSE ~4~ PENSTOCK IN AK£ WALL ,--fl---, ID I I I I ... JL E: RACK/ t DEFLECTOR B r r --- ~ FORESAY PLAN CANAL OUTLET WORKS SCALE' ,', 40'-(1 ~o 20 0 40 A-A SCAL€: : 1-... 40'-0" 40 20 0 eo 80 DEFLECTOR WALL OE"LECTOR RACKS '" /"~ nDW BAY D , J"O- I ~ V-::r-SPILL WAY BAYS j D SPILLWAY STRUCTURE :;6' POWER INTAKE SECTION C-C SCALE: ,': 20'-O· 20 '0 0 20 40 FOREBAY WALL IllJ~1 I SPILLWAY DISCHARGE CHANNEL { BYPASS GATE I ~EL'75' SPillWAY GATES BACKFILL DOWNS TEAM SPILLWAY SECTION D-D SCALE ,'=2IJ-cf --20 10 0 20 40 NEWHALEN RIVER CANAL DIVERSION RIVER DIVERSION & REGIONAL POWER PROJ, BRISTOL BAY REGIONAL POwER PLAN ALASKA POWER AUTHORITY STONE &. WEBSTER E:NG1NEERj~G CORPORATlON J 0 14001 DE NV£R ... COLO JUNE 1982 L----------------------FIGURE A.2-26A A EL 20' EL 17' A-A SCALE ''',,10'' 10 5 0 10 I 1 I r A : 1 tUNIT2 17' 34' .... ~ DISTRIBUTOR EL 32' 20 '" \ \ 90' \ tUNIT 1 I I 1,7:--, 28' STATOR & ROIDR ERECTiON It. UNITS ~ 10'ACCESS DOOR i SERVICE AREA / EL5J'~ />.cc£SS ftOI'O ---S\.OP£ _vI' PLAN TURBINE GENERATOR FLOOR ® EL 55' SCALE 1 ", 10' o 10 20 NEWHALEN RIVER CANAL DIVERSION REGIONAL POWER PROJECT SAY REGIONAL POWER PLAN ALASKA POWER AUTHORITY STONE & WEBSTER ENGINEERING CORPORATION J. Q 14007 DENVER. COLQ DEC. 19B1 L------------------------FIGURE A.2-27------ c: ) ( ( .J PIKE LAKE 177 0<\ () 0 \)0 00 n NEWr~ CULVER%~/ 200 ~+---NE"W ROAD I\I~~ ""/(:-<1/"/2 GENERAL PLAN SCALE ,".500- 5OO!!!!!!!!!!..,;250~O ........... ~500~~'OOO NEWHALEN RIVER DIVERSION LOCAL POWER PROJECT BR!STOL BAY REGIONAL PLAN ALASKA POWER AUTHORITY STONE & \vEBSTER ENGINEERING CORPORATION 'J: 14 ·';87 DENVER, COLO iJE"(' ~981 POWERHOUSE "~~ A L_~~u.LJ~LS::J...L~2A.L-_12'.fI.._UNL_INED __ ~.I.-..,...;"""""_ FIGURE A.2-29 200 (GATED NEWHALEN INTAKE RIVER", (ROCK BARRIER ~A ~ • /31\Ulf"'""" ws DAM EL106'\ ---=-E't'1#:' ~ , 150 100 L.A 50 INTAKE CHANNEL o A-A SC ALE' ,", 20' 2;:;---;'0 0 20 41' C-C SCALE: '",'0' 10 5 o '0 / --.. ·,.e '''' e ~Ah\' 12' HORSESHOE UNLINED TUNNEL PROFILE THROUGH FLOW LINE 20 HORIZONTAL SCALE. 1", 500' 500 250 0 20' 1000 EL 125' WSEL106' TRASH RACK GUIOE---__ 20' GATED INTAKE STRUCTURE SCALE: ,", '0' 10 5 0 '0 20 -\ POWERHOUSE \.~WHAL'N , RIVER W,S EL47' ,.' - STEEL PENSTOCK 50' 12' J '3' I 7' ! ! .. C 200 150 100 o ,S' NEWHALEN RIVER 22' 10' ROCK BARRIER DAM SCALE 1".20' 20 10 0 5 ~ 20 B-B SCALE ;;f',,',O' o ... . ~~ , I SERVICE :: 0, ~. AREA\ ~ '" - ----, ;., ;-r-.., + jNITS 0 ~:/L50 c--f-'2' DOORwAY ;., ~ 0 0 % EL .. e'~ 0 RAMP DRAFT TUBE DECK ~ '" ~ ~ EL 50' ""HANORAIL TAILRACE CHANNEL~ 1.., C PLAN TURBINE GENERATOR FLOOR () EL 50' SCALE "'.10' 10 5 0 10 20 ~ ACCESS ROAD) g NEWHALEN RIVER DIVERSION LOCAL POWER PROJECT BRISTOL BAy REGIONAL POWER PLAN ALASKA POWER AUTHORITY STONE & wEBSTER ENGINEERING CORPORATION J,O 14007 OENVER, COLO DEC 198' A FIGURE A.2-30---" " D---~---~----- ~ \. / ~ " .. t--"-'.;-::-~ ~- L " J '\, L..--.f '\ /' , ---~', ~" .----~ \ ;- \ \ -t--- :' L AK E ... ' .. ' 7<'f { \. ,~ , '. , I - ... • ... it KUKAKLEK LAKE 9{X •..• --.... -.---···--"""" ..... --t~-·1--- 200 -~.---.. ------.•.... --.. --.... --~ ... PLAN 1 MAIN- TRANSMISSION LINE '~P'"""i"'l_riil.-"'I_riil.-~~"_iil-!'lii_iil-!'lii_iiiO~!"""'!"""'!"""'!"""'!"""'~"""iiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiii;;iii2 MILES ... _-_ .... __ .... -+----+-.... _------ CUT AND COlER STEEL PIPELINE 100 .---.. ---.... --~-.---.... -.... ----~. ~-.---... ---... -.. -~~ .. ---.. . ····---TRANSMISSION TO IGIUGIG ACCESS <lOAD ILIAMNA LAKE WS.EL 47'(t) PONERHOUSE ····--70:> ,.. ··----68J ~ .. ~500 ' IUM··· .. >lA LAKE ~ -400 ~ w ~300 ;Z -:-'00 o--~--4--+_--+--+_·-_+--~---+_-_+--··~--+--1L--+---+---+_--~---~--4_--_+--t--~--1~-~-·-+-~~~=t~·O PROFILE a a ~ o o o o '" KUKAKLEK LAKE DEVELOPMENT REGIONAL POWER PROJECT BAY REGONAL PCWER P:"t.~ ALASKA POWER S":"ONE 8. WLBs:E~ ENG'r-.. EERiNG CORPORATION J 0, ~..: co' C'EJ\;VER, COLC. DEC. 1981 FIGURE A.2-32---- ,. A t.. 860 - 840 - 820 - 800 780 - 900 - 000 INTAKE STRUCTURE 700 600 -POWERHOUSE !;oo --500 400-----------------------------------------------------------------------------------------------------------------------------------------~-----------------------------------------t I i INVERT ELBOO WATER CONDUIT PROFILE -LOCAL PCMfER PlAN SCALE T'.~ GATE SLOT OF GROUND PART PLAN REGIONAL & LOCAL SCALE '" 20" 20 '0 0 20 20' 20' TOP C1" Bl>CllFILL EL 627 EL.850~ PENSTOCK COUPLING ----.;----- '-EOTTOM OF EXCAVATION FOR PENSTOCK TRE~H A-A SCALE '''.20' 20 '0 0 20 PENSTOCK 1-1 TYPICAL DETAIL OF EXCAVATION SCALE '".20' 2010020 20 '0 I Ii. I B-B SCALE '''·20' o 20 KUKAKLEK LAKE DEVELOPMENT REGIONAL & LOCAL POWER PROJECTS BAY REGIONAL POWER PLAN ALASKA POWER AUTHORITY STONE e. WEBSTER ENGINEERING CORPORATION J O. '4007 DENVER, COLO DEC '98' FIGURE A.2-33----' .~ r~ 70 LIM:! a; ROCK EXCAVAT:ON 1 I 1 I r ( r;: 15 ~ 7 -~ 50' A PLAN -TLRBNE GENERATOR FLOOR REGICNAL POWERHOUSE SCALE~1' ~10' 10 5 0 10 A-A SCAi....E '!"~10 10 5 0 '0 20 L ~o' \ D \ r \ c j L D EL53'! .r------70 ~'1K'''G AREA EL. ~3' El. 53' ~ I I , t , [ ~~ 60' PLAN -FLOW REGULATING STRUCTURE S:ALE .1' .. 10' 10 5 0 10 20 -:----~--- 1 / i - 1 p I \ "---~ li NOn::, THIS STRUcTLRE IS LDCATED AT THE OUTLET OF KUKAKLEK LAKE, ----,~' ---~~ AREA 7' C PLAN -TURBINE GENERATOR FLOOR -EL500' LOCAL PONERHOLEE SCALE,f.10' 10 !; 0 10 20 B-B seA:"'£:: ;"~,o' '0 !; 0 10 20 10 5 l I I ! ",I "'\ D-D SCAL~ '1.1C' o 10 20 KUKAKLEK LAKE DEVEUJPMENT REGIONAL & LOCAL POWE8 PROJECTS ALASKA POWER AUTHORITY STONE &. WE eSTER E4G/NEERrNG CORPORATION J,O, '4007 DEWER,COcO, DEC,1981 L------------------------FIGURE A.2-34----.... t f I 1,_ "-> ~-----~; ..... 'f I • .~ I :~bD -~- '" o .. , . . ' . '-," \ , . - ----.r-> a • > K U ." ... t"-... 1>1 ..... "'1 -,.k. ..... I;:; 1 • . " ) I I -< Z :E -< -- 700 600----' 650 700 700 20 21 ~~~=-~~------------~,-~£~~~--~~---------------=~~~----------~~~o 29 28 850 GENERAL PLAN SCALE 1'>500· 860- 800- 1000 BOO 950 1000 30 29 31 32 INTAKE CHANNEL KUKAKLEK LAKE EL 810~) 840- 820- 800- 850 ~ A-A INTAKE CHANNEL SECTION (TYP.) (CDR REGO<AL AND LOCAL DEVELOPMENT) SCALE, 'i' _ 20' 2010020 ct. I 20 cu.1PEQ ROCK FILL $2E 18"and LARGER CHANNEL ~=""IllI""Il!~~'I11II"~~~~~~~~'NVERTEL.eoo. a-a ROCK BARRER DAM SECTION (Fa? REGONAI... AJ<) LOCAL DEVELCPMt:!\;;) SCALE.,.. 20' 20 10 0 20 40 KUKAKLEK LAKE DEVELOPMENT LOCAL POWER. PROJECT BRISTOL SAY REGIONAL POWER PLA.N ALASKA POWER AUTHORITY STONE &. WE&srER ENGINEERING CORPORATION J 0 14001 OEN"€R,COLO DEC 1981 L..----------------"'---------FIGURE A.2-36--....1 A. 3.1 General APPENDIX A.3 DIESEL POWER Diesel power presently generates the major part of the electrical energy used in the Bristol Bay region. The equipment is easy to install and operate; it is also reliable if properly maintained. The cost of oil, however, is increasing. In this study, Caterpillar, Detroit-Stewart & Stevenson, and Cummins engines were used to compare consumption, costs, and operating ranges. The only generation assumed to be existing is that which belongs to an electrical company, REA, a co-op, or native school districts. Private generation is not included. For those scenarios which use diesel generation, the assumption was made that all would have a central diesel generating system, either located in each village or in a central load center. This assumption tends to favor diesel generation scenarios because of lower fuel consumptions resulting from the more efficient centralized systems. A review of regional generating modes shows that central diesel generating systems exist in the villages such as Dillingham and Naknek, two areas where almost 80 percent of the present total regional energy needs are being met, New Stuyahok, Clarks Point (new housing development), Portage Creek, and Koliganek. A central system is being installed to serve the Iliamna-Newhalen-Nondalton villages. The economic benefits resulting from the assumption of centralized systems is somewhat counterbalanced by the assumption for early installation of required diesel generation for meeting the needs of 100 percent reserve. The capital investments for such installations were applied in the same economic time period as the development of the centralized systems. For small units of 50 to 200 kW, the installed cost ranges from $430 to $1, OOOjkW. For larger units up to 1,500 kW, the cost ranges from $340 to $430jkW installed. There is also a heavy-duty diesel available in the A.3-1 1,000 to 4,500 kW range; the cost for the heavy-duty unit ranges from to $640/kW installed. The heavy-duty units run about five times as between overhauls. $530 long .. ... -.. .. The condition of the presently existing equipment that is to be considered • for use is unknown or varied. To give all equipment a known base to start .. from, it is assumed that all existing equipment is to be completely rebuilt; money is allotted for this overhaul in the economic evaluation. The oil storage existing at many villages is unknown. Therefore, it is assumed the existing storage is at the 1980 energy level. The 1980 energy demand was mUltiplied by the fuel consumption-to-output ratio; this would .. be the assumed existing storage capacity in gallons of oil. It is also III! assumed that the storage tank would only be filled annually to meet the energy demand for a year (this pertains to the full-time operating plants) . Oil storage for the reserve plants is 25 percent of the annual energy demand for each village. If a village is isolated from the system, it will be able to operate for at least three months. This should be sufficient time for the system to be repaired. Two types of oil storage tanks are available: pre-fabricated and field-fabricated. Pre-fabricated storage tanks up to 18,000 gal are more economical than field-fabricated. Field-fabricated tank capacity is up to 600,000 gal each. There is a wide range of installed costs up to $475,000/tank; each tank would be installed on a concrete pad with a retaining wall for spill protection. An average generator output-to-fuel consumed ratio was assumed for 50, 75, and 100 percent load (Ref 1). Table A.3-1 summarizes these data. The installation of equipment is in five-year increments. Powerhouse expansion is in 10-year increments. The powerhouse will be large enough to house two five-year expansions of equipment. In all scenarios, the peak demands of the villages were compared to the peaks in July and December. Rural non-fishing villages have a peak in A.3-2 .. .... .. It - .. December (Figure A.1-20), while fishing villages have a peak in July (Figure A.1-22). In the BP-l scenario, central system diesel generation is installed in each village with a 100 percent reserve (Table A.3-2). This allows the engines to be operated only 50 percent of the time, and extends the equipment life from 20 years to 30 years (Ref 2). An operating and maintenance cost for each village is assumed. Dillingham, Naknek, and Newhalen will have permanent personnel. In the other villages, a part-time operator will be contracted from within the village to check the equipment once or twice each day; maintenance or repair crews will be flown in once or twice yearly. In the B-15 scenario, there are four diesel load centers and the surrounding lines. The villages are load center connected to each load capacity meets the peak center by transmission demand of itself and related villages or its own peak plus 100 percent reserve, whichever is larger. The related villages have adequate generation capability but no other reserve. The installation schedule for the generators is shown in Table A. 3-3. In this scenario, the load center generates continually and the related villages operate only in an emergency. The B-17 scenario is based on interconnecting all Bristol Bay region vil- lages. It will take about two years to install the transmission lines. For this study, it is assumed that the line will be in service in January 1986. Realizing that the installation of transmission lines will take place, a 100 percent reserve will not be installed in the smaller villages for the first few years; however, each village will be able to meet its own peak demand and have some reserve. The generation is installed from the beginning as if the transmission lines are already installed. Table A.3-4 shows the percent of reserve above the peak demand for the years 1983 through 1985. The oil storage for the load center meets the total energy requirement for all the villages in the group being served by the center for one year. The A.3-3 storage in the related villages is 25 percent of the yearly energy requirement; this is provided for emergency operation and tests. The B-16 scenario is very similar to B-15 except Dillingham and Naknek are intertied with a transmission line. It is assumed these two villages can .. share reserve capabilities; therefore, the reserve is cut to 50 percent of the peak of the respective village or the total peak demand of the load center and all of its related villages, whichever is larger. Table A.3-5 shows the installation schedule. In scenario B-16, as in B-15, it is assumed that the transmission lines will be completed in January 1986, and the reserve will be below 100 percent in some villages. The percent of reserve is shown in Table A.3-6. The oil storage and all other aspects of this scenario are the same as those for B-15. In the B-17 scenario, all of the villages are connected by transmission lines. The diesel load centers are in Dillingham and Naknek. Table A.3-7 shows the installation schedule. One load center is staffed with a full crew; the other centers would have only one or two men. All other villages have a part-time operator. The load is divided between Dillingham and Naknek at the Kvichak River, and the Kvichak villages load is part of the Naknek load. Dillingham and Naknek each have a 50 percent reserve. All villages have .. Jilt .. .. generation to meet their own peak needs if isolated. In the B-17 scenario, - as in the two previous scenarios, it is assumed that the transmission lines will be completed by January 1986. The reserve is below 100 percent in some villages, as shown in Table A.3-8. The B-19A, B-19B, B-19C, and B-19D scenarios use the same diesel requirements as the Base Plan (BP-l). The B-19E scenario has the same diesel requirements as BP-l for all villages except Iliamna, Newha1en and Nondalton, which are supplied by a local Tazimina Hydroelectric plant. A.3-4 .. r A.3.2 Heavy Fuel Heavy fuel is available from the North Pole Refinery at Fairbanks. The cost F.O.B. Fairbanks is in the range of $0.75 to $0.78jga1 (1982 dollars) (Ref 3). Shipping and loading costs to Dillingham are estimated in the range of $0.29jga1. Some very large 2,500 kW locomotive diesels can operate on heavy diesel; however, the use of heavy fuel creates certain problems. The engine must be started with No. 2 diesel fuel and then switched to heavy oil after the engine is warm. The heavy oil needs to be heated. Before the engine is shut down, it needs to be switched back to No. 2 to clean the fuel lines. If the heavy oil is left in the lines, it can block them and prevent the engine from starting until the fuel lines are cleared. There are other difficulties in using heavy fuel. The valve seats and cylinder wall wear out much sooner. The time between overhauls is reduced from 60,000 hours to 40,000 hours, a reduction of 33 percent (Ref 4). When heavy fuels are used, all fuel supply lines and tanks need to be heated or the oil will not flow in cold temperatures (Ref 5). Most manufacturers do not build engines to use heavy oil, nor do they convert them to this use. Because of the fouling and higher maintenance costs, many diesel manufacturers advise against using heavy fuel (Ref 6, 7, 8). The higher sulfur content of heavy fuel requires that the oil and filter be changed more often; parts wear out faster and there is more S02 in the exhaust discharge. In addition, the chemical analyses of heavy fuels may vary, and this can affect the operating efficiency of the engines. Because of this increased maintenance, shorter engine life, increas ed air pollution, and lack of manufacturers t heavy fuel does not appear to be an generation at this time. A.3-5 interest and approval, the use of advisable alternative for power References for Appendix A.3 1. Technical Manuals provided by Caterpillar, Detroit-Stewart & Stevenson, and Cummins, 1982. 2. Alaska Power Authority Economic Guidelines, 1981. 3. Notes of telephone conversation between R. Stout (SWEC) and S. Lewis (North Pole Refinery), February 1982. 4. Notes of telephone conversation between R. Stout (SWEC) and K. Gloor (Transamerica DeLaval), February 1982. ", - • - • WI - 5. Notes of telephone conversation between R. Stout (SWEC) and G. Barnetti - (Cummins Diesel), February 1982. 6. Notes of telephone conversation between R. Stout (SWEC) and G. Colman (Caterpillar Diesel Wagner), February 1982. 7. Notes of telephone conversation between R. Stout (SWEC) and D. Toland (Detroit-Stewart & Stevenson), February 1982. 8. Notes of telephone conversation between R. Stout (SWEC) and B. Hamilton (Isuzu Diesel), February 1982. A.3-6 .. .. .... .. ", ", - - ", Load 50% 75% 100% 50 kW 7.5 8.0 8.5 TABLE A.3-1 GENERATOR COMPARISONS kWh/Gal of Oil 75 kW 8.0 8.5 9.0 100 kW 9.0 9.5 10.0 500 kW 11.0 11.5 12.0 1,000 kW 12.0 12.5 13.0 1,500 kW 12.5 13.0 13.5 Dillingham 1982 through 1987 1992 1997 Naknek 1982 through 1987 1992 1997 Clarks Point 1982 through 1987 1992 1997 Ekuk , .. 1982 through 1987 Portage Creek 1982 through 2002 Manokotak 1982 through 1987 1992 Ekwok 1982 through 1987 New Stuyahok 1982 through 1987 1992 Koliganek 1982 through 1987 " .... Egegik 1982 through 1987 TABLE A.3-2 DIESEL UNITS TO BE INSTALLED Scenario BP-1 2 -1,500 kW 1 -1,000 kW and 1 -1,500 kW 2 -1,500 kW 1 -1,500 kW 1 -1,500 kW 1 -1,500 kW 1 -75 kW and 2 -150 kW 1 -75 kW 1 -100 kW 2 -550 kW, 2 -300 kW, and 2 -60 kW -0- 2 -75 kW 1 -50 kW 2 -50 kW 1 -175 kW 1 -175 kW 2 -100 kW 2 -650 kW Levelock 1982 through 1987 1992 1997 Igiugig 1982 through 1987 1992 Newhalen 1992 1997 TABLE A.3-2 (continued) DIESEL UNITS TO BE INSTALLED Scenario BP-1 2 -50 kW 1 -50 kW 1 -50 kW 2 -75 kW 1 -75 kW 1 -450 kW 1 -450 kW Dillingham 1982 through 1987 1992 1997 Naknek 1982 through 1987 1992 1997 New Stuyahok 1982 through 1987 1992 Levelock 1990 Manokotak 1982 through 1987 1992 Clarks Point 1982 through 1987 1992 Igiugig 1987 1992 Ekwok 1997 Ekuk 1982 through 1987 TABLE A.3-3 DIESEL UNITS TO BE INSTALLED Scenario B-15 1 -1,000 kW and 2 -1,500 kW 2 -1,500 kW 1 -1,000 kW and 2 -1,500 kW 1 -1,500 kWand 1 -1,000 kW 1 -1,500 kW 1 -1,500 kW 1 -175 kW and 1 -75 kW 1 -175 kW 1 -75 kW 1 -75 kW 1 -75 kW 1 -150 kW 1 -100 kW 1 -50 kW 1 -50 kW 1 -50 kW 2 -550 kW TABLE A.3-4 PERCENT OF RESERVE Scenar io B -15 1983 1984 1985 Dillingham 195 182 169 Naknek 148 142 137 New Stuyahok 136 122 110 Clarks Point 32 27 23 Ekuk 10 10 10 Levelock 103 84 68 Igiugig 38 29 21 Newhalen 264 241 220 Portage Creek 461 433 416 Manokotak 60 51 43 Ekwok 60 50 39 Koliganek 100 90 83 Egegik 18 20 21 Dillingham 1982 through 1987 1992 1997 Naknek 1987 1997 New Stuyahok 1982 through 1987 1992 Egegik 1982 through 1987 Levelock 1990 Clarks Point 1982 through 1987 1992 Koliganek 1982 Igiugig 1987 1992 TABLE A.3-5 DIESEL UNITS TO BE INSTALLED Scenario B-16 1 -500 kW and 1 -1,500 kW 2 -l,500kW 1 -1,500 kW 1 1,500 kW 1 -1,000 kW 1 -75 kW and 1 -75 kW 1 -175 kW 2 -330 kW 1 -75 kW 1 -150 kW 1 -100 kW 1 -100 kW 1 -50 kW 1 -50 kW TABLE A.3-6 PERCENT OF RESERVE Scenario B-16 1983 1984 1985 Dillingham 102 93 84 Naknek 99 94 90 New Stuyahok 136 122 110 Clarks Point 32 27 23 Ekuk 10 10 10 Levelock 103 84 68 Igiugig 38 29 27 Newhalen 264 241 220 Portage Creek 471 433 416 Manokotak 60 51 43 Ekwok 60 50 39 Koliganek 100 90 83 Egegik 18 20 21 Dillingham 1982 through 1992 1997 Clarks Point 1982 through 1992 Ekuk 1982 through Ekwok 1997 Koliganek 1982 through Manokotak 1982 through 1992 New Stuyahok 1997 Naknek 1987 1997 Egegik 1982 through Igiugig 1987 1992 Levelock 1997 1987 1987 1987 1987 1987 1987 TABLE A.3-7 DIESEL UNITS TO BE INSTALLED Scenario B-17 1 -1,000 kW and 1 -1,500 kW 1 -1,000 kW 1 -1,000 kW and 1 -1,500 kW 1 -150 kW 1 -100 kW 2 -550 kW 1 -50 kW 1 -100 kW 1 -75 kW 1 -75 kW 1 -50 kW 1 -1,500 kW 1 -1,000 kW 2 -330 kW 1 -50 kW 1 -50 kW 1 -75 kW TABLE A.3-8 PERCENT OF RESERVE Scenario B-17 1983 1984 1985 Dillingham 126 115 105 Naknek 99 94 90 New Stuyahok 57 47 39 Clarks Point 32 27 23 Ekuk 10 10 10 Levelock 103 84 68 Igiugig 38 29 21 Newhalen 264 241 220 Portage Creek 471 433 416 Manokotak 60 51 43 Ekwok 60 50 39 Koliganek 100 90 83 Egegik 18 20 21 APPEND IX A. 4 WASTE HEAT RECOVERY Diesel waste heat can be removed from the engine exhaust and cooling water. When fue 1 burns in the engine, 30 percent is converted to shaft power, 30 percent turned to heat in the cooling water, 30 percent is turned to heat in the exhaust, and 10 percent is radiant heat (Ref 1). The water jacket recovery system and the combination water jacket and ex- haust recovery system were considered. In the combination system (Figure A.4-1) about 50 percent of the exhaust heat can be recovered; however, in the Alaska climate. moisture condenses in the exhaust (Ref. 2) . This moisture increases maintenance to both the recovery system and the diesel engine. Because of the initial cost of the exhaust recovery system and the increased maintenance, the combined system is not included in this study. The water jacket recovery system is very simple, with low maintenance costs (Figure A.4-2). This is the system used for this study. The cooling water temperature is in the range of 165 to 2000 F. This water can easily be used for space heating. It is advisable to go through a heat exchanger to transfer the heat to another system, as this prevents loss of cooling water to the engine by a leak in the secondary system. The fluid from the heat exchanger to the home is typically a water-glycol combination. The plate heat exchanger transfers the heat from the cooling water system to a system used to heat nearby buildings. These buildings will need a secondary heating system when the waste heat system is not in operation. A typical BOO-ft loop system (400 ft out from the power plant) is developed with a pump to circulate the fluid (Figure A.4-3). Arctic pipe is used for low heat loss. At the present time, there is a waste heat system, in Alaska, which is 1,200 feet from the power plant to the building that is heated. The heat loss is about 10 F . Therefore, for this report it is assumed the heat loss on the BOO ft loop is zero (Ref. 2). It is also assumed that Dillingham and Naknek have waste heat equipment installed on A.4-l the existing engines (Ref 3). This study does not investigate the additional cost in the house for piping, radiators, valves and other equipment required to use the hot water for heating the home. This would add to the capital cost. The daily load curve is not investigated, that is, whether or not the electrical demand curve coincides with the daily heat demand curve. Waste heat cost for the pipe and delivery system installed will be in the range of $156/ft of pipe. This does not include the heat exhanger. The Alfa-Laval plate heat exchanger would range in price from $4,800 to $16,000. Waste heat is already being used over 1,200-ft from a source; to be conservative use 1,000 ft. The waste heat available for Dillingham or Naknek is 10 percent or less of the space heating requirements. Therefore, it would be safe to assume the powerhouse to be within a 1,000-ft. radius of 10 percent of the space heating load. In the smaller villages 10 percent of the heat load would be within a 200 ft. radius of the powerhouse. Since only Naknek and Dillingham are of a larger size, it is assumed that a 400 ft. radius is about average. It is assumed that since 10 percent of the heating load is within the average radius, then 100 percent of the available waste heat load is used. The heating value of fuel (137,500 Btu/gal of oil) used as typical is taken from local operating records (Ref 4). To determine the waste heat avail- able. 30 percent for cooling water plus 3 percent of the radiant heat for heating the powerhouse, or a total of one-third of the fuel, can be re- covered. Table A.4-l relates the waste heat available to the kWh/gal of fuel. The waste heat recovered is assumed to replace space heat. The heating load decreases in the summer months, when warmer temperatures prevail and schools are not in session. In a discussion with Naknek Electric Assoc- iation, it was stated that "less than 5 percent of the waste heat produced during May, June, July, and August was used" (Ref 5). For this report, it is assumed that no waste heat is used in the four summer months. This A.4-2 .. *' Ie .. • .. Ilk .. eliminates the use of a larger portion of the waste heat in the villages involved in the fishing industry. In Ekuk, Clarks Point, and Egegik, 85.17 percent of the waste heat produced cannot be used to replace space heating (Table A.4~2). However, this heat can be used in some other manner, i.e., heating greenhouses for the production of fresh vegetables or to dry peat. The temperature of the water in the water jacket is from 165 to 2000 r. To use this water in the compression stage of a cooling cycle it would cool a brine solution down to 40 to 45 0 r which would not be of much use. To get temperature down to freezing it would require temperatures around 600 0 r and 10 psi (Ref. 6). The temperature could be obtained from the exhaust; however, it was recommended by APA not to use waste heat recovery equipment on the exhaust (Ref 2). The B-19A and B-19C scenarios assume the continuation of diesel generation in the present procedure. In this case, waste heat can be added in all villages; however, it does not appear to be economically feasible in Ekuk, Egegik, Clarks Point, or Portage Creek. In the B~15 and B~16 scenarios, waste heat equipment is installed in the load centers in Dillingham, Naknek, New Stuyahok, and Newhalen. In all other villages the diesels are intended for reserve generation and are not operated except in emergencies or tests. In the B-17 scenario, the waste heat recovery equipment is only in Dillingham and Naknek. All other generators are reserve. In all cases, the operating and maintenance cost is assumed to be 2 percent of the capital cost of the waste heat equipment. The installation of equipment is in five~year increments. A.4~3 References for Appendix A.4 1. Standard Handbook of Engineering Calculations, Hicks, 1972. 2. Telephone conversation between R. Stout (SWEC) and Jerry Larson (APA) , February 1982. 3. University of Alaska -Institute of Social and Economic Research, draft report to Stone & Webster Engineering Corporation, January 1982. 4. Nushagak Electric Cooperative, Operating Records, January-December 1980. 5. Telephone conversation between R. Stout (SWEC) and G. McCormick (Naknek Electric Association), January 1982. 6. Telephone conversation between R. Stout (SWEC) and W. Axt (SWEC, Boston) Refrigeration and waste heat specialist. June 1982. A.4-4 .. .. .. - TABLE A.4-1 WASTE HEAT RATE PER KILOWATT-HOUR 137,500 Btu/Gal of Fuel Waste Heat Recovered kWh/Gal Gal/kWh Btu/kWh Btu/kWh 7 0.1429 19,643 6,548 8 0.1250 17,186 5,729 9 0.1111 15,278 5,093 10 0.1000 13,750 4,583 11 0.0909 12,500 4,167 12 0.0833 11 ,458 3,819 13 0.0769 10,577 3,526 14 0.0714 9,821 3,274 Village B-l9A Scenarios Dillingham Naknek Clarks Point Egegik Ekuk Ekwok Egiugig Koliganek Levelock Manokotak New Stuyahok Portage Creek Newhalen TABLE A.4-2 USA "SI.E AND NON -USABLE WASTE HEAT Percent of Waste Heat Produced in May, June, July, and August 32.58 42.01 87.17 87.17 87.17 26.01 26.01 26.01 26.01 26.01 26.01 26.01 26.01 Percent of Usable Waste Heat 67.42 57.99 14.83 14.83 14.83 73.99 73.99 73.99 73.99 73.99 73.99 73.99 73.99 B-15 and B-16 Scenarios Dillingham Naknek New Stuyahok Newhalen B-17 Scenario Dillingham Naknek 39.25 45.07 26.39 25.97 38.20 43.56 60.75 54.93 73.61 74.03 61. 80 56.44 r-------------------------------------------------------------------------------------------.... N HEAT RECOVERY SILENCER EXHAUST 1 ENGINE HOT WATER LINE COOL WATER LINE ~ 1---1"'" ,.. L.ot WATER JACKET '" - HOT WATER .A-----~ .. TO HEATING SYSTEM ""'" COLDWATER ..... __ '..+""-----FROM HEATING SYSTEM HEAT EXCHANGER SYSTEM DIAGRAM FIGURE A.4-1 o N • N ~ EXHAUST 1 ENGINE ~ " HOT WATER '" TO HEATING SYSTEM , HOT WATER LINE ..... .H --, COOL WATER LINE ~ COLDWATER ~ FROM HEATING SYSTEM HEAT EXCHANGER " .....,j "'" , WATER JACKET - SYSTEM DIAGRAM -FIGURE A.4 2 .. M CI N • N ~ ~----------------------------------------------------------------------~N .. HEAT EXCHANGER PUMP SUPPLY LINE RETURN LINE TO BUILDING tRETURN FROM BUllf'NG TYPICAL CLOSED LOOP HOT WATER SYSTEM ""'---------------FIGURE A.4-3-.... CI N • N CI c( A.5.l. Introduction APPENDIX A. 5 ENERGY CONSERVATION Conservation of electrical and space heating energy is an economically attractive source of new energy that is and can continue to be available to the Bristol Bay region. Evidence from weatherization programs indicates that conservation can be effectively implemented at costs which are competitive with present and projected costs of diesel heating fuel. Conservation can mean greater energy efficiency and a better use of energy resources. Despite the fact that conservation may require what may appear to be substantial initiative investments. these initial costs are almost always offset by years of benefit. Conservation can touch our lives in numerous ways and through varying means, from the conservation of the foodstuffs to conservation of electric and space heating energy. The State of Alaska has recognized the merits of conservation (Ref 1). Through Senate Bill 438, the State is providing numerous programs committed to energy efficiency. Conservation is now underway in Alaska and in the Bristol Bay region. Data from current conservation efforts are being analyzed and should provide future guidelines for both energy savings and social impact. New programs should also provide methods for monitoring and evaluating conservation components when these programs are planned. Conservation should involve both energy producers and users: the state, the public, the utilities, the profit and non-profit village corporations of the Bristol Bay region and last, but most importantly, the individual homeowner. Conservation could prove to be an important untapped pool of energy, specifically with to space heating. For the purpose of this appendix, only the merits of energy conservation relating to the space heating demand forecasts of the Bristol Bay study area have been reviewed. Conservation, as it may relate to load management, is discussed in Appendix A.lO. A.5-1 Of direct interest are the residential and commercial/government space heating requirements. A precise evaluation of the benefits of energy conservation as applied to these two sections of the community can only be eval ua ted by the performance of detailed energy audit programs, which are beyond the scope of this study (this is also true of addressing the benefits of conservation on the military and industrial sections of the study region). For the Bristol Bay study region, our attention focused primarily on the application of conservation measures with respect to space heating energy needs; this is not to say, however, that conservation measures should not be implemented with respect to electrical needs. There exists within the study region a large variety of housing stock with respect to size, needs for space heating energy, and responsiveness to weatherization conservation measures. On one hand, the application of energy conservation measures may be too difficult to implement from the consumers' standpoint. It is doubtful that energy conservation could be applied to a point where the cost of an additional "unit" of conservation would be equal to the cost of an additional unit of energy saved. This is essentially an application of the law of diminishing returns. The difficulty of conservation implementation results from several factors: 1) the need for up-front financing, 2) plans by a property owner to sell his property prior to the time required to realize a net benefit from a conservation investment he might be considering, 3) the lack of knowledge about materials and methods of application, and 4) the fact that the benefits of energy conservation are inherently hidden to the consumer. These factors tend to restrain the pace of conservation improvements in both the residential and commercial/government sectors. On the other hand, there also exist incentives which tend to make the consumer aware of the benefits of conservation. Some of these are: 1) the cost for space heating, 2) available grants through weatherization programs and low interest loans, and 3) educational programs and literature on conservation measures. It A.S-2 ... I!II!' III liil! .. is hoped that these incentives will be strong enough and can be effectively applied to stimulate the desire for energy conservation into action within the study area. A brief evaluation study on conservation was made by ISER. This study was based on the examination of residential conservation data and energy audits by the Rural Alaska Community Action Program (Rural CAP). The data was on 142 low-income Bristol Bay homes, encompassing 12 of the 18 study area communities. The study cons idered an average retrofit horne and compared the heating energy needs of this average horne prior to retrofit with an average horne that was "wished" into retrofit conditions complying with HUD efficiency standards. This brief study showed that the total fuel oil requirements of the average low income horne declined 31 percent, from 1,300 gallons to 900 gallons. Although it is unrealistic to assume that all Bristol Bay residential households could achieve this result, discuss ions with a Department of Energy and Power Development respresentative (Ref 2) indicate that an overall regional res idential savings 15 to 17 percent in space heating energy yearly needs would not be impossible to attain. Others (Ref 3) have reported that between 30 and 50 percent of the space heating energy consumed by existing dwellings could be eliminated through conservation measures such as caulking, weather-stripping, using of storm windows, adding additional insulation, and improving the efficiency of heating systems. Similarly, it has been reported that in the commercial and industrial section, thermal efficiency improvements along with energy management techniques could conceivably reduce energy consumption by 12 to 15 percent. For the residential sector, there are areas where individual improvements can be made, such as: • Insulation of attic, walls, and floors • Weather-stripping and caulking • Storm windows and doors • Foundation insulation A.5-3 • Vapor barriers • More efficient oil heating system • Nore efficient hot water heating system The specific contribution of space heating savings by each of the above as these may apply to the present conditions existing in each of the communities of the Bristol Bay study region can only be evaluated by careful and detailed energy audits and analyses i such audits and analyses are beyond the scope of this present study. However, the implementation of some of these energy savings measures could be addressed in general terms to show their cost-effectiveness. In discussing weatherization aspects for the Bristol Bay study area with a representatitive of the Alaska Department of Energy and Power Development (Ref 2) and also with a representative from Rural CAP (Ref 4), it was determined that in most instances, the greatest efforts and expenditures related to the implementation of conservation measures are those that reduce infiltration. These are caulking, weather-stripping, and the application of plastic-type storm windows. These measures are usually followed by insulation applications to ceilings and/or walls. Both representatives were quick to has to be carefully audited effective conservation program. caut ion t::ha t every home is unique and each t::o det::ermine the priorities for a more Weather-stripping and Caulking Weather-stripping and caulking around leaky windows, doors and corners of a house saves more energy per dollar of investment than any other conservat::ion measure. Calculations show that fuel usage can be reduced by about 8 percent by reducing the infiltration of air from approximately 0.5 changes per hour to 0.30 changes per hour. The initial cost investment, even considering outside labor, can range from $100 to $125 per home for caulking and weather-stripping. Insulation -The next most cost-effective conservation approach relates to insulation, particularly the insulation of the more accessible areas such as ceilings, roofs, and underneath floor areas. Insulating a ceiling in a A.S-4 .. .. lilt _ill II' Iii! • II' 23 ft x 30 ft home to improve its resistance from R25 to R38 (adding 3 5/8 in insulation) could present an initial investment of about $640 for material and labor. This investment alone could result in a 3 percent savings in fuel needs per year. Insulation of floors would represent a similar investment, but with a somewhat lower, but still cost effective, return. Both of these estimates assume a life use of the insulation of 20 years. Insulating wall areas for conservation is more difficult to assess due to unknown construction conditions and often difficult access. Windows and Storm Doors - A single glazed window has an R-value of about 0.89 while a double-glazed windows has an R-value of 1.89. Windows are the greatest heat robbers of a home per square foot of area. The addition of glass glazed windows can be a very effective means of reducing heat losses. A change in the conductivity "u" values from 0.69 to 0.47 over a total window area of about 130 sq ft could result in a fuel savings of about 8 percent in a hypothecical 23 ft x 30 ft house. G lass glazing is expensive; for example, it could cost about $1,800 in a Bristol Bay study home. Other less expensive means, such as using a transparent plastic/vinyl material, would have essentially the same effect in energy savings at a substantially lower cost. An additional savings is realized with the installation of storm windows, due to the reduction of infil trating air. Similarly, the use of storm doors or weatherstripped insulated doors can improve the heat efficiency of a home. Estimations of the amounts of first-time investments which must be made to achieve a particular percentage of yearly space heating fuel savings for different periods of live cycles of the various conservation measures are given by Figures A.S-1 through A.5-4. It should be noted that these data are given co show the "break-even" conservation investment. As an example: assume chat fuel oil costs $1.20/gal and that conservation measures are planned such that they could result in a 20 percent savings in fuel needs, and that these measures have a 10-year life and are being A.5-5 applied to a home which, prior to application of the conservation measures, had a total yearly fuel use of 1,080 gal. From Figure A.S-3 (for 10 year life), $1.20/ga1 and 20 percent anticipated savings give $2.30/ga1 burned/year; or $2.30/gal/year x 1,080 gal/year = $2,484 maximum investment to be made for conservation to achieve a 20 percent savings. Based on the present cost of fuel oil and on its anticipated future costs, it would appear that some substantial investments could be made on conservation measures. Conservation expenditures could be presented to the Bristol Bay study region as an energy-producing resource program. The cost of such a program and its comparative evaluation with alternative energy plans can be made with some reasonable confidence on the basis of additional information on the effectiveness of conservation measures in lowering the existing space heating needs and on the basis of a having a firm plan for the future development of energy-efficient building stock. A.S-6 .. - •• -... •• References for Appendix A.5 1. "State of Alaska Long-Term Energy Plan", an Executive Summary prepared for Governor J. Hammond by the Department of Commerce and Economic Development, Division of Energy and Power Development, draft dated April 1981. 2. Notes of Telephone conversation between T. Critikos (SWEC) and M. Carr (Alaska Department of Energy and Power Development), January 1982. 3. Alaska Center for Policy Railbelt," prepared for the Alternatives Study Committee, Studies, "Energy Alternatives for the Alaska State Legislature, House Power August 1980. 4. Notes of telephone conversation between T. Critikos (SWEC) and T. Buckley (Weatherization Supervisor), February 1982. 5. C.H. Hartman and P.R. Johnson, "Environmental Atlas of Alaska", University of Alaska, second edition, no date. A.5-7 General EVALUATION OF \vEATHERIZATION ON AVERAGE STUDY HOUSEHOLD The 1980 average res idential heating fuel consumption is assumed to be 1,118 gal/year, which includes hot water needs (Appendix C). Assumptions a. Assume that fuel requirements for hot water heating represent 10 percent of total average household fuel needs. (1,118 gal/year) -(0.10 x 1,118 gal/year) = 1,006.2 gal/year. This results in a net fuel need for space heating of 1,006.2 gal/year. b. Assume that the average home size is 24 ft x 30 ft x 12 ft. Such a home would have: c. Wall area 1,296 sq ft Roof area 720 sq ft Floor area 720 sq ft Area of windows at 1/10 of wall space 130 sq ft Door area, two, each 3 ft x 7 ft 42 sq ft Assume that the insulating characteristics of the average home are: • Walls are 2" x 4" construction, studs at 16" on center with R-12 insulation having a wall a "u" factor of 0.08. • Ceiling is 2" x 8" construction at 16" on center. Unheated attic with 6" insulation having a "u" factor of 0.04. A.5-8 ,. .'" ... .... 8. Ii, .. • --.. • • Floor is 2" x 12" or 2" x 10" construction with crawl space, insulated perimeter and 6" insulation with a "u" factor of 0.08. • Window "U" factor of 0.69. • Door "U" factor of 0.32. • Infiltration rate at 0.50 air change per hour. Heat Loss Calculations Heat Loss Walls (1296 ft 2)(0.08) == 103.7 Btu/hr tot Heat Loss Ceiling ( 720 ft 2)(0.04) == 28.8 Btu/hr tot Heat Loss Floor ( 720 ft 2)(0.08) == 57.6 Btu/hr tot Heat Loss Windows ( 130 ft 2)(0.69) = 89.7 Btu/hr tot Heat Loss Doors ( 42 ft 2)(0.32) == 13.4 Btu/hr tot SUBTOTAL HEAT LOSS == 293.2 Btu/hr tot Heat loss due to air change of 0.5 air changes per hour. 0.5/hr (8,640 ft 3) (0.075 lb/ft 3) (0.24 Btu/lb tot) = 77.8 TOTAL HEAT LOSS = 371.0 Btu/hr tot Fuel Calculation The average degree heating days within the Bristol Bay study region ranges from 11,000 to 12,000 (Ref 5). Use 11,500 for study exercise. Btu/year = 371.0 Btu/hr At x 24 hr/day x 11,500 degree days 6 Btu/year = 102.4 x 10 Btu/year Fuel use (assuming diesel fuel at 137,500 Btu/gallon) 6 Fuel = 102.4 x 10 Btu/year x 1/137,500 Btu/gal x 1/0.72 gal effective = 1034.3 gal/year/family. The calculated value of 1,034 gal/year compares within 3 percent the average household space heating of 1,006 gal/year. A.5~10 • .. - - .. • • - .. .. General WEATHERIZATION EFFECT ON AVERAGE STUDY HOUSEHOLD Several means are available to reduce the space heating needs of the study average household. As an ultimate, one can consider a similar home constructed to applicable Housing and Urban Development CHUD) standards. Other improvements applied individually or collectively will be examined. Considering Average Household for HUD Standards Reference should be made to attached Exhibit A, and use the following ItU" factors. Walls Ceiling Floor ~vindows Doors Heat Loss Calculations Heat Loss Walls Heat Loss Ceiling Heat Loss Floor Heat Loss Windows Heat Loss Door Itu" factor = "u" factor = "u" factor = "u" factor = "u" factor = (1296 ft 2 )(0. 05) C 720 ft 2 )(0.026) ( 720 ft 2 )(0.05) ( 130 ft 2 )(O.47) ? ( 42 ft-) (0.32) SUBTOTAL HEAT LOSS 0.05 0.026 0.05 0.47 0.32 = 64. B BtuJhr At = 1B.7 BtuJhr At = 36.0 BtuJhr At = 61.1 BtuJhr At = 13.4 Btu/hr At = 194.0 Btu/hr At Assume that due to better construction for space heating efficiency, the infiltration rate of the study average household is reduced to 0.30 air changes per hour (Ref 3). A.5-11 Heat (loss through air change of 0 .. 30 air changes per hour is 0.30/hr (8640 ft 3 )(O.075 lb/ft 3 )(0.24 Btu/hr ~t) = 46.7 Btu/hr ~t TOTAL HEAT LOSS OF HUD STUDY HOME = 240.7 B~u/hr ~t Fuel Calculations Btu/year = 240.7Btu/hr t.t x 24 hr/dilY x 11,500 degree days 6 Btu/year = 66.4 x 10 Btu/year Fuel Use (assuming diesel fuel at 137,500 Btu/gal) 6 Fuel = 66.4 x 10 Btu/year x 1/137,500 Btu/gallon x 1/0.72 gal effective. = 670.7 gal/year/home The 670.7 gal/year family represents about a 35 percent reduction needs, had the average household been built to HUD standards. A.5-12 of fuel ,. ., .. .... ' IF -.. .. tIIIIII -.. • .. ... ... "" .. .. .-... • ., II -.-.. ., .. Ii' .. .. ... "". .. EFFECT OF HEATHER-STRIPPING AND CAULKING IMPROVEMENTS ON AVERAGE STUDY HOUSEHOLD Assume that the average study household is caulked and weather-stripped with the following results. Item Btu/hr bot Heat Loss Walls 103.7 Heat Loss Ceiling 28.8 Heat Loss Floor 57.6 Heat Los 5 Windows 89.7 Heat Loss Doors 13.8 Infiltration 46.7 SUBTOTAL HEAT LOSS = 340.3 Btu/hr llt Fuel Calculations Fuel = 340.3 Btu/hr llt x 24hr/day x 11,500 degree days x 1/137,500 Btu/ gallon x 0.72 gal effective. Fuel = 948.7 gal/year/home. Fuel Needs for the average study home were calculated at 1,034.3 gal/year/ home. The savings is equal to 85.7 gal/year/home. This savings in fuel relates to: 85. 7 gal/year/home x 137, 500 Btu/gal = 6 11.78 x 10 Btu/home of energy saved. Assuming that the cost for weather-stripping and caulking is about $100 to $125 per home, and using $125 per home, the energy savings relates to: 6 $125/home/11.78 x 10 Btu/home = O.OOlC/Btu A.S-13 EFFECT OF ADDITIONAL INSULATION FOR CEILINGS ON AVERAGE STUDY HOUSEHOLD Assume that additional insulation is placed on the ceiling of the average household to improve its "u" value from 0.04 to 0.026. This would means changing from an R=25 value to an R=38 value with the use of insulation, or the addition of another 3 5/8 inches of insulation (R=13) across the ceiling joists. It is estimated that the cost for these improvements would be: Insulation (R-13) @ $0.30/sq ft x 720 sq ft = Installation @ 1.5 x material cost = Adjustment Factor for rural area to account $216 $324 for the shipment of material and the travel/lodging expenses of labor force SUBTOTAL $lOO/home $640/home The heat loss factors applicable to this modified horne are: Item Heat Loss Walls Heat Loss Ceiling Heat Loss Floor Heat Loss Windows Heat Loss Doors Heat Loss Infiltration SUBTOTAL HEAT LOSS = A.5-14 Btu/hr b.t 103.7 18.7 57.6 89.7 13.4 i7 .8 360.9 Btu/hr t.t .. .. .. .. • .. .. • • III - .. --.. "'" - Fuel Calculations Fuel = 360.9 Btu/hr l1t x 24 hr/day x 11,500 degree days x 1/137,500 Btu/ gal x 1/0.72 gal efficiency = 1,006.1 gal/year/home The fuel needs for the average study home were calculated at 1,034.3 gall year/home. The fuel savings due to improvement of ceil ing insulation are 1034.3 gall year/home less 1,006.1 gal/year/home or 28.2 gal/year/home. This fuel savings relates to 28.2 gal/year/home x 137,500 Btu/gal = 3.88 x 6 10 Btu/home of energy saved. Assuming the cost for this improvement, is $640 per home, the energy savings relates to $640/home/3.88 x 10 5 Btu/home = 0.016C/Btu. A.S-1S EFFECT OF ADDITION OF STORM WINDOWS ON AVERAGE STUDY HOUSEHOLD Assume that the average study household has a double pane window or better installed such as to improve its "U" factor from 0.69 to 0.47. Included in the designation "double pane" is the installation of an additional glass, plastic, or transparent membrane barrier either to the inside or outside of the window. windows", This is assumed to compare to the installation of "storm With this modification, the average study house would have the following characteristics. Item Btu/hr At Heat loss, walls 103.7 Heat loss, ceiling 28.8 Heat loss, Floor 57.6 Heat loss, windows 61.1 Heat loss, doors 13.4 Infiltration 77.8 SUBTOTAL HEAT LOSS = 342.4 Btu/hr At Fuel Calculations Fuel = 342.4 Btu/hr At x 24 hr/day x 11,500 degree days x 1/137,500 Btu/ gal x 1/0.72 gal effective (Fuel = 954.6 gal/year/home) The fuel savings from installation of storm windows is 1,034.3 gal/year/ home less 954.6 gal/year/home, or 79.7 gal/year/home. A.S-16 - .. .. .. - .. .. • .. • - ., - .. This fuel savings relates to: 79.7 gal/year home saved. x 137,500 Btu/gal Assuming the use of glass storm windows: 6 = 10.9 x 10 Btu/year/home of energy Storm window material at $8.30/sq ft x 130 sq ft = $1,079 Installation labor @ S4.30/sq ft x 130 sq ft = $559 Adjustment factor for rural areas, to accounts for the shipment of material, and the travel/lodging expenses of labor force, per house = $150 Subtotal Cost = $1,788.00 The resulting cost for this energy savings relates to: $1,788/home/l0.9 6 x 10 Btu/year/home = $ 0.016/Btu/year. A.5-17 .-r---------------------------------------------------,: o * a: ~ w ~ 2.5 ffi 2.0 z a: ::J a:I Z o ..I ..I ~ ~ I": 1.5 z w ~ en w > Z Z o i= ~ 1.0 a: w en Z o (J z w > w lII:: ~ w 0.5 a: a:I 0.0 o ,40% / J ~ 30% 2 YEAR LIFE I / I / $/ / h / ~J / ~ J ~ ~ h / ~ / ~ 20% ~ ~Vf / / II / / &7 1/ / I J ~ ". , / / I / / 1/ / / / / 10% / / ../ / ./ / ~ ./ ~ 5% l/'" ~ ~ ,... 1 2 3 4 FUEL COST, 1982 $/GALLON )\tGALLONS BURNED ARE BEFORE CONSERVATION SAVINGS ASSUMES NO ELECTRICAL SPACE HEAT. CONSERVATION INVESTMENT FIGURE A.5-1 ----' N • N o c( - -* a: < w ~ 6 C 5 w 2 a: ~ III 2 o ...I ...I < 4 ~ ~. 2 w ~ ~ en w ~ 3 2 o ~ < > a: w en 2 2 o (J 2 w > w ~ < w a: III 1 o o '(40% 300/0 5 YEAR LIFE J / , / I L $' L P L ~'l ~, ~, / P, L ~ 20% J'J il L / ~ff / L tJ'? L / q ~ ~ ~ C ~ I / / I / / If/ / / ~ ,. L 10% 1/ / ../' / / / ~ ~ ~ 5% ~ ~ - 1 2 3 4 FUEL COST, 1982 $/GALLON * GALLONS BURNED ARE BEFORE CONSERVATION SAVINGS ASSUMES NO ELECTRICAL SPACE HEAT CONSERVATION INVESTMENT FIGURE A.5-2----' ~--------------------------------------------------~~ ... 12 * 11 a: 0( w ~ Q 10 w z a: ::> IX! 9 z o ...I ...I 0( 8 S! o 1-' Z w 7 ! CIJ w ~ 6 z o ~ 5 > a: w CIJ Z 4 8 z w ~ 3 ~ 0( w a: IX! 2 1 o o ,40% 10 YEAR LIFE J ~ 30% I / 1 / $1 / n / ~y , II / ~, / ~ 20% J'J d / / 7t / / .:::.,'tIf'. ~Y / / oY J , ~ ". I / / 1 / / If / / / ~ ~ 10% if / ~ /' ~ /' ~ ./ ~ 5% ~ ~ ~ 1 2 3 4 FUEL COST, 1982 $/GALLON *GALLONS BURNED ARE BEFORE CONSERVATION SAVINGS ASSUMES NO ELECTRICAL SPACE HEAT CONSERVATION INVESTMENT FIGURE A.S-3 ......... o '" .. '" o « P---------------------------------------------------~~ ~ 24 *' 22 ex: <C w ~ 20 w 2 ex: :::) CO 18 2 o ....I ....I <C ~ 16 ., ,.: 2 w 14 ~ CI) w ~ 12 2 o j:: <c 10 > ex: w CI) 2 8 8 2 w ~ 6 ~ <c w ex: co 4 2 o o 1/40% 20 YEAR LIFE J J 30% / / I / ~/ / g / ~l V ~ / ~ ~ / ~., 20% ~ / / ~ ~y / / If / / 0/ I(' ~ (J ... ~ I / ./ 7 / / II / / / ~ , ~ 10% / / ~ ./ ..,/ ",. 1/ ~ ~ ~ 5% ~ ~ -~ 1 2 3 4 FUEL COST, 1982 $/GALLON * GALLONS BURNED ARE BEFORE CONSERVATION SAVINGS ASSUMES NO ELECTRICAL SPACE HEAT CONSERV A TION INVESTMENT FIGURE A.5-4 ---' o ... • ... o c( EXHIBIT A "1~r, • HUD/FHA DENVER REG/AREA OFFICE REQUIREMENTS : ~IIIIII:; THERMAL '-Ii .... The following .ini.um thermal requireMents are applicable to dwellings constructed under the Single Flmily ·Mini~ Property Standards 4900.1. Revision 61.f (Final), lovelber 1980. NAU"II UEIiRU DAY~ IUILDING I.UI'IP"UJ'lt.N1 l501 to ;)500 1;)501 to .500 .:'01 to 1000 ~OOI to 1000 1001 + MAIU R REO MAIU R REO MAIU It lEO MAIU II lEO MAXU WALLS F.F. .08 R-13 .07 R-I4 .07 R-14 .07 R-14 .05 E.R. .OS R-20 .05 R-20 .OS 1 .. 20 .OS R-20 .OS CEII.INGS F.F. .04 R-25 .03 a-33 .03 R-33 .03 R-33 .026 E.R. .03 R-33 .03 R-33 .03 R-33 .026 R-38 .026 flOORS OVER UNHEATEO F.F. fIR .07 R-14 .07 R-14 .07 R-14 .OS SPACES E.R. .07 R-14 .05 R-20 .OS R-20 .OS R-20 .05 FOUNDATION WAl.L F.F. 0.17 R .. 6 0.17 R-6 0.10 R-I0 0.10 R-I0 0.10 SECTION E.R. 0.17 R .. 6 0.17 a-6 0.10 R-I0 0.10 R-I0 0.10 WINDOWS F.F. 1.13 .69 .69 .69 .47 E.R. .69 .69 .47 .47 .47 SLIDING 1.13 .69 .69 .69 .69 GLASS PATIO ,F.F. DOORS E.R. .69 .69 .69 .69 .69 EXTERIOR F.F. A 1 3/4-_Ul insulated door W'fth •• 1_ U of 0.32 Ind •• 1I11III DOORS E.R. STORM DOORS F.F. E.R. infl1trlt1on "Ite of .50 CFM -.v be aed ./0 Ito,. door. A st~ door 1s requ1 .... d when the pr1.ry door 15 • hollow co,.. door, or is ove" 251 gllss Note: F.F ... FOSSIL FUEI.S E.R ... ElECTRIC RESISTANCE The at:r.M R* Val.l»a are II1nJalm fer' _icna VIII. baic tIcuIIe ClC:Ntruct.iCl'l. It'S D!F1Nl'1'I~ CF .",. VALUE: .",. OJER!W.. ~c:rpq CF iFxr '1!WII1PiSI~ REQO The. ClClllbined ther.l value of all the .tarials in • tu1ld1nf; 8eCtiCl'l, &it splICeS .xl mrface air fillll. -U-.i.I ec:;a:--' in IlnJ (IJR X SO PI' X tF). It REO R-20 R-20 R-38 R-38 R-20 R-20 R·I0 R-I0 JIB'lAL w:r:RXJIi: A ttJerMl t::n.k, ex • c:i::rdlnMt.1CIn ~~ factar lCII") of 35 is recJJind .... r. the dltaign t.tIIIperat:l.l.r. 18 100 F ex CIQlder. a.....ent wi.ndc:IwlI IIhall _t the ... c:rltarl8 .. all ott.r ~ .., u..s in hllblt.ble ~t ~. tIIWS: ".. -U-value of IInIIe .u fan:!atiQ1 ana IIhall t. ttJe ... as fex _tariCX' wl.lI. A ainiaD of .. 10 ah&l.l t. inst:&l.l.:l Q1 bu w •• t wl.lI of hIIbi tatWt ~. c::AlltIalG: CallJdng IIhall t. pl'CIridIId arCU'ld all qlIIn1.ngll in ttJe _tariCX' ....... lq:Ie. !'DEPI.IIC!S , J"!.IRW:ES t· All fireplM.::u ..ad fw:naces IIh&U t. pl'cwidlld wi th _tar iex CCIIli:IUstiQ1 air frail the ateriex of -..c:h VIO.l..-tMt will ~te foe the ~ J.c:.t thrQ.l9h flue .... rcn. &.Ic::h CiCllD.lst.i,Q1 air mall be directed into the CCII'It:ustian c:hmber. ex into ttJe rCICIII in ~ prcximi ty to .... f. ttJe _li--=-is J.ccated. If 11\ q:.rable wi.ncboI is utill* • ..ad J.ccata'l to usura draft-fr .. c:aafart. tt.\ a g.lMa fir.ec:reen is re<J.Iirec1. ItEM JOlS'1'S: Prcwide ... inlulatian as 1'eIFired fex wl.lI. .. • • . , .. - Jti'{ Ill' .. .. ... .. ., .. .. -.. .. .. III' • • 1lII:, • .. .. .. • • .' .. • .+ .. • .. .. '1 -, • lfI A.6.1 Introduction APPENDIX A.6 WIND ENERGY Wind energy is discussed at length in Appendices Band D of this Interim Assessment report. This section of Appendix A discusses the assumptions made in calculating the life cycle costs of supplemental wind energy. The wind turbine generator sizes considered in this study are the 7-, 17-, and 25-meter rotor diameter turbines. Several practical reasons limit the size and number of installed wind turbines: power penetration level, proven reliability in the Alaskan environment, and installation schedule. These reasons or factors are combined to give an optimistic, yet realistic, economic evaluation of wind as a supplementary source of electrical power. A.6.2 Power Penetration Level Unlike a fuel burning machine or a hydraulic turbine, the motivating fluid (wind) of a wind turbine cannot be easily controlled. Therefore, in actual installations, the energy output of wind machines is not regulated within a set output range, but is either stored or integrated into the electrical system by some means. For utility-size applications in the Bristol Bay region, there is presently no economical way of storing wind-generated electricity. The only practical method of utilizing the wind energy is to feed the energy directly into the distribution or transmission system as it is generated. If the total capacity of the wind turbines is sufficiently small compared to that of the system into which they feed, the variations or disturbances caused by the fast-changing wind power output can be accommodated by the main system generating units. As the electrical load share contributed by the wind increases, system control and management become more difficult. A.6-1 For the purposes of this study, the power penetration level of wind-generated electrical energy has limited to approximately 20 percent of the peak electrical demand (kW) to minimize these control problems. A.6.3 Installation Schedule Electric generating units in a utility system should be selected to minimize operating and maintenance expenses as well as provide the most economical generation. The optimal combination of wind turbine units would consist of identical units of the most economical size; making the system's generating units identical will reduce spare parts inventory and engineering and procurement expenses. In addition, familiarity with common units will reduce training requirements, reduce the number of procedures required, promote easy maintenance, and aid in trouble-shooting for system problems. Therefore, in arriving at the installation schedule for each case evaluated, wind turbines were selected both from a common size standpoint and to maintain 20 percent power penetration level. In this way the previously mentioned advantages are realized at the same time the greatest amount of wind generation within the allowed penetration level is attained. These criteria must be tempered by considerations of the practicality of the number of units or the availability of the selected size. Too many units could result in siting problems or attempting to oversee and maintain too many machines. could mean larger machines than are available at the time of installation. Too few units, on the other hand, proven reliable and commercially A.6.4 Maximum Output of Selected Wind Turbine Sizes The units selected for utility installation in the Bristol Bay region were those with rotor diameters of 7 meters, 17 meters, and 25 meters. The following data are repeated from Appendix D, for convenience: A.6-2 • • ., - • ." ., ." .. • .. • - • ., WI ." .. ., ., ., • • Rotor Diameter, (Meters) 7 17 25 Efficiency 25 25 30 Maximum Output (kW) at 30 mph Wind Speed 10 69 200 Machines smaller than the 7-meter size are considered too small for utility application. Wind turbines larger than 25 meters, however, are not developed sufficiently to be cost competitive, and are not expected to be proven reliable in the Alaskan environment until approximately 1990. The 7-meter wind turbine, which is a relatively small machine, is considered most reliable of the three sizes evaluated, and is assigned an availability factor of 90 percent. The 17-and 25-meter machines are assigned an availability 5 percent less, or 85 percent. The wind power density for a given area takes into account the varying wind velocities and periods of insufficient wind. The availability factor is a measure of the time that the wind machine is capable of producing electrical power, assuming wind is present and sufficient. The availability factor accounts for periods when the wind is insufficient and the wind turbine is inoperable, such as when the machine is shut down for maintenance either to repair a malfunction or due to rotor icing conditions. A.6.5 Determination of Wind Turbine Generators for Each Case As discussed in Appendix D, the high wind power density of the Bristol Bay region is not well documented. The wind power density levels used in this study are based upon a limited number of data points with a low degree of certainty. In this light, areas with a wind power class below class 4 (as defined in Appendix D) are not considered suitable for utility-size wind turbine generator installation. The best areas in the Bristol Bay region for wind machine installation included the following three villages: A.6-3 Naknek -Wind power classes 4 and 5 Egegik -Wind power class 4 Igiugig -Wind power class 4 In applying the wind energy conversion systems for this study, loading schemes were developed to supplement diesel generation scenarios B-19B, B-19E, B-15, B-16, and B-17. These wind generation schemes are listed below: • Single Village schemes (B-19B and B-19E) -The wind turbines in these schemes supply power only to the particular village in which they are located since there are no transmission interties. For scenario B-19B, wind turbines were installed in the villages of Naknek, Igiugig, and Egegik as shown in Figures A.6-1, A.6-2, and A.6-3, respectively. Scenario B-19E included wind turbines only for the village of Naknek, and these systems were installed as shown in Figure A.6-1. • Grouped village scenario B-15: This scenario considered the villages grouped into four independent clusters, with transmission interties only within each cluster of villages. The three villages with sufficient wind resources were all included in a cluster of villages consisting of Naknek, South Naknek, King Salmon, Egegik, Levelock, and Igiugig. Since these villages were intertied, the wind turbines were assumed to be located in the region with the best wind resource (Le., Naknek). The wind turbine installation schedule is shown in Figure A.6-4 to supply 20 percent of the peak demand of the cluster. The other three .. -.. .. .. -• .. • .. .. .. .. • .. -.. clusters of villages had no wind generation due to the lack of .. • sufficient wind resources Grouped village scenario B-16: This scenario considered the villages grouped into three independent clusters, with transmission interties only within each cluster of villages. The three villages with sufficient wind resources were all included in a cluster of villages consisting of Dillingham, Naknek, Manokotak, A.6-4 .. .. .. Aleknagik, C larks Point, Ekuk, Portage Creek, South Naknek, King Salmon, Egegik, Levelock, and Igiugig. Since these villages were intertied, the wind turbines were again assumed to be located in the region with the best wind resource (Le., Naknek). The wind turbine installation schedule is shown in Figure A. 6-5 to supply 20 percent of the peak demand of the cluster. The other two clusters of villages had no wind generation due to the lack of sufficient resources. • Interconnected regional scenario B-17: This scenario considered all villages in the Bristol Bay region interconnected with transmission lines. Thus, sufficient wind generators to supply 20% of the peak regional demand were installed in the best wind resource region at Naknek. The wind generator installation schedule is shown in Figure A.6-6. It should noted that for the Egegik village case, the single 7-meter wind turbine maximum capacity, or penetration level, is sized for the loads excluding that of the three summer months. The summer month loads are about 20 times greater than the other months (Fig. A.1-22). Sizing the wind penetration level for summer conditions would result in serious control problems during the rest of the year. In addition, the small size of the required wind turbine would probably justify the installation of several smaller privately-owned units instead of the single 7-meter diameter machine. This consideration might also be applicable to the Igiugig village case, where only one 7-meter unit is required during the initial nine years. A.6-5 P---------------------------------------------------~o ~ l- SIZE AND NUMBER OF UNITS INSTALLED AT THE NAKNEK/KING SALMON AREA J 5,000 +------+----+-------.1f-------+-/-I--I---+----1 I j 14x17M IN OPERATION 1-------+-----+----__+-/--1---1--+---+ (1 RETI RED - 2 ADDED) 1/ / ~Q/ 80% OAD LINE -+----1 f'~"o, e( 4,000 +-----+-----+---~ ~ ./ ?--+-q,«; v/ ~~X17M 9 ADDED /' /k::M 3,ooo+--fJlC----1I-+~---+----I--«--:X-J17~M---t-----+------+--I 9x17M ~ t---~~~8x17M ~ TURBINES 1980 1985 1990 1995 2000 YEAR VILLAGE-LOeA TED WIND TURBINE ALTERNATIVE 2005 o N ID ... o c( a.....-______ FIGURE A.6-1----' 150 50 1980 SIZE AND NUMBER OF UNITS INSTALLED, IGIUGIG AREA ~ V /~ 3x17M ~ / / / ~ -R~ ~NE MACHINE ~ t-;,Q v RETIRED, ANOTHER ~ ~O~ ONE INSTALLED ~~ ~ / ~ rx;M TURBINES / ,J ~ ~ V/ ~~ V ~ , ~M TURBINES 1985 1990 1995 YEAR 2000 VILLAGE-LOCATED WIND TURBINE ALTERNATIVE 2005 g N • ... ~ ~------FIGURE A.6-2----.. E ~ SIZE AND NUMBER OF UNITS INSTALLED, EGEGIK AREA OO~--__ ---+--------~------4-------~L-----__ ~~ 1--------.::rIF-----I1x7M TURBINE RETIRED 1x7M TURBINE ADDED 1x7M TURBINE 9 40~--~---+--------~------4---~~~~--____ ~~ :IIi: ~~-------+--------~------~-------+--------r-~ 1980 1985 1990 1995 2000 YEAR VILLAGE-LOCA TED WIND TURBINE AL TERNA TIVE 2005 '---------FIGURE A.6-3--' 6 5 4 3 1980 SIZE AND NUMBER OF UNITS INSTALLED, FIRST ZONE NAKNEK SOUTH NAKNEK KING SALMON EGEGIK LEVElOK IGIUGIG I j I I I 16x17M (11 RETIRED, 12 ADDED) I' I n ",0 t,~~ .t <tv.; /' / I /'.X17M ~ , / ~ ~~ 14x17M V ~'\"2X17M ~ 11x17M TURBINES - 1985 1990 1995 YEAR 2000 GROUPED ·VILLAGES WIND TURBINE ' ALTERNATIVE 2005 ------------FIGURE A.6-4 ............ 13 12 11 8 7 6 5 1980 SIZE AND NUMBER OF UNITS, SECOND ZONE DILLINGHAM EKUK EGEGIK NAKNEK PORTAGE CREEK LEVELOCK MANOKOTAK SOUTH NAKNEK IGIUGIG CLARKS POINT KING SALMON J , 3x17M l1x25M I (22x17M RETIRED, 9x25M ADDED) / Q I , ~O~ ~~" ,,0 J ~ ~ /' 'f' /25X'7M 2x25M ~I ~/ ~~ 25x17M 1x25M L , , ~~X'7M /' " 22x17M TURBINES 1985 1990 1995 YEAR 2000 GROUPED'VILLAGES WIND TURBINE ALTERNATIVE 2005 ~------FIGURE A.6-5--..J en I: « i: 14 13 12 11 g 10 ::III:: C Z « en ::> o 9 j: 8 7 6 1980 SIZE AND NUMBER OF UNITS INSTALLED / V j 22x17M RETIRED 9x25M INSTALLED I (TOTAL OF 13x25M OPERATING) / I {J ) )~O c§l ~ I ~vo 9 ,J 4x25M I , ~ 22.17M / L 3x25M 22x17M ,I ~ /~ / 22x17M 22x17M ~rx25M -"'" ~ 2x17M TURBINES /' 1985 1990 1995 YEAR 2000 2005 INTERCONNECTED BRISTOL BAY REGION WIND TURBINE' ALTERNATIVE ""---------FIGURE A.6-6--'" A.7.1 APPENDIX A. 7 POWER TRANSMISSION The transmission of power in the Bristol Bay characterized by relatively long distances and region can low power. generally be In addition, roads are non-existent along most of the line corridors under study, a condition which must be maintained during initial construction and later operation. Wood pole structures designed to meet REA construction standards would be used for the transmission lines, which would also be designed in accordance with the National Electric Safety Code. All materials would be imported from outside the state, probably from the Pacific Northwest. Al though there appears to be timber in plentiful supplies in Alaska, there are no facilities for manufacturing and treating wood poles for electric transmission lines. Although winters are severe in Alaska, existing power lines in the Dillingham and Nakek areas have not experienced significant problems due to icing and winter storms. However, there appears to be large areas, especially near the coast, where the soil contains organic materials and clay. In these areas, the frost heaving of the transmission line structures could be a problem and specia.1 construction techniques would be necessary. Permafrost does not appear to be a significant problem for construction of transmission lines in the region. If permafrost does exist, it probably is located at depths which would not be reached by pole installations. A. 7.2 Right-of-Way Routing The transmission line corridors for the Bristol Bay Regional Power plan were selected with regard to economic, technical, social, and environmental A.7-1 considerations. The following general criteria were used to select the best transmission routes: • • • • Minimize Cost Insure Reliability Minimize Environmental Impact Consider Local Routing Preferences When conflicts between these criteria occurred, the objective was to select a route which would minimize cost within acceptable limits for the other criteria. The first step was to collect data necessary for identifying potential routes. This included information on topography, geology, wildlife, land use, vegetation and trees, and locations of rivers, streams and lakes. Generating sources and points of use were identified. Then on a large topographic map, the most direct main and feeder line routes were located using engineering judgment with respect to routings which would minimize cost and ensure reliability. Other judgment factors included ease of construction and maintenance. The next s~ep was to adjust these routes, based on a regional evaluation of potential environmental impact. Proposed main routes were flown to confirm or supplement previous environmental information relative to wildlife and vegetation. Proposed routes and al ternati ves were then redrawn on maps, and preliminary designs and cost estimates prepared. Following the initial location of transmission routings based mainly on technical considerations, the proposed routes were reviewed further. This review was intended to get the reactions of agencies involved in regional planning and environmental protection and to determine preferences of local residents. Meetings were held with agencies on several occasions in Anchorage, and proposed routes were presented at village meetings in Bristol Bay in the fall of 1981 and the spring of 1982. In addition, those involved in sociocultural data collection questioned villages on their A.7-2 .. .. II! .. ... .. .. II! .. .. .. .. .. .. .. • .. .. .. .. preferences for routes. As a result of these meetings, a number of local preferences and concerns were identified which resulted both in refinements to routing and further definition of criteria. Because of the long distances involved between the power plant and the load center, particularly for the regional plans, the costs of the transmission system would be a relatively large part of the overall project cost. To minimize project cost, an attempt was made to select line corridors which would result in the shortest distances between source and loads. Since the cost of transmission lines increases in mountainous, hilly, swampy, and heavily wooded terrain, these types of areas were avoided. Where possible, consistent with fairly direct routing, the corridors selected were on flat, dry and open or lightly wooded areas. In SOme cases, because of the many rivers in the region, the corridors were selected in order to cross rivers at their narrowest points. This would result in shortest river spans requiring lower and less costly and unobtrusive structures. Local village preferences include (a) keeping main lines as far from villages as practical, (b) no building of roads for transmission line construction or maintenance, and (c) avoidance of game areas. Also, villages were concerned about the social effect of construction workers near their villages. Therefore, the transmission lines will need to be built without the use of roads. This would require that the men and material be transported to the line corridors by helicopter. Where possible, the corridors were located as close as practical to navigable rivers and lakes in order to transport men and materials the majority of the distance by water, and the remaining by helicopter. This location also would facilitate future repair and maintenance of the lines. During the public meetings in the Bristol Bay Region, the Villagers requested that attempts be made to locate corridors to avoid customary wildlife habitat, migration paths, and native hunting areas. Also, corridors were selected in an effort of avoiding native-owned lands by routing along state and federal lands as much as possible. A.7-3 In other cases, the corridors were located for safety reasons to avoid certain villages and frequently travelled rivers and river crossing. Unless unavoidable in order to cross rivers, the corridors were not placed in close proximity of the larger rivers in the area. Since the rivers are used as guide routes for low flying small aircraft in low visibility weather, this would minimize risk of aircraft collisions with the transmission lines. A. 7.3 Reliability of Operation To date, power transmission lines in the Dillingham and Naknek areas have proven to be very reliable, with only a small percentage of outage time. Therefore, this study is based on a transmission system consisting of single circuits for the main lines and feeders to each village. However, in the event of the loss of a line, it is planned to have backup diesel generation in each village. Redundant transmission lines would be prohibitive from both a standpoint of cost and impact on the environment. A.7.4 Line Design Details Transmission lines rated 25 kV through 46 kV would be constructed of single-pole structures with horizontal cross arms. Lines rated 69 kV through 138 kV would have structures of H-frame design with a single horizontal member. The conductors would be aluminum conductor, steel reinforced. Pole heights above the ground for voltages 46 kV and below would be about 30 ft. Heights of pole structures for higher voltages would be 40 to 50 ft above ground. Experience has shown that lightning is not a significant problem in the area; therefore, overhead ground wires would not be needed. All lines would be three-phase, 60 Hz. For the transmission of power over given distances and voltage regulations, a three-phase line can transmit twice as much power as a single-phase line. Also, since many commercial and industrial customers use large, three-phase motors, supplying single-phase power to these users would not be practical. A.7-4 .. iii! - - .. iii! -.. ., --.. - - • .. -iii! Because of its relatively lower cost, three-phase generating equipment is normally used to provide power. Generators operate most efficiently with a phase-balanced output in terms of kilowatts. It is very difficult to provide a balanced system through single-phase feeders to several villages that are widely separated and whose power requirements are all different. However, with three-phase power available to the villages, three-phase and single-phase loads within each village can be apportioned between the phases to provide a balanced system. Single wire ground return (SWGR) transmission lines have been suggested for the Bristol Bay region as a means to reduce the cost of transmission; however, the use of SWGR transmission lines is not recommended for the following reasons: a. SWGR is a single-phase system and has all the disadvantages discussed above for that type of transmission. b. The use of earth as a normal return current path is prohibited by the National Electric Safety Code, which Alaska has adopted as a design code for transmission lines within the state. c. Losses and voltage regulation for SWGR lines are inherently higher than those for three-phase lines. d. There are no known SWGR transmission lines presently in use in Alaska or the lower 48 states equal to the system proposed for the Bristol Bay region. There is only one demonstration line existing at Bethel, Alaska, built to transmit a very small load over a short distance. e. A SWGR line cannot be readily converted to a three-phase line. f. There are no significant data available to indicate that a SWGR line, built to the same design standards as a three-phase REA transmission line, would be more economical to construct. A.7-5 Depending on the voltage, height of poles, conductor size, and terrain, the spans between structures in a particular transmission line would be between 500 and 800 ft. A.7.5 Determination of Line Voltages The choice of line voltage ratings is usually limited to a comparatively small range and dictated by the need to obtain satisfactory regulation and line losses. Line regulation is the drop in voltage from the generation source to the load; in this study, an attempt has been made to limit the regulation between 5 and 7 percent. • - .. Line regulation is greatly affected by the load power factor. The load .. power factor has been assumed to be 90 percent lagging, which is a conservative value. regulation. A higher power factor would result in less line For a given regulation and power factor, line voltage selection is largely a matter of the amount of power transmitted and the distance of .. .. .. transmission. The capability of a line to transmit power varies directly .. as the square of the voltage for a given distance, regulation, and power factor. The initial line installations would be designed to transmit the loads forecast for the year 2002, since uprating the lines periodically as load increased would be costly and impractical. In general, when the lower voltage lines are less costly. This is especially true line's conductors are selected on the basis of mechanical considerations rather than current carrying ability. Lower voltages also result in savings in terminal equipment such as transformers which increase in cost with voltage. Table A.7-1 shows three phase transmission line capacity in terms of megawatt-miles. Megawatt-miles is simply the product of megawatts transmitted by the distance in miles. For example, transmitting 14 MW a distance of 85 miles results in 1,190 megawatt-miles. Table A.7-1 indicates that a line voltage of 115 kV is required, using a 636 kcmil ACSR conductor. A.7-6 .. .. .. -.. .. .. • .. .. .. - The values shown in Table A.7-1 were obtained from transmission line regulation and loss charts (Ref 1). Values for 25, 34.5, 46, and 69 kV were taken directly from the reference charts; values for 115 and 138 kV were computed using formulas given in the same reference. A. 7 . 6 Transmission Systems The transmission systems for the several scenarios are shown by Figures 6.2-1 through 6.2-18, contained in Volume 1. These illustrations show the main lines, feeder lines, power plants, and substations. In general, the main lines will be 138, 115, 69, or 46 kV. the feeder lines will be 25 or 34.5 kV. Substations are shown where feeders are tapped from the main lines. In some cases transformers will be included in the substations to step the voltages down to feeder voltages. In other cases, the substation will be only a switching point where all voltages in the substation are the same. An attempt was made to locate substations in areas where local preferences were indicated by the residents. A. 7.7 Costs Transmission line costs have been estimated as follows: Line Voltage Base Costs 25 kV $90,OOO/mile 34.5 kV $95,OOO/mile 46 kV $105,000/mile 69 kV $120,000/mile 115 kV $160,OOO/mile 138 kV $175,OOO/mile The above costs include the costs of transmission line construction in Alaska, in open tundra, utilizing helicopters to haul men, materials, and equipment such as a power auger and stringing and tensioning machines to the construction sites. A.7-7 Additional construction cost adjustment factors have been applied to the base costs to account for the increased costs of constructing transmission lines due to the terrain crossed by the lines. Terrain factors are affected by heavily wooded, mountainous and hilly, and wet or swampy areas. .. II' ., .. II' These terrain factors are shown on Figure A.7-1 for the various _ transmission line locations. Reference for Appendix A.7 1. Westinghouse Electric Transmission and Distribution Reference Book, .. Chapter 9. .. A.7-S ..... .. -., -.. - -- • .. - i;"¥'i':; TABLE A.7-1 THREE-PHASE TRANSMISSION LINE CAPACITY 5 PERCENT REGULATION, 0.9 POWER FACTOR (MEGAWATT-MILES) Conductor Size Line Voltage -kV 25 34.5 46 69 138 1/0 AWG 16 35 65 140 418 602 4/0 AWG 25 55 100 220 692 925 266.8 kcmil 33 75 140 290 808 1,164 366.4 kcmil 37 85 160 340 920 1,325 477 kcmil 45 100 180 380 1,076 1,550 636 kcmil 50 110 200 450 1,176 1,693 795 kcmil 55 120 220 470 1,276 1,837 Conductors are Aluminum Conductor, Steel Reinforced. .. ----------------------------------------~~--~~~~--------------------~----------------~~~-------------------------------------------~~ V TO BeLuGA ~ (f) w ::.::: « ..J ::.::: NONDALTON SCALE .,.t:2 at S w: .;::a o 10 20 30 40 50 MILES TRANSMISSION LINE TERRAIN CONSTRUCTION COST ADJUSTMENT FACTORS FIGURE A.7-1 '" '" o III APPENDIX A.B FOSSIL FUEL ALTERNATIVES Of the nine technologies identified by the Task 2 report (Appendix B) as potentially viable candidates to supply the Bristol Bay region's energy needs, four were fossil fuel alternatives. These four fossil fuel technologies, which are to be further evaluated from an economic standpoint, are: 1) diesel generation, 2) coal-, oil-, and natural gas-fired steam electric, 3) coal gasification, and 4) combined cycle. The engineering and technical considerations associated with diesel power are discussed in Appendix A. 3. The engineering and technical cons iderations associated with the remaining potentially viable technologies are addressed below. A.B.1 Coal-Fired Steam Electric A coal-fired steam electric generating station is an efficient means of converting the chemical energy of coal into electrical energy. The coal is burned in the boiler, imparting the heat to water fed into the boiler, continuously generating steam. The steam created in the boiler is expanded through a turbine where the heat energy is converted to the mechanical work of rotation. The rotation of the electrical generator coupled to the turbine creates electricity. The steam which has expended its energy in the turbine is condensed in the condenser, heated. and returned to the boiler to continue the steam generation cycle. A . B • 1. 1 Coal Resources Three sources of coal were identified which are capable of supplying the quantities of coal needed for a coal-fired power station. These sources are listed below: A.B-1 The Usibelli Mine near Healy, Alaska is the only operating coal mine in Alaska at the present time, although others are being developed. By the summer of 1982, the Usibelli Coal Company expects to have coal unit trains in operation to a port facility near Seward. The coal could then be barged to the Bristol Bay region. Usibelli coal has a heating value of approximately 8,000 Btu/lb as received, and would cost: At the mine RR transport to Seward Loading barge at Seward Barge to Dillingham or Naknek Total $22/ton $ 9/ton $ S/ton $34/ton $70/ton B.C. Coal, International could supply coal to a port at Roberts Bank, British Columbia for transport to the Bristol Bay region. The coal is Grain Hills Thermal Coal with a heating value of 11,000 Btu/lb, as received, and would cost: Loaded on barge at Roberts Bank Barge to Dillingham or Naknek Total $SO/ton $2S/ton $7S/ton Essel Resources Canada could supply coal to Vancouver, British Columbia for barging to the Bristol Bay region. This coal is from the Byron Creek mine with a heating value of 11,000 Btu/lb and rough cost of $75/ton F.O.B. Dillingham or Naknek. A. 8.1. 2 Technical Assumptions The plant is assumed to have a 16 MW capacity to supply the entire Bristol Bay region electrical requirements. Economy-of-scale dictates that capital, operating, and maintenance expenses are less per electrical unit (kWh) generated with the larger power station. Operating personnel are reqUired around-the-clock when a steam turbine unit is operating. The availability of trained operating and maintenance A.8-2 .. .. .. - • .. • •• .. • • ., .. personnel is a necessity to keep the plant running. Based on past experience and discussions with other Alaskan utilities operating coal-fired steam electric power stations, a total staffing of 20 people was assumed for the 16 MW plant. With this requirement for trained personnel, it is assumed that the station would be located close to the more populated areas of the Bristol Bay region, either Dillingham or Naknek. The station consists of two 8 MW units, each with stoker-fired boilers, pulse jet filter baghouses, and dry scrubbers for flue gas desulfurization. The dual unit concept improves station reliability and allows more efficient operation at reduced electrical loads. Several heat balances were performed for a small coal-fired power plant in Alaska reflecting realistic conceptual design conditions. This enabled the selection of a practical unit heat rate (Btu/kWh) for the plant, which in turn allowed an accurate calculation of coal use over the life of the station. The flue gas desulfurization system uses lime to reduce sulfur dioxide from the boiler flue gas. Lime can be shipped in from Tacoma, Washington at an approximate cost of $375/ton. Lime costs are calculated and included in the life cycle cost analysis. Operating and maintenance costs include the salaries of a 20-person operating staff in addition to maintenance costs scaled from other Alaskan coal-fired steam electric power plants. A clamshell-type coal barge unloading facility is assumed to remove the coal from the incoming barges. Sufficient coal storage was estimated to allow for the cold weather months when the coal barges cannot enter the region. Fluidized bed boiler plants are similar in capital, maintenance costs to conventional stoker-fired boiler separate capital and life cycle cost analyses were not coal-fired power stations with fluidized bed boilers. A.8-3 operating, and plants. Thus, performed for A. 8 . 1. 3 Economics Four fossil fuel power plant scenarios have been considered in this study: B-9A, B-10, B-ll, and B-12. Scenarios B-9A and B-10 consider the development of a main fossil fuel-fired plant either at Dillingham (B-9A) or Naknek (B-10) to supply power for villages in the study region. Scenarios B-ll and B-12 consider a fossil fuel-fired plant at either Dillingham (B-ll) or Naknek (B-12) for supplying power to the Nushagak River region villages and to the Kvichak River region villages, except for Iliamna, Newhalen, and Nondalton, which are to be supplied by power from the Newhalen hydroelectric site project. Life cycle costs were calculated for the four scenarios, using both Healy and Canadian coal resources. Transmission line costs and diesel generator back-up costs were included in the analYSis as well as in the hydroelectric facility costs for scenarios B-ll and B-12. The present worth life cycle costs for each alternative are as follows: Scenario B-9A and B-10 coal-fired plant using Healy coal B-9A and B-IO coal-fired plant using Canadian coal B-1l and B-12 coal-fired plant using Healy coal B-l1 and B-12 coal-fired plant using Canadian coal Present Worth Life Cycle Costs in Million $ $305 $281 $304 $281 The above life cycle costs show no appreciable difference between scenarios B-9A, B-10, B-ll, and B-12. Thus, for the other fossil fuel alternatives, only B-9A will be analyzed. Differences in the costs for the two coal sources, as expected, heavily benefit the use of the Canadian coal resources. This comparison also shows the impact of coal prices (per Btu) upon total plant life cycle cost. For the coal gasification analysis, only Canadian coal will be used, since it is clearly the most economical. A.8-4 • .. • --- • .. • • .. --- .. .. .. • A.B.2 Oil-and Natural Gas-Fired Steam Electric Oil-and natural gas-fired steam electric power stations generate electricity by the same basic method as coal-fired plants, except for the fuel burned in the boiler. Also, the equipment associated with fuel distribution, fuel storage, and pollution abatement is much different than that required for coal-firing. Coal, being a solid fuel, requires much more extensive handling and storage equipment. Fuel handling requirements for oil or natural gas boilers are less complex, consisting mainly of storage tanks, piping, and pumps, or an evaporating station (in the case of liquefied natural gas). Another considerable difference between coal-, oil-and natural gas-fired units is in the amount of waste products generated by fuel combustion. A coal-fired unit creates substantial waste products, an oil-fired unit less, and a natural gas-fired unit almost none. A. B. 2.1 Oil Resources Exploration for oil and natural gas resources in the Bristol Bay region is imminent. At the present time there are no producing wells in the area. Some test wells have been drilled, but without success. The chances of a significant discovery are considered "low to moderate", with "moderate" being optimistic according to the Department of Natural Resources (Ref 1). With the belief that natural gas and/or oil deposits exist in the Bristol Bay area, there is the possibility of a source of energy for heat and electricity. However, according to federal agencies, if there are discoveries made, it will take at least ten years before the source could be developed for use in the region. The high costs of exploration, the expense and difficulty of obtaining land and mineral rights, and the improbability of finding substantial deposits of natural gas and/or oil in the area, present too great of a risk to accept in developing power supply plans. Another aspect which is not addressed due to the lack of firm data is the adverse impact of oil and gas wells on fisheries. A.B-5 If there are significant discoveries during the period of investigation of Phase II of this study, then, a natural gas or oil fired steam plant should be investigated further. At the present time only plans in which there is a known source of energy will be considered. Therefore, any oil or natural gas burned for power generation must be brought into the Bristol Bay region from outside sources. Fuel oil is presently barged in to the Bristol Bay region for use in existing diesel generating plants and for space heating. Diesel generators make more efficient use of fuel oil than oil-fired steam electric units. From Dillingham and Naknek operating reports, the average diesel generator heat rate is approximately 10,900 Btu/kWh, whereas the oil-fired steam turbine plant would have a full load or best heat rate of 12,000 to 13,500 Btu/kWh. The oil-fired steam electric unit also costs more to construct and requires more people to operate and maintain than comparably sized diesel generators. Therefore, the oil-fired steam electric unit should not be considered further for burning fuel oil. Crude oil from the Alaska pipeline is available at Valdez, Alaska, for barging to the Bristol Bay region. However, crude oils are seldom used as fuel because they are more valuable when refined to petroleum products. A long-term crude oil supply at a firm and reasonable price could not presently be assured. As discussed in Appendix A. 3, heavy or residual oil is available at North Pole, Alaska for $0.75 to $0.78/gal. Shipping and handling costs for this heavy oil to Dillingham or Naknek would be approximately $0.29/gal, making the total heavy oil cost $1. 04 to $1. 07/gaL Diesel fuel costs $1. 25/gal at Dillingham. Thus, electricity generation costs due to fuel use only are as follows: • Diesel generator with a heat rate of 10,900 Btu/kWh burning No.2 diesel fuel (137,500 Btu/gal) at $1.25/gal: (10,900 Btu/kWh x $1.25/gal) divided by 137,500 Btu/gal = 9.9C/kWh A.8-6 • .. • .. • .. .. .. .. .. .. • • - • .. - • • .. .. .. ., • • Heavy oil-fired steam electric plant with a heat rate of 13,000 Btu/kWh burning heavy oil (138,000 Btu/gal) at $1.04/gal: (13,000 x $1.04) divided by 138,000 = 9.8¢/kWh The oil-fired steam electric plant would have higher construction, operating and maintenance costs than the comparably sized diesel generator plant. Thus, for the negligible difference in fuel expenses per kWh generated, the oil-fired power plant burning heavy oil is uneconomical. A.8.2.2 Natural Gas Resources As with oil resources, no natural gas resources are currently in existence or expected for near-term development in the Bristol Bay region. Natural gas would have to be brought in from outside the region. The only practical way to transport natural gas in the quantities needed for power generation would be in its liquid state. Only one supplier of liquefied natural gas (LNG) was located, on the Alaskan Kenai Peninsula, and this supplier would not quote a firm price nor commit to providing the fuel for a Bristol Bay power plant. The supplier said that L~G was currently being sold under contract to other customers for roughly $6/million Btu at the L~G facility on the Kenai peninsula. Handling and storage costs for LNG are prohibitive since the liquid must be o kept at -240 F to prevent vaporization. Propane, a clean-burning gaseous fuel, which was found to be more available for transportation to the Bristol Bay region than natural gas, was also investigated. Propane would be transported to the region in the liquid state, as with natural gas. The liquid propane (LPG) must be maintained at -44 OF to -48oF, which makes handling and storage much simpler than for LNG. Based on the handling difficulties of the cryogenic LNG and its limited availability, LPG would be a less expensive fuel for comparable use in the Bristol Bay region. The best price quoted for LPG was $8.25/million Btu F.O.B. Dillingham, from a Canadian supplier. This price was significantly lower than others received, which were more than $14/mil1ion Btu. The cost to generate electricity with the lowest cost propane in a propane-fired steam electric plant would be (fuel only): A.8-7 13,000 Btu/kWh x $8.25/1,000,000 Btu = 10.7C/kWh This cost is more than the previously calculated 9.9C/kWh fuel oil cost for generating electricity with a diesel plant. Propane and natural gas, which would be even more expensive and less available, should not be given further consideration. A. 8.2.3 Economics Fuel costs to generate electricity at oil-or gas-fired steam electric facilities are higher than those to generate electricity with diesel generators. The steam electric facilities are also more complex, making them more expensive to build, operate, and maintain than comparably sized diesel plants. Therefore, oil-and gas-fired steam electric technology should not be evaluated any further in this study. A.8.3 Coal Gasification Coal gasification involves reacting coal with air or oxygen and steam to produce a combustion gas. Depending upon the process used, the combustion gas would be either low-Btu, medium-Btu, or high-Btu. This combustion gas can be used for electricity generation. Electricity generation with the gasified coal may be accomplished by diesel generators, combustion turbines, conventional steam electric facilities, or combined cycle systems. The most efficient of these methods of electricity generation is the combined cycle unit; for the purposes of economic evaluation, the coal gasification process will be integrated with the combined cycle unit to generate electricity. A.8.3.l Technical Assumptions The integrated coal gasification combined cycle (ICGCC) plant is sized to generate 16 MW of electricity for the entire Bristol Bay region. The regional ICGCC plant is assumed to be located near Dillingham or Naknek for easy fuel access and to maximize the availability of operating and maintenance personnel. As with the coal-fired steam electric plant, A.8-8 ., • .. .. • .... .. ., • • ., -.. --.. -.. ., .. ., ., ., personnel are required around-the-clock to operate the unit. The coal gasification portion of the ICGCC plant will require approximately the same number of people that a conventional coal-fired steam plant flue gas desulfurization system does. In other words, the complexities of the two different coal technologies are essentially balanced. Therefore, a staff of 20 people, identical to the coal-fired steam plant, is assumed. The station consists of three low-Btu coal gasifiers, each 50 percent capacity; two gas scrubbers; and one full-sized combined cycle unit. Diesel generators provide emergency electrical power if the ICGCC unit is shut down. A risk factor is introduced because the low-Btu coal gasification facility has not been run in combination with a 16 MW combined cycle unit before. Operating and maintenance costs are assumed identical to those of the coal-fired steam electric plant. The coal gasifiers and gas scrubbers of the ICGCC balance with the flue gas desulfurization equipment of the coal-fired steam unit, and the packaged combined cycle unit balances with the less complex (but not packaged) single steam cycle of the coal-fired steam plant. As previously noted, the complexities of the two technologies tend to balance out when viewed overall. The coal handling and storage is the same as that for the coal-fired steam electric generating plant. A. 8 . 3 . 2 Economics Present worth life cycle costs were calculated for scenario B-9C using the most economical coal source of 11,000 Btuj lb Canadian coal. Transmission line costs and emergency diesel generator back-up costs are included in the analysis. The present worth life cycle costs for the ICGCC unit total $269,300,000. A.8.4 Combined Cycle The combined cycle power plant, as used previously with coal gasification, integrates combustion turbine, heat recovery boiler, and steam turbine into A.8-9 a "combined" system in order to achieve a higher thermodynamic efficiency than is possible using a conventional Brayton cycle (combustion turbine) or steam Rankine cycle. This section will consider the combined cycle unit alone, fired by expensive diesel fuel. A.B.4.1 Technical Assumptions A regional combined cycle plant capable of generating 16 MW is assumed to be located near Dillingham or Naknek. As with the steam electric plants, the combined cycle unit must be staffed around-the-clock to keep the station running. A staff of 16 people, in<=;luding supervision, is assumed for the combined cycle facility. Operating and maintenance costs are approximately midway between those of comparably sized diesel generating facilities and coal-fired steam turbine power stations. Fuel oil for the combined cycle plant is the same as that used in existing diesel generators. A. B .4. 2 Economics Present worth life cycle costs were calculated for scenario B-9B using diesel fuel. Transmission line costs and emergency diesel generator back-up costs are included in the life cycle cost analysis. The combined cycle unit present worth life cycle costs total $388,500,000. A. 8.5 Summary A comparison of the fossil fuel alternative life cycle cost is presented below. Scenario B-9 is used in all cases except the diesel base case BP-l. In addition, only the coal alternatives using the most economical coal source, Canadian, are listed. A.8-10 • • ., .. .. .. .. ., .. .. ., - .. .. • .. • .. ., Technology Diesel Generation (BP-1) Coal-Fired Steam Electric (B-9A) Combined Cycle (B-9B) Present Worth Life Cycle Cost $291,500,000 $281,000,000 $388,500,000 Integrated Coal Gasification Combined Cycle (B-9C) $269,300,000 The costs for the diesel, coal-fired steam electric, and ICGCC units are very close considering the accuracy of the estimates (within 25 percent) and the assumptions made. Reference for Appendix A.8 1. Telephone conversation between R. Stout (SWEC) and C. O'Conner (Department of Natural Resources), July 1982. A.8-11 ASH DISPOSAL LANDFILL AREA AIR COOLED "\ / CONOENSE7 ,.---, ENCLOSED : SWITCH I , n--OUTDOOR COAL STORAGE I YARD • • I COAL TORAJ::E }URBINE / " .... , BUILDING -( COAL PILE RUN-OFF COLLECTION TRENCH ) -MAIN PLANT -CONVEYOR -r ~I~~~ CRUSHER/TRANSFER TOWER '--. BOILER ~ I BOTTOM ENC OSURE J. ~~~CL ASH DISPOSAL LANDFILL AREA ASH BIN :t:t TANK SCRUBBER I ~'Q C3i I FABRIC FILTER -WATER TREATMENT BUILDING ENCLOSURE STACK8 Jl FL Y ASH SILO--RAW WATER STORAGE "~fLAM-SHELL TYPE BARGE UNLOADIN FACILITY , BARGE TYPICAL PLAN COAL -FIRED' STEAM } ELECTRIC GENERATING STATION ( RIP-RAP BREAK WATER DAM ) FIGURE A.8-1 APPEND IX A. 9 ORGANIC RANKINE CYCLE A Rankine cycle which uses an organic working fluid instead of water/steam has unique characteristics that allow it to generate power by recovering waste heat or using other relatively low temperature sources. The organic fluid chosen for the cycle depends upon the operating conditions and system costs. In the Bristol Bay region, the most economical heat source for the organic Rankine cycle (ORC) is the waste heat given off by existing diesel generators. However. the diesel jacket water waste heat is at too low a temperature to be effectively used by an ORC unit. Rather, diesel engine exhaust waste heat is at the correct temperature for ORC operation. Care must be taken with diesel exhaust heat recovery systems in the Alaska climate; many problems have been experienced with condensation in these systems, leading to increased engine and heat recovery system maintenance. A.9.1 Technical Assumptions The two largest population centers of the Bristol Bay region, Naknek and Dillingham, have been chosen for ORC installation. TIlese villages have the largest diesel generating capacity and therefore, the largest source of waste heat for the ORC units in the region. One 750 kW capacity ORC unit would be installed in each Village. Smaller ORC units are commercially available, but the 750 kW unit properly matches the waste heat available in each village and exhibits some economy-of-scale. Most ORC unit costs still contain a small amount of "developmental" expense, which will disappear as the units gain more commercial operating experience. Operating and maintenance costs for the 750 kW ORC unit are assumed to be $0.015/kWh (based upon manufacturers' quotations) generated by the ORC unit. The number of personnel used to staff the existing diesel generator plants is not increased to allow for the addition of ORC units. The $0. DIS/kWh A.9-1 rate includes any extra time spent by existing diesel plant personnel to operate and maintain the ORC. As a conservative estimate, it is assumed that the ORC unit can generate 10 percent of a diesel generator I s total electrical output for supplemental power. Thus, the economic calculations credit the amount of fuel saved by a diesel/ORC combination in generating a given amount of electricity. A.9.2 Economics The present worth life cycle costs for the diesel/ORC system for Dillingham and Naknek are summarized below. For comparison purposes, diesel scenarios with other means of waste heat recovery and with supplemental wind generation for the two villages are also listed. Present Worth Life Cycle Costs Diesels with ORC (B-19D) Existing diesels (BP-1) Diesels with other waste heat recovery (B-19A) Diesels with wind generation (B-19B) Diesels with wind generation and other waste heat recovery (B-19C) Dillingham $100,800,000 104,700,000 86,400,000 Naknek $ 97,500,000 10 I, 400,000 85,200,000 97,800,000 83,800,000 The life cycle analysis shows that adding ORC units to an existing diesel generating facility does not result in appreciable savings. The estimates for diesels alone and diesels with ORC are very close, within 4 percent, taking into account the accuracy of this estimate. A.9-2 .. .. .. .. - .. II1II> .. .. .. .. -.. .. .. .. .. • .. • .. .. -.. APPENDIX.A.I0 BRISTOL BAY LOAD MANAGEMENT ANALYSIS Load management presents the utility planner with possible alternatives to additions of generation capacity. For many utilities, effective load management programs will result in substantial savings in the areas of postponed generation, fuel costs, and/or purchased power costs. Experience throughout the electric industry indicates, however, that for many utilities load management is neither technologically nor economically feasible. There are no simple or universal rules to achieving success with load management programs; this is because the operating and service area characteristics vary too widely to draw general conclusions regarding the specific benefits to a particular utility. Without rigorous analysis, the best that can be done is to assess the generation/fuel mix, load characteristics, and energy end uses for the Bristol Bay load area, and evaluate the probable success of load management techniques, given their operation and impacts in other service territories that have similar attributes. It appears that the likelihood of success in implementing currently available load management technologies is very small. Factors leading to this conclusion are: 1. The current and potential fuel mix. 2. The dispersed generation within the non-integrated systems 3. The nearly complete absence of end-use loads that could be effectively influenced Broadly speaking, load management consists of actions by either the utility or the consumer to shift, shed, or shave loads in order to shape the utility load curve to the most economically efficient configuration. These A.I0-l conclus ions for Bristol Bay are based on what is believed to be the only rational criteria: economic efficieny. In a properly regulated environment, this means minimizing revenue requirements of the utility in order ,to meet a specifi~d load curve (both shape and level). From another viewpoint, this equates to maximizing the difference between the value that customers receive from the use of electricity and the costs that must be incurred in serving them. Load management techniques might be justifiable using alternative criteria, but evaluation cannot be supported based upon such rationale. Load management technologies can be divided into two broad categories: active systems and passive systems. This categorization is from the utility's perspective; active systems involve the direct intervention by the electric supplier into the consumption patterns of the users, while passive systems are those that are perhaps influenced by the utility although controlled by the consumer. The most common techniques in use are: Active Direct equipment control Controlled fuel switching Interruptible service Voltage reduction Distributed generation Passive Time-of-use rate Local logic devices Consumer education Conservation The fourth pass ive technique, conservation, is the one program falling in the broadest definition of load management that may in fact be effective in Bristol Bay. Even here, however, it would seem that given the relatively high energy costs, energy consumers have had the stongest incentive for pursuing all effective conservation measures. Electric generation in the Bristol Bay region currently consists entirely of isolated diesel units in three nonintegrated REA systems. To obtain fuel savings from load management requires that the generating utility have the ability to shift load from one time period to another to take advantage A.10-2 .. • .. ., ., ., ., ., .. .. .. .. .. .. .. .. .. .. .. .. • .. .. .. .. 1& .. .. .. ., of generation with lower variable costs (primarily fuel expense). The prospect of this result, given the current operating characteristics of the system, is virtually nil. The addition of lower cost capacity would create the possibility of significant fuel savings given a sizable fuel cost differential. To accommodate this shift requires load characteristics and energy consuming equipment amenable to load management. Economically-sound load peak that is caused by management programs generally target I one season s the high coincidence of certain appliances or equipment (as examples, air conditioners or water heaters). The Bristol Bay load area has summer and winter system peak demands that are approximately equal so that load management programs aimed at one seasonal peak would probably have little impact on the other seasonal peak. Rather than a program designed to control or influence a relatively large number of end-use loads, one would want to adopt a program to reduce or shift specific controllable, on-peak loads. The primary cause for the area summer peak demand is fish processing. There might conceivably be some time-of-use or interruptible service rate that would entice fishing industries to alter their summer load curve. Also, there may be a possibility of reducing load through local logic devices (e. g., a minicomputer control system) installed on the few larger customers. Realistically, however, the short fishing season requires that the processing plants operate at very high load factors; there is little hope of materially reducing the summer peak. The winter peak appears to result from the high coincidence of lighting loads and air handling systems on fossil-fired heating systems. There is an insignificant number of electric water heating customers, who are prime candidates for load control. If the economics for future electric space heating loads become favorable, a very unlikely prospect, then the promotion of duel-fueled units would be a likely load management project; this would allow the customer to switch from electric heat to oil or gas during peak periods. The severity of the winters and lengthy daily and weekly heating periods certainly raise doubts for success of this scheme that has proven successful for several utilities. A.lO-3 From the system planner I s viewpoint, the most reliable load management system is the utility-controlled type where the utility can positively reduce demands on the system by shutting off specific, addressable customer loads. Positive benefit/cost ratios for these types of systems generally require high density and very large numbers of controllable loads. These characteristics are prerequisites for the efficient operation of the communication systems and the reduction of per unit cost of the central control system (as examples, the control computer or radio transmitter). Again, the characteristics of the Bristol Bay power system do not meet the requirements conducive to utility controlled load management systems. With the very high cost of additional generation facilities, load management programs to postpone construction are attractive options for many utilities. The specific characteristics of the Bristol Bay service territory and supply system, however, are severe impediments to economically and technically sound load management. A.10-4 .. .. .. .. • .. .. •• .. .. .. .. ... .. ., ... .... APPENDIX B ENERGY SUPPLY TECHNOLOGY EVALUATION - -- - Appendix B BRISTOL BAY REGIONAL POWER PLAN ENERGY SUPPLY TECHNOLOGY EVALUATION ALASKA POWER AUTHORITY JANUARY 1982 Stone & Webster Engineering Corporation Denver, Colorado Section 1 2 3 3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 3.9 3.10 3.ll 3.12 3.13 3.14 3.15 3.16 3.17 TABLE OF CONTENTS Title Page SUMMARY. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B. 1-1 INTRODUCTION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B . 2-1 ANALYSIS AND DISCUSSION ............................ B.3-l FOSSIL FUEL ALTERNATIVES Diesel Generation.................................. B. 3-2 Coal-, Oil-, and Natural Gas-Fired Steam Electric Generation............................... B. 3-9 Coal Gasification .................................. B.3-20 Combined Cycle... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B. 3-24 Combustion Turbine................................. B-3-27 NON-GENERATING RESOURCES Energy Conservation ............................... . Waste Heat Recovery ............................... . RENEWABLE RESOURCES Wind Energy ....................................... . Hydroelectric Power ............................... . Tidal Power ....................................... . Solar Thermal Energy .............................. . Solar Photovoltaic Electric Systems ............... . MISCELLANEOUS RESOURCES Organic Rankine Cycle ............................. . Biomass (Wood) Energy Systems .................... . Energy from Waste/Refuse .......................... . Peat Energy ....................................... . Geothermal Power .................................. . B.3-3l B.3-34 B.3-40 B.3-50 B.3-58 B.3-67 B.3-70 B.3-72 B-3-76 B.3-82 B.3-84 B.3-87 ':f~ Section 3.18 3.19 3.20 3.21 3.22 3.23 3.24 3.25 4 5 6 TABLE OF CONTE~TS (cont.) Title NUCLEAR RESOURCES Conventional ~uclear Power ......................... B.3-95 Nuclear Fusion and Breeder Reactors ................ B.3-101 ADVANCED TECHNOLOGIES Fuel Cell .......................................... B.3-104 Magnetohydrodynamics. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. B. 3-106 Wave Energy Conversion Systems .................. '" B.3-108 Ocean Current Energy ............................... B.3-109 Salinity Gradient Energy Conversion ................ B.3-110 Ocean Thermal Energy Conversion .................... B.3-111 CONCLUSIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. B. 4-1 RECOMMENDATIONS.................................... B.5-1 REFERENCES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. B. 6-1 LIST OF TABLES Table 3.17-A Proposed Geothermal Electric Plants Figure 3.2-1 3.3-1 3.3-2 3.4-1 3.5-1 3.5-2 3.7-1 3.7-2 3.7-3 3.7-4 3.7-5 3.8-1 3.10-1 3.10-2 3.13-1 3.14-1 3.14-2 3.17-1 3.17-2 3.17-3 3.20-1 3.20-2 3.21-1 3.25-1 LIST OF FIGURES Title Typical Steam Turbine Generating Unit Integrated Gasification Coal-Fired Plant Integrated Coal Gasification Combined Cycle Power Plant Typical Combined Cycle Power Plant Simple Combustion Turbine (Brayton) Cycle Simple Combustion Turbine Cycle with Regenerator Waste Heat Recovery -Combustion Turbine Waste Heat Recovery -Steam Turbine Waste Heat Recovery Diesel/Steam Waste Heat Recovery -Diesel/Hot Water Waste Heat Recovery -Diesel/Hot Air Wind Energy -HAWT and VAWT Typical Tidal Power Plants Tidal Power -Generation Cycles Organic Rankine Cycle Typical Wood-Fired Power Plant Forest Survey Area Geothermal -Dry Steam Cycle Geothermal -Single Flash Cycle Geothermal -Dual-Flash Cycle Fuel Cell Fuel Cell Power Plant ~1HD/Steam Power Plant Ocean Thermal Energy Conversion Power Plant • . SECTION l' SUMMARY SECTION 1 SUHMARY 1.1 INTRODUCTION As a part of the Bristol Bay Regional Power Plan, this Energy Supply Technology Evaluation identifies and evaluates a variety of potential power generation methods to meet the energy requirements of the Bristol Bay region. The energy demand forecast of Appendix C predicts a peak electrical need of less than 15, 000 kilowatts CkW) for the entire Bristol Bay region in the year 2002, neglecting space heating considerations. The initial screening of energy supply candidates involves investigating the commercial availability, technical restraints, constructibility, environmental impacts, operating and maintenance aspects, regional restraints, and regulatory restraints of each of the potential resources. The assumptions, data collected, and findings of the energy supply technology evaluation are included in this appendix. 1.2 ENERGY TECHNOLOGIES CONSIDERED A wide range of potential energy resources has been identified for evaluation. These resources are classified by general categories and further subdivided into 25 individual technologies. Each individual technology is addressed separately. The following is a complete list of each category and technology. • Fossil Fuel Alternatives Diesel generation Coal-, oil-, and natural gas-fired steam electric generation Coal gasification Combined cycle Combustion turbine B.1-1 • Non-Generating Resources Energy conservation Waste heat recovery • Renewable Resources • • Wind energy Hydroelectric power Tidal power Solar thermal energy Solar photovoltaic electric systems Miscellaneous Resources Organic Rankine cycle Biomass (wood) energy Energy from waste/refuse Peat energy Geothermal Nuclear Resources Conventional nuclear power Nuclear fusion and breeder reactors • Advanced Technologies Fuel cell Magnetohydrodynamics Wave energy conversion systems Ocean current energy Salinity gradient energy conversion Ocean thermal energy conversion B.1-2 .. .. .. - • • .. • .. --., • - 1.3 Several of the energy resources or technologies within a category can be readily rejected as near term practical sources of energy for the Bristol Bay region. Of the fossil fuel alternatives, the combustion turbine is not recommended for further consideration, as its thermal efficiency is not competitive with the other fossil fuel technologies. The much more efficient combined cycle technology, with a combustion turbine, waste heat boiler, and steam turbine cycle is discussed separately in this report. The tidal range in Bristol Bay is favorable for power generation. However, characteristic fluctuating generation, ice effects, and restraints on fish movements make tidal power impractical for development. Conventional tidal power also requires a very large development, much larger than the energy needs of the Bristol Bay region, to be economically viable. The renewable solar resources, thermal and photovoltaic would receive insufficient sunlight to render them economically competitive in Bristol Bay. Passive solar thermal energy is a viable space heating option, however, and is discussed separately in the Energy Conservation section. The only biomass resource of any consequence to power generation in Bristol Bay is wood, but these wood resources are too scarce to support a wood-fired power station without creating detrimental environmental effects. Similarly, the extraction of peat in quantities necessary for electricity generation would have significant adverse environmental impacts. Space heating energy demands are larger than electrical demands in the Bristol Bay region. Thus, wood and peat should not be used for space heating except on a very limited basis. Wood and peat are not recommended for consideration in the study plan. B.l-3 Obtaining energy from waste/refuse is not practical in Bristol Bay because not enough refuse is available for power generation. Geothermal energy should not be evaluated further because of the lack of proven resources in the Bristol Bay area. Nuclear resources are not feasible to supply power to the region for many reasons, including regulatory uncertainty, costs, undesirable seismic conditions, and the need for highly trained operating personnel. In addition, fusion and breeder reactors remain in the developmental stage. The advanced technologies could not be seriously considered as viable candidates for near term use as they either are not commercially available or are only in the early stages of development. The results of the Energy Supply Technology Evaluation indicate the following resources to be the most attractive for application in Bristol Bay: • Diesel generation • • • • • • • • Coal-, oil-, and natural gas-fired steam electric generation Coal gasification Combined cycle Energy conservation Waste heat recovery \Hnd energy Hydroelectric power Organic Rankine cycle The Bristol Bay region currently relies on diesel generators to meet its electrical power needs. The "Base Plan" will consider a continued reliance upon diesel generation, and will serve as a basis for comparing alternatives in the study plan. Diesel generation justifies its present status in the region by comparing favorably with all the other resources evaluated in this report except hydroelectric power. Diesel generators B.1-4 .. .. If .. • .. .. • .. may vary in size, allowing their use on an individual dwelling or village basis or more regional concept. The primary disadvantage of diesel generators is their consumption of expensive fuel oil. Conventional steam turbine generating units are a proven technology for base load power generation. The boilers associated with st.eam electric generation may be fired with coal, oil, or natural gas; all three of these fossil fuels must be t.ransported into Brist.ol Bay from outside the region and may not. prove cost competitive. However, further economic evaluation will be necessary to det.ermine t.heir feasibility. Economies-of-scale dictate that a st.eam t.urbine unit should be a central station with transmission lines t.o surrounding villages. Small coal gasification plant.s producing gas wit.h low or medium heating values are commercially available for installation in Bristol Bay. Coal gasification allows the more effective removal of sulfur compounds creating a clean, gaseous fuel which can be burned in an environmentally acceptable manner. However, the gasification process produces airborne pollut.ant.s in varying degrees, depending upon the type of process used. Advantages may be gained by the storage of t.he gaseous fuel products, as opposed to raw coal storage in a central power plant scheme. Packaged generating units containing both a combustion turbine and steam turbine are commercially available and make efficient use of fossil fuels. These combined cycle units are available in sizes 4,000 kW and above, making them suitable for central station applications in the Bristol Bay region. Energy conservation and waste heat recovery technologies are proven methods of reducing an area I s energy demands through the more efficient use of present and future resources. In the Bristol Bay region, potential means of conserving energy and recovering rejected or waste heat should be investigated and implemented where practical. The wind is a renewable resource which can be harnessed through wind energy conversion systems (wind turbines) to generate electricity. Using B.1-5 wind power density as a measure of wind availability, several areas of Bristol Bay appear suitable for power generation. be produced when the wind is blowing within Wind energy can only a certain range of velocities, which does not always correspond to the need for electricity; thus, wind power must be used to supplement other continuous power generation techniques. Wind should be considered a supplemental resource in the study plan. A major difficulty in utilizing wind energy is to balance or control its fluctuating generation characteristics with the varying system demands to feed the wind~generated electricity directly into the power grid. Various storage techniques for wind-generated electricity are not yet economically viable on a utility scale. Ice storms in the Bristol Bay region also cause wind generator outages, and maintenance during winter months is difficult. A renewable resource which is very attractive for development in the Bristol Bay region is hydroelectric power. Proper site selection enables a hydroelectric power station to be operated with minimal impact on the surrounding environment. Hydroelectric power stations are also reliable, require little maintenance, and offer low operating costs. For economics of scale, a single station would have to supply energy for a major portion of the region. A commercially available system capable of using relatively low temperature sources, such as waste heat from a diesel engine, to generate electricity is the organic Rankine cycle (ORC). Small ORC units can be installed on a village f s existing diesel generating equipment to capture the waste heat and supplement the village I s electrical demands. The organic Rankine cycle will be evaluated as a supplemental energy resource, similar to wind. Further investigation and optimization, particularly with regard to economics, is recommended for the following alternatives: (1) diesel generation, (2) coal-, oil-, and natural gas~fired steam electric generation, (3) coal gasification, (4) combined cycle, (5) energy conservation, (6) waste heat recovery, (7) wind energy, (8) hydroelectric power, and (9) organic Rankine cycle. This extended evaluation will be performed as a part of the continuing Bristol Bay Regional Power Plan. B.l~6 .. • .. -.. • .. .. SECTI,ON2· INTRODUCTION . .' ~ . .'. "." ". J: . -.. , ..... ;, . ;'., . . / SECTION 2 INTRODUCTION 2.1 PURPOSE A wide variety of alternatives are available to meet the energy requirements of the Bristol Bay region. The purpose of this appendix is to provide the initial screening of these energy resources in order to arrive at the most suitable, site-specific tehnologies for application to the Bristol Bay Regional Power Plan. The initial screening will select energy producing, generating, or conserving systems that deserve more detailed investigation in the continuing development of the study plan. The assumptions, data collected, and findings of the energy supply technology evaluation are reflected in this appendix, which was prepared as a part of the Bristol Bay Regional Power Plan. 2. 2 METHODOLOGY The selection of the optimal energy supply scenario for Bristol Bay began with the consideration of a large number of alternatives. Through a review of technical publications and SWEC t S past experience, a list of all potential energy resources for the Bristol Bay region was derived. The initial screening of these potential energy options was accomplished by reviewing each from a number of standpoints, including state of technology, technical restraints, constructibi1ity, operating and maintenance aspects, regulatory restraints, environmental considerations, and regional restraints. Certain energy alternatives considered unlikely for use in Bristol Bay, such as ocean thermal energy conversion, are addressed briefly to ensure that this examination of energy options is as complete as possible. A general description of each energy resource is included to provide the reader with insight into the system being investigated. A more thorough B.2-1 discussion of the basic evaluation criteria follows: • • • • • • State of Technology -Commercial availability of a resource is critical to its use in Bristol Bay. Several energy alternatives may be approaching commercial development, but are not yet proven adequately for near term use in the Bristol Bay region. Technical Restraints Technical problems, such as "scaling down" a nuclear power station to a usable size for Bristol Bay, can impose severe limitations on the use of a resource. These technical difficulties generally affect the costs associated with the alternative. Constructibility -The ease of install ing an energy system in remote regions has a significant impact on its use in the Bristol Bay region. Labor costs in the Bristol Bay region are high, primarily due to the scarcity of a local work force; construction materials are quite expensive, since most have to be brought in from outside the region. Operating appreciable generating and Maintenance ASDects The absence of an local work force creates an advantage for power systems requiring small operation and maintenance staffs. Other important items considered under this evaluation factor are system reliability, flexibility of power generation to meet electrical load, replacement parts, ease of maintenance, and general operating and maintenance costs. Regulatory Restraints contacted to define State and federal agencies regulatory barriers associated were with constructing and operating the various types of power stations. A review with similar obj ectives was also conducted of numerous Alaska and federal statutes. Environmental Considerations -Site-specific investigations into the effects of energy resources on the Bristol Bay surroundings B.2-2 • lit .. .. .. .. .. • .. Wi' .. .. .. • .. were performed. Of primary concern in this region are any adverse effects to the anadromous fish or wildlife population. Subsistence as well as commercial fishing and hunting are the mainstay of the Bristol Bay residents. Only energy alternatives whose adverse environmental impacts can be minimized will survive the initial screening. • Regional Restraints -Through discussions with native agencies, participation in town meetings, area reconnaissance, and a study of regional literature, constraints to the construction and operation of different energy technologies in Bristol Bay were identified. Comparing produced a which can the energy resources on the basis of the above criteria list of proven, reliable, commercially available resources be utilized in the Bristol Bay region with little adverse environmental impact. Further investigation of the remaining resources is necessary to compare their respective merits and economics. 2.3 OVERVIEW The main body of this Energy Supply Technology Evaluation Appendix consists of sections entitled Recommendations, and References. is summarized below: Analysis and Discussion, Conclusions, The content of each of these sections Analysis and Discussion -This section involves the individual discussion of each energy technology. There are 25 groupings of technologies in the Analysis and Discussion section which are arranged in major energy categories: fossil fuel, non-generating, nuclear, and advanced. A brief description each energy technology follows: B.2-3 renewable, miscellaneous, regarding the findings of • • • FOSSIL FUEL ALTERNATIVES Diesel Generation commercially available, Reliable diesel generator sets and have proven relatively easy are to install, operate, and maintain. Coal-, Oil-, and Natural Gas-Fired Steam Electric Generation - Conventional steam turbine generating units are a proven technology for base and intermediate load power generation. Coal-, oil-or natural gas-fired units can be constructed in a central station to supply regional power requirements. Coal low- Gasification Small coal gasification plants and medium-Btu fuels are commercially available. producing In the Bristol Bay region, coal gasification could be used to provide fuel for a conventional steam electric unit, diesel engine, combustion turbine, or a combined cycle unit. • Combined Cycle -The combination of both combustion turbine and • steam turbine efficient use generating units of petroleum into fuels. a single cycle makes This technology is commercially available in large generating unit sizes (ratings above 4,000 kW) for central station applications. Combustion Turbine Because of low thermal efficiencies, commercially available combustion turbine generating units are primarily used in stand-by power applications. Small combustion turbines, of the size required to meet the Bristol Bay region power demands, consume significantly greater amounts of fuel than comparably sized diesel generators. The high fuel consumption of these units make them economically unattractive. B.2-4 • .. .. .. • .. .. .. .. .. NON-GENERATING RESOURCES • Energy Conservation -Energy conservation is a key element in energy planning. In the Bristol Bay region, potential means of conserving energy must be identified and implemented. • • Waste Heat Recovery The use of rejected heat from diesel engines, gas turbines, or steam turbines for space heating or process uses is a commercially proven concept. In the Bristol Bay region, waste heat from generating units can be used for space heating. Wind Energy -Wind generators can provide a renewable energy source to supplement regional power system generating capabilities. • Hydroelectric Power -With proper site selection, hydroelectric power can provide a renewable energy source with minimal impact on the surrounding environment. A regional hydroelectric power station, providing energy for a major portion of the region would have definite economy of scale advantages. • • Tidal Power Harnessing tidal fluctuations for generating electricity has been demonstrated in France, Russia, and China. However, due to unfavorable climatological, terrestrial, technical, and economics of scale aspects, and the possible impacts on aquatic ecosystems, tidal power generation is not considered feasible for Bristol Bay. Solar Thermal Energy Central solar power stations require large areas of reflector or collector surface to receive the quantities of insolation (radiation per unit area) necessary for utility power generation. This technology is not cost competitive with other energy sources at this time primarily due B.2-5 • • • • • to the low quantity of solar radiation received in the Bristol Bay region. Passive solar energy is considered separately, in conjunction with energy conservation. Solar Photovoltaic Electric Systems Photovoltaic electricity. The systems systems convert solar energy directly into required for this technology are too expensive for utility power generation in the Bristol Bay region because of the small amount of solar radiation existent. MISCELLANEOUS RESOURCES Organic Rankine Cycle electricity from relatively diesel engine waste heat, units are small and can be ORC units capable of generating low temperature sources, such as are commercially available. These installed on a village-by-village basis to supplement existing diesel generation. ORC units merit further consideration as a potential energy supply for the Bristol Bay region. Biomass (Wood) Energy -Wood is the only biomass resource of any significance to power generation in the Bristol Bay region. However, wood is too scarce to provide fuel for a central power station, and the adverse environmental impacts associated with large-scale tree harvesting as well as its detrimental effects upon subsistence living, preclude the use of wood for Bristol Bay electricity production. Energy from Waste/Refuse -The economic feasibility of using refuse as fuel in a steam turbine generating unit is dependent on an adequate local supply of refuse. Such a supply does not exist in the Bristol Bay region. Peat Energy The use of peat as fuel in steam turbine generating units has been successfully implemented outside the United States. The environmental impact caused by large-scale B.2-6 • • ., .. .. .. .. .. .. .. .. .. .. .. .. .. .. • .. .. • .. • peat harvesting is too severe to consider such a power plant in the Bristol Bay region. • -This technology is a proven source of energy in many regions of the Western United States. However, the geothermal resource data available for the Bristol Bay region indicates there are no proven sites in close enough proximity for this use. NUCLEAR RESOURCES • Conventional Nuclear Power -The complexities associated with safe, reliable nuclear power station design and operation make this technology less practical for small units. Undesirable seismic conditions, regulatory uncertainty, the need for highly trained personnel, and costs make nuclear power an unattractive energy supply option for the Bristol Bay region. • Nuclear Fusion and Breeder Reactors -These technologies are very complex and will not be developed for commercial power generation in the near term. ADVANCED TECHNOLOGIES • -Fuel cells make efficient use of fuel supplies in both central and dispersed plant applications. However, the technology has not yet been commercially demonstrated, nor is it expected to be before 1985. • Magnetohydrodynamics -This technology is a means of producing electricity by expanding hot, electrically conductive gases through a magnetic field. ~!agnetohydrodynamics is still in the early development stages and will not be ready for commercial generation in the near term. • Wave Energy Conversion Systems -Ctilizing the energy in the B.2-7 • • • traveling force or rise and fall in waves has not been demonstrated as technically feasible. Ocean Current Energy -Ocean current conversion systems use the momentum of ocean currents to generate electricity. The development of this technology is in the early stages of feasibility assessment. Salinity Gradient Energy Conversion -Salinity gradients at the interface of an ocean and a fresh water river are a potential source of energy. Preliminary results of ongoing studies indicate that utilizing this energy source would not be cost competitive with other energy supply alternatives. Ocean Thermal Energy Conversion (OTEC) Systems Thermal differences in ocean waters can evaporate and condense binary cycle fluids for driving turbine-generators. Ocean thermal differences must be at least 360 F before this technology becomes feasible. Ocean thermal differences off the coast of Alaska are insufficient to support an OTEC system. Conclusions Of the 25 energy resources discussed above, nine were identified as viable candidates for further study in the Bristol Bay Regional Power Plan. Four of the nine viable candidates can only supplement other methods of meeting Bristol Bay's total energy needs. The supplemental resources considered feasible at this point in the study are: (1) energy conservation, (2) waste heat recovery, (3) wind energy, and (4) organic Rankine cycle. The remaining five of the nine selected alternatives are capable of supplying, either individually or in combination with other alternatives, Bristol Bay's primary electrical power requirements. These five energy producing systems are: (1) diesel generation, (2) coal-, oil-, and .natural gas-fired steam electric generation, (3) coal gasification, (4) combined cycle, and (5 ) hydroelectric power. Diesel generation and hydroelectric power resources were predetermined to B.2-8 .. .. .. .. .. .. ., .. .. .. .. • ., .. be studied in following phases of the Bristol Bay Regional Power Plan. Their individual evaluations also provide justification to their consideration as viable energy resources for the Bristol Bay region. The remaining technologies were removed from further consideration for the following reasons: • Combustion Turbine -Thermally inefficient, resulting in large consumption of fossil fuel. • Tidal Power -Unfavorable environmental, technical, and economic aspects. • Solar Thermal Energy -Insufficient solar radiation to justify cost competitiveness. • • Solar Photovoltaic Electric Systems Solar energy for power generation purposes in the United States is limited by economics to the southwest areas of the country, due 'to the amount of sunlight available. Biomass (Wood) Energy Adverse environmental impact and scarcity of wood resource. • Energy from Waste/Refuse -Not enough refuse to support power generation. • Peat Energy -Unfavorable environmental impact. • Geothermal -No proven geothermal resources in the immediate area. • Conventional Nuclear Power Undesirable seismic conditions; regulatory uncertainty; need for highly trained personnel; and economic aspects for scale of development required for the region. B.2-9 • • Nuclear Fusion and Breeder Reactors -All of the disadvantages attributed to the development of conventional nuclear power in this region; plus, these technologies are not commercially proven. Fuel Cell, Magnetohydrodynamics, Wave Energy Conversion Systems, Ocean Current Energy, Salinity Gradient Energy Conversion, and Ocean Thermal Energy Conversion Svstems In early development stages or not yet commercially demonstrated. Recommendations -The nine most attractive energy options for the Bristol Bay region are: • • • • • • • • • Diesel generation Coal-, oil-, and natural gas-fired steam electric generation Coal gasification Combined cycle Energy conservation Waste heat recovery Wind energy Hydroelectric power Organic Rankine cycle These resources are recommended for further study in the Bristol Bay Regional Power Plan. References -An extensive literature search was performed to accumulate both technical and regional information to support the assumptions and technical positions presented in this appendix. The references listed in this section are only those directly applicable to the report material. A large amount of applicable general literature was reviewed but not listed. Each reference is listed in as much detail as available to allow the reader to locate the reference for technical verification. B.2-l0 .. .. - .., • .. • .. .. .. .. .. • .. .. .. .. SECTION,3 ANALYSIS AND DISCUSSION ;1 .' .", .'. . ',' .. '" ,. • ~ ,', .:. ... ~~ ,. -., __ • : . '. . -0' _' ..".. .' SECTION 3 ANALYSIS A~~ DISCUSSION The detailed review and evaluation of the potential Bristol Bay energy resources is included in this section. The evaluation criteria for these resources encompass their commercial availability, technical restraints, constructibility, operating and maintenance aspects, regulatory restraints, environmental considerations, and regional constraints. General descriptions and figures are also included to provide the reader added insight into the various technologies. Energy resources which satisfy all of the above listed evaluation criteria will be considered for further investigation in the Bristol Bay Regional Power Plan. This method provides an effective screening of the wide variety of energy alternatives. B.3-1 .. -.... -.. -.. .. .. -... • .. ... - .. ." .. • 3.1 3.1.1 General Description Diesel generator units account for about 1 percent of the electric power generating capability in the United States (Ref. 1). Because of their reliability and ability to start quickly. diesel generator sets are often installed for peak load and stand-by power. In addition, their small size, commonly about 2,000 kilowatts (kW) per unit although some approach 10,000 kW, has limited their use in base load applications. However, small diesel generating units are used for providing base load power in regions throughout the United States where load demands are low and transmission lines are not integrated with power stations. The main components of a diesel generator unit are the diesel engine, generator, auxiliary systems, switchgear, transformers, and control/monitoring equipment. The building or diesel generat:or enclosure is also an important part of the unit. Diesel engines can be fueled with oils ranging from heavy crudes to light distillates. Selection of the optimum fuel for a diesel plant depends on parameters such as engine requirements, operating conditions, and fuel costs, availability and quality. For reliable diesel engine operat:ion the fuel injection pumps or ejectors require fuel oils with low viscosities, in the range of 50 to 100 SSV. Therefore, when high viscosity, heavy crude oils are used, the fuel oil system must include pumps, centrifuges, filters, and heaters for conditioning the crude oil to the proper consistency and viscosity for injection. Light dist:illate fuel oils require no special conditioning prior to injection into the diesel engine. Heavy and light fuel oils can also be blended to meet diesel engine requirements. All trade-offs between differential fue 1 costs, maintenance costs and operating costs must be evaluated for proper diesel plant fuel oil selection. The diesel engines commonly used for power generation are low speed reciprocating internal combustion machines similar to those used in marine B.3-2 • ., applications. These engines operate on an open, compression ignition two-• or four-stroke cycle. The sequence of events in the four-stroke diesel cycle is as follows: The cycle is initiated by introducing air into the open engine cylinder during the first downstroke of the piston. The cylinder is then closed and the compression stage commences with the first upstroke of the piston. As the piston moves upward, fuel is injected into the cylinder. The heat of the compressing gases ignites the fuel. After the fuel ignition, the internal combustion forces the piston through a second downstroke. This downstroke, commonly referred to as the power stroke, transmits forces through the piston and rod linkage to the drive shaft where the translational momentum is converted to rotational momentum. The final upstroke of the piston purges the open cylinder of all remaining gases, and thus the sequence continues. The two-stroke diesel cycle is a variation where the purging of gases is accomplished by blowing air (or air and fuel) in through the cylinder, thus eliminating the exhaust and intake strokes. EVen though the two-stroke cycle completes twice as many power strokes in a certain number of revolutions as the four-stroke cycle, the power output is not doubled. This is due to the incomplete scavenging of gases, a greater loss of unburned fuel, and the power consumption of compressing air for scavenging. Some of the auxiliary equipment supporting the diesel engine operation includes air intake filters and silencers, engine starters, the cooling system, the lube oil system, the fuel oil system, exhaust mufflers and coolers, and various control and monitoring devices. The generator is coupled to the diesel engine drive shaft. The basic elements of a generator are the same as for a synchronous electric motor: the rotor and stator. In an alternating current (ac) generator, the stator is the stationary winding and the rotor is the rotating winding, sometimes called the field. Although early generators had a stationary field, all modern ac generators are of the revolving field type. B.3-3 .. • - The phenomenon of magnetic field to causing a voltage currents to flow. ac electric power generation is created by causing a pass across the stationary stator windings, thereby to be developed in the stator windings and electric The revolving field is created by applying a dc voltage across the field windings, which are mounted on poles on the rotor. Alternate poles on the rotor have opposite electrical polarity. This causes the induced current in the stator to flow first in one direction and then in the opposite direction, creating alternating current. The frequency of the alternating current depends on the rotating speed of the rotor and the number of poles on the rotor. Current flowing in the stator winding also creates a magnetic field in the stator which interacts with the rotor field. This interaction causes a torque in the generator shaft which is overcome by the power produced by the diesel engine. Some of the equipment supporting the generator operation includes the exciter, governor, and voltage regulator. The exciter supplies power to the generator field. Generally, the exciter is a smaller generator also coupled to the diesel engine drive shaft. This type of exciter generates ac power that is rectified and applied to the main generator rotor. The governor is a mechanism with proper characteristics to adjust the diesel engine power output to meet the load on the generator while maintaining constant speed. A voltage regulator is required to control generator voltage and for bringing generator units into parallel operation. The current generated is directed through transformers and switchgear to the transmission lines. The transformers mUltiply the voltage and divide the amperage to allow for more efficient transmission. The switchgear allows for interrupting and applying load on the generator units. B.3-4 3.1.2 State of Technology Diesel generator units have been used for base load, stand-by, and auxiliary power generation for many decades. Diesel generator sets with proven reliability and high thermal efficiencies are commercially available. In fact, the conversion of chemical energy to electrical energy in a diesel generator set occurs at approximately 35 to 40 percent thermal efficiency when operating at, or near the rated output of the engine. In addition, if extens ive waste heat utilization is implemented, a diesel generator unit can reach as high as 80 percent thermal efficiency (Ref. 2). Technological advances in diesel generator sets have focused on auxiliary systems that support the engine and generator operation. Other advances have been made in utilizing waste heat from the diesel engine. The diesel engine auxiliary systems receiving the major thrust of advancement are related to the combustion processes. The engine cylinder combustion chambers have been adapted to allow for more gas turbulence and therefore more complete combustion. The fuel oil systems have been refined to improve timing and measure, in fuel injection. Air injection at pressures substantially higher than atmospheric has made it possible to burn more fuel per cycle, thus increasing power output (turbochargers which use exhaust gas momentum to compress incoming air are now used extensively for air injection). Two major technological advances have been made in generators for diesel generator sets: (1) the generator stator exciter arrangement has been revised to allow its mounting on the main drive shaft, which has eliminated the need for a large set of lead-acid wet cell batteries; and (2) silicon diodes have replaced the old standard of brushes, commutator, and slip rings. The technological advances mentioned have enhanced the reliability of diesel generator units. The adaptation of diesel generator units for waste heat utilization is discussed in Section 3.7. B.3-5 .. • .. .. .. ., .. .. .. -.. -.. • .. • .. .. ., 3.1.3 Technical Restraints None identified. 3.1.4 Constructibility The merits associated with the constructibility and ease of installation of diesel generator units are a consideration that should be weighed favorably against other alternative power plans. For low unit load installations, 1, 000 kW or less, the major plant components, that is, diesel generator sets, are commercially available and can be delivered with various design options and supporting systems mounted on a single skid. For higher unit load installations greater than 1, 000 kW, the diesel engine and generator are available mounted on a single skid, and separate fuel-oil, lube oil, cooling, air intake, exhaust, and control and monitoring systems will have to be installed. In either case, the major construction effort will be in erecting the building and transmission equipment. 3.1.5 Operating and Maintenance Aspects Diesel generating units require an extensive but relatively simple maintenance program. As with other internal combustion engines, routine maintenance includes cleaning, f i 1 ter changes, oil changes, coolant flushes, clearance checks and adjustments, and bolt torquing. The generator requires load tests, resistance tests, insulation tests and other periodic checks. Host manufacturers of diesel generator sets will either work with operators in setting up a maintenance program or offer a maintenance contract to the customer. The ~peration of diesel generator units can be fully automatic. If this is the case, the operators should only have to make observations of the unit a few times daily. B.3-6 3.1.6 Regulatory Restraints and Environmental Considerations In general, diesel generating units do not pose particularly difficult or unusual environmental problems. With regard to air pollutant emissions, both state and federal permits may be necessary, depending upon the unit's size. If the diesel engine requires 50 million Btu per hour or more heat input and air contaminent emission controls to comply with state emission standards, a state permit will be required. The federal Prevention of • - - ., ., Significant Deterioration (PSD) guidelines allow up to 250 tons per year of _ pollutant emissions before PSD analysis is necessary. With diesel engines _ the main pollutant is NO. An estimate of NO emissions from a 3,000 kW x x ., diesel generating unit operating about 60 percent of the time with a time/load distribution of 20 percent at full load, 40 percent at 75 percent load, 30 percent at 50 percent load and 10 percent at 25 percent load, is about 250 tons per year. Therefore, to avoid PSD analysis, a single site '. generation capability would have to be limited to approximately 3,000 kW. ., Existing diesel generating units in Alaska have not required any exhaust .. gas scrubbing or particulate collecting equipment; however, new units will have to meet the previously mentioned requirements. Another concern associated with diesel generator units is noise emission. Noise can easily be muffled with enclosures, silencers, or other noise abatement equipment. 3.1.7 Regional Restraints Fuel oil is currently shipped into the Bristol Bay region for use in space heating and diesel power generation. Converting to central generating facilities would reduce oil consumption for present electrical load. Oil exploration is now in progress in the Bristol Bay region. However, a ., -., .. ., ., • refined oil supply local to the region is not anticipated in the near _ future. ., B.3-7 .. - 3.1.8 Conclusions Diesel generator units have proven to be reliable and efficient. Some of the advantages of installing diesel generator units in the Bristol Bay region are the relatively simple constructibility, maintainability, and operability, the minimal environmental impact on land and water resources; and the possibilities of implementing cogeneration. A drawback with diesel generator units is the dependence on an expensive fuel source that could diminish in the future. However, a 20-year forecast indicates that the economics of installing diesel generator units is expected to weigh favorably against many alternative electric power sources. This technology should be evaluated more extensively in the next phase of the Bristol Bay Regional Power Plan. B.3-8 3.2 COAL·, OIL·! AND NATURAL GAS-FIRED STEA.1'1 ELECTRIC GENERATION 3.2.1 General Description A steam electric generating station is one of the most efficient means of converting the chemical energy of fossil fuel into electrical energy. The - fuel, either coal, oil, or natural gas, is burned in the boiler and imparts its energy to water fed into the boiler, continuously generating steam. The steam created in the boiler is then expanded through a turbine where the heat energy is converted to the mechanical work of rotation. The rotation of the electrical generator coupled to the turbine creates electricity. The steam which has expended its energy in the turbine is condensed in the condenser, heated, and returned to the boiler to continue - the steam generation cycle (Figure 3.2-1). The major difference between a coal-fired unit and natural gas-or oil-fired unit is the fuel handling equipment. requires special handling and preparation to properly sized coal into the boiler. There are Coal, being a solid fuel, insure a smooth flow of two primary boiler coal .. - burning systems: pulverized and stoker. Stoker types, common in smaller ., boilers such as would be used in the Bristol Bay region, feed coal onto a - moving grate within the boiler, and the coal is burned completely as it passes through. In pulverized coal systems, the coal is ground to a very fine dust and burned in suspension as an air-coal mixture. The pulverized systems burn the coal and operating costs more make efficiently, but stoker systems I them more cost effective for lower capital small boi lers . Equipment that transfers the coal to either the stoker or pulverizers also requires a significant capital expenditure. This includes barge or railroad car unloading facilities, stacking/reclaiming equipment, coal storage facilities, conveyors, transfer houses, coal crushers, etc. Fuel handling requirements for oil or natural gas boilers are less complex, consisting mainly of storage tanks, piping, and pumps (pumps for oil only, evaporating stations for liquefied natural gas). B.3-9 .. .. • ., .. ., .. .. .. Another considerable difference between coal-fired, oil-fired, and natural gas-fired units is in the amount of waste products generated by fuel combustion. The waste products consist of ash and scrubber sludge. Scrubber sludge would exist only if a flue gas desulfurization system, as described in Section 3.2.2a, were installed at the plant. A coal-fired unit creates substantial waste products, an oil-fired unit less, and a gas-fired unit almost none. 3.2.2 State of Technology Conventional fossil fuel-fired steam power plants have been in operation for decades and are a proven technology. Technological advancement in coal-fired steam electric facilities has focused upon the control of air pollution. generating Three major exhaust gas components have received the primary emphasis: sulfur oxides, nitrogen oxides, and particulates. a. Sulfur oxides in the exhaust gases can be reduced by two commercial methods: mechanical cleaning and washing, and flue gas desulfurization. :1echanical cleaning and washing removes only a portion of the coal's inorganic sulfur and none of the organic sulfur. The cleaning/washing is done prior to burning the coal. Thus, the coal has to be dried again before burning. TIle expense of washing and cleaning the coal is not justified with the small reduction, 40 percent at best, of total sulfur. Flue gas desulfurization, or "scrubbing" the combustion gases, involves bringing the sulfur oxide-laden exhaust gases into contact with a substance, for example, lime, with which the sulfur oxides can react and be removed from the gas stream. The various flue gas desulfurization schemes are distinguished from one another by whether a wet or dry scrubbing agent is used and whether the used scrubbing agent is thrown away or regenerated for reuse. B.3-10 ., b. Coal combustion forms nitrogen oxides by drawing nitrogen from both the coal and the air in which it burns. The amount of NO x ., formed depends on flame temperature, the amount of excess air in the flame, the length of time combustion gases are maintained at elevated temperature, and the rate of quenching. Higher flame temperatures and excess air foster nitrogen oxide production, as does rapid cooling (Ref. 3). New coal-fired boilers can be designed to minimize NO emissions, reSUlting in NO release rates x x below regulatory requirements. c. There are four types of particulate control systems: mechanical collectors, electrostatic precipitators, wet scrubbers, and fabric filter baghouses. Mechanical collectors use gravity, inertia, or centrifugal force to separate the particles from the gas. .. .. Electrostatic precipitators consist of high-voltage discharge .. electrodes and grounded collection plates, between which the flue ., gases pass. Par.ticles are charged by ions emitted by the discharge electrode and move toward the collection plate where they can be collected and removed. Wet scrubbers use water to wash solid particles out of the gas stream. We.t scrubbers are expensive to install and operate, and are not widely used for .. particulate control, although some installations exist. Fabric filter baghouses are the most effective of all particulate control methods against small particles, but the pressure drop involved in forcing the gas through the necessary fine filters increases operating costs. These devices have been used in industrial particulate control for many years, but the high temperatures and corrosive chemicals in coal combustion gases, among other problems, have limited their use with utility boilers. Improved heat and chemical resistant filters have been developed recently, making this option more attractive to utilities. In view of the health hazards of small, respirable particles produced in coal combustion, it is likely that filter devices will be used increas ingly in the future, and they warrant vigorous deve lopment (Ref. 3). B.3-11 ., .. II, ., .. II • • .. .. Fluidized bed combustion is a technology being developed for boilers in utility power plants. The technology is new to power stations, but fluidized bed chemical reactors have been in use for several decades by the chemical and petroleum industries, and fluidized bed combustion is currently being commercialized for industrial boilers. Fluidized bed boilers have a layer of small, noncombustible particles (limestone in the case of high sulfur coal combustion) resting on a distribution plate. Combustion air is forced through the nozzles or openings in the plate and turbulently mixes the bed material, giving it a fluid-like motion. Fuel (coal) is mixed with the combustion air entering the bottom of the bed, and is burned in the bed. Fluidized bed combustion offers the following advantages (Ref. 4): a. The coal is burned in the bed in intimate contact with the b. limestone. The limestone is calcined to calcium oxide which reacts with the sulfur dioxide in the flue gas to form calcium sulfate, a relatively inert material which is removed with the ash. Virtually all the sulfur is captured by the lime, and very little S02 is discharged with the flue gases. The need for flue gas desulfurization with high sulfur coals is thus eliminated. Combustion normally takes place between hundreds of degrees below the point formation becomes troublesome. 1,5000 F and o 1,750 F, where atmospheric NO x c. High heat transfer coefficients are realized due to solids/metal contact, thereby permitting more compact boiler designs. d. Due to the ability to burn coarser fuel sizes, the costs of fuel preparation are reduced in comparison to pulverized coal systems. e. Low combustion temperatures minimize or eliminate ash slagging problems. B.3-12 f. Virtually any type of combustible material may be burned by properly adjusting factors such as type and particle size of bed material, fluidizing velocity, feed methods, and rate of feed. Three approaches are being developed for fluidized bed combustion: atmospheric, circulating, and pressurized. As the names imply, combustion in an atmospheric fluidized bed combustor (FBC) takes place at or near ambient pressure, while the pressurized version is pressurized from 3 to 16 atmospheres. In a circulating bed, the bed material is circulated outside the combustion zone and used as a heat transfer medium. Atmospheric FBC boilers are currently being commercialized, with several demonstration plants under construction and in operation. The pressurized FBC boilers offer higher efficiencies, better limestone utilization, and more compact design than their atmospheric counterparts, but are quite complex and still in the early development stage. Circulating fluidized beds have been used for commercial operation with certain fuels in Europe and are rapidly being developed in the United States. In the last several years SWEC has been active in fluidized bed combustion proj ects, a number of which included evaluation of the present state-of-the-art and its potential for broad commercial application. SWECts evaluation brought to light significant problems relating to design arrangements representative of the general state-of-the-art. The problems concerned the placement of heat absorbing tubes in the bed resulting in limited load turndown, fuel distribution requiring too many feed points, marginal combustion efficiency, and excessive proportions of limestone needed to react effectively with the sulfur in the coal. SWEC concluded that improvement in methods of applying fluidized bed combustion would be needed if it were to become acceptable for steam generation. That conclusion led directly to SWEC proprietary interest in a new patent covering a concept called the Solids Circulation Boiler. The Solids Circulation Boiler operation can be summarized as follows: A bed of inert solids of an average 200 micron particle size, covers • .. • .. If! If! If! lllij If! ., .. • .. • .. IIti .. .. .. .. .. ., the base of a water cooled enclosure. The floor of the enclosure is a ., B.3-13 .. distributor through which combustion air is admitted to burn the fuel in the bed. The hot solids from the bed pass into an air stream and are carried up a water-cooled riser and down a return channel to be cast over the bed surface. The cooling effect of the returned solids plus the heating of the combustion air is matched by the heat released in burning the fuel in the recirculation channel system. The projected size of one Solids Circulation Boiler module is about 100,000 pounds per hour of stearn generation. This fluidized bed technology is currently in the preliminary demonstration stage. 3.2.3 Technical Restraints None identified. 3.2.4 Constructibility The major plant components, that is, the boiler, turbine-generator, and condenser can be either shop-assembled package units or field-assembled, depending upon manufacturer and size. Considerable capital cost savings could be gained by constructing major portions of the plant outside of Alaska and shipping it by barge to Bristol Bay to minimize field assembly. A coal-fired power plant is more complex and expensive to build than oil- or natural gas-fired units. \{ith a coal-fired plant, the coal storage, coal preparation, ash handling, and pollution abatement systems add a significant amount of additional equipment and space not associated with oil-or gas-fired plants. 3.2.5 Operating and Maintenance Aspects The additional equipm~nt necessary to generate electricity by burning coal a Iso increases the operating and maintenance costs, causing them to be significantly higher than those associated with oil-and natural gas-fired plants (Ref. 5). B.3-14 Operating personnel are required. on an around-the-clock basis when a stearn turbine generating unit is operating, using any of the three fuels. The availability of trained operating personnel is a necessity to keep the plant running. Thus, the station should be located close to the more populated areas of Bristol Bay, i. e., Dillingham or Naknek. One central station (multi-unit for reliability) would be desirable, since economy-of-scale dictates that the operating and maintenance expenses, as well as capital costs, are less per kilowatt-hour generated the larger the power station becomes. Steam turbine generating units can be designed to cycle electrical output to match electrical power demand. Since the major cost considerations (fuel use) center around the boiler, which is most efficient at full load, the highest practicable boiler utilization rate is encouraged. 3.2.6 The federal Fuel Use Act prohibits any stationary electric generating unit or fuel burning installation consisting of a boiler, gas turbine, combined cycle unit or internal combustion engine with an expected heat input rate of 100 million Btu per hour or greater for a single unit (250 million Btu per hour for two or more units) from using petroleum or natural gas as a primary energy source (Ref. 6). This means a new steam turbine power station firing oil or natural gas would have to be limited to approximately 8 megawatts (MW) for a single unit installation or 20 MW for a multi-unit installation. Temporary and permanent exemptions can be grant:ed if it can generally be proven that all alternative fuel sources are economically less favorable than firing imported petroleum or natural gas through the entire life cycle of the power st:at:ion. For coal-, oil-, and natural gas-fired units, a state permit will be required if: (1) the unit has a rating of 50 million Btu per hour or greater and an air contaminant emission control unit is required to comply B.3-lS with state emission standards, and (2) the unit has a rating of 100 million Btu per hour or greater. Relative to item (1), applicable state emission standards are: a. Visible emissions may be no greater than 20 percent opacity for a period or periods aggregating more than three minutes in anyone hour. b. Particulate matter emissions may not exceed 0.1 grains per standard cubic foot of exhaust gas. c. Sulfur dioxide emissions may not exceed 500 parts per million. For units of the sizes being considered, a Federal Prevention of Significant Deterioration (PSD) permit will be required if emissions of sulfur dioxide, nitrogen dioxide, total suspended particulates, or carbon monoxide equal or exceed 250 tons per year. 3.2.7 Environmental Considerations Coal~fired units are more detrimental to the environment than oil~ and natural gas~fired units. As mentioned in Section 3.2.1, coal-fired units generate considerably greater amounts of waste products than oil-and natural gas-fired units. Environmental controls associated specifically with coal-fired units are ash removal and disposal, flue gas desulfurization, flue gas particulate removal, coal dust suppression, and control of water runoff from the coal pile or ash disposal areas so that it does not leach into the groundwater. In addition, a safety as w'ell as environmental concern for coal-fired plants is to control spontaneous combustion of coal in storage areas and in the plant to prevent fires. Environmental controls must also be placed on mining and transporting coal from the source. With small oil-and natural gas-fired units, the flue gas emissions are generally less detrimental and require less control. A concern with oil-fired units is the safe access of oil-laden barges to ports for unloading. B.3-l6 • • • .. • - • ., .. - • - • .. • • • .. • ., • • • -• - 3.2.8 Regional Restraints The Usibelli mine near Healy is the only operating coal mine in Alaska at the present time, although others are being developed. By the summer of 1982, the Usibelli Coal Company expects to have coal unit trains in operation to a port facility near Seward. Coal for a power station in Bristol Bay could be purchased at the Seward port facility and shipped by barge around the Alaska peninsula to the plant. The Chignik and Herendeen Bay coal fields, in particular, were investigated due to their proximity to Bristol Bay. However, these fields are not expected to be in production in the near future. Obtaining coal from locations outside of Alaska, such as British Columbia and the lower 48 states, should also be investigated in the further optimization of the coal resource. Coal barging can only be accomplished during the warmer weather months, when Dillingham and Naknek are not iced in. This means a plant would require an extensive storage pile to use through the winter months, when barging cannot be accomplished. The stored coal would also have to be . protected in some manner to prevent fuel handling problems due to ice and snow. Fuel oil is currently shipped into the Bristol Bay region for use in space heating and diesel power generation; an oil-fired power station would use the same fuel. The oil storage facilities would have to be large to enable plant operation during winter months, when oil is not shipped into the area. Purchas ing oi 1 in large quant i ties for use in a central power generation facility with electric transmission lines connecting outlying villages could be economically advantageous to the remote villages. Remote villages could have electricity costs similar to those in Dillingham or Naknek. Oil companies are exhibiting major interest toward oil and natural gas exploration in the Bristol Bay region. However, there are currently no developed oil or gas resources in the area. The Department of Natural Resources rates the Bristol Bay area prospects of significant finds of oil or natural gas as "low or moderate" (Ref. 60). Factors that would present B.3-l7 obstacles to the locating and developing of such resources are the high cost of exploration, the expense and difficulty of obtaining land and mineral rights, and the impact of oil wells on the fisherie~, particularly with off shore drilling. A minimum of 10 years would be required to develop a newly discovered well for use in the Bristol Bay region. Although discoveries may appear imminent, the size and timing are uncertain, and oil and natural gas resources cannot be considered feasible for near term use in this study. If there are discoveries in the period of this study, they should be examined in Phase II. Since production of crude oil or other heavy fuels is not presently available locally, these fuels would have to be transported in by barge. The delivered cost of crude is not competitive with coal on a dollar per million Btu basis. The cost of delivered coal is presently $3. 41/mm Btu while delivered crude would be $7.54/mm Btu. While local petroleum resources remain undeveloped, heavy fuels cannot economically compete with coal. Since natural gas is not present ly available locally, it would have to be barged in, similar to coal and oil. Transporting natural gas other than by pipeline is most cost effective when the gas is liquefied. Liquefied natural gas (LNG) is produced on the Kenai peninsula and sold to Japan. This is the only LNG facility in Alaska, and the producer may not be able to provide LNG for a Bristol Bay power station. If the LNG were available, a custom designed barge and receiving facility would have to be furnished with the power station. 3.2.9 Conclusions The steam turbine concept of generating electricity is proven and efficient. However, the economics of steam turbine power plants as small as needed for Bristol Bay may be prohibitive. Additionally, fuel availability is a problem for each of the fossil fuels: coal, oil, and natural gas. Barging fuel around the Alaska Peninsula to the Bristol Bay power plant would be expensive. Steam turbine generating units should not be eliminated from further consideration, however, without a more thorough economic evaluation. This B.3-18 - .. .. .. .. II! .. .. - • .. .. .. .. .. .. .. .. .. III' • technology should be evaluated more extensively in the next phase of the Bristol Bay Regional Power Plan. Fluidized bed boilers, although being commercialized on an industrial scale, have not yet been proven commercially reliable sources of steam for large utility power stations. The FBe technology shares the same regional restraints as the other steam turbine generating units and should receive equivalent consideration for implementation in the Bristol Bay Regional Power Plan. B.3-19 r---------------------------------------------------------------~m .., r-:-:l~---~~ISl~::-1--...-! .... EXHAUST TO STACK AQC"II- SYSTEM FLY ASH TO DISPOSAL COAL, OIL, OR NATURAL ......... GAS INDUCED DRAFT FAN STEAM r-------------------. I BOILER I ~-f--I r---- - - - - -_EE~C~~S::'AM~..J r-----------':a...J I I I r-----~-' I I ~~~ I r-I FORCED DRAFT FAN a: w I- ~ C w w u. I I I I I OEAERATOR I STORAGE TANK I I I I l: I I I I __ ...J LOW PRESSURE CONDENSER w l- e:( CI) Z w C z 8 BOTTOM ASH TO DISPOSAL HIGH PRESSURE FEEDWATER HEATERS FEEDWATER PUMPS FEEDWATER CONDENSATE HEATERS PUMPS * AIR QUALITY CONTROL SYSTEM INCLUDING FLUE GAS DESULFURIZATION AND PARTICULATE REMOVAL. ELECTRIC GENERATOR TYPICAL STEAM TURBINE GENERATING UNIT FIGURE 3.2-1 o m - 3.3 COAL GASIFICATION 3.3.1 General Description Coal gasification involves reacting coal with air or oxygen and steam to produce a combustion gas containing carbon monoxide, hydrogen, methane and heavier hydrocarbons. Gas produced can be subdivided into three categories: low-Btu (100 to 200 Btu per standard cubic foot, or scf), medium-Btu (250 to 500 Btu per scf), and high-Btu (900 to 1,100 Btu per scf). Low-Btu gas is produced by gasifying coal with air. l1edium-Btu gas is produced by gasifying coal with oxygen. Pipeline quality high-Btu gas is produced by further processing the medium-Btu synthesis gas to produce methane. The gasification of coal provides a means for the removal of sulfur and mineral matter compounds to produce a "clean" fuel which can be burned in an environmentally acceptable manner (Ref. 7). Coal gasification can be carried out at a central station with the produced gas distributed to users. However, due to its low energy content, low-Btu gas cannot be transported economically over long distances. In general, all applications of low-Btu gas involve on-site, or directly over-the- fence, production and utilization. Medium-Btu gas can be economically piped approximately 100 to 150 miles. High-Btu pipeline quality gas, or synthetic natural gas (SNG), has characteristics similar to natural gas and can be transported over long distances. Coal gasification can also be integrated into a central steam electric power plant, diesel generator plant, combustion turbine, or combined cycle plant. Figure 3.3-1 shows how a low-Btu coal gasification system could be integrated with a conventional steam electric power plant. Figure 3.3-2 shows the more efficient system of integrat into a combined cycle power plant. 3.3.2 State of Technology a coal gasification plant Low-and medium-Btu gasification technologies have been used commercially B.3-20 for decades. A few of the low-Btu technologies marketed today include Wellman-Galusha, Wilputte, Riley-Morgan, Woodall-Duckham, Stoic, and Wellman-Incandescent. The major medium-Btu technologies include Lurgi, Winkler, and Koppers-Totzek. Numerous second-and third-generation technologies are actively being developed. SNG production is based on existing gasification, carbon monoxide shift, gas purification, and methanation technologies. While each of these technologies has operated commercially in other applications, they have not been integrated to produce high-Btu gas on a large commercial scale. A large, high-Btu gasification facility is currently under construction in North Dakota. The owner is American Natural Resources and the plant, upon completion will be capable of producing 137 million scf of substitute (or synthetic) natural gas per day. 3.3.3 Technical Restraints Although low-and medium-Btu technologies have existed for decades, until recently, abundant supplies of natural gas in the United States have restricted the commercial development of the more efficient, second generation, high-capacity gasifiers for use in today's large central station power plants. A number of second generation gasifier demonstration plants are currently under construction and many pilot scale units are in operation to provide the necessary technical data and operating experience required for large units. There are no technical restraints to the use of small gasifiers to satisfy the projected load growth of the Bristol Bay region. 3.3.4 Constructibility The construction of a conventional power plant with an integrated coal gasification facility would be more complex than the conventional plant alone. This is because of the additional required equipment, land area, and interfaces created by the added coal gasification facility. B.3-21 .. .. .. .. .. • .. • -.. .. .. .. • " • • 3.3.5 Operating and Maintenance Aspects The gasification facility, which is basically a "chemical plant", increases significantly the operating and maintenance costs that would be incurred by the conventional plant alone. However, the increase in efficiency (lcwer plant heat rate), which is inherent in an integrated gasification-combined cycle power plant, and elimination of a flue gas desulfurization system offer advantages that can balance these increases. 3.3.6 Regulatory Restraints and Environmental Considerations As mentioned previously, coal gasification" with gas cleaning provides "clean" fuel which can be burned in an environmentally acceptable manner. The power station permitting and emission control requirements depend on the site, the coal feed, and which coal gasification process is implemented. In general, the complexity of the gas clean-up can be balanced to meet environmental regulations. 3.3.7 Regional Restraints The regional restraints of gasification are similar to those of the coal-fired steam turbine generating units discussed in Section 3.2 of this report, the primary difficulty being coal availability. A coal gasification plant at Herendeen Bay would be the sit:e nearest Bristol Bay for mine-mouth operation. However, the Herendeen Bay coal fields are not expected to be developed in the immediate future. A coal gasification facility could be located near Dillingham or Naknek (population centers with better availability of operating and maintenance personnel) with the coal barged to the plant, as is done for the steam turbine units (Section 3.2). An advantage could be gained over the coal-fired steam units by converting the coal to gas and burning the gas in individual home furnaces as a space heating alternative. However, low-and medium-Btu gas contain dangerous amounts of carbon monoxide which B.3-22 homeowners would have to be protec~ed against. In addition, to burn these gases, the furnace burners would require replacement or major modification, negating some of the economic benefits of the fuels. Thus, burning low-or medium-Btu gas for space heat is not recommended, and burning high-Btu synthetic natural gas is not developed sufficien~ly for use in the region. 3.3.8 Conclusions Coal gasifiers have operated commercially for years throughout the world and are a reasonable alternative to conventional coal-fired units with "back-end" flue gas desulfurization systems. No recent studies have been done to compare the relative costs of small coal gasification power plants, 100,000 pounds per hour steam capacity, or approximately 9 MW, with conventional coal-fired units. Coal gasification should, therefore, no~ be ruled out as an alternative to conven~ional coal-fired units, and should be considered as a potential power source for the Bristol Bay region. B.3-23 ., .. .. - ., .. ., .. .. • • .. .. • .. • .. • .. .. .. • .. • .. ., .. .. .---------------------------------------------------------------------------------------..~ o COAL STORAGE CONDENSATE PUMP AIR---.... HOT .------1 CONDENSER --, I I ELECTRIC GENERATOR COAL COAL COAL RAW GAS * AQC EXHAUST 1------1111 PREPARATION GASIFIER FINES CHAR STEAM BOILER 1-----1 SYSTEM 1---' TO STACK *AIR QUALITY CONTROL SYSTEM INCLUDING FLUE GAS ASH DESULFURIZATION AND PARTICULATE REMOVAL (TO DISPOSAL) INTEGRATED GASIFICA TION COAL-FIRED PLANT FIGURE 3.3-1 ... • ... :( r-----------------------------------------------------------------------------------------~~ COAL STORAGE (I) W z ii: COAL PREP. ...I « 8 AIR HEAT RECOVERY BOILER EXHAUST EXHAUST GAS BURNER HOT CLEAN COAL RAW GAS GAS GAS GASIFIER I----..... SCRUBBERI--= .......... CHAR ASH OIL & TARS COMPRESSOR STEAM CONDENSATE PUMP FUEL CONDENSER COMBUSTION TURBINE (TO DISPOSAL) WASTE WATER TREATMENT INTEGRATED COAL GASIFICATION COMBINED CYCLE POWER PLANT ELECTRIC GENERATOR EXHAUST ELECTRIC GENERATOR .. o N .. N o 4: 1.....-------------FIGURE 3.3-2---- 3.4 COHBINED CYCLE 3.4.1 General Description The combined cycle power plant as depicted in Figure 3.4-1 integrates combustion turbine(s), heat recovery steam generator(s), and a steam turbine into a "combined" cycle in order to achieve a higher thermodynamic efficiency than is possible utilizing a conventional steam (Rankine) cycle. Air is taken into the combustion turbine and compressed. From the compressor section, the high pressure air flows to a burner where fuel is burned in combination with the air to produce a high temperature, high pressure gas. The gas is then expanded through the turbine section of the combustion turbine, turning its shaft and producing electrical energy through an electric generator. The high temperature turbine exhaust gases are directed to a heat recovery boiler to produce high pressure steam. The steam is expanded through a steam turbine to generate additional electrical energy through a second electric generator. Combustion turbines are available in two general types: aircraft and industrial. The aircraft type is usually of lighter construction and has thinner metal cross sections than the industrial type. 3.4.2 State of Technology Many domestic and foreign manufacturers offer commercially proven combined cycle plants for applications. 3.4.3 Technical Restraints None identified. 3.4.4 Constructibility pre-engineered, packaged, industrial and utility Manufacturers offer standardized, package modular designs adaptable to the B.3-24 user's power needs, thereby simplifying and minimizing the amount of field work required. 3.4.5 Operating and Maintenance Aspects Gas turbines provide maximum fue I flexibi li ty, since they can be des igned to operate on a wide range of liquid and gaseous fuels. With suitable duct dampers, bypass ducts, and stacks, the gas turbine can be operated independently of the balance of the system. This will allow maintenance of the heat recovery boiler(s) and steam turbine while generating approximately two-thirds of the unit's power rating. Of the two gas turbine types, the aircraft derivative exhibits a greater ease of maintenance, with fast tear-down and re-assembly. There is a long-standing debate within the industry as to whether one type exhibits lower maintenance costs than the other. 3.4.6 Regulatory Restraints and Environmental Considerations The regulatory restraints and environmental considerations for combined cycle power plants are common to those for combustion turbines (Section 3.5.7 and 3.5.8), except that a cooling water source is usually required for a combined cycle unit unless air-cooled condensers are used. 3.4.7 Regional Restraints None identified. 3.4.8 Conclusions The combined-cycle power plant is a commercially available and proven power system. However, its commercial availability is limited to sizes above 4 MW. Five manufacturers (all foreign) have been identified as offering power plants between 8 and 35 MW (Ref. 8). Because of the limitation on B.3-25 • .. • .. - • .. .. Ill! • • • .. .. .. minimum size and the moderate projections of total electrical demand (Ref. 9), the combined cycle would be limited to a central station concept. It is recommended that the combined-cycle power plant be considered as a potential source of energy for the Bristol Bay region. B.3-26 r---------------------------------------------------------------------------------------.. ~ III AIR FUel HEAT RECOVERY BOILER COMBUSTION TURBINE EXHAUST ELECTRIC GENERATOR STEAM CONDENSATE PUMP CONDENSER elECTRIC GENERATOR TYPICAL COMBINED CYCLE POWER PLANT FIGURE 3.4-1 o -• c( .. , l~ 3.5 COMBUSTION TURBINE 3.5.1 General Description A combustion (gas) turbine generating unit basically consists of a turbine, axial air compressor, combustion chamber, and electric generator (Figure 3.5-1). The turbine is directly coupled to and drives the electric generator and air compressor . Atmospheric air is drawn into the compressor, where it is pressurized and forced into the combustion chamber or burner. Fuel delivered into the combustion chamber burns, raising the temperature of the mixture of air and combustion products. The compressed, heated gases then flow through the turbine, dropping in pressure and temperature as the heat energy is converted into mechanical work of rotation. The gases exhaust to atmospheric pressure at temperatures of 850 0 F to 1,0000 F. A portion of the power developed by the turbine is used for driving the compressor, while the balance is used to drive the generator. Utilities use two types of combustion turbines for the generation of electric power: aircraft and industrial. Aircraft-type combustion turbines are lightweight and are used primarily in peaking applications. Aircraft turbines are more restricted in the fuels they can burn, that is, they primarily burn light distillate fuels, but can be adapted to burn natural gas or fuel oil by altering the fuel system and combustor. The industrial combustion turbine is a rugged, heavy-duty machine capable of using a wide variety of low cost, low-grade fuels. The combustion turbine has demonstrated its suitability as a prime mover for supplying peaking, emergency, and reserve electrical power. It requires no boiler; needs no water for cooling; involves minimal siting, housing, and foundation problems; and requires a minimum of power-consuming external auxiliaries (Ref. 10). B.3-27 3.5.2 State of Technology Utilizing combustion turbines common practice for decades. to generate electrical power has been a However, the use of simple cycle combustion turbines has declined drastically in recent years due to natural gas and oil price escalation. Pre-engineered, packaged, commercially proven combustion turbine generating plants are currently offered by a large number of manufacturers. 3.5.3 Technical Restraints None identified. 3.5.4 Constructibility The modular, packaged generating units minimize the amount of construction work required at the site. The major plant components would be manufactured outside of Alaska and barged to the Bristol Bay region for installation. Foundations, controls, fuel storage/distribution systems, and electrical switchyard construction would encompass the primary site efforts. Simple (Brayton) cycle combustion turbine generating units are the easiest of the fossil-fueled power stations (i.e., diesel, coal, etc.) to construct. 3.5.5 ~faintenance Requirements The aircraft-type combustion turbine is easier to disassemble for maintenance, whereas the industrial combustion turbine is heavier duty, requiring less maintenance. As discussed in Section 3.4, the industry does not agree as to whether one type exhibits lower maintenance costs than the other. Maintenance requirements vary widely among different units depending on such factors as hours of operation, startup frequency, operating modes, and fuel quality and type. Continual load cycling of the units necessitates increased frequency of maintenance and repair. B.3-2B • ... .. .. ... .. .. - .... -.. • .. .. .. • .. ... • .. .. .. • .. .. lit. • .. • • Difficulties will be experienced in training personnel to properly maintain the combustion turbine units; however, these training difficulties will be no more severe than for the other types of fossil-fueled power plants. 3.5.6 Operating Aspects Combustion turbines can be designed to operate on a wide variety of gaseous and liquid fuels such as natural gas, petroleum distillates, residual fuel oil, propane, blast furnace gas, butane, etc. The product of a coal gasification facility (Section 3.3) can also be used as fuel for combustion turbines. Heavy fuels are not considered suitable since they are highly erosive on combustion turbine bladings. Turbine loading is controlled by adjusting the amount of fuel burned, thus varying the available energy per pound of air entering the turbine. The air compressors run at a constant speed; the rate of air flow will be essentially constant at all loads. Because of the constant air flow, gas turbine efficiency drops off rapidly below full load operation. The reason for this is the lower turbine inlet temperatures due to a decrease of fuel burned with no change in air flow. One method to help overcome the drop in efficiency during partial load operation is the addition of a regenerator in the cycle, as shown in Figure 3.5-2. The regenerator uses exhaust gases at elevated temperatures to heat the combustion chamber inlet gases, which reduces consumption of fuel in the combustion chamber. The resultant thermal efficiency is higher, but even with the regenerator, there is a rapid drop in efficiency during part load operation (Ref. 11). Thermal efficiencies of the simple combustion turbine cycle, even at full load with regenerator, are less than those for diesel generating plants. A combustion turbine unit can be brought from the cold shutdown mode to full load operation in a short time span. Thus, the combustion turbine is effective for providing power under peaking or emergency conditions. Gas turbine generators can be completely automated, requiring no operating personnel at the plant site. B.3-29 3.5.7 Regulatory Restraints The federal Fuel Use Act (FUA) also applies to combustion turbines as described in Section 3.2.6 on steam turbine power stations. Under the federal FUA, combustion turbines can be installed if the output capacity is limited to roughly 7 MW for single stations and 17 HW for multiple unit stations. As with steam turbines, the federal and state clean air standards also apply. 3.5.8 Environmental Considerations The simple cycle gas turbine generating unit requires no cooling water source, thus eliminating water use concerns and the adverse impact on aquatic life. The air pollutant emission concerns are similar to those for steam turbine generating stations firing oil or natural gas (Section 3.2.7). 3.5.9 Regional Restraints None were identified other than those common to all fossil-fuel generating facilities. 3.5.10 Conclusions The gas turbine has low thermal efficiency at base load and even lower efficiency when at partial load. In the Bristol Bay region, the gas turbine plant would have to function at partial load a majority of the time, resulting in the consumption of natural gas or fuel oil in larger quantities than other equivalently loaded fossil-fueled power plants. The simple cycle combustion turbine should not be considered further as an electrical energy source for the Bristol Bay region due to its poor thermal efficiency. However, the combustion turbine in a more efficient system, the combined cycle, is discussed in Section 3.4 and is a viable candidate for power generation in the Bristol Bay region. B.3-30 • • • ." • - • • .. - ,. .. r------------------------------------------------------------------------------------------.~ 20 15 -""".- THERMAL EFFICIENCY, % 10 ..", ~ TYPICAL SIMPLE COMBUSTION TURBINE PERFORMANCE ~ ~ 5 o /' o COMPRESSED AIR TO COMBUSTION CHAMBER OR 20 FURNACE ---..... 40 60 80 100 LOAD, % COMBUSTION CHAMBER OR N---FURNACE 14--HOT COMBUSTION GAS TO TURBINE SIMPLE COMBUSTION TURBINE (BRA YTON) CYCLE FIGURE 3.5-1 ~ o • -;( .. ----------------------------------------------------------------------------------.... 20-t------t----t--=-__ ~--_t_--_I THERMAL E F F ICIENCY, % 10 -t-----t.::."",-=o'---t---_t_--_t_--_I O~~--~----~----~----~----~ o 20 EXHAUST .... _____ ......... GAS AIR INTAKE 40 60 LOAD, % 80 COMBUSTION CHAMBER FUEL--~L-__ ~ __ ~ 100 TYPICAL COMBUSTION PERFORMANCE WITH REGENERATOR ELECTRIC GENERATOR SIMPLE COMBUSTION TURBINE CYCLE WITH REGENERATOR FIGURE 3.5-2 1ft o • - 3.6 ENERGY CONSERVATION 3.6.1 Energy conservation is an alternative energy plan that is mutually beneficial to the energy supplier and consumer. Traditionally, as energy needs increase, utility planning is directed toward increasing supply. Over the last decade, restrictive government regulations, unpredictable economic conditions, and escalating fuel prices have forced utilities to re-evaluate their energy planning ideals. For utilities, energy conservation has become a viable means of satisfying increasing energy needs without proportionally increasing energy supply. To the consumer, energy conservation is often considered an economic burden with no short-term benefits. On the contrary, energy conservation can be initiated administratively, at no cost, with immediate results. Some items that can be initiated by the energy consumer are listed below: a. Turn off all incandescent lights when lighted area is vacated. b. Only use electric or fuel powered appliances when results cannot be achieved manually. c. When electric or fuel powered appliances are used, turn them off as soon as results are achieved. d. Manually set back heating system when heated area is vacated. e. Separate solid waste and burn paper and other wood by-products for space heating (if burning facility is available). f. Cycle window covers open and closed to utilize solar heat gain and restrict radiant heat loss. B.3-31 g. h. i. In meal planning, consider the additional use of cooking heat for space heating. Only use the amount of hot water necessary to accomplish intended use. Manually set back water heater temperature when not in use. Other energy conservation measures will require capital expenditures. These measures can be most effectively implemented when unique costs and benefits are evaluated and priorities are placed. Many utilities have initiated energy audit programs that aid the energy consumer in developing individual energy conservation plans. to consider are as follows: Some of the more effective measures a. Install additional insulation and weather stripping. b. Install more effective insula~ing windows and window covers. c. Install storm doors and entrance portals. d. e. Install fluorescent lighting instead of incandescent lighting. Make adjustments on heating systems and install "set back" thermostats. f. Install an efficient wood burning facility for space heating. g. h. Retrofit the existing heating system and/or wood burning facility for better effectiveness. Retrofit existing industrial energy equipment and process controls for better efficiency. B.3-32 .. • • • .. .. .. .. 111' .. • .. .. • .. • .. i. Design new buildings to utilize passive solar heating. j. Install consumer load management systems. Passive solar heating is an architecturally designed method of using solar energy without the aid of mechanical or electrical inputs (Ref. 12). Examples of passive solar heating designs are (1) installing large, coverable, south-facing windows; (2) landscaping around windows with deciduous trees; and (3) building the north face of a structure into an earthen hill, leaving the south face to solar exposure. While passive solar heating is an essential consideration in designing new energy efficient bUildings, it is extremely difficult and therefore less practical to retrofit existing buildings with this design. The limited daylight in winter months, when heating reqUirements are the greatest, severely reduces the advantages of passive solar heating. 3.6.2 Regional Restraints In general, in regions such as Bristol Bay with harsh climatic conditions and relatively expensive fuel sources, energy conservation awareness is already widespread among energy consumers. The potential for conservation within the context discussed in this item is therefore limited primarily to a small number of large energy users. An extensive investigation of a large sample of the energy consumers in the region would be necessary to adequately assess energy conservation potential, which is beyond the scope of this study. 3.6.3 As noted previously, energy conservation has become a key element in energy planning. As such, energy conservation is a supplemental energy plan that should be considered further in the Bristol Bay Regional Power Plan. B.3-33 3.7 WASTE HEAT RECOVERY 3.7.1 General Description Fossil fuel-fired electric generating plants exhaust almost two-thirds of their available energy as waste heat, while creating heat for space heating or process uses by direct firing of fossil fuels (in furnaces or process boilers) is more energy efficient. Although process steam boilers and furnaces are more efficient energy converters, they cannot effectively utilize the high combustion temperatures (more than 3,0000 F) of their fuel o resource for applications requiring 400 F process steam or space heating air at even lower temperatures. The optimal use of fossil fuels is obtained in a situation where both electrical generation and space/process heating can be combined. The total fuel required to produce both power and heat in one system is less than the fuel required to produce the same amount of power and heat in separate systems (Ref. 13, 14, 15). The utilization of the fossil fuel resource to generate heat for two separate processes, such as elec~ricity generation and space/process heating, is known as cogeneration. Cogeneration systems incorporate either a bot~oming cycle or topping cycle. In the bottoming cycle, fuel is burned initially to produce process or space heat, with the reject heat used to produce mechanical or electrical power. In the topping cycle, fuel is burned to produce high temperature gas or stearn for generation of mechanical or electrical power, and the reject heat is used to produce process or space heat. Bottoming cycles are used when the primary goal of the cogeneration system is the process or space heat, with electricity generation being secondary. Topping cycles are just the opposite, as electricity production assumes the major role. Waste heat may be recovered in a number of forms. It can be used to create s~eam, hot water, or hot air, and is occasionally used for combinations of the above in the same system. In addition, waste heat can be used in a lower temperature electricity generation system such as the Organic Rankine Cycle (ORC) discussed in Section 3.13. B.3-34 .. .. .. .. ... .. .. .. . .. • - In the Bristol Bay region the most practical methods to generate electricity and recover as much waste heat as possible are topping cycles associated with combustion turbines, steam turbines, and diesel generators (excluding ORC, which is separately addressed in Section 3.13). A variety of heat recovery options are possible for each of the electricity generation alternatives: combustion turbine, steam turbine, and diesel. However, only the following proven and commercially available methods will be discussed further in this section: a. Combustion turbine topping cycle, using waste heat to generate steam. b. Steam turbine topping cycle, using waste heat to generate steam. c. Diesel topping cycle, using waste heat to generate steam, hot water, or hot air. A combustion (gas) turbine topping cycle is shown in Figure 3.7-1. In this cycle, a gas turbine drives a generator, producing electricity. The gas turbine's exhaust is then used to produce steam in a waste heat recovery boiler. The steam can, depending on its temperature and pressure, be used for a number of different processes: for space heating, for cooling via absorptive chillers, for cooking, and for laundry. This cycle is well suited to installations where the demand for electricity is high and the demand for steam is low. The combustion turbine topping cycle in which process steam is used to generate electricity, a combined cycle system, is discussed in more detail in Section 3.4. A steam turbine topping cycle is shown in Figure 3.7-2. The cycle has two basic variations, depending on the type of turbine used. In the backpressure, or noncondensing, steam turbine version, steam produced in a boiler is sent through a turbine which drives a generator, producing electrici ty. The steam exhausted from the turbine is used as process steam. The extraction steam version operates in a similar manner except that the steam is extracted at intermediate stages of the turbine for use B.3-35 as process steam, and a condenser is required. Steam topping cyc les are best suited for installations rated greater than 1,000 kW. The diesel topping cycles illustrated in Figures 3.7-3, 3.7-4, and 3.7-5 are similar to the combustion turbine cycle except that a diesel engine is used to drive the electric generator and reject the waste heat. The major sources of waste heat from a diesel engine are the jacket water heat, lubricating oil heat, exhaust gases, and radiation losses. Recovery systems incorporating any or all of these waste heat sources are possible, depending upon equipment costs, pumping costs, requirements of the process using the recovered heat, engine duty cycle, engine-generator size, etc. a. Diesel steam heat recovery systems are principally of two types, those with complete (or nearly complete) return of condensate, and those requiring 100 percent makeup. A typical example of a system with condensate return is shown in Figure 3.7-3. Where condensate return is possible, it may be practical to operate the engine jacket water system at a sUfficiently high temperature to produce steam in the flash tank, as shown in Figure 3.7-3. However, the engine should be designed for this high temperature operation since it could adversely affect the engine's useful life and operation. When complete makeup is required, it will be necessary to operate the jacket water loop as an isolated system or to use treated makeup water to avoid corrosion or scale in the engine jackets (Ref. 2). b. Diesel hot water heat recovery systems are, similar to steam systems, of two bas ic types: (1) where the water is used in a once-through system, and (2) where there is complete, or nearly complete, return of the heat recovery water from the process. Depending on the amount of heat required, the equipment can be arranged to recover the heat from the engine jackets only. This type of heat recovery can usually be utilized without expensive equipment because hot water can be circulated directly to the process without an intermediate heat exchanger. A typical B.3-36 • • • -• .. -.. • - .. .. • .. • .., ..... diagram of this arrangement is shown in Figure 3.7-4. If more heat is required, the jacket water, on leaving the engine, can pass through an exhaust gas heat exchanger, thereby recovering part of the exhaust waste heat. c. Diesel air heat recovery usually is accomplished by circulating heated jacket water through radiator-type heat exchangers. Cool air is blown through the radiator, transferring the diesel's waste heat to the air. The warm radiator outlet air is then used directly in a space heating system. A typical schematic of an air heat recovery system is shown in Figure 3.7-5. As with the diesel hot water system, exchanger can be rejection. if extra heat is required, an exhaust gas heat used to supplement the jacket water heat All of the cogeneration systems discussed in this section will require supplemental heating if process heat demands exceed the amount of heat recoverable from the waste heat source. Conversely, for diesel engines, supplemental cooling must be provided if the cooling requirements of the engines exceed the total heat demand. 3.7.2 State of Technology The technology of cogeneration, and its implementation, has existed since the turn of the century. Historically, if reliable utility-supplied electrical power was not available, industry generated their own electricity and process steam, although not necessarily by cogeneration. Until recently, the availability of relatively inexpensive oil and gas, coupled with the construction of increasingly efficient and reliable utility power plants, has discouraged the growth of cogeneration. The gas turbine topping cycle represents a well established and reliable configuration, with components available in the small sizes required for the Bristol Bay region. Components that make up the diesel topping cycle are also available in small sizes. The steam turbine topping cycles are B.3-37 based upon proven, highly reliable technology for which there exists a large body of operating experience. However, they are not well suited for installations smaller than 1,000 kW. 3.7.3 Technical Restraints None identified. 3.7.4 Constructibility The major plant components for the diesel topping cycle and gas turbine topping cycle would be small enough to be pre-packaged and barged to the Bristol Bay region. Depending on size, (i.e., boiler, turbine-generator, and pre-packaged units or field-assembled. the steam topping cycle components feedwater heaters) can be either 3.7.5 Operating and Maintenance Aspects Operating and maintenance requirements for the steam topping cycle are similar to those of a small steam electric plant. However. operation is complicated by mismatching and variations in process steam demands versus electrical loads. Similar complications exist for the gas turbine topping cycle and diesel engine topping cycle. 3.7.6 Regulatory Restraints and Environmental Considerations There are no regulatory restraints associated with cogeneration alone. Cogeneration is viewed by most regulatory agencies as a favorable way to increase conventional plant design effectiveness. If the heat input to a generating station is not increased to accommodate cogeneration, One of the technology is cogeneration the environmental impact will not be significantly altered. major issues that affects the acceptance of cogeneration environmental impact; the environmental implications of must be determined on a case-by-case analysis of local B.3-38 - .. ., .. .. .. .. .. --- • .. .. - • - • • conditions and on both federal and state environmental policies. New industrial cogeneration facilities that sell at least one-third or more of their potential electrical output capacity or at least 25 MW of electricity fall under EPA regulations which require new facilities to use the best demonstrated continuous emissions reduction system. 3.7.7 Regional Restraints The regional restraints apply primarily to the availability, transportation, and storage of fuel (coal, oil, and gas). Problems related to fuel supply are similar to those discussed in Section 3.2. 3.7.8 Conclusions Cogeneration, the combined production of power, either mechanical or electrical, and useful thermal energy such as process steam, is more efficient than the separate production of power and thermal energy. The type of cycle utilized is dependent upon the size of the cogeneration plant and the ratio of electrical or mechanical power to process heat requirements. Cogeneration plants should be considered for the coincident generation of electrical power and recovery of waste heat in the Bristol Bay region. B.3-39 .-----------------------------------------------------------------------------------------~~ - COMBUSTION TURBINE TOPPING CYCLE STEAM HEAT RECOVERY AIR WASTE HEAT RECOVERY BOILER GAS TURBINE EXHAUST _P!!9£E S.!. _ -+ STEAM PROCESS CONDENSATE & MAKE-UP ELECTRIC GENERATOR W ASTE HEAT RECOVERY FIGURE 3.7-1 ... N :( ~------------------------------------------------------------------------------------,~ STACK STEAM TURBINE NONCONDENSING COGENERATION CYCLE SUPERHEATER f----------1 FUEL AIR r---'y---T-t><l-~ }o PRESSURE _----"--~.. * NONCONDENSING REDUCING TURBINE VALVE I BOILER ECONOMIZER r, DESUPERHEATER GENERATOR L,.J I r-----------....J I I r - - - - - - -....J I PROCESS I ,.....L - - - - ---' ----+ STEAM I I I I FEEDWATER HEATERS WASTE HEAT RECOVERY FE~~~~~R FEEDWATER PUMPS STORAGE TANKS PROCESS CONDENSATE AND MAKEUP --CD N ;c FIGURE 3.7-2---...1 DIESEL TOPPING CYCLE STEAM HEAT RECOVERY ELECTRIC GENERATOR NOTE: DIESEL ENGINE IN THIS HIGH TEMPERATURE SYSTEM, SUPPLEMENTAL COOLING WATER MUST BE SUPPLIED TO AIR AFTERCOOLER AND LUBRICATING OIL COOLER. N.C. -NORMALLY CLOSED VALVE JACKET WATER PUMP W ASTE HEAT RECOVERY r -__ ... PROCESS STEAM I FLASH TANK PROCESS -..... -CONDENSATE CONDENSATE RETURN PUMP & MAKEUP FIGURE 3.7-3 .. --------------------------------------------------------------------------------------------.,~ o DIESEL TOPPING CYCLE HOT WATER HEAT RECOVERY ELECTRIC GENERATOR DIESEL ENGINE N.C. -NORMALLY CLOSED VALVE SURGE TANK PROCESS L---------------~------~HOT JACKET WATER PUMP LUBRICATING OIL COOLER WASTE HEAT RECOVERY WATER DRY HEAT EXCHANGER II (RADIATOR) PROCESS RETURN ..... -(COOL) WATER & MAKEUP N III '---------------FIGURE 3.7-4----.. r---------------------------------------------------------------------------------------------~~ DIESEL TOPPING CYCLE HOT AIR HEAT RECOVERY ELECTRIC GENERATOR SPACE HEATERIS) DIESEL ENGINE N.C. -NORMALLY CLOSED VALVE LUBRICATING OIL COOLER JACKET WATER PUMP DUCT TO SPACE HEATING t t t t t W ASTE HEAT RECOVERY HOT WATER COOL RETURN WATER o N .. i FIGURE 3.7-5--.a 3.8 WIND ENERGY 3.8.1 General Description Wind energy can be harnessed with commercially available wind turbines to produce electricity. There are approximately 50 manufacturers of wind generators in the United States today and an equal number overseas. These machines range from experimental first generation units to well-proven production models, in the small sizes, with several years of operating experience (Ref. 16) . However, the commercially proven wind machines in Alaska are all less than 4 kW in size. A few of the 10 kW systems have been installed in Alaska, but their performance remains questionable. There are many factors that affect a machine's wind generating potential. The rotor-swept area (the area of windstream intercepted by the wind turbine) and the wind velocity are two major factors that affect power output. Since wind velocities increase with height above the ground, tower elevation is also an important consideration in wind generating potential. Wind turbine rotors spin around Conventional Horizontal wind turbines such Axis Wind Turbines either as the (HAwT) . a horizontal or Dutch windmill Others, such as about a vertical axis ("eggbeater") Vertical Axis turbines rotate Wind Turbines (VAWT) . Both HAWT and and VAWT illustrated in Figure 3.8-1. vertical axis. are known as the Darrieus are known as machines are Conventional wind turbines employ one-, two-, or three-blade rotors transverse to the wind and normally house the generator and transmission on top of the tower supporting the rotor. Conventional wind turbines must turn (yaw) about the tower axis in response to changes in wind direction. Vertical axis wind turbines, of which the Darrieus "eggbeater" turbine is the most familiar, have two inherent advantages over their horizontal axis counterparts. First, the vertical axis of rotation allows the generator and gear train to be mounted at ground level, which aids servicing. B.3-40 Second, VAWT's are omnidirectional, they are able to accept the wind from any direction without swinging the entire rotation assembly about the tower axis. Since wind velocity is variable and intermittant, wind generating can not supply a continuous power output. As electricity is generated by wind turbines, it must be either integrated with a power system, stored, or a combination of the two utilized. Several methods of storing electricity generated by the wind are as follows (Ref. 16); a. b. Batteries -Lead-acid batteries are by far the most common type of energy storage device for wind electric systems. Deep cycle batteries are preferred. These batteries are designed to sustain repeated deep discharge without damage, and are commonly used in forklifts and golf carts. Batteries for wind electric systems are costly, so it is desirable to use them under conditions which will result in their most efficient operation and longest life. Consequently, batteries as a storage medium are best suited for s i tuat ions where t he owner can provide the proper care, such as individual cabin or homestead use. Batteries require the periodic addition of water and must be protected from freezing. The owner must also see to it that the batteries are never charged or discharged at too high a rate. Battery sets must also be fully charged periodically to equalize the charge on the individual cells. Keeping batteries from overheating can also be a problem, but this will rarely be of concern in the Bristol Bay area. For loads larger than a single homestead, the number of cells involved becomes overwhelming. The maintenance costs alone for lead-acid batteries would be prohibitive in a utility-sized battery bank used for anything other than very short-term storage. Significant advances are being made in battery technology; however, it may be as long as ten years before they become commercially available and inexpensive enough to use for a village-scale storage scheme. Compressed Air Storage -Compressed air storage involves using all wind-generator power not immediately needed for other uses to B.3-4l ., .. lit ... .. .. .. .. .. .. • .. .. .. • .. • .. c. operate an air compressor that pumps air into either a metal tank or an underground storage vault. To retrieve the power, the process is reversed; the compressed air drives a motor-generator combination. For some uses where the reconversion to electricity would be unnecessary, the compressed air could be used to drive tools and machinery directly. Air tools, for example, are commercially available. The principle drawbacks to compressed air are its low conversion efficiency and the large volume of storage required. In the study area, no known naturally occurring storage exists, which is considered a prime requirement to using compressed air storage on a village scale economically due to high costs of constructed storage. Pumped Storage Hydroelectric Pumped storage hydroelectric generation is accomplished by pumping water from a lower to an upper reservoir with an electric motor and pump when spare energy is available, and using this stored water to generate electricity with a turbine-generator to meet peak energy requirements. In most pumped storage hydroelectric systems, the pump and the turbine are one and the same machine whose operation is reversible as are the motor and generator. A suitable site must be found with locations for upper and lower reservoirs and a differential head. Generally these facilities are large, several hundreds of MW, to take advantage of economy of scale. Smaller facilities do exist, however; these have been combined with existing conventional reservoir facilities. d. Hydrogen Storage -Hydrogen storage involves electrolyzing water into hydrogen and oxygen gas, and storing the hydrogen. The flammable hydrogen can then be used as a fuel in a conventional motor-generator system or in a fuel cell system. The fuel cell is described in more detail in Section 3.20. Hydrogen storage appears to be a reasonably good storage method in theory, although it cannot match the efficiency of a conventional battery. B.3-42 At the present time, few, if any, of the major components, including electrolyzers, hydrogen storage systems, fuel cells, or hydrogen-fueled motors, are readily available. These components would be expensive to manufacture specifically for use in this application. e. f. Flywheel Storage Flywheel storage is accomplished by using excess power in an electric motor to spin a flywheel; the energy is thus stored as kinetic energy. Later, the spinning flywheel can be reconnected to the motor, which will then generate electricity by withdrawing the stored kinetic energy. Like hydrogen systems, flywheel storage is in the developmental stage. Research is being done for applications in many fields, but no practical systems are commercially available. Thermal Storage heaters or a heat insulated container. Thermal storage uses electrical resistance pump to warm up a material in a heavily This hot material can then be used later to boil a fluid and produce an expanding vapor which can then be used to drive a conventional turbine-generator. A thermal storage system would have a low efficiency for electrical power production; thermal storage is more practical when heating is the end use because less energy is lost during transfer from storage. Wind systems have been des igned and built based on the principle that surplus power be used to heat water, which can later be used for domestic hot water uses or for a hot water space heating system. This, of course, is indirect electric heating, which is almost always more expensive than any other means of heating. As a result, this is not usually a cost-effective idea unless the wind generator is generating power which otherwise would be wasted. Surplus electricity could be used to run a freezer. This could be advantageous for a community freezer in a village during the summer when fish and game need to be frozen for the rest of the year. B.3-43 .. ., ., .. .. .. • .. .. -• .. .. -.. .. .. ., • -.. -.. .. • .. .. • -.. .. .. II' More details regarding wind energy are available in Appendices A.6 and D of the Interim Report. 3.8.2 State of Technology Wind generators are commercially available in sizes up to 300 kW. All wind turbines installed in Alaska to date have been in the 30 kW and smaller range. Medium-sized machines in the 50 to 250 kW range have been installed in Canada and the lower 48 states. Although the medium-sized wind turbines are not in mass production, they have logged a considerable number of operating hours, and data on performance and reliability is available (Ref. 16). Large machines, generating 1 to 4 MW, are being demonstrated for possible future production. Several manufacturing and aerospace firms have entered the large wind turbine market. Most of these firms' efforts were tailored to the U.S. Department of Energy's development program. Because of federal budget cutting, the large machine program has been sharply curtailed. Several machines are in operation but no more are planned in the public sector. Private wind farm developers have contracted with two of the manufacturers for large machines, but delivery on these orders is speculative at present (Ref. 16). 3.8.3 Technical Restraints The major technical difficulty with wind generation will be integrating it into the power system directly (no storage facilities). Wind must be used to supplement the overall grid system's load capabilities. In the Bristol Bay region, variations in base load are commonplace; coupling this with the varying wind velocities creates control problems for both wind and base load generators. These control problems are dicussed further in Section 3.8.5. 3.8.4 Constructibility The wind turbine housing, rotor, gearbox, and generator are fabricated in B.3-44 the shop and require minimal erecting the tower are the installing a wind generator. field assembly. Setting the foundation and major construction efforts associated with 3.8.5 Operating and Maintenance Aspects Wind turbines require maintenance typical to other machines with rotating drive lines. necessary. Periodic checks on the moving parts and generator would be The wind turbine can be designed to be fully automatic power production equipment for use on a utility grid. To satisfy this requirement the wind turbine control system can be capable of monitoring wind conditions, maintaining alignment with the wind, controlling rotor speed and power level, starting, synchronizing and stopping the wind turbine safely, monitoring key parameters throughout to assure that critical items are operating within specified tolerances, and providing a power dispatcher or remote operator with the capability of starting and stopping the machine. Five control systems can be provided to accomplish these tasks: a. A rotor blade pitch controller adjusts blade pitch to control rotor speed or generator power output. b. c. d. e. A yaw con~roller keeps ~he wind turbine aligned with the wind. A microprocessor controls the automatic operation of the machine including startup synchronization and shutdown. A safety system monitors turbine shutdown signal detected. system operation and provides a wind when out of tolerance performance is A remote control and monitor system provides a remote operator with the ability to enable the microprocessor to start or stop the wind turbine and to monitor machine performance. B.3-45 .. • .. .. .. .. .. .. III' .. .. ... .. -., -.. .. ... • • • .. .. To operate the wind turbine, an operator sends a start-up command which activates the microprocessor located in the control building at the base of the wind turbine tower. The microprocessor then monitors the wind speed and when this value becomes high enough to generate power, the nacelle is aligned with the wind and the start-up sequence is initiated. Once the generator has been synchronized with the utility grid, the wind turbine continues to produce power until normal operation is stopped by either high or low wind speed or by an out of tolerance condition detected by the microprocessor or the safety system. During normal operation, the yaw system keeps the turbine aligned with the wind and the blade pitch controller limits the power output. wben the wind speed either exceeds the high wind limit or drops below the low speed limit, the microprocessor initiates the shutdown sequence. Also, the safety system is capable of shutting the machine down independent of the microprocessor when a dangerous condition is detected. Operational impacts of wind energy conversion systems (WECS) interconnected with utility electrical systems are of two basic types: (1) those for WECS with energy storage provisions, and (2) those for wECS without energy storage provisions, which are tied directly into the power grid. These are discussed separately below (Ref. 17, 18, 19, 20): a. WECS without energy storage - A number of studies have indicated that significant penetration of wind energy into utility systems is likely to have adverse operational impacts. In particular, penetration levels must be coordinated with system response and dispatch requirements. Additionally, variable winds increased need for spinning reserve requirements adequate load following and frequency control. may cause an to achieve Common utility operating practice is to schedule unit commitments on a 2-to 3-day planning horizon, according to near term load projections, and then dispatch the units on a 10-to 30-minute basis. For the Bristol Bay area this may not be the case, since relatively small diesel units are more common as compared to a B.3-46 large central station type of utility. The full impact of wind turbine penetration on such practices has not yet been fully investigated. b. WECS with energy storage -For any given utility or power dispatch region, the type and size of conventional generation mix and the magnitude and variability of the wind resource within the area will define the point where increased penetration of wind turbines becomes significant. At this point, load following and frequency control requirements become large enough that system response becomes non-economical. Some interesting conclusions from a number of studies are: o o o To limit frequency and area control error deviations, rated wind turbine penetration should be limited to a few percent of the utility's system capacity. Minute-to-minute ramping and daily frequency excursion limits will require wind turbine operating restrictions and/or increased spinning reserve. For a case study, spinning reserve and load following requirements increased linearly with respect to penetration of intermittent capacity. This increases production costs and eliminates energy and capacity credits from wind turbines. Clearly, operational issues of introdUCing WECS into utilities are system and site-specifiC. Further study is required to identify and confidently resolve the problems posed by these issues. 3.8.6 Regulatory Restraints None identified. B.3-47 .. .. iii> ... ... ... ... ... .. .. .. • .. .. ... .. .. 3.8.7 Environmental and Regional Considerations An area of relatively high wind power density exists in the Bristol Bay region, with the best utility-size wind farm sites being King Salmon, Egegik, Naknek-South Naknek, and Igiugig (Ref. 16). Local terrain, land use, ownership, soil conditions, and proximity to transmission lines or electrical demand are important general factors to be considered in site selection. Other major factors to be evaluated in site selection are: a. Safety - a clear zone is required around the wind generator site to allow for the possibility of a blade breaking or flying off the turbine. A less likely occurrence, the tower falling over, must also be considered. Ice thrown from the blades is also a significant safety hazard. b. Radio and televis ion interference - a wind turbine with metal blades will cause television and radio interference. This int:erference is primarily with high frequency signals, and is caused by the rotating blades deflecting the high frequency waves. Thus, to avoid interference the wind turbine should not be placed between the sender and receiver, such as bet:ween ham radio operators, or between a television satellite and its ground receiver. Proper wind turbine siting can eliminate interference problems. c. Noise the blades of modern wind turbines are designed to prevent creation of sonic booms when they rotate. However, noise levels of wind machines and air pulses created by them must be taken into account. Aesthetics and interference with airplane and bird flights are also site selection factors worthy of mention. The iCing of wind turbine blades can be a problem in the Bristol Bay region: when the wind is not blowing, ice can build up on the stationary B.3-48 wind turbine blades. The resumption of wind will start the blades turning, causing ice shedding on portions of the blades. The ice will shed unevenly from the blades, causing imbalance and increasing vibration as the turbine picks up speed. This phenomenon can destroy the wind turbine. Two measures commonly taken to reduce or prevent turbine damage are: (1) design the turbine blading to withstand the vibrations, or (2) provide shutdown of the turbine upon reaching a certain vibration, or ice buildup level. Ice can also accumulate on the rotating wind turbine blades, creating the same problems as described above. Again, either ice detectors or vibration indictors can be used to provide the system shutdown signal. 3.8.9 Conclusions Wind power is a renewable energy source that can supplement regional power supply; it is not suitable for base load application. The amount (penetration) of wind energy tied into the Bristol Bay utility systems must be carefully evaluated to avoid major control problems. \Vind energy should be given further consideration in the Bristol Bay Regional Power Plan. .. .. .. .. .. .. .. .. • ., .. • .. .. .. .. .. .. ., ., ., .. .. .. . ' CUTAWAY VIEW OF NACELLE, SHOWING GENERATOR TOWER-....... ROTOR BLADE HORIZONTAL AXIS WIND TURBINE ~-TIEDOWN ~-..... --... -GENERATOR VERTICAL AXIS WIND TURBINE ROTOR BLADE FIGURE 3.8-1 ... ID -~ 3.9.1 A hydroelectric falling water 3.9 HYDROELECTRIC POWER generating station converts the energy into electrical energy. The water replenished by natural precipitation and no fuel available from is continually is required. Hydroelectric energy is a renewable resource. The water is harnessed by a dam or diversion, which directs water into a conveyance system such as a penstock or tunnel and then to a turbine where water energy is converted to the mechanical work of turbine rotation. The water is then returned to the stream or river. The rotation of the electric generator coupled to the turbine creates electricity. Since fuel is not required to generate electricity, as in a diesel or other fossil-fuel generating station, the hydroelectric generation of electricity is not affected by rising fuel costs. Once the struct:ures are constructed to contain and transport the water to the turbines and house the turbines and generators, and the appurtenant equipment is installed, the only additional costs are operation and maintenance. In hydroelectric generation, water drives turbine blading and forces the turbine to rotate. Once past the turbine, the wat:er returns to the environment with only an insignificant change in temperature or chemistry. 3.9.2 State of Technology Hydro power stations have been in existence for hundreds of years. Early hydro power stations were primarily used to do mechanical work, grinding wheat into flour or making wool. With the advent of electric generation in the last hundred years hydro power stations have become hydroelectric power generating stations. The technology is highly refined. There are two basic types of turbines used in hydroelectric power generating, impulse and reaction. In an impulse turbine, a free jet of B.3-50 water impinges on the revolving element of the machine that is called a "runner", which rotates in air. In a reaction turbine, runner rotation takes place as a result of water flowing through the runner under water pressure in a closed chamber. The energy delivered to both types of • .. ., .. turbines results from the momentum of the water through a dynamic force .. exerted on the runner or rotating element. The impulse turbine is sometimes called a tangential water wheel or Pelton wheel. This type of turbine develops all its energy in the form of kinetic energy delivered by a jet of water impinging against the runner. The runner is made up of split buckets which are mounted around the circumference of a central spider which rotates a shaft. The shaft, in turn, is connected to the generator for producing electricity. The water jet is normally controlled by a needle valve which adjusts the water flow. The Pelton-type turbines can be mounted vertically or horizontally and can be driven by one or more jets of water. Pelton turbines are normally used in a head range of 200 to 5,000 ft, but can be used in lower heads. There are two types of reaction turbines, Francis and propeller. There are several adaptations of propeller machines. In the usual Francis turbine, water enters a scroll case and moves to the runner through a series of guide vanes with contracting passages which convert water pressure head into water velocity head and drive the runner and shaft. The scroll case is a steel pressure vessel which distributes water from the penstock around the turbine runner. Guide vanes are steel wings placed in the scroll case to direct the flow of water to the turbine runner. The runner is that portion of the turbine which is turned by the pressure of the water. which in turn is connected to the The runner is connected to a shaft generator. The shaft drives the generator, producing electricity. The vanes in a Francis turbine are usually adjustable, controlling the quantity and direction of ~he flowing water. The Francis turbine is normally mounted vertically; however, horizontal axis machines are sometimes used. This type of turbine is normally used in head ranges of 70 to 2,000 ft. B.3-5l .. .., .. .. .. .. ... ... .. ... .. ... -.. .. ... .. .. ... • Common propeller turbines are designed to have an axis of rotation that is either horizontal, s lightly inclined, or vertical. The usual runner has from four to eight blades mounted to a drive shaft hub that is coupled to the generator. The blades and hub normally look very similar to a marine propeller. Several specific adaptations are common to the propeller turbine. A Deriaz type turbine is an adjustable-blade diagonal flow machine where flowing water is directed inwards as it passes through the blades. A Kaplan turbine is a propeller turbine with movable blades whose pitch can be adjusted. An axial-flow turbine-generator unit is set in line with flowing water. This type of unit may have the generator outside the water conduit or inside the water conduit. The bulb turbine is one type where the generator is set ins ide the water conduit, while the inclined-axis machine is of the type where the generator is mounted outside the water conduit. Propeller turbines are normally used in head ranges of 10 to 150 ft. Energy conversion efficiency of a hydroelectric power generating plant depends on several controlling factors, but relates mainly to the efficiency of the turbine, generator, water conduit system, and main electrical transformer, and also to station service needs. Overall efficiency conversions ranging from 80 percent to 85 percent are typical of hydroelectric power installations. Another type of turbine utilized in modern generation technology is the pump-turbine. This turbine is designed to operate in a pumping as well as generating mode. This technology allows hydroelectric generation during peak load periods and pump storage during off peak load periods. 3.9.3 Technical Restraints None identified. 3.9.4 The turbine and generator components are usually preassembled in the manufacturer I s shop to the extent possible and shipped to the project B.3-52 site, where the components are fully assembled into opera~ing units. Small packaged units can be shipped entirely shop-assembled ready for operation. If required, and depending on shipment limitations, the units can be shipped in parts for assembly at the project site. The construction of dams, diversion works, intakes and outlet works, tunnels, penstocks, and the powerhouse are of conventional materials, soils, rock, concrete, and steel. 3.9.5 Operating and Maintenance Aspects The operating and maintenance costs of a hydroelectric station are small compared with fossil and nuclear generation. Hydroelectric equipment is of simpler and more sturdy design; thus, overall operating and maintenance expenses are reduced. Tne hydroelectric equipment consis~s of a turbine, governor, generator, transformers, breakers, and auxiliary support mechanical, electrical, and control devices. The operating equipment can be in-plant or remote-controlled. Depending upon plant design size and client desires, operating personnel may be required to be in the plant from B hours per month to 24 hours per day. Automation allows remote operation and requires in-plant inspection for control of settings, equipment lubrication, and other minor support tasks. Large capacity multi-turbine installations normally require 24 hour in-plant operation, usually consisting of monitoring operating equipment and personnel availability for problem assessment. ~laintenance of large multi-turbine installations is a crew effort requiring the full time services of many disciplines. Smaller machines can be maintained satisfactorily by a mechanic and an electrician/electronics technician on an lion-call II basis. Access maintenance and operation should be sustained year-round; thus, station should be located to allow accessibility by air or land. B.3-53 for the .. • .. .. -- iii. .. .. .. • .. .. Large capacity, low head turbine-generators are physically large and require an in-plant bridge or gantry crane for installation. The hoisting machinery is normally permanently installed for use in maintenance operations. Smaller installations do not require permanent in-plant crane capacity, but are designed to allow mobile crane access for major overhaul and turbine maintenance. High head Pelton machines are presently produced in the 200 to 5,000 kW range, which requires a limited hoisting capacity. This is because the turbine runner is lightweight and small in diameter, allowing easy access and removabil i ty. This type of turbine requires a minimum capacity in-plant hoist, usually a chain-fall or electric winch. Existing installations which allow scheduled maintenance to be performed during seasons permitting ease of access have proven hydroelectric power stations very reliable, with predictable maintenance operations. 3.9.6 Regulatory Restraints Hydroelectric power plants are customarily licensed by the Federal Energy Regulatory Commission (FERC) by authority of the Federal Power Act. All phases from inception through plant operation are closely monitored by this federal agency, who would act as a lead agency in coordinating permitting and licensing aspects with federal, state, and local agencies. An application for preliminary permit is normally made once a site assessment has been completed. This permit allows the applicant to secure priority of application for a project license under Part I of Lhe Federal Power Act. Concurrently, the permittee obtains the data and performs those acts required to determine the feasibility of the project and support an application for a license. The preliminary permit may be amended or cancelled, or priority may be lost, as determined by the Commission. An application for license is normally made once the project is proven feasible. This application shows the design data and supportive information necessary for the Commission to authorize project construction. The applicant is granted a license at the B.3-S4 conclusion of the project construction, and once the plant is in operation. Should the licensee desire to make a change in the physical project features or its boundaries for the betterment, conversion, or abandonment of the project, the licensee must prepare an application for amendment of license. Annual charges are assessed by the Commission against each licensed project to reimburse the United States for the cost of the administration of the Federal Power Act. The process of permitting and licensing guarantees that a11 interested citizens, groups, and federal, state, and local agencies will have opportunity to comment, intervene, and present information in the public interest. The process requires that the applicant and licensee comply with federal, state, and local laws and regulations. This part of the process is site specific and its particular requirements can only be addressed upon identification of the site. The specific site needs will be addressed as required and would be coordinated through the offices of the Alaska Permit Information Center. In its license application, the applicant presents to FERC an environmental report prepared in consul tation with local, state, and federal agencies with expertise in environmental matters. The following specific areas must be addressed: a. b. c. d. e. f. g. General description of locale Report on water use and quality Report on fish, wildlife and botanical resources Report on historical and archeological resources Report on recreational resources Report on land management and aesthetics List of literature that was consulted in the preparation of the environmental reports .. .. .. .. .. .. .. .. .. • .. .. .. .. In many respects, the FERC process is a benefit to the developer. The .. procedures and requirements are clearly defined and the whole process can be carried out in a systematic and orderly manner. B.3-55 • .. .. .. .. 3.9.7 Environmental Considerations Some potential environmental impacts can result from the operation of a hydroelectric plant. These impacts are identified and resolved prior to the project construction by the licensing process required by FERC. The major environmental considerations are: a. Fish and Marine Invertebrates -The lakes, rivers, and streams support populations of anadromous and resident fish. The free passage and spawning of the fish must be preserved to maintain this resource. b. Wildlife -The areas surrounding the lakes, rivers, and streams support a wide variety of mammals and birds. The banks of the water body provide a source of food and habitat which must be addressed prior to raising the water level. c. Vegetation -Vegetation is also inundated when the water level is raised. The effect can be two-fold: root rot and physical inundation. Root rot is caused by raising the water table into the root zone. In cold weather regions the water table is usually near the surface, which minimizes this impact. d. Land -Due to operations of the reservoir, some acreage of land will be lost due to inundation. Land lost due to the raising of the reservoir is identified as to use in the environmental impact statement required during the FERC licensing process. e. Socioeconomic Considerations -Population increases and changes to the economy, employment, and earnings which may result from the construction of a hydroelectric project must each be addressed. These may be minimal, as with a small scale run-of-river installation or may be large, as with the construction of a major development. Each site must be investigated and each consideration must be addressed based on the type of installation proposed. B.3-56 f. Archeological and Historical Cons iderations -Archeological and are investigated. Burial and sacred grounds historical sites are identified. Community discussions are held and historical research is conducted in order to obtain an assessment of each aspect. process. Each site is addressed during the FERC licensing 3.9.8 Regional Restraints Cold weather, accessibility, constructibility, availability of construction material, and seismic aspects relating to the design of a hydroelectric project present problems which must be addressed and resolved prior to actual construction. Geological investigations are required to identify construction material sources, geotechnical data, faults, weaknesses in the rock, unique soil formations, any soils subject to liquefication and frost susceptibility. The structural design must incorporate the particular requirements from the geotechnical investigation to assure safe and stable project structures. Ice formation on gates and other hydraulic project operations and may affect the equipment project can affect the safety. Design redundancies are required to provide space heating, and other means are required to assure reliable operation during winter months. However, the construction and operation of hydroelectric power plants in cold weather regions is common with favorable performance. 3.9.9 Conclusions With proper investigations, hydroelectric development offers a reliable alternative to other forms of generation and should be considered further as a source of energy for Bristol Bay. B.3-57 .. .. • lit .. • .. • • ., • ., ., • ., II. • .. .. 3.10 TIDAL POWER 3.10.1 General Description Oceanic tides are caused by the gravitational attraction of the moon and, to a lesser extent, by the sun upon the oceans of the earth. The magnitude of tidal variations is dependent upon the relative positions of the moon and sun. The highest tides occur along the shore, whereas mid-ocean tides are very small (on the order of 2 feet). Local tidal fluctuations are also affected by the earth's kinetic energy and solar heat energy (although the extent of these effects is a matter of debate among scientists), and by resonant conditions peculiar to the tidal estuaries. Tidal power is similar to other conventional hydroelectric energy sources in that electrical energy is produced by water flowing from a higher elevation to a lower elevation through a hydraulic turbine. However, tidal power's primary differences lie in creating the hydraulic elevation differences utilizing tides. This is accomplished by damming an estuary or bay (adjacent to the ocean), and alternately filling and emptying the enclosure through hydraulic turbines. A major difficulty in harnessing tidal energy is in providing a controlled electrical output to serve system load demands from a source of energy which continually fluctuates. There are two tidal cycles approximately every 24 hours; that is, two high tides and two low tides. However, each high tide varies somewhat from the preceding and succeeding high tides, and each low tide varies somewhat from the preceding and succeeding low tides. Thus, the two daily tidal ranges are different. Furthermore, tides also vary from day to day, week to week, month to month, and even year to year (Ref. 21). No electrical power generation capability is available when the height difference between the tidal power basin water level and the ocean is too small. Design concepts must be developed to match the continually cycling water levels to the system electrical demands or to store the energy in some manner. B.3-58 A number of tidal power schemes have been developed to take advantage of the ocean' s tides. The simpler configurat ions are preferred today, and those receiving most consideration are (1) the single basin-single effect, (2) the single basin-double effect, and (3) the double basin-single effect. The three basic design concepts are discussed in more detail below (Figure 3.10-2): a. The single basin-single effect design is the simplest of all schemes. A dam is constructed across an estuary to create a single pool. The units are designed to operate in only one direction, preferably on the ebb tide. At high tide, the filling .. ., .. r. gates are closed; when sufficient differential head is created by ~ b. c. the falling tide, the units can begin operating. .. The single basin-double effect scheme also involves the construction of a dam across an estuary to create a single pool. The powerhouse and sluice gate structures usually are part of the dam. The units will operate in both directions of flow during flood and ebb tides. In the double basin-single effect installation, there is an upper and a lower pool, with a powerhouse located between them. There are filling gates between the sea and the upper pool, and emptying gates between the lower pool and the sea. With a two-pool scheme of this type, it is possible to produce power continuously, although the amount of power will vary as the head differential between the pools changes. The single effect flow is always from the high pool into the low pool. The upper pool is reE lIed during each flood tide by opening the filling gates, ""hile the lower pool is drained during each ebb tide by opening the emptying gates. The primary advantage of a two-pool scheme is that it can provide a certain amount of dependable capacity and firm energy to suit system load requirements, regardless of the time of day and tidal B.3-59 ., .. .- • • .. - ... ., • •• conditions. However, additional investment costs are incurred due to the need for more dams and gate structures when compared with single-basin schemes (Ref. 21). Pumping in the reverse direction may be a desired supplement for both two pool and single pool schemes to increase operating head and, consequently, power output. This would allow extra water to be pumped into the basin near the end of the filling cycle or out of the basin near the end of the emptying cycle. The extra water, pumped into, or out of, the basin against a low head, could be released through the turbines at a higher head so that a net gain in energy is achieved. Pumping would be particularly desirable under "neap" tide (a tide of minimum range, depending upon the moon's and sun's gravitational effects) conditions. Only the double basin concept, or variations thereof, can provide continuous power and some measure of dependable capacity without the use of auxiliary generation and/or energy storage (Ref. 21). The two best places in the Bristol Bay region for tidal power development are the Dillingham area (mean tidal range 15.3 ft at nearby Clark's Point) and the Naknek River entrance (mean tidal range IB.5 ft) (Ref. 22,23). 3.10.2 State of Technology Modern tidal power plants are in operation in France, Russia, and China and a pilot project is currently under construction at Annapolis Royal on the lower reaches of the Annapolis River, Nova Scotia. The technology necessary to design, construct, and operate a tidal power facility is available in the United States, and has been demonstrated in the previously mentioned countries. Irrespective of the technology's status, modern tidal electric power generation remains in its infancy, primarily due to its unfavorable economics. Tidal power generation requires longer dams and physically larger equipment and structures than comparably sized conventional high head hydroelectric plants. Economy of scale dictates that tidal power plants be very large, in the order of several hundred MW, B.3-60 to bring costs per kWh down to acceptable levels. However, comparative economics are improving somewhat as the cost of rises (Ref. 24,25,26). tidal power fossil fuel Conventional hydroelectric power plants contain mechanical and electrical equipment very similar to that required for a tidal plant. The primary difference between conventional and tidal hydroelectric equipment is the relatively low head available at tidal plant sites. Because of the low operating head, extremely large volumes of water must be discharged through the hydraulic turbines to develop the electrical energy. There are four types of configurations, each involving propeller turbines, thought to be suitable for use in tidal plants. These consist of: a. b. Vertical shaft units, the direct connected (Figure 3.10-1) or conventional Kaplan turbines, in which generator is located above the turbine Horizontal shaft bulb units with the generator components installed in a steel bulb surrounded by the turbine water passages (Figure 3.10-1); horizontal shaft bulb units are currently preferred for tidal plants, since they provide maximum operating efficiencies and the lowest costs for any proven equipment design. c. Tubular units with either sloping or horizontal shafts having a generator outside the fluid stream, either upstream or downstream of the turbine (Figure 3.10-1) d. Rim-type units which consist of a horizontal shaft turbine connected to a rim-type generator (a generator which surrounds the turbine blades, with a seal to isolate the electrical parts) that operates in the dry (Figure 3.10-1) Reversible turbines basin tidal plant) provide greater operating flexibility and increase the annual electrical (for a single power output. B.3-61 .. .. - ..- .. .. .. .. III> • .. III' :w • -.. .. - lit lilt • .- l1li l1li. However, reversible units are also more expensive, require more maintenance, and require more filling gates in tbe tidal dam complex. Unless reverse pumping offers definite economic advantages, it is better to simplify the turbine design by making it nonreversing. Further reduction in turbine costs can be achieved by using fixed blade units instead of adjustable blade units, with only relatively minor reductions in overall electrical power production (Ref. 21). 3.10.3 Technical Restraints Tidal power plant turbine-generators operate at low speeds, and thus have relatively large physical dimensions. The dimensions of large turbine generators (large in comparison v.'ith equally rated conventional high head hydroelectric turbine-generators) are reflected in the higher civil cost of providing more extensive structures to house them. In addition to the increased powerhouse civil costs for the large units, the units themselves will be expensive compared to conventional higher head hydroelectric units. The low available heads necessitate a high water discharge rate to generate electricity, resulting in large dimensions for water passage and high cost per kW for equipment. 3.10.4 Constructibility The construction of a dam that contains a powerhouse across the mouth of an ocean inlet or cove would be challenging. Once the bay is enclosed by the dam, it must be able to either hold water in or keep water out, as the ocean level varies with the tides. Sandy or silt laden soils (Section 3.10.8) dictate special construction practices to seal the bay. such as excavation to impermeable soils or lining the bottom and sides of the bay, both of which would be very expensive. Available (rip-rap) geologic maps for the tidal miles east-northeast of of the Bristol Bay region indicate that rock dam construction is available approximately 20 Naknek or approximately 20 miles north of B.3-62 Dill ingham . These are the two closest sources of rock to the potential tidal sites; however, further geological investigation would be required if it was decided to proceed with a tidal power plant. Roads would have to be built to the potential rock quarry at Naknek, but there may be direct river access to the potential quarry north of Dillingham. This is another substantial expense to be considered in the construction of a tidal plant. 3.10.5 Operating and Maintenance Aspects The large amounts of submerged metal in sea water require extensive cathodic protection systems. To complicate matters, the submerged metal structures are complex in shape and are usually constructed of dissimilar metals. This combination plus the requirements that there be minimal maintenance on the cathodic protection system requires that the protective system be efficiently and effectively designed and constructed. The technology to provide adequate cathodic prot.ection for the tidal facility is well established. Tidal power is not readily integrated into an electric system for several reasons. The time of high and low tide cycles advances approximately 50 minutes each day, and it is only coincidental if the time of tidal power product.ion is in step with system demand. For single-pool schemes, there are times when no power is being produced. Even with the most complex multi-pool scheme, the tidal power output is not constant, although some level of output can be maintained cont.inuous1y, if desired (Ref. 27). The ability of any electric system to utilize raw tidal energy efficiently depends on the nature of the load pattern, the amount of tidal energy being generated as compared to the total system generation, and the relative amount of energy and capacity being produced by the various types of generating equipment available in the system (Ref. 27). Operating schemes must. be developed to integrate all these factors and effectively utilize the power generation facility. B.3-63 • .. - .. .. .. • --.. ... .. • .. '. • .. .. ., 3.10.6 The steps necessary to license a tidal power station are essentially the same as those for conventional hydroelectric facilities. The authority of the Federal Energy Regulatory Commission (FERC) would extend to the tidal facility, and FERC would be the regulating federal agency in the licensing effort. State and local agencies would also have jurisdiction controlling the project. The Alaska Coastal Management Program is one such regulatory entity which establishes coastal policies and controls development along coastal areas. 3.10.7 Considerations Tidal power projects, being oceanic or coastal in nature, differ in their effect on the environment compared to conventional hydroelectric projects, which are usually located in the middle or upper reaches of rivers and streams. The construction of a conventional hydroelectric project creates a reservoir which submerges land areas that were previous ly above water. However, tidal projects do not submerge previously dry land; they merely divide a tidal bay or estuary into parts, creating one or more pools where ebb or flood tide waters are trapped and held for some period of time (Ref. 27). One of the primary considerations for the Bristol Bay region would be the restraints on the migration patterns of anadromous fish in the tidal basin(s). In addition, vegetative cover for both temporary construction facilities and permanent plant facilities would have to be removed. The construction of the power station would involve dredging, cofferdam placement and dewatering, rock fill or gravel placement, and soil disposal. These construction activities would be harmful to marine organisms. The possible development of highways across the dams could adversely affect terrestrial organisms by increasing public access to present wilderness areas. Bay impoundment may also reduce the tidal B.3-64 wetlands available to migrating, nesting, or feeding waterfowl and spawning fish or shellfish. The pattern of sediment deposition in the tidal plant area could be affected, as could ice formation and ice flows. 3.10.8 Regional Restraints From a power generation standpoint, it would be most efficient to install a tidal facility across a river in either the Dillingham or Naknek areas in order to utilize both the tidal effects and water inflow from the river to generate electricity. However, the large runs of anadromous fish in the Bristol Bay region preclude darns across rivers or tributaries which support fish spawning. Therefore, a natural bay or estuary would have to be found close to Dillingham or Naknek which could be dammed to hold the tidal waters. An estuary could also be created by excavation, but this would be much more expensive than damming a natural bay. Assuming a natural estuary were located in either the Dillingham or Naknek area, or both, the locale may be underlain by sands, gravel, and silt formations. Further geological investigation would need to be done to determine whether the soils surrounding the estuary and upon which the darn would be built could sustain imposed structural loads and/or retain water. Presently available information (Ref. 28) indicates that the sandy-silty soil around Dillingham and Naknek could cause difficulty in the construction of the tidal plant estuary. During the winter months, icing is a problem for tidal power plant operation. Drift ice which moves with the wind and tides necessitates that the turbines and sluice gates be located well below the water surface and floating ice levels. Ice gr.eatly influences the strength calculations of the structures (and cost). Design of protective barriers to prevent damage to trash racks and gate structures will also increase project costs (Ref. 29, 30). 3.10.9 Conclusions Tidal power is not presently a viable Bristol Bay region energy resource B.3-65 • • .. - ., .. .. .. ., .. .. • .. - .. • .. .. ., ., .. due to its generation characteristics not meeting system demand requirements, ice effects, restriction of fish movements and high costs. Tidal power is expensive compared to other electrical generation technologies even when developed in large sizes. several hundred MW, to maximize economy of scale benefits. The Bristol Bay region electrical demands are much too small to justify conventional tidal power development. This technology should not be considered further in the Bristol Bay Regional Power Plan. B.3-66 r-------------------------------------------------------------------------------------------------------.. ~ .. INTAKE GANTRY HIGH POOL FLOW~ RIM-TYPE TURBINE-GENERATOR POWERHOUSE GANTRY ~. FLOW ...... LOW POOL HIGH POOL FLOW GATE GANTRY CRANE LOW POOL BULB-TYPE TURBINE-GENERATOR TUBE-TYPE TURBINE-GENERATOR GANTRY CRANE LOW POOL VERTICAL SHAFT (KAPLAN)-TYPE TURBINE-GENERATOR TYPICAL TIDAL POWER PLANTS ~-------------FIGURE 3.10-1 co -• -:( r-----------~----------------------------------~------~------------------------------------------..N > ... u _-+-_ « c.. C3 2 HOURS POWER CURVE > ... U « ..... -t---t---I!--- c.. « u 4 HOURS POWER CURVE NO SLUICES NO SLUICES, DISCHARGE (DISCHARGE THROUGH THE POWERHOUSE) THROUGH POWERHOUSE. (GENERATION FROM BASIN TO SEA) SINGLE·BASIN DOUBLE-EFFECT SINGLE-BASIN SINGLE-EFFECT OPERATING CYCLE HOURS POWER CURVE DOUBLE-BASIN SINGLE-EFFECT \I> o -• -< ~~~~~~~~~_T~I~DA~L~P~O~W~E~R~-FIGURE3.10-2~ 3 . 11 SOLAR THERMAL ENERGY 3.11.1 General Description The application of solar thermal technology for electric power generation has involved two approaches: the central receiver and the distributed collector. Passive solar energy is discussed as a conservation measure in Section 3.6. The central receiver system is intended for central station power plants, approximately 25 to 100 MW. The design consists of an array of individually controlled mirrors (heliostats) that direct the solar radiation onto a common receiver (boiler) situated on top of a tall tower. The energy is transferred to a working fluid which, in turn, is applied in a thermodynamic cycle to convert the energy to electricity. Distributed collectors operate by collecting, focusing, and converting sunlight to heat at each collector module. Conversion to electricity may be accomplished at each module or by a common power conversion system. Distributed collectors are particularly attractive for small, remote, and isolated communities. 3.11.2 State of Technology technically feasible. Solar thermal technology has been proven to be Numerous pilot plants directed at characterizing system costs, and increasing system reliability performance, reducing and durability are in central receiver and before 1989 and 1985, progress. The initial commercialization of distributed collector systems is not expected respectively (Ref. 31). 3.11.3 Technical Restraints Substantial cost reductions are needed before solar thermal systems can compete on a national scale with the more conventional technologies. This B.3-67 will require significant technical development directed at increasing component life and system operating efficiency, and decreasing maintenance requirements. 3.11.4 Constructibility Site preparation (clearing, grading, etc.) receiver plant may be substantial; otherwise, similar to that of conventional power plants. required for the central constructibility should be The modular nature of distributed collectors permits siting closer to users, thereby reducing transmission distances; offers better adaptability to existing sites; and lends itself to incremental construction to meet changing power needs. 3.11.5 Operating and Maintenance Aspects The modular nature of distributed collectors offers the opport:unity for reduced operating and maintenance costs because individual units can be repaired or replaced without the need of shutting down the entire system. 3.11.6 Environmental Considerations Solar thermal power plants require extensive areas for the heliostats or collectors. The primary adverse effects of a solar power station would be on terrestrial ecology, due to the clearing and grading of large land areas for mounting solar reflectors or collectors. 3.11.7 Regulat:ory Restraints None identified. 3.11.8 Regional Restraints It is generally accepted that application of solar energy for power B.3-68 • - .. .. .. .. .. .. .. ., .. .. .. .. • .. -.. .. .. .. III! • ." ., III! .. ." • generation purposes in the United States will be limited by economics to southwestern areas of the country, principally due to differences in the amount of sunlight available. The economic feasibility of utilizing solar energy for electric generation in the Bristol Bay region is unlikely when one considers that the daily insolation values at King Salmon averaged 794 Btu per sq ft from 1941 to 1970, compared to 1,870 Btu per sq ft at Phoenix, Arizona for the same period (Ref. 31). Furthermore, little solar radiation is available from mid-November through January, which would necessitate some form of backup power during the period. During the winter months, when days are short and nights are long, electricity and space heating demands are high when the availability of solar energy is minimal. Solar thermal energy development is expensive by itself, but with the addition of a major backup power source for the long winter months, the costs are prohibitive. 3.11.9 Conclusions It is recommended that solar thermal technology not be investigated further at this time as a source of power for the Bristol Bay region because of the regional restraints. B.3-69 3.12 SOLAR PHOTOVOLTAIC ELECTRIC SYSTEMS 3.12.1 General Description Photovoltaics is the only solar technology that converts sunlight directly into electricity. The basic generating unit is the solar cell which consists of combinations of transparent semiconductor materials placed in metallurgical contact to form junctions. In the presence of light, these junctions induce electric current. 3. 12.2 State of Technology The technical feasibility of photovoltaics has been proven. Photovoltaic technology is in the development and demonstration stage and numerous demonstra~ion projects are either operating or under construction. 3.12.3 Technical Restraints Substantial cost reductions are compete with other technologies. needed before photovoltaic sys~ems can This will require significant technical development directed at reducing the cost of manufacturing the solar cells. 3.12.4 Cons~ructibility Since photovol taics convert sunlight directly into elec~ricity, the need for an intermediate thermodynamic energy conversion system is eliminated. This results in a relatively simple system with no moving parts. Construction time and manpower requirements would be significantly less than most other technologies. 3.12.5 Operating and Maintenance Aspects Since pho~ovoltaic conversion systems contain no moving parts, maintenance should be minimal, although the limited operational experience with the B.3-70 - • .. - • l1li • -.. .. .. .. • - - • .. .. • .. • .. .. .. • existing demonstration plants has not yet provided a historical base. The modular nature of photovoltaic arrays should also reduce operating and maintenance costs because individual panels can be repaired or replaced without the need of shutting down the entire system. 3.12.6 Regulatory Restraints None identified. 3.12.7 Environmental Considerations Clearing and grading land areas for installation of photovoltaic collectors would be the only significant environmental effect. 3.12.8 Regional Restraints It is generally accepted that application of solar energy for power generation purposes in the United States will be limited by economics to southwestern areas of the country principally due to differences in the amount of sunlight available. The economic feasibility of utilizing solar energy in the Bristol Bay region is unlikely when you consider that the daily insolation values at King Salmon averaged 794 Btu per sq ft from 1941 to 1970, compared to 1,870 Btu per sq ft at Phoenix, Arizona for the same period. Furthermore, little solar radiation is available from mid-November through January, thus necessitating some form of backup power during the period. During the winter, when days are short and nights are long, electricity and space heating demands are high when the availability of solar energy is minimal. Solar photovol taic energy development is expensive by itself, but with the addition of a major backup power source for the long winter months, the costs are prohibitive. 3.12.9 Conclusions Photovoltaics should not be investigated further at this time as a source of power for the Bristol Bay Region because of the regional restraints. B.3-71 3.13 ORGANIC RANKINE CYCLE 3.13.1 General Description A Rankine cycle which uses an organic working fluid instead of water/steam has unique characteristics that allow it to generate power by recovering waste heat or using other low temperature sources. This cycle is useful for situations where heat is available at temperatures in the range of o 1,000 to 1,200 F or less (Ref. 32). An organic Rankine cycle (ORC) could be used in the Bristol Bay area for power generation from sources such as geothermal energy or diesel generator waste heat. The ORC is not the most efficient system to use with direct combustion of fuels such as coal, wood, or peat since the heat available is in higher temperature ranges, above 18000 F, which is more suitable for use in a standard water/steam Rankine cycle. A schematic showing the basic ORC arrangement is presented in Figure 3.13-1. Several organic fluids are candidates for use in this cycle, such as freon, isobutane, and toluene. The fluid choice depends on the operating conditions and system costs. As shown in Figure 3.13-1, the low boiling point organic working fluid is vaporized in a heat exchanger with energy supplied from a geothermal well, diesel generator exhaust· gases, or other heat source. The organic fluid vapor is then expanded through a turbine generator for electricity production, sent to a condenser with heat rejection to a liquid or air cooling tower system, and pumped back to the heat exchanger to complete the cycle. Compared to a flash-steam cycle, an ORC has several advam:ages, including the following (Ref. 33): a. b. c. Better suited to low temperature sources Smaller turbine size for a given output Less expensive turbine for a given output d. High pressure operation, with no vacuum sections e. No air in-leakage B.3-72 .. .. ., .. • .. lIB .. .. .. .. .. .. • • • • f. Non-corrosive working fluid in turbine g. Higher isentropic turbine efficiencies h. Completely dry expansion, eliminating erosion problems i. Condensing temperatures can be lower for better cycle efficiency Some of the ORC disadvantages include: a. Organic working fluids are expensive b. No leaks can be permitted c. Heat exchangers are expensive d. Flammability of hydrocarbon working fluids results in additional fire protection requirements Variations in the ORC are possible, such as substitution of a direct contact heat exchange system in place of the typical shell and tube heat exchanger. Systems of this type have been constructed and tested under the sponsorship of the U.S. Department of Energy for use with geothermal sources (Ref. 34, 35). 3.13.2 State of Technology The technology associated with the ORC has been known for many years. However, until the rise in fuel prices during the 1970's, the ORC was not economically competitive. Depending on the local economic conditions and fuel prices, ORC systems using geothermal, waste heat, or other energy sources may now be competitive with other power systems. Since ORC systems are commercially available, the technology is available for use in the Bristol Bay region. 3.13.3 Technical Restraints None identified. B.3-73 3.13.4 Constructibility Construction of an ORC system would pose no significant problems beyond those normally encountered in the relatively remote regions around Bristol Bay. ORC systems could be skid mounted which would facilitate shipping and site installation. 3.13.5 Operating and Maintenance Aspects The maintenance and operation of an ORC system should generally be simpler than a conventional power plant due to the relatively small size of the ORC units and their lack of complexity compared to a conventional plant. The maintenance requirements could be increased, however, if the energy source stream is contaminated with dissolved or suspended foreign substances. This could occur with cer~ain waste heat or geothermal sources. 3.13.6 Regulatory Restraints None identified. 3.13.7 Environmental Considerations The major environmental effects from an ORC installation would include thermal pollution and potential spills or leaks of organic fluids. All thermodynamic power cycles require heat rejection to the environment. The ORC would use a liquid or air cooled heat rejection system for this purpose. Since the ORC contains an organic working fluid, the potential exists for spills or leaks of this fluid and the resulting contamination of soil or water resources. Proper design procedures which include a method to contain the working fluid inventory in the event of a spi 11 or leak will eliminate this potential problem. B.3-74 .. .. .. .. ., -.. .. .. -.. .. .. ., • .. .. .. • .. .. ., 3.13.8 Regional Restraints None identified. 3.13.9 Conclusions There are no known technical, regional, or regulatory barriers which would prohibit the use of ORC systems in the Bristol Bay region. Thus, ORC systems should be considered for power generation with energy sources such as waste heat or geothermal wells. B.3-7S r-----------------------------------------------------------------------------~: .. THERMAL RESOURCE GENERATOR COOLING ---+----'~r-_+--___ WATER ORGANIC WORKING FLUID ORGANIC RANKINE CYCLE FIGURE 3.13-1 .. • ... :( 3.14 BIOMASS (WOOD) ENERGY SYSTEMS 3.14.1 General Description Biomass is organic matter produced by terrestrial and aquatic plants and includes plant derivatives such as agricultural and forest residues, and animal manures. However, wood is the only biomass resource of any significance to power generation in the Bristol Bay region. Wood resources can be either used as fuel directly (combustion of raw or densified wood) or converted to another form of fuel (wood gasification, pyrolysis, or alcohol production) for use in various types of power stations to generate electricity. a. Direct combustion -The burning of wood in the presence of oxygen, for use as a direct heat source in a stearn electric generating station, is the most common method of generating electricity with wood. Burning dens if ied wood offers the advantages of increased heating value (Btu content), low moisture content, and uniform size. However, the densification plant adds significant costs and complexities to the power station; wood densification plants are not widely distributed in the United States (Ref. 36). Any boiler designed for raw wood chips will burn densified wood efficiently. A typical wood-fired power plant is shown schematically in Figure 3.14-1. Wood can be burned either in a pile, in suspension, or in a combination of the two methods (semisuspension). Modern wood-fired boilers use inclined grates for burning high moisture raw wood (up to 60 percent moisture by weight) without the need for auxiliary firing. b. Wood gasification -The thermal conversion of wood to a gas that can be used in producing power is very similar to coal gasification, which is discussed in detail in Section 3.3 of this report. The primary dif ferences between wood and coal gasification are the availability and handling of the resource. B.3-76 c. d. Pyrolysis Burning of wood in the absence of oxygen causes chemical and physical decomposition creating carbon char, pyrolytic oil, combustible gases, and water containing soluble organic compounds. Indirect heating can be used to supply the necessary heat for the process, but it is more efficient to use a portion of the feed material as fuel. Once a relatively small amount of heat is absorbed to initiate the process, the pyrolysis action is self-sustaining. Pyrolysis is quite similar to gasification, except its emphasis is upon creating multiple products from the fuel, as opposed to gasification 1 s one major product. Alcohol Production from Wood Methanol, often called wood alcohol, can be made from the gas that is produced from the pyrolysis of wood. However, methanol is not as desirable for use as a fuel as is another form of alcohol, ethanol. Ethanol is not as difficult to mix or burn as methanol. Also, producing ethanol from wood is less expensive than producing methanol. Making ethanol involves hydrolysis, which converts the cellulosic material into sugars, and fermentation, which converts the sugar into ethanol. Most fermentation processes presently use corn or wheat to produce ethanol. Though feasible, using agricultural products does not presently produce an economical fuel. The key to making fermentation competitive is in finding low-cost sources of sugars. Cellulosic biomass, such as wood, is the most abundant potential source (Ref. 36). 3.14.2 State of Technology Direct combustion is the only wood-energy conversion technology, of those listed above, in general commercial usage throughout the United States. Wood gasification and pyrolysis technologies are rapidly developing, and pending successful operation of demonstration plants, could be commercially available in 5 to 10 years. The Alaska Village Electric Cooperative (AVEC) is actively pursuing electricity generation through gasification of wood. B.3-77 .. .. .. .. .. .. - .. • .. - .. .. .. AVEC has placed a small demonstration plant in operation, and is looking into adding similar installations. The AVEC generating area encompasses several areas of Alaska which are suit.able for commercial forest harvesting, making wood resources more accessible t.han in Bristol Bay, which is rather sparsely wooded. Direct combustion of raw wood, being the most common method of generating electricity with wood, will be analyzed further in this section. The other wood energy conversion processes will not. be reviewed in more det.ail here, since gasification is discussed in Sect.ion 3.3, and pyrolysis/alcohol production technologies are not commercially proven. The governing fact.or in any wood energy conversion system is the availabilit.y of the resource, which is addressed herein. The direct combustion technology of convert.ing wood energy to elect.rical energy has exist.ed for decades. Wood-burning boilers are available in sizes from a few thousand pounds per hour (lb/hr) to more than 500,000 lb/hr (approximately 50 megawat.ts,MW) for the larger units (Ref. 37). 3.14.3 Technical Rest.raint.s None ident.ified. 3.14.4 Construct.ibility Boilers can be eit.her shop-assembled package units or field-erected units, depending on boiler size. As wit.h other solid fuel plants, fuel handling (including st.orage and preparat.ion), ash handling, and pol1ut.ion abatement., require a significant amount of additional equipment and space compared to oil-or gas-fired plant.s. 3.14.5 Operating and Maintenance Aspects The operating and maint.enance aspects of a wood-burning plant are similar B.3-78 to those of a conventional coal-fired plant. However, the need for S02 removal equipment, with its associated high operating and maintenance costs, is eliminated, since wood is sulfur-free. Corrosion of equipment due to the formation of sulfuric acid in the flue gas is also eliminated. This assumes that coal or other sulfur-bearing fuel is not fired as an auxiliary fuel. Wood containing moisture levels above 55 to 60 percent may not produce sufficient energy to sustain combustion; therefore, supplemental firing with an auxiliary fuel or drying of the fuel prior to combustion may be required. Harvesting equipment will need periodic maintenance. Harvesting roads may need periodic upgrading before harvests. Personnel recruiting problems would be similar to other steam electric plants. Alaska requires licensed personnel to operate boilers and turbines, and these people are required 24 hours per day to keep the plant operating. 3.14.6 Regulatory Restraints The same regulatory restraints that apply to other steam electric generating units (i.e., oil-, coal-and natural gas-fired) also apply to wood burning power plants (Section 3.2.6), except that: (1) visible emissions of up to 30 percent are allowed for boilers burning more than 20 percent wood waste, and (2) particulate matter emissions of up to 0.15 grains per standard cubic foot of exhaust gas are allowed for fuel burning equipment using wood waste as fuel. 3.14.7 Environmental Considerations and Regional Restraints The use of wood for power generation requires the assurance of an adequate local resource during the life of the plant. Careful analysis is required to obtain the sustained yield that the wood resource could supply within the economical transport range of the fuel to the generation plant. Rough B.3-79 • • .. .. .. .. .. --.. .. .. .. .. • .. .. .. calculations show that a 10 MW wood-fired power station would burn at least 10,000 to 12,000 board ft (9 to 11 cords) per hour at full load; and a 20 MW station, at full power, would burn 17,000 to 23,000 board ft (16 to 19 cords) per hour. Most of the Bristol Bay region is nonforest, and unsuitable for the substantial wood harvesting efforts necessary to support a wood-fired power plant. The Alaska Forest Service inventoried the timber resources in an area which encompassed a portion of Bristol Bay including Dillingham (Figure 3.14-2). Of the area inventoried; 5 percent was commercial class forest, 16 percent was unproductive forest, and the remainder was nonforest (Ref. 38), Further evidence of the sparse forest resources in the Bristol Bay region is illustrated by the "Commercial Forestry Potential in Interior Alaska" map (Ref. 39) and "Forest Types in Alaska" map (Ref. 22). Stone & Webster Engineering Corporation also performed a visual reconnaissance of the area with similar results. Even if the region were heavily forested, the removal of large quantities of wood to burn in a power station would severely impact the local ecosystems. The Forest Service report (Ref. 38) defined commercial forest as capable of producing at least 8,000 board feet of lumber per acre. The 10 MW and 20 HW wood-fired power stations mentioned above would consume 1 to 3 acres of commercial class forest per hour, respectively. In the sparsely wooded area of Bristol Bay, the land would be stripped of timber products at a much more rapid rate, leaving minimal wood supplies for the natives I use in space heating or as lumber. Addi tionally, numerous roads would be established to harvesting areas, and continually extended to reach the ever-receding wood supply. These roads would allow easy access to remote areas, thus, adversely affecting subsistence hunting and fishing. Long-term wood supply can be guaranteed only by replenishing the harvested areas quickly with a fully-stocked forest. If this is not done, wood must be harvested from increasingly distant locations, making transportation eventually uneconomical, and the wood supply will run out (Ref. 39). Forest regeneration times in Bristol Bay exceed 100 years, making quick B.3-80 replacement of consumed trees impractical. This adds to the detrimental environmental effects on the region, in addition to making wood collection more expensive. Consideration must be given to competing uses for the wood, primarily the pulp, paper, and lumber industries. Additionally, land use conflicts must be assessed. Land used for parks, wildlife refuges, or recreational purposes is not likely to be available as a source for harvesting wood. 3.14.8 Conclusions Capital costs (in 1978 dollars) have been estimated at $3,000 per kilowatt (kW) to about ~900 per kW for plants ranging in size from 10 to 100 MW, respectively (Ref. 40), and, thus benefit appreciably from economies of scale. Therefore, utilization of wood would appear to be best accomplished in a central station concept. The conversion of wood to electrical energy is a mature and commercially available technology. However, due to the limited timber resources in Bristol Bay and the adverse environmental, socioeconomic and lifestyle impacts of a wood-fired power station, wood should not be considered further as a source of electrical energy for the region. B.3-81 .. .. .. .. - .. .. III .. -.. -.. .. .. III, .. III .. .. .. .. -.. .------------------------------------------------------------------------------.-... FLYASH TO DISPOSAL WOOD STORAGE & HANDLING BOTTOM ASH TO DISPOSAL 4---1 FORCED DRAFT FAN FABRIC" ___ IM~ FILTER BOILER INDUCED DRAFT FAN ...--........ --- ~--I~ EXHAUST TO STACK CONDENSER CONDENSATE PUMP ELECTRIC GENERATOR TYPICAL WOOD-FIRED POWER PLANT FIGURE 3.14-1---- 0::> -00 -< BRISTOL BAY (Ref. 38) ....--------------FIGURE 3.14-2----- FOREST SURVEY AREA ... ,.. o N ... ,.. o c( 3.15 ENERGY FRm1 WASTE/REFUSE 3.15.1 General Description Refuse (municipal solid waste) typically contains about 75 percent combustible materials (paper, garbage, textiles, wood, etc.), 8 percent metals (ferrous and nonferrous), 10 percent glass, and 7 percent miscellaneous debris. Refuse would typically have a 9 to 10 million Btu per ton heating value, compared to 23 million Btu per ton for coal. The actual composition and heat content may vary significant ly, depending on the source of the refuse. Refuse can be burned in a water-walled incinerator to generate low pressure steam. The refuse is not normally processed prior to firing except for the removal of large items. Refuse can also be processed into a solid refuse-derived fuel (RDF) which is a more suitable feedstock for burning in a utility-type boiler. The refuse undergoes a significant amount of processing (shredding, separation, classification, etc.) to convert it to RDF. Usable materials, such as metal and glass, may be recovered for recycl The RDF may be sold as a fuel or burned at the processing facility to generate steam and/or electricity. 3.15.2 State of Technology The commercial use of refuse as a fuel for power generation has been widely applied in Europe where the availability of land for solid waste disposal is at a premium. Commercial application in the U.S. has been actively pursued in the last 10 years as an alternative to fossil fuels. 3.15.3 Technical Restraints None identified. 3.15.4 Constructibility Boilers can be either shop-assembled package units or field-erected units, depending on boiler size. As with other solid fuel plants. fuel handling (including storage and preparation), ash handling, and pollution abatement require a significant amount of additional space compared to oil-or gas-fired plants. 3.15.5 Operating and Maintenance Aspects The operating and maintenance aspects of a refuse-fired plant are similar to those of a conventional coal-fired plant. 3.15.6 Regional Restraints The amounts of refuse available in the Bristol Bay region will not supply sufficient fuel to support an economically feasible power plant design. 3.15.7 Conclusions The economic feasibility of utilizing refuse dependent on an adequate local supply of refuse. for generating power is Such a supply does not exist in the remote Bristol Bay region; therefore, waste/refuse should not be cons idered as a potential power source for that area. B.3-83 .. .. - - .. ---• - ... ., • - • .... .. 3.16 PEAT ENERGY 3.16.1 General Description Peat is partially carbonized vegetable tissue formed by the partial decomposition in water of various plants over a period of thousands of years. It is found on the surface in deposits generally 6 to 25 ft deep. Peat typically contains 70 to 95 percent water. This moisture level must be reduced to about 40 to 50 percent before the peat can be burned. Traditionally, it has been done by removing the peat from the bog and exposing it to the sun for drying. Mechanical drying is difficult and can reduce moisture to about the 70 percent level. Recent power generation installations typically fire air-dried, pulverized peat that is dried further by flue gas generated in the combustion process. Cyclone and/or fluidized bed combustion systems can also be used. 3. 16.2 State of Technology Peat has been used extensively for decades as a fuel for generating electricity in such countries as Ireland, Finland, Sweden, and the Soviet Union where the cost of peat was economically attractive relative to other fuels. It has not to date been applied as a fuel in the United States because of the availability of less expensive alternative fuels (Ref. 41, 42) . 3.16.3 Technical Restraints The difficulty of using peat as a fuel arises from its high moisture content and the difficulty inherent in removing this moisture. The moisture cannot be readily removed by mechanical means, and forced drying may require more energy than is available from combustion of the solid. To overcome the moisture problem, some research and development have been B.3-84 undertaken to find more practical ways to extract the energy Methods such as peat gasification and wet-air oxidation investigated but are only in the early stages of development. 3.16.4 Constructibility from peat. have been Constructibility of a peat-fired power plant should be similar to that of a conventional coal-fired power plant. 3.16.5 Operating and Maintenance Aspects The operating and maintenance aspects of a peat-fired power plant should be similar to that of a conventional coal-fired power plant. 3.16.6 Regulatory Restraints The same regulatory restraints that apply to other steam turbine generating units, that is oil-, coal-and natural gas-fired, also apply to peat-fired units (Section 3.2.6). 3.16.7 Environmental Cons iderations Peat harvesting on a scale large enough to supply fuel to a power plant in the Bristol Bay region would be extremely detrimental to the ecosystems in the harvesting areas. Roughly 2, 000 acres of peat land would have to be harvested per year to fuel a 10 MW power generating unit (calculations based on Ref. 43). Harvests covering this much area would contr ibute significantly to the siltation of wetlands and deterioration of permafrost. 3.16.8 Regional Restraints The use of peat for power generation requires the assurance of an adequate local resource during the life of the plant. Because of the high moisture, low energy density nature of peat, the resource should be relatively close to the power plant. B.3-85 .. .. • • - .. There are five potential peat harvesting sites in the vicinity of Dillingham. The fuel value of the peat in these sites is generally very good. The peat heating values and ash contents range from 6,200 to 9,308 Btu per pound and 9.3 to 35.1 percent, respectively. All five potential harvesting sites are within a five-mile radius of Dillingham (Ref. 43). 3.16.9 Conclusions The use of peat for power generation has been successfully utilized outside the United States. However, a careful assessment of the cost of harvesting, drying, and transporting the peat is required to determine the cost effectiveness of this type of fuel utilization. The environmental impact of installing a peat-fired power plant is too severe for the Bristol Bay region. Therefore, this technology should not be considered further in the Bristol Bay Regional Power Plan. Peat usage could be feasible on a limited basis for individual home space heating. This alternative is currently being actively pursued by the Bristol Bay Native Association in the Dillingham area. B.3-86 3 . 17 GEOTHERMAL POWER 3.17.1 General Description Geothermal power uses the intrinsic heat from the center of the earth in power conversion cycles similar to those used in conventional coal or nuclear power plants. Although geothermal energy is not a renewable resource (resource lives are estimated to be between 30 and 200 years), it is considered to be a preferred energy alternative in most states. The center core of the earth, composed of magma under great pressure, extends to within a few miles beneath the surface of the earth in certain regions. Water heated by the magma can be forced to the earth's surface in the form of hot water or steam, providing the energy source for electrical generation. In general, one of four basic power cycles is used in a geothermal power plant. The cycle choice depends primarily on the state of the geothermal resource, i.e., whether steam, high temperature water, or low temperature water is naturally present in the geothermal well. The four basic cycles include the following: a. b. c. d. Dry steam cycle Single-flash cycle Dual-flash cycle Binary cycle The dry steam cycle (Figure 3.17-1) is the simplest of the four cycles. This cycle uses steam directly from the geothermal well to turn a turbine-generator and produce electricity. Rather than exhausting the steam from the turbine directly to the atmosphere, a condenser is employed which results in a lower turbine backpressure and an increase in turbine efficiency. Cooling water is generally supplied from a cooling tower, with the steam condensate used as cooling tower make-up water. B.3-87 - - • - • L' • - .. • - - In the case of a geothermal well which produces intermediate to high temperature water or a water/steam mixture, the single·flash cycle (Figure 3.17-2) could be used. This system separates the liquid and steam phases in a flash separator by flashing the hot liquid at a reduced pressure, feeding the steam to the turbine generator, and sending the brine to a mineral recovery and/or reinjection system. A condenser/cooling tower would be incorporated as before. A dual-flash system can be used in systems where the geothermal hot water source supplies water at a sufficiently high temperature. In this case, the flash pressure of the brine leaving the separator is high enough to economically justify a second flash separator where the brine is flashed a second time. This lower pressure steam can then be fed to a separate low pressure turbine-generator or to a low pressure stage of the same turbine, as shown in Figure 3.17·3. The binary cycle is used when only a low temperature heat source is available from the geothermal well. This system employs two heat transfer fluids: the geothermal source fluid and an organic fluid such as freon or isobutane. A description of the binary cycle and a system flow schematic are included in Section 3.13. The binary cycle has advantages over the other cycles since the geothermal fluid, containing various contaminants, does not directly enter the turbine, which results in longer equipment life. In addition, the contaminants in the geothermal fluid are in an isolated system and are not a potential pollution source as in the other three cycles. 3.17.2 The technology associated with geothermal power plants is well established (Ref. 44). Currently, there are seventeen power plants operating in the United States which use geothermal sources (Ref. 45). These plants produce a total of 922 megawatts(MW). In addition, a total of 44 other plants have been proposed for construction in the U.S. (see Table 3.l7-A). If built, B.3-88 they will supply a total of 2,200 MW (Ref. 45). Thus, the technology is available for the construction of a geothermal power plant in the Bristol Bay region. 3.17.3 Technical Restraints No major technical restraints exist which would prohibit the use of geothermal power in the Bristol Bay region. The major difficulties would be encountered in the construction and operation of a geothermal power plant due to the remote location of the known geothermal resources relative to Bristol Bay region (discussed under Regional Restraints). Since a geothermal power plant is very similar to a conventional plant, the primary technical problems involve the geothermal resource itself. The geothermal steam or hot water generally contains contaminants which impose special requirements on certain components such as turbines. However, methods of mitigating these problems are available and could be employed if a geothermal plant was built in the Bristol Bay region. 3.17.4 Constructibility Construction of a geothermal power plant poses no significant problems beyond those encountered in a conventional power plant; the majority of the systems in a geothermal plant are nearly identical to those in conventional plants. The main differences occur in the system used to collect the geothermal resource: in the pretreatment to eliminate certain contaiminants in the resource (if needed), and in methods of handling solid, liquid, and gaseous wastes. However, significant problems and additional expense would be encountered for Bristol Bay in the construction of a geothermal plant due to the remote location of the known resources. 3.17.5 Operating and Maintenance Aspects The operational aspects of a geothermal plant are similar to those of a conventional power plant. However, additional maintenance requirements are B.3-89 .. .. • --• -.' - - usually necessary due to the characteristics of the geothermal resource. Depending on the geology at the plant site, geothermal steam or hot water may contain a large number of dissolved or suspended foreign substances. Many of these substances are corrosive. For each possible thermodynamic cycle, either a heat exchanger, flash evaporator, or the turbine itself will come in contact with these corrosive materials. Special design considerations and materials may be required for these components in a geothermal power plant to achieve reasonable equipment lifetimes. However, it is likely that those equipment items in direct contact with the geothermal resource will require maintenance and replacement at a more rate than at a conventional plant. Previous experience at geothermal plants (such as those at The Geysers, California) has shown that these potential problems can be handled within a reasonable cost. 3.17.6 Regulatory Restraints The development and use of geothermal energy, as with conventional energy sources, involves federal, state, and local governmental agencies. These institutions may have varying degrees of involvement in several aspects of geothermal energy, including land ownership, resource exploration, resource development, energy distribution, and energy consumption. Within the federal government, the primary agency involved with geothermal energy is the U. S. Geological Survey in the Department of the Interior. The Geological Survey program includes exploration methodology, resource appraisal, reservoir development, utilization technology, and environmental moni toring. Other agencies, such as the Department of Energy and the National Science Foundation, have been involved in research and development related to geothermal energy. The State of Alaska, through the Department of Natural Resources, regulates the geothermal leasing on state-owned lands. A revised set of geothermal regulations is currently being proposed (Ref. 46) in order to encourage the use of geothermal resources where possible. B.3-90 The known geothermal resources in the vicinity of Bristol Bay are mainly to the east, near the Aleutian Range. Several serious problems exist relative to the development of these resources for the benefit of the Bristol Bay region (Section 3.17.8). However, there are no known regulatory restraints that would prohibit the use of these resources. 3.17.7 Environmental Considerations Several potential environmental impacts can result from the operation of geothermal power plants. These effects can usually be reduced to an acceptable level, although local conditions may impose special problems and control requirements. The major considerations include the following: a. b. c. d. Land Requirements -As for all types of power plants, geothermal plants require land surface area for buildings, roads, transmission lines, etc. However, geothermal plants may require a somewhat larger area due to the pipeline systems used to gather the water or steam from the wells. Gaseous Emissions Noncondensable gases are present in the effluents from a geothermal well. The largest constituents include carbon dioxide, ammonia, hydrogen sulfide, and methane. The major problem is hydrogen sulfide, primarily due to its objectionable odor. Various methods have been proposed and used in existing plants for dealing with this emission, such as chemical oxidation or incineration. Water Contamination -Geothermal plant operation could result in the contamination of surface or groundwater by solid or liquid wastes. Proper precautions and understanding of the local geologic formations can result in avoidance of these problems. Induced Earthquakes In some previous cases where fluids have been injected into geological formations, small earthquakes have been triggered (Ref. 47). Each prospective geothermal site should B.3-91 .... • .. ... • - be thoroughly evaluated for active faults to ensure that no reinjection is performed near a fault zone. e. Land Subsidence -In certain cases where large amounts of material have been withdrawn from underground, such as oil and gas fields, land surface subsidence has occurred. The withdrawal of geothermal fluids could also produce this effect if preventive measures are not taken. Reinjection of waste water has been proposed as a solution to this problem at geothermal plants. 3.17.8 Regional Restraints For the Bristol Bay region, the fundament: a 1 issue concerning geothermal power is the uncertain availability of geothermal resources within a reasonable distance from the proposed electrical distribution system. The known geothermal resources forty to several hundred miles Many of these resources are remote, inaccessible areas. closest to Bristol Bay from the region (Ref. located in or near the occur from about 48, 49, 50, 51). Aleutian Range in Although no definite guidelines are available, it is unlikely that geothermal steam or hot water could be piped for more than a mi Ie before cost and thermal loss penal ties would be prohibitive. Thus, there are no known resources that would allow a geothermal plant to be built within approximately 40 miles of the proposed transmission lines. If a power plant was constructed, it would have to be located near the geothermal resource with a transmission line connecting the plant to the Bristol Bay region. Another problem is the lack of data regarding the quality of the geothermal resources nearest to the Bristol Bay area. Data regarding temperature, heat rate, total energy cont:ent, etc., are not available for many of the potential geothermal sites. The data that are available indicate that some of the identified sites are hot springs with temperatures too low for B.3-92 effective use in power plants. Al though some geothermal resources may be available within approximately 40 miles of Bristol Bay, the location of the closest resource with an adequate delivery temperature and heat rate is unknown. Any exploratory programs to confirm geothermal resource potential within the Bristol Bay region would be very risky and cost prohibitive. In summary, the regional restraints on geothermal power for the Bristol Bay area may be significant enough to preclude the use of the resource. Available data indicate the closest geothermal resource is at least 40 miles from Bristol Bay, however the adequacy of this resource for power generation is unknown. Since geothermal steam or hot water could not be piped this distance, the only option would be a power plant located at the resource site with a transmission line to Bristol Bay. It would be very costly to build and operate a geothermal power plant in the remote areas where most potential resources are located. 3.17.9 Conc1us ions Economy of scale for geothermal power stations is similar to many other power generation technologies. That is, the larger the plant in generating capacity, the smaller the cost per unit of electricity generated. This is true for both capital ($ per kW) and operating/maintenance ($ per kWh) costs. The central station concept would be most economical for the Bristol Bay region. There are no known technical or regulatory barriers that would prohibit the construction and operation of a geothermal power plant for the Bristol Bay region. The primary issue is the location of geothermal resources relative to Bristol Bay. The available data regarding geothermal resources in this region of Alaska are sketchy and incomplete. Based on the known sites, it appears that the closest site to Bristol Bay is about 40 miles east. Several other sites in the region have been observed, with many located in remote areas around the Aleutian Range. Data regarding temperature and heat rate are not available B.3-93 • .. • - .. - • .. • -• -.. for many of the recorded sites. power plant site is not known. Thus, the location of the closest adequate The exploratory program necessary to define geothermal resources in the area would be extremely expensive, more than the costs of the geothermal power plant alone. The distances to potential sites and their remote locations indicate that it would be uneconomical to build the plant at the resource site with a transmission line to the Bristol Bay region. Therefore, based on the information currently available, it is not recommended that geothermal energy be considered further as a resource for the Bristol Bay region. B.3-94 1ft 0 (Ref. 45) --• N PROPOSED GEOTHERMAL ELECTRIC PLANTS :( NET YEAR PLANT OUTPUT ON STATE AREA DEVELOPER UTILITY PLANT TYPE MWE Line CA Brawley Un ion 0 i I SCE CA Brawley CU-I Venture CDWR F I ash 45 1984 CA Brawley Union OJ I SCE SCE CA COSO Ca lifo rn j a Energy US Navy COSO #1 F I ash 20 1983 CA COSO Ca lifo rn i a Ene rgy US Navy COSO #2 F I ash 55 1989 CA East Mesa Republ ic Geothermal SDG&E F I ash 50 1982 CA Geysers CDWR Binkley Steam 55 1986 CA Geyse rs MCR Geothermal CDWR Bottle Rock Steam 55 1984 CA Geyse rs NCPA NCPA NCPA #1 Steam 66 1985 CA Geysers She I I OJ I NCPA NCPA #2 Steam 110 1982 CA Geyse I'S Occidental Geo. Inc. Oxy #1 80 1988 CA Geysers Aminoj I USA SMUD SMUD #1 Steam 75 1984 CA Geysers SMUD SMUD #2 Steam 55 CA Geysers SMUD SMUD #3 Steam 55 CA Geysers GeotherlTlal Kinetics CDWR S. Geysers Steam 55 1986 CA Geysers Amiboi I USA PG&E Unit #16 Steam 110 1983 CA Geysers Union-Magma-Thermal PG&E Unit #17 Steam 110 1982 CA Geysers Union-Magma-Thermal PG&E Unit #18 Steam 110 1982 CA Geyse rs Aminoi I USA PG&E Unit #19 Steam 55 1986 CA Geysers Union-Magma-Thermal PG&E Unit #20 Steam 110 1984 CA Geysers Union-Magma-Thermal PG&E Unit #21 Steam 110 1986 CA Geysers PG&E Unit #22 Steam 110 1990 CA Geysers PG&E Unit #23 Steam 110 1990 CA Geysers PG&E Unit #24 Steam 110 1990 CA Heber Chevron SDG&E B i na ry 45 1985 CA Heber Chev ron SCE SCE #1 F I ash 50 1983 CA Heber Chevron SCE SCE #2 F I ash 100 1986 CA Mono-Long Va Iley Magma Power SCE SCE Hybri d 20 1985 CA Nil and Un ion 0 i I SCE SCE CA Nil and Union Oil SCE SCE Pi lot 10 1982 CA Nil and Magma Power SDG&E SDG&E #1 F I ash 26 1983 CA Nil and Magma Power SGE&E SDG&E #2 F I ash 49 1985 CA Wendel-Amedee Geop roducts CDWR Hyb rid 50 1985 CA Westmo r I and Republ ic Geothermal F I ash 48 1984 HI Puna Thermal-Di I I Ingham Helco 25 1988 HI Puna State of Hawa i i Helco BGP-A F I ash 3 1981 ID Raft River INEL/EG&G B i na ry 5 NM Va lies Ca Idera Union Oil PNM Baca #1 F I ash 45 1983 NV Northern Nevada Ph i I lips Petroleum NORNEV NORNEV #1 B i na ry 10 1982 NV Northern Nevada Ph i I lips Pet ro I eum NORNEV NORNEV #2 B i na ry 10 NV No rthe rn Neva da Ph i I lips Petroleum NORNEV NORNEV #3 F I ash 10 UT Roosevelt H.S. Ph i I lips Petroleum UP&L UP&L #1 F I ash 20 1983 UT Roosevelt H.S. Ph i I lips Petro I eum UP&L UP&L #2 F I ash UT Roosevelt H.S. Ph i I lips Petroleum UP&L UP&L #3 TOTAL 2,237 TABLE 3.17-A r-------------------------------------------------------------------------------------~~ - DRY STEAM CYCLE SCHEMATIC DIAGRAM STEAM .------1 I I I I I I I FROM GEOTHERMAL WELLS GENERATOR ---t---' V---f ___ ,.COOLING WATER COOLING TOWER MAKE-UP GEOTHERMAL ----------------FIGURE 3.17-1---- --• N 4: r---------------------------------------------------------------------------------------------..~ SINGLE·FLASH CYCLE SCHEMATIC DIAGRAM STEAM r--------, I I FLASH SEPARATOR GENERATOR ---+--' \I-...... ------i .. COOLING MINERAL RECOVERY! FROM GEOTHERMAL WELLS REINJECTION COOLING TOWER MAKE-UP GEOTHERMAL WATER -.. «I COol :( '---------------FIGURE 3.17-2---" .-----------------------------------------------------------------------------------------~~ DUAL-FLASH CYCLE SCHEMATIC DIAGRAM STEAM r------l FROM GEOTHERMAL WELLS I FLASH SEPARATOR I I GENERATOR ~------, FLASH SEPARATOR MINERAL RECOVERYI REINJECTION GEOTHERMAL \_~I__-. COOLING ---+---1 WATER COOLING TOWER MAKE"UP .. -• ... ;( '----------------FIGURE 3.17-3---- 3.18 CONVENTIONAL NUCLEAR POwLR 3.18.1 General Description Present-day conventional nuclear power stations consist primarily of light water reactors, although heavy water reactors are in commercial operation in Canada (Ref. 3) and a high temperature gas cooled reactor is also in operation in the United States. The heat of fission (splitting of an atomic nucleus) of heavy elements is liberated in a nuclear reactor. This heat is then transported by reactor coolant to external equipment where it is converted to electricity. Nuclear fuel is made of isotopes that are easily fissioned by slow neutrons. These are known as fissile isotopes. The only fiss ile isotope that exists in nature in usable abundance is uranium-235. This makes up about 0.7 percent of natural uranium, and natural uranium is therefore the basic resource for nuclear power. There are two other isotopes from which fissile isotopes can be made in a reactor. These are uranium-238, the more common isotope and the major constituent of natural uranium, and naturally occurring thorium-232. Fissile plutonium-239, the most common form of plutonium, is made from uranium-238, and fissile uranium-233 is made from thorium (uranium-238 and thorium-232 are called fertile isotopes) (Ref. 3). As the fissile isotopes originally loaded in a reactor are destroyed, new fissile isotopes are formed from fertile isotopes. The relative rate of replacement is the conversion ratio. When the conversion ratio is greater than l, new fissile isotopes are formed faster than the original fissile isotopes undergo fission, and the reactor is called a breeder. A reactor that operates at conversion ratios below 1 is known as a converter (Ref. 3). Conventional nuclear power stations as discussed in this section, operate at conversion ratios less than 1. Breeder reactors are discussed later herein. B.3-95 3.18.2 State of Technology Nuclear power is a mature technology which presents an economical means of power generation when approached on a large scale (800 ~IW and upward). Nuclear fission stearn electric generating facilities in the size range of 50 .MW or less have not been pursued on a commercial basis in the United States. Modern reactors of this size are found only in military installations, making technical and economic information practically unobtainable. 3.18.3 Technical Restraints Large nuclear power station designs are somewhat standardized, especially in the nuclear stearn supply system (reactor) design. Although a small nuclear power station could be designed, an enormous amount of engineering and design expense would be incurred in scaling down one of the large plants. 3.18.4 Constructibility Nuclear power stations require a larger initial capital investment than other conventional power generation alternatives (i. e. fossil fuel, hydroelectric). Nuclear plants are more expensive to build because, as a rule, they contain more concrete, steel, piping, circuitry, etc. than other conventional power stations. Additionally, more thorough documentation is required for the material and for construction procedures. Extensive lead time is traditionally required for the design and construction of nuclear fission steam electric generating stations. The current lead time ranges from 9 to 15 years, and includes a great deal of time securing the necessary regulatory approvals. 3.18.5 Operating and ~1aintenance Aspects Highly trained operators, engineers and maintenance personnel are required to operate a nuclear power generation facility. The Nuclear Regulatory B.3-96 • • '" .. • .. • .. • .. • .. • -.. • • .' - • .. • .. Commission (NRC) must review not only the operating staff. but the entire support staff (i. e.. engineering, quality control, management) of the nuclear facility owner to ensure the owner's capabilities to safely operate the station. The NRC will not issue the owner an operating license until satisfied with owner's nuclear expertise. A training program in nuclear power is an economical expense for large utilities with large nuclear power generating stations. However, for the small and remotely located utilities of Bristol Bay, this training would be difficult and an immense economic burden. To arrive at the most workable nuclear facility, a number of factors must be balanced: (1) the largest plant would be the least expensive, per kilowatt, to design and construct, (2) nuclear power stations are much more efficient when utilized for base loading rather than cycling, and (3) plant outages (scheduled or unscheduled) for one central unit would de-energize the entire power grid unless sufficient reserve was provided. Upon consideration of these factors, a nuclear power station is not currently feasible for the Bris~ol Bay region from an operational standpoint. 3.18.6 Regulatory Restraints Alaska Public Law of 1981, Chapter No. 93, Source FCC SSE 29 relating to hazardous wastes and to nuclear and radioactive facilities and materials became effec~ive January 1, 1982. Following are several of the more noteworthy clauses from this law as it applies to nuclear power stations: a. A nuclear utilization facility can not be constructed in the state unless a permit is obtained from the Department of Environmental Conservation. The permit must be approved by the municipality (local government), the legislature, and the governor. b. The legislature shall designate by law, the land in the state on which a nuclear utilization facility may be located. B.3-97 c. d. e. The transportation of high level nuclear waste material (e.g., used nuclear reactor fuel), except for purposes of disposal outside the state, is prohibited. A person who conducts an operation which results in the discharge of low level radioactive materials to the air, water, land, or subsurface land of the state must obtain a permit from the department before commencing the discharge. It is unlawful to dispose of hazardous wastes in the state unless: • • The waste has been treated and disposed of in a manner that uses the maximum degree of reduction of the harmful qualities of a hazardous waste which the department, on a case-by-case basis, determines is achievable for the hazardous waste by application of production processes and available methods, systems, and techniques, taking into account energy, environmental, and economic impacts and other costs. The waste is disposed of in a manner that will ensure the protection of human health, livestock, wildlife, property, and the environment. This law is not an insurmountable obstacle to es~ablishing a nuclear power generating station in Alaska. It does present a number of important state requirements in addition to the already numerous federal regulations. A significant amount of public participation, through elected representatives, is required to meet all the regulatory requirements for licensing a nuclear facility. Nuclear power is controversial with the public, and will probably remain so. In the United States, there is a significant core of very strong opposition to nuclear power-opponents who will continue efforts to persuade the public to abandon this source of energy. Thus, even if all other aspects were favorable for the installation of a nuclear power plant in the Bristol Bay region, it would be questionable whether the plant could be licensed. B.3-98 : .. • ,Wt • • • • • .. • .... , - 3.18.7 The major environmental concerns with conventional nuclear power stations are the disposal of high level nuclear waste material and potential discharges of low level radiation. Under current regulatory restraints, these concerns can be safely controlled. 3.18.8 Southwest Alaska is part of a vast, continuous seismically active belt that circumscribes the entire Pacific Ocean basin. This region is one of the most seismically active in North America, both in number of earthquakes and amount of energy released (Ref. 52). The Bristol Bay region is located within one of the two major earthquake zones in Alaska. This zone runs from the Copper River valley west along the Alaskan Peninsula and Aleutian Islands to Kamchatka. Most Alaskan earthquakes occur in this zone, which is a substantial number as 6 percent of the world's large shallow earthquakes occur in Alaska (Ref. 22). An important criteria in siting a nuclear power station is to locate it in an area of minimal seismic activity. Many structures, piping supports, and equipment in a nuclear power plant must be designed to withstand a maximum hypothetical earthquake for the specific site selected. For such a plant located in the Bristol Bay region (high seismic activity), the seismic design would demand much heavier and more costly structures and equipment to withstand the potentially higher intensity earthquakes. Nuclear fuel and large equipment components for maintenance would have to be barged into the area due to lack of roads and limited airplane carrying capacity. Barging cannot be accomplished during the winter months due to ice conditions. Unplanned plant outages caused by failure of equipment could be extended by the inability to receive replacement parts during certain times of the year. B.3-99 3.18.9 Conclusions Nuclear power stations gain their advantage over fossil-fired means of electricity generation through lower fuel costs and lower operating and maintenance cost (Ref. 53. 54 ). However. this analysis is true only for power stations in the range of 800 l'1W and larger. For the electrical demands of the Bristol Bay region, a small nuclear power station would be required. The small nuclear plant would still contain the complexities in design and operation of a large nuclear station. Thus, operating and maintenance costs would be much higher per unit of electrical generation (kWh) than for a standard-sized nuclear plant. Conventional nuclear power should be removed from consideration as a potential source of energy for the Bristol Bay region. Among the reasons for this recommendation are high capital and operating costs, regulatory uncertainty, generation characteristics not matching system demand, inaccessibility, undesirable seismic conditions, and unavailability of nuclear-trained operating personnel. B.3-l00 • .. .. • • .. .. ., • • • .. • 3.19 NUCLEAR FUSION AND BREEDER REACTORS 3.19.1 General Description The breeder reactor is a nuclear reactor fueled with plutonium separated from the spent fuel of present day (conventional) light water reactors and/or with depleted uranium left over from the enrichment process for weapons material and light water reactor fuel. The breeder, in combination with light water reactor technology, produces more fuel than it consumes in the production of electrical power and reduces the amount of spent fuel wastes to be stored (Ref. 3). Another potential source of electricity, thermonuclear fusion, makes use of deuterium--widely found in ocean water. Thus, fusion has the potential for infinite reserves of low-cost fuel. The fusion reactor uses the concept of fusing deuterium and tritium into helium at temperatures about ten times that of the sun's core to decompose matter into atoms whose electrons are stripped away. The result is an ionized gas, or plasma, that conducLs electricity and responds readily to magnetic and electric forces (Ref. 3). 3.19.2 State of Technology Breeder reactor technology is still in the developmental and demonstration stage. Construction of commercial breeder reactors is expected close to the turn of the century, approximately the year 2005 (Ref. 3,55). Nuclear fusion is not as advanced as breeder reactor technology; in fact, it has yet to be demonstrated as technically feasible. Commercial availability of fusion reactors is anticipated by the year 2015 (Ref. 55). 3.19.3 Technical RestraintsjConstructibility/Operating and Maintenance Aspects Breeder and fusion reactor technology is properly discuss technical restraints, not developed sufficiently to constructibility, maintenance B.3-101 requirements, and operational aspects. However, it is expected that once the technology is developed, the previously noted items will be similar to those discussed for conventional nuclear power in Section 3.18. 3.19.4 Regulatory, Regional, and Environmental Considerations The environmental impact of the breeder reactor is similar to that of the conventional light water reactors, except that the breeder reduces the amount of spent radioactive fuel wastes to be stored by using depleted uranium as fuel. Although fusion reactors would have some of the same problems as fission reactors, the problem of radioactive waste management would probably be less severe. The safety and environmental liabilities attending the use of fusion for power cannot be analyzed in sufficient detail at the present stage of development. Some impacts may be more severe than those of the breeder reactor program. Other regulatory and regional restraints will be similar to those of conventional nuclear power in Section 3.18. 3.19.5 Conclusions Breeder and fusion reactor ~echnologies remain in the developmental stage. These technologies will not be commercially available in time to meet the Bristol Bay Regional Power Plan needs. Additionally, both breeder and fus ion reactors wi 11 have all the disadvantages of conventional nuclear power stations relative to Bristol Bay, that is, high capital and operating costs, regulatory uncertainty, inadequate load matching characteristics, inaccessability, undesirable seismic conditions, and difficulty in obtaining personnel with nuclear experience. B.3-102 ., • .. • - .. • • ., .-... For the above reasons, the reactors as electrical power recommended. utilization sources for B.3-103 of nuclear fusion or breeder the Bristol Bay Region is not 3.20 FUEL CELL 3.20.1 General Description A fuel cell is comprised of two electrodes separated by an electrolyte, which produces electricity by electrochemically combining fuel and oxygen. As shown in Figure 3.20-1, hydrogen-rich fuel gas is passed over a fuel electrode (anode), and oxygen (or air) is passed over an adjacent air electrode (cathode). The hydrogen molecules split up into hydrogen ions and electrons. The hydrogen ions and the free electrons migrate to the cathode through the electrolyte and an external circuit, respectively, where they combine with the oxygen to form water. The direction of ion migration depends on the specific electrolyte used and the type of ion present. A fuel cell plant consists of a fuel processor, fuel cell section, and an inverter, as shown in Figure 3.20-2. The processor converts the fuel to hydrogen while removing sulfur compounds and carbonaceous impurities. The inverter converts the low-voltage dc power to high-voltage ac power, while the power conditioner filters and regulates the ac output. Cells may be fueled by fuels such as propane, methane, naphtha, or No. 2 fuel oil. Efficiencies of current phosphoric acid cells fueled by naphtha are in the 38 to 40 percent range. 3.20.2 State of Technology The technical feasibility of fuel cells was demonstrated in the Gemini and Apollo space programs. The technology nearest to commercialization is the phosphoric acid fuel cell. The Electric Power Research Institute (EPRI) has set the year 1985 as a goal for the technology' s commercial introduction (Ref. 56). This B.3-104 .. • - • • - • .-.. -.. .. .. .. • -• lilt • -• ,. technology has entered the demonstration phase with the installation of a 4.5 MW power plant, to be operated by Consolidated Edison, in New York City. 3.20.3 Technical Restraints Technical development will focus on maintainability, reducing manufacturing costs, fuels. 3.20.4 Constructibility improving endurance and and expanding the range of Fuel cells will be available as factory-assembled units, which should lead to reduced installation time and man-hours. The modular nature of fuel cells should permit dispersed siting closer to the user, thereby redUCing transmission costs and offering better adaptability to existing sites. 3.20.5 Operating and Haintenance Aspects Fuel cell plants have few moving parts, thereby offering the potential for reduced operating and maintenance costs. 3.20.6 Conclusions Fuel cells are an attractive potential power source. They can be applied in both the central station and dispersed plant concepts. Environmental impact (noise, emissions, etc.) should be minimal. However, the technology has not yet been commercially demonstrated, nor is it expected to be so before 1985. With the possible reduction or cessation of government funding, commercial demonstration may be delayed. Therefore, fuel cells should not be considered further as a potential source of power for the Bristol Bay region in the near term. B.3-l05 .----------------------------------------------------------------------.-1ft SPENT FUEL .. CJ---- (C02, CO) ELECTRIC LOAD ---I •• WATER, N2 1...-_ CATHODE ELECTROLYTE (PHOSPHORIC ACID) ANODE FUEL CELL -----------------FIGURE 3.20-1----- o -• -:( .-------------------------------------------------------------------------------------." 1ft co .. • .. :( A IR STEAM r--------, I I I I , , .. DC INVERTER AND FUEL ..... FUEL H2 ..... FUEL POWER ..... POWER "" PROCESSOR , ,. CELLS ,. CONDITIONER ,. AC POWER ,,. IMPURITIES FUEL CELL POWER PLANT ...... -------------FIGURE 3.20-2--.... 3. 21 MAGNETOHYDRODYNAMI CS 3.21.1 General Description Magnetohydrodynamics (MHD) technology is a means of producing electricity wi thout the need for a turbine; this is accomplished by expanding hot, electrically conductive gas (such as flue gases treated to conduct electricity) through a magnetic field. The interaction of the accelerated conducting gas with an intense transverse magnetic field induces an electric field in the gas. If electrodes are present to collect the current, then electric power can be supplied to an external load. The emissions from an MHD plant would be almost free of sulfur, even if raw coal combustion gases were used, because the potassium salt (seed) used to render the gas conductive would combine with the sulfur and separate it out as the potassium is recycled. The high operating temperatures will increase the potential of NO problems in the exhaust gases. This x potential for increased NO emissions must be balanced against the lower x total emissions per unit of electricity generated that are due to the higher efficiency of the MHD plant. Efficiencies of as much as 50 percent from coal to electricity can be achieved using raw coal combustion gases and capturing the heat of the high temperature exhaust gases for use in a steam turbine topping cycle, as shown in Figure 3.21-1 (Ref. 3,57). 3.21.2 State of Technology and Technical Restraints The technology necessary to generate electrical energy by MHD on a commercial scale is not expected until the year 2005 (Ref. 55). The present state of materials technology is inadequate in several respects to achieve full-scale MHD power generation. Advances in materials technology will be required for a number of components such as nozzles, valves, ductwork, and boiler tubes, but the most challenging problem areas are those represented by the air heaters, electrodes, and insulators. The problems lie in the extremely high temperatures used (1,8000 F to 5,0000 F), corrosive environments, thermal cycling, and long-duty cycle. In addition, B.3-106 the requirement for the mutual compatibility of different materials in these environments can pose significant constraints on the materials selection and component design (Ref.57, 58). 3.21.3 Constructibility, Operating and Maintenance Aspects MHD technology has not developed adequately to allow a proper discussion of construction, maintenance, and operating capabilities of a commercial plant. 3.21.4 Regulatory, Regional Restraints and Environmental Considerations MHD power generation would have the same social and environmental impacts as a coal-fired power station. However, the impacts would be less severe, since the higher efficiency of the MHD cycle would result in a reduction of fuel used (and the attendant gas/solid waste by-products). 3.21.5 Conclusions MHD is not recommended as an energy source for the Bristol Bay region, the primary reason being that MHD is still in the early development stages and will not be ready for commercial power generation in the near future. B.3-107 • .. .. .. • ., • • .. -.. .. • .. .. .. .. .. .. .. .. .. r-----------------------------------------------------------------------------------------------... ~ on COAL PROCESSING & DRYING COAL e a COMBUSTOR GENERATOR SEED AIR MAKEUP SEED SEED PROCESSING SULFUR RADIANT SLAGGING FURNACE MHO AC POWER TO BUS AIR RECOVERED SEED AIR LOW TEMPERATURE AIR HEATER 1===1 GENERATOR CONDENSER AC POWER TO BUS TO STACK SEED RECOVERY o -• - MHO/STEAM POWER PLANT ------------------FIGURE 3.21-1----- 3.22 WAVE ENERGY CONVERSION SYSTEMS 3.22.1 General Discussion Wave energy conversion systems utilize the energy in waves by harnessing either, or both, the energy in the rise and fall of waves, or the traveling force of the wave itself. 3.22.2 State of Technology Wave energy is in the assessment of technical early stages feasibility. of resource identification and Research has primarily been undertaken by European countries who have a vested interest in the development of this highly attractive North Atlantic resource. 3.22.3 Conclus United States wave energy resources have not been identified, nor has the technology been demonstrated as technically feasible. It is recommended that wave energy conversion systems not be investigated further at this time as a potential source of power for the Bristol Bay region. B.3-l08 3.23 OCEAN CURRENT ENERGY 3.23.1 General Description Ocean current conversion systems extract the energy of currents and convert it to electrical energy. Two devices have received attention. The first is a drogue chute device composed of a series of parachutes in a continuous loop and driven by the current. The loop is connected to the drive shaft of an electrical generator. The second device being investigated is an axial flow turbine held below the ocean surface and faced into the current by moor ings . 3.23.2 State of Technology Ocean current energy conversion technology is in the very early stages of technical feasibility assessment. 3.23.3 Conclusions Ocean current resources, other than off the Florida coast, have not yet been identified as recoverable. The technology is still in the early stages of assessment. Therefore, this type of conversion system should not be investigated further as a source of power for the Bristol Bay region. B.3-109 .. .. • • .. -- • • .. • I11III • • 3.24 SALINITY GRADIENT ENERGY CONVERSION 3.24.1 General Description Salini ty gradients occur at the interface of the ocean and freshwater rivers. Power from salinity gradients can be obtained in several ways. Two approaches being studied are direct osmosis and reverse electrodialysis. of different salinity are water passes through the accomplished by allowing a This head is used to drive a In the osmotic exchange method, two masses separated by a semipermeable membrane. Fresh membrane by osmosis. Energy conversion is difference in hydrostatic pressure to build. hydroelectric turbine. In the reverse electrodialysis method, use is made of the electrical potential produced by combinations of anion-and cation-permeable membranes that allow one type of dissolved salt to pass through the membrane in one direction and the other in the opposite direction. Thus, the system acts much like a battery. 3.24.2 State of Technology Salinity gradient energy conversion is in the very early stages of development. 3.24.3 Conclusions Preliminary results of ongoing studies indicate ~hat salinity gradient technology will not be cost-competitive with other ocean energy conversion systems. Furthermore, the magnitude of estimated available resources compared to other ocean energy conversion systems is low. For these reasons, it is expected that research on salinity gradient technology will receive a lower priority compared to other systems. Therefore, this technology should not be considered further as an energy source for the Bristol Bay region. B.3-110 3.25 OCEAN THERMAL ENERGY CONVERSION (OTEC) 3.25.1 General Description The OTEC concept utilizes the temperature difference between relatively warm surface (0 to 160 ft) ocean water and colder, deep (over 3,000 feet) water to run a heat engine and generate electricity. In the typical closed cycle shown in Figure 3.25-1, warm water vaporizes and the cold water condenses a working fluid (ammonia is widely proposed) which drives a turbine-generator. The electrical energy is connected to the onshore grid via a transmission cable. Open cycles use ocean water as the working fluid. Warm water is evaporated under vacuum to produce low-pressure steam to drive a turbine-generator. 3.25.2 State of Technology The technical feasibility of OTEC systems has been proven and technical development is entering the pilot plant stage. 3.25.3 Conclusions DTEC should. not be given further cons ideration as a potential power source for the Bristol Bay region. A resource must be characterized by a minimum average temperature differential of 36 0 F between cold and warm water intakes (Ref. 59). Ocean thermal differences off the coast of Alaska are insufficient to support an OTEC system. The most promising regions in United States waters continue to be the Florida Gulf Stream, the Gulf of Mexico, and waters off Hawaii, Puerto Rico, the Virgin Islands, and Guam. B.3-111 -... ... ' .. Wi ., • • .. -- • .----------------------------------------------------------------------------.N 1ft WARM WATER PUMP EVAPORATOR CONDENSER .-BINARY CYCLE FLUID (e.g., FREON) CONDENSATE PUMP ELECTRIC GENERATOR COLD WATER PUMP OCEAN THERMAL ENERGY CONVERSION POWER PLANT ...... -------------FIGURE 3.25-1-" o .. • .. :c SE,CTION 4 CONCLUSIONS SECTION 4 CONCLUSIONS Various energy resources were reviewed as potential electrical power alternatives or energy supplements for the Bristol Bay region. Nine energy resources were identified as viable candidates for further study in the Bristol Bay Regional Power Plan. Of these nine alternatives, four resources are supplementary, that is, they can only be used to supplement other means of providing Bristol Bay's total energy requirements. The supplemental resources are: (1) energy conservation, (2) waste heat recovery, (3) wind energy, and (4) organic Rankine cycle. The remaining five viable energy candidates, which can be used individually or in combination to supply Bristol Bay's full power requirements, are: (1) diesel generation; (2) coal-, oil-, and natural-gas fired stearn electric generating units; (3) coal gasification; (4) combined cycle; and (5) hydroelectric power. Of the potential base load energy supply alternatives, hydroelectric and diesel generation were preselected for further study under Alternative Plan "A" and the Base Case, respectively. However, their individual comparisons with other energy alternatives within this task also confirmed that they should be given additional consideration. The supplemental energy alternatives were analyzed as follows: • Energy conservation must be encouraged at all levels, although it is difficult to convince individual consumers to undertake activities with only long-range benefits. Consumers of electricity and (space heating) fuel oil are more inclined to adopt energy conservation measures which have an immediate economic benefit, that is, turning down the horne thermostat to decrease space heating energy consumption. Regardless, energy conservation must be evaluated further, since additional methods B.4-l • • • of conserving energy become more desirable as fossil fuel prices continue to rise. Waste heat recovery encompasses a number of methods to more efficiently produce electricity and steam, hot water, or hot air simultaneously from a given source of fuel. The low temperature steam, hot water, or hot air produced as a by-product of electricity generation is usually suitable for space heating and use in industrial processes, for example, canneries. However, waste heat recovery is only justified when the steam/hot water/hot air recovered can economically displace existing process and space heating resources. Wind energy is a renewable resource which is technically feasible in the Bristol Bay region. However, without expensive energy storage equipment, such as batteries or pumped storage hydroelectric facilities, wind energy cannot be used for base electrical load. Wind should be evaluated as a "topping" system, which can supply electricity directly to the power grid, when wind is available. Organic Rankine cycle units provide a unique method of generating electricity from low temperature resources, such as waste heat from diesel generators. ORC units are commercially available and can be small in size to allow individual village installations. For example, the ORC unit could be used to generate additional electricity using a village's existing diesel generator waste heat, if proven economically feasible. The most reliable and efficient of the commercially available fossil fuel-fired electric generating stations are the steam turbine, combined cycle, and feasible in coal gasification units. These units are considered most the central station concept, since economies of scale are evident in each. B.4-2 ., ., • .. - ., • - ., .. • • .. ., ., .. • • .. Hydroelectric power offers a proven, . reliable source of energy for the region, which, when properly sited, creates minimal environmental impact. Being a renewable resource, hydroelectric generation also provides shelter from increasing fossil fuel prices. Several energy technologies were eliminated due to being in early development stages or not yet commercially demonstrated. These resources include (1) fuel cell, (2) magnetohydrodynamics, (3) wave energy conversion systems, (4) ocean current energy, (5) salinity gradient energy conversion, (6) nuclear fusion and breeder reactors, and (7) ocean thermal energy conversion. In addition, ocean thermal energy conversion (OTEC) is not feasible because of lack of a usable thermal gradient in the Bering Sea near Bristol Bay. Bristol Bay regional restraints proved insurmountable for waste/refuse power generation, geothermal energy, solar thermal energy, solar photovol taic electric systems, and tidal power. Generation of electricity by burning refuse is not feasible in Bristol Bay because there is not enough waste available to sustain a power station. Geothermal resources are unexplored and, as a result, not well defined in the region. If presently identified potential geothermal sources were explored and found to support electrical power generation, they would still be prohibitive distances from the load centers of the Bristol Bay region. Solar thermal and photovoltaic systems do not receive adequate sunlight in Bristol Bay to warrant further consideration as sources of electrical power. However, passive solar energy will receive additional space heating consideration in this study. Tidal ranges in the region are among the largest in the world, but geological conditions, load matching inabilities, ice effects, and anadromous fish constraints, and high costs, prove tidal power technology infeasible for Bristol Bay. The large-scale extraction of peat from the Bristol Bay lowlands to support electrical power generation is too environmentally deleterious to allow the construction of a peat-fired power station. However, peat utilization on a limited scale for space heating may be feasible and is being investigated by the Bristol Bay Native Association. B.4-3 The only biomass resource of any significance to electrical power generation in Bristol Bay is wood. The evaluation of wood-fired power generation produced results very similar to those of peat, except that wood resources are more scarce than peat. The adverse environmental impacts of burning wood to generate electricity are as severe as those for peat utilization. Wood also can be, and is being, used on a limited basis for space heating in the Bristol Bay area. Combustion turbines cannot compete economically with diesel generators, because of their low thermal efficiencies at reduced power output. The combustion turbine is being evaluated further in this study, as part of more efficient systems (waste heat recovery and combined cycle). Conventional nuclear power stations are not feasible to supply Bristol Bay power generation for many reasons. including regulatory uncertainty, costs, undesirable seismic conditions, and difficulties in obtaining operating personnel. B.4-4 • .. '* • -.. .. .. • • .. ., -.. .. .. • .. • lit .. iii • .. -,. SECTION 5 RECOMMENDATIONS SECTION 5 RECOMMENDATIONS The analyses of the numerous energy resources, addressed individually in Section 3, indicate that those most promising for application in the Bristol Bay region are as follows: • Diesel generation • Coal-, oil-, and natural gas-fired steam electric generation • Coal gasification • Combined cycle • Energy conservation • Waste heat recovery • Wind energy • Hydroelectric power • Organic Rankine cycle It is recommended that these technologies be studied in more detail for eventual development of the three Bristol Bay power plans. B.5-1 S:E:C'T'IO'N 6 . REFER·ENCES SECTION 6 REFERENCES 1. Olmsted, L. M. Electric Power Systems. In: McGraw-Hill Encyclopedia of Energy. McGraw-Hill Book Company, Inc., New York, N. Y., 1976. 2. Standard Practices for Stationary Diesel and Gas Engines, Sixth Edition. Diesel Engine Manufacturers Association, New York, N. Y., 1972. 3. National Research Council. Energy in Transition 1985-2010. Final Report of the Committee on Nuclear and Alternative Energy Systems, 1980. 4. Berman, Outlook. I. M. Fluidized Bed Combustion Systems: Progress and Power Engineering, Vol. 83, No. 11, November 1979, p. 46-56. 5. rCF Looks at Industrial Boilers and Fuel Choices. The Coal Observer, RI 658/03-09, September 1978, Dean Witter Reynolds Inc., New York, N. Y. 6. Environmental Applications, Inc. Summary Analysis: Power Plant and Industrial Fuel Use Act, Electric Generating Power Plants, Regulatory Requirements. San Diego, CA, (no date). 7. Cavanaugh, E. C.; Corbett, Assessment Data Base for W. E. and Page, G. C. Low/Medium-Btu Gasification Environmental Technology: Volume II. Appendices A-F. Radian Corporation. Prepared for the U. S. Environmental Protection Agency, Washington, D. C., November 1977. 8. Combined Cycle Plants-Gas Turbine Performance Specifications. Gas Turbine World Handbook 1981-1982. Vol. 6, p. 71-79. B.6-1 9. Robert W. Retherford Associates, Arctic District of International Engineering Co., Inc. Bristol Bay Energy and Electric Power Potential-Phase I. Prepared for the U. S. Department of Energy, Alaska Power Administration, Juneau, Alaska, December 1979. 10. Federal Power Commission. Gas Turbine Electric Plant Construction Cost and Annual Production Expenses. First Annual Supplement, Washington, D.C., 1973. 11. LeClerc, S. A., Stone & Webster Enginee.ring Corporation. Combined Cycles of Generation. Presented at Engineering and Operation Conference, Northwest Public Power Association, Portland, Oregon, April 27, 1979. 12. Alaska Center for Policy Studies. Energy Alternatives for the Railbel t, Study of End-Use Structure, Energy Conservation Potential, Alternative Energy Resources, and Related Public Policy Issues. Prepared for Alaska State Legis lature, House Power Alternatives Study Committee, Anchorage, Alaska, August 1980. 13. Comptroller General, U. S. General Accounting Office. Cogeneration What It Is, How It Works, Its Potential. Washington, D. C., April 29, 1980. Industrial EMD-80-7, 14. Power Engineering Editorial Staff. Cogeneration. Power Engineering, March 1978. 15. Brill, W. R. How Does an Industrial Company View Cogeneration? E. I. DuPont de Nemours & Company, Inc. Wilmington, Delaware, (no date). 16. Wind Systems Engineering, Energy Analysis, Phase 1 Inc. Bristol Bay Regional Power Plan Wind Preliminary Report. Prepared for Stone & Webster Engineering Corporation, Denver, Colorado, December 1981. B.6-2 - <II, 1111 -•• ." .. .. -.. .. .. • - • 17. Raddock, T. W. and Barnes, P. R. A Review of Utility Issues for the Integration of Wind Electric Generation. Proceedings of DOE/NASA workshop on Large Horizontal Axis Wind Turbines, July 1981. 18. Tennessee Valley Authority. Impact of Large Penetration of Wind Turbines on Electric Utility Operations. Progress -January 1982. Chattanooga, Tennessee, In 19. Zaininger Engineering Co. Wind Power Generation Dynamic Impacts on Electric Utility Systems. EPRI AP -1614, TPS 79 -775, November 1980. 20. Lee, S. T. and Yamayee, Z. Penalties for Intermittent PAS-100, No.3, March 1981. A. Load Following and Spinning Reserve Generation. IEEE Transactions, Vol. 21. Wayne, W. W. Jr. Final Report on Tidal Power Study for the United States Energy Research and Development Administratdon. Stone & Webster Engineering Corporation, March 1977. 22. Hartman, Charles W. and Johnson, Phillip R. Environmental Atlas of Alaska. Institute of Water Resources, University of Alaska, 1978. 23. U. S. Department of Commerce. Tide Tables 1982, West Coast of North and South America. National Oceanic and Atmospheric Administration, 1981. 24. U. S. Department of Commerce. Harnessing Tidal Oceanic and Atmospheric Administration, Current August 1978. Energy. National Issue Outline 78-2, 25. Wayne, W. W. Jr. North American Tidal Power Prospects. Prepared for International Journal of Ambient Energy. Stone & Webster Engineering Corporation, undated. B.6-3 26. Seoni, Raj. M. Major Electrical Equipment Proposed for Tidal Power Plants in the Bay of Fundy. IEEE Transactions on Power Apparatus and Systems, Vol. PAS-98, No.5, September/October 1979. 27. Wayne, W. W. Jr. The Current Status of Tidal Power; Can It Really Help? Stone & Webster Engineering Corporation, October 31, 1977. 28. Beikman, Helen M. Geologic Map of Alaska -1980. State of Alaska, Department of Natural Resources, Division of Geological and Geophysical Surveys. 29. Bernshtein, L. B. Tidal Energy for Electric Power Plants. Ministry of Electric Power Station Construction of the U.S.S.R. All-Union Planning and Design Institute, copyright 1965. 30. Behlke, C. E. and Carlson, R. F. An Investigation of Small Tidal Power Plant Possibilities on Cook Inlet, Alaska. URiversity of Alaska, Fairbanks, Alaska, April 1976. 31. Cinquemani, J. R.; Owenby, J. R. Jr.; and Baldwin, R. G. Input Data for Solar Systems, November 1978. 32. Niggemann, R. E., Greenlee, W. J., and Lacey, P. D. Fluid Selection and Optimization of an Organic Rankine Cycle Waste Heat Power Conversion System. Contributed by the Energetics Division of the American Society of Mechanical Engineers for presentation at the Winter Annual Meeting, San Francisco, Calif., December 10-15, 1978, ASHE Paper No. 78-WA/Ener-6. 33. Anderson, J. H. The Vapor Turbine Cycle for Geothermal Power Generation. Geothermal Energy: Resources, Production, edited by P. Kruger and C. Otte, Stanford Univ. Press, 1973. B.6-4 Stimulation, Stanford, CA, • .. ., - • ... .. .. .. .. • - - .. .. - 34. Hlinak, A., Lobach, J., Nichols, K.) Olander, R., and Werner, D. Final Design, Installation and Baseline Testing of 500 kW Direct Contact Pilot Plant at East Mesa. Prepared for U.S. Department of Energy by Lawrence Berkeley Laboratory, Report No. LBL-11153, May 1980. 35. Rapier, P. M. Design Features and Equilibrium Flash Hodeling of Direct Binary Fluid Heat Exchangers for Use With Geothermal Brines. Prepared for U. S. Department of Energy by Lawrence Berkeley Laboratory, Report No. LBL-12115, January 1981. 36. Helms, Stephen A. Considerations in Selecting Wood as an Immediate Source of Reliable and Economical Energy for Military Installat.ions. U.S. Department of Commerce, National Technical Information Service, AD-A071-791, December 1, 1978. 37. Solar Energy Research Institute. Use for Small Industrial Users. February 1980. Decis ionmaker' s Guide to Wood Fuel Final Report (SERI/TR-8234-1), 38. Hutchison, O. Keith. Alaska's Forest Resource. Institute of Northern Forestry, Juneau, Alaska. Pacific Northwest Forest and Range Experiment Station, U.S. Department of Agriculture. U.S. Forest Service Resource Bulletin PNW 19, reprinted 1968. 39. Marshall, H. G. W. Use of Wood Energy in Remote Interior Alaskan Communities. Reid, Collins Alaska, Inc. for State of Alaska, Division of Energy and Power Development, Anchorage, Alaska, September 1981. 40. JBF Scientific Corporation. Northeas'C Regional Assessment Study for Solar Elect.ric Options in the Period 1980-2000, April 1981. 41. Othmer, D. F. Peat for Power. Combustion, August 1978, p. 44-47. 42. Punwani, D. V. Peat Bogs Offer a Reliable, Local Source of Fuels in Several Sta'Ces. Power, October 1981, p. 106-109. B.6-5 43. Northern Technical Sevices and EKONO, Inc. Peat Resource Estimation in Alaska Final Report Volume I. Prepared under contract to State of Alaska for the U.S. Department of Energy, Grant No. DE-FGOl-79ET14689, August 1980. 44. Berman, 1. M. Developments in Geothermal Power Plants. Power Engineering, July 1981, p. 58-66. 45. Murphy, Mary and Etingh, Daniel J. Status. Geothermal Resources Council Geothermal E lectr ic Power Plant Transactions, Vol. 5, October 1981. Authors from the ~1itre Corp., McLean, VA. 46. Harrison, Glen. Notice of Proposed Changes in the Regulations of the Department of Natural Resources. Letter from the Director, Division of Minerals and Energy Management, Alaska Department of Natural Resources, August 24, 1981. 47. Healy, J. H. et al. The Denver Earthquakes. Science, Vol. 161, 1968, p. 1301-1310. 48. Markle, Donald R. Geothermal Energy in Alaska: Site Data Base and Prepared for U. S. Department of Energy, DOE/ET Development Status. 28476-T8, April 1979. 49. Smith, R. L. et al. Comprehensive Table Giving Physical Data and Thermal Energy Estimates for Young Igneous Systems of the United States. U. S. Geological Survey. Open-File Report 78-925. 50. U. S. Geological Survey. Assessment of Geothermal Resources of the United States -1978. Circular 790, Map #2. 51. Turner, Donald L.. et al. Geothermal Energy Resources of Alaska. Geophysical Institute, University of Alaska. Report to Division of Geothermal Energy, U. S. Department of Energy, UAG R-279, September 1980. B.6-6 .. .. .. .. • .. .. .. .. .. .. -.. .. • .. .. .. 52. Selkregg, L. L. Alaska Regional Profiles. For the State of Alaska, by the University of Alaska, Fairbanks, Alaska, undated. 53. Roberts, J. 0.; Davis, S. M.; and Nash, D. A. Coal and Nuclear: A Comparison of the Cost of Generating Baseload Electricity by Region. Office of Nuclear Reactor Regulation, U. S. Nuclear Regulatory Commission, Report No. NUREG-0480, December 1978. 54. National Research Council. U.S. Energy Supply Prospects to 2010. Report of the Supply and Delivery Panel to the Committee on Nuclear and Alternate Energy Systems, 1979. 55. Electric Power Research Institute. Overview and Strategy: 1981-1985. EPRI Journal, January/February 1981. 56. Electric Power Research Institute. 1980-1984 Research and Development Program Plan -Program Descriptions. (EPRI P-1309-SR), February 1980. 57. Research and Education Association. Modern Energy Technology Volume II. New York, N. Y., 1975. 58. Chapman, J. N.; Strom, S. S.; and \o/u, Y. C. L. HHD Steam Power-Promise, Progress, and Problems . University of Tennessee Space Institute. Mechanical Engineering, Vol. 103, No.9, September 1981. 59. Wolff, P.M. Temperature Difference Resource. Proceedings of the Fifth Ocean Thermal Energy Conversion Conference, Vol. 1, September 1978. 60. Telephone conversation between R. Stout (SWEC) and C. (Department of Natural Resources), July 1982. B.6-7 O'Conner "', t.., .. APPENDIX C ENERGY DEMAND FORECAST PRELIMINARY ELECTRICITY DEMAND FORECAST FOR THE BRISTOL BAY REGIONAL POWER PLAN by Oliver Scott Goldsmith William E. Nebesky Judy Zimicki Elsa Aegerter Teresa Dignan Institute of Social and Economic Research University of Alaska 707 A Street, Suite 206 Anchorage, Alaska 99501 February 1982 I. II. III. IV. V. VI. VII. VIII. TABLE OF CONTENTS Introduction . . . Residential Sector Residential Customers Residential Appliance Saturation Analysis (Use per Customer) Residential Energy Costs as a Proportion of Income Commercial/Government Sector Commercial/Government Customers Use per Customer Number of Customers Industrial Sector Shore-based Processors Fish Camps and Buy Stations Military Sector Electric Space Heating Residential . . . Commercial/Government Industrial Load Curve Individual Community Projections 1 10 10 14 19 35 35 38 41 43 43 46 49 50 53 55 57 59 62 1. 2. 3. 4. LIST OF TABLES Bristol Bay Power Plan Overall Energy Demand Projections . . . . Bristol Bay Regional Power Plan Energy Demand Projections by Customer ..... Historical Population Growth in the Eighteen Study-Area Communities . . . . Population and Households in the Bristol Bay Study Area . . . . 5. 1980 Residential Customers in Eighteen 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. Study-Area Communities Projected Appliance Electricity Consumption Power Cost Assistance Subsidy in Bristol Bay Base Year Electricity Prices With and Without the Power Cost Assistance Subsidy . . . . . 1980 Average Household Income in the Eighteen Bristol Bay Communities Projected Household Income and Residential Energy Consumption for Central-Station Communi ties . . . . .. ..... . Projected Household Income and Residential Energy Consumption for Seasonal/Central- Station Communities .. ..... . Projected Household Income and Residential Energy Consumption for Noncentral Station Communi ties . . . . . . . . . . 1980 Electricity Consumption in the Bristol Bay Commercial/Government Sector . . . . Commercial and Government/Community Buildings. 1981 . . . . . . Historic Growth in Electricity Use per Customer for Selected Utilities Average Annual Rate of Growth in Residential and Commercial Customers: United States. Alaska. and Bristol Bay Utilities .... .. 7 8 .. 11 13 15 .. 18 20 .. 21 25 27 .. 28 .. -.. 29 36 .. 37 .. .. 38 .. 41 .. • 17. Growth in Use per Customer and Number of Customers in the Commercial lB. 19. 20. 21. 22. 23. 24. 25. 26. 27. 2B. 29. 30. 31. 32. 33. 34. Government Sectors Electricity Consumption by Bristol Bay Fish Processors: 19BO . Average 19BO Production at Nushagak and Kvichak Bay Fish Processors . Bristol Bay Seafood Processor Electricity Demand Projections Bristol Bay Fish Camps and Buy Stations Electricity Demand Projections Electricity Break-Even Prices for Typical Residential Heating System Conversions in Bristol Bay Space Heating in 1980 in the Eighteen Study-Area Communities . Space Heating by Commercial/Government Users in 1980 . . . . Bristol Bay Electricity Consumption, All Communities . Bristol Bay Electricity Consumption, Aleknagik/Dillingham Bristol Bay Electricity Consumption, Naknek, South Naknek, King Salmon Bristol Bay Electricity Consumption, Egegik Bristol Bay Electricity Consumption, Manokotak Bristol Bay Electricity Consumption, New Stuyahok . . Bristol Bay Electricity Consumption, Ekwok Bristol Bay Electricity Consumption, Portage Creek . . Bristol Bay Electricity Consumption, Koliganek Bristol Bay Electricity Consumption, Iliamna 42 44 45 47 48 52 54 56 63 64 65 66 67 68 69 70 71 72 35. 36. 37. 38. 39. 40. 41. 1. 2. 3. 4. 5. 6. 7. 8. 9. Bristol Bay Electricity Consumption, Newhalen Bristol Bay Electricity Consumption, Nondalton Bristol Bay Electricity Consumption, Iliamna, Newhalen, Nondalton . Bristol Bay Electricity Consumption, Clark's Point . . . . Bristol Bay Electricity Consumption, Ekuk Bristol Bay Electricity Consumption, Levelock Bristol Bay Electricity Consumption, Igiugig LIST OF FIGURES Projected Electricity Prices in Bristol Bay Projected Heating Fuel Price in Bristol Bay Household Income, Electricity Expenditures, and Household Heating Expenditures for Central Station Communities, 1980-2002 Household Income, Electricity Expenditures, and Household Heating Expenditures for Seasonal Central-Station Communities, 1980-2002 .. . Household Income, Electricity Expenditures, and Household Heating Expenditures for Noncentral Station Communities, 1980-2002 Nonresidential Electricity Consumption per Customer for Selected Southwest Alaska Utilities . Nonresidential Electricity Consumption per Customer for Selected Alaska Utilities in the Railbelt Region Nushagak Electric Cooperative, Inc., Monthly Sales, 1980 .... Naknek Electric Association Sales, 1980 • • 73 .. 74 .. . 75 76 77 .. 78 79 .. • 23 24 - 30 .. • 31 - • 32 • 39 40 60 61 • .. I. Introduction This report contains a preliminary forecast of electrical energy demand for the eighteen study-area communities included in the Bristol Bay Regional Power Plan. The preliminary forecast is based on a methodology that analyzes appliance saturation, uses historical data from utilities within and outside of Bristol Bay, and analyzes the potential limits of electricity consumption based on income con- straints. In this sense, it is similar to the methodology we intend to use in the final energy demand projections. The major distinction between this preliminary forecast and the final version (forthcoming) is that the SCIMP-model economic proj ections are not included here. Consequently, population and income growth in this forecast are based on our informal interpretation of probable economic development in Bristol Bay over the next two decades. Furthermore, alternative electricity supply scenarios are still under investigation at this time. Our assumptions about how electricity is supplied may even- tually be replaced by different interpretations of future price and availability. The electricity-consumption forecasts in this report are based on a "business-as-usual" interpretation of future economic activity and energy-use patterns. Essentially, we assume trends in economic deve- lopment and energy-use that are similar to recent historical patterns. The business-as-usual scenario is based on the following key assumptions: 1. 2. 3. 4. 5. Electricity is primarily diesel powered. Electricity production remains decentralized so that economies of scale (savings in money outlays due to efficiencies inherent in larger-scale operations) do not offset rising fuel prices. Consequently, elec- tricity prices escalate at the same rate as fuel oil prices--2.6 percent per year above the general rate of inflation. Electricity prices are not uniform across study-area communities. The effect of state intervention to lower electrici ty prices continues throughout the period, consistent with levels experienced consumer forecast in 1981. Electricity patterns do not change dramatically from those observed in the recent past. Thus, electric space heating and energy conservation are assumed not to occur in this forecast. (See discussion of electric space heat in Section VI.) The eighteen study-area communities have been grouped into cate- gories reflecting the degree of electrification in the 1980 base year. These categories are: Central-Station Utility Dillingham Aleknagik Naknek South Naknek King Salmon Egegik Manokotak New Stuyahok Seasonal Central-Station Utility (school generator off in summer) Portage Creek Ekwok Koliganek 2 .. .. .. .. ... .. .. .. .. -.. • .. • ., Noncentral-Station Utility Iliamna Newhalen Nondalton Clarks Point Ekuk Levelock Igiugig These categories were developed for two reasons. First, setting aside differences in economic characteristics, communities having similar electrification properties are likely to share common price levels and availability constraints, which are important determinants of electricity-use. Second, limited data restricted the accuracy and scope of the analysis, especially on a community level. By merging communities into larger groups, the information base is enlarged and possibly more reliable. It should be stressed that the community groups were selected on the basis of characteristics in the base year. This does not mean that characteristics pertaining to the degree of electrification are retained by communities of a given group throughout the forecast interval. In fact, we assume that all communities presently class i- fied as "noncentral" become electrified by 1987. Electrification is currently underway in Iliamna, Newhalen, and Nondalton, all of which anticipate having central-station power by late 1982. Our analysis captures the effects of electrification as well as the influence of seasonal variation on patterns of energy use. 3 The forecast methodology classifies electricity consumers into four groups: Residential Commercial/Government Industrial Military Residential consumers in this study are the same as the utility classification. For communities without utilities, residential con- sumers are equal to the number of households that are hooked into village or school electricity or that have their own generators. Commercial/Government (C/G) consumers encompass all other civil- ian electricity customers except those involved in seafood processing. Thus, our definition of C/G consumers includes both small commercial and large power (LP) customers under the conventional utility classi- fication. The C/G classification used in this report covers a wide range of users having varied energy-use characteristics (e.g., schools versus the village store). To account for these possibly significant differences in our forecast, we have further divided C/G consumers into types having relatively uniform energy-use characteristics such as schools, village stores, and community centers. Industrial consumers consist exclusively of large shore-based seafood processors, fish camps, and buyers. At present, seafood processing represents Bristol Bay's only industry. Seafood processors 4 • • ., .. .. ., .. • .. JIll .. .. .. • .. .' .. • .. .. 111:# use large quantities of electricity over a short time period, creating special circumstances for forecasting. Military consumers consist of the Alaska Air Command Station in King Salmon. The general forecast methodology used throughout this study is based on the following relationship: Annual Electricity Consumption = Number of Customers x Average Electricity Use per Customer The number of consumers (C) and average use per customer (AU) are estimated in the base year for each consumer category across all eighteen Bristol Bay communities. The base year estimates of C and AU are calculated from field data collected from several sources in the fall of 1981 by study team members of the Institute of Social and Economic Research (ISER). The primary sources are: 1. Village leaders and other Bristol Bay inhabitants knowledgeable about energy use 2. Bristol Bay electric utilities 3. Bristol Bay regional school districts 4. Household l and commercial/government surveys 5. Alaska Village Electric Cooperative 6. Fish processors lWe are especially grateful to Dillingham High School energy students and the Naknek High School senior class for their participa- tion in a lengthy and valuable household survey. 5 Although we encountered discrepancies in the count of households and population from different sources, we used the 1980 U. S. Census count for base year estimates because it offered a uniform data base across all eighteen study-area communities. We then estimated growth rates to allow for increases in C and AU over the forecast period. The growth rates are derived in part from an analysis of historical energy-use patterns from Bristol Bay utili ties, from AVEC, and from southwest utilities outside of the immediate Bristol Bay study area. Growth rates for C and AU are calculated for each of the three communi ty electrification groups described above (central, seasonal! central, and noncentral). To forecast energy use for individual communities, we assigned to individual communities the growth rates for C and AU corresponding to the larger community group. Thus, electricity-use forecasts were performed on two levels of aggregation: (1) the three community electrification groups and (2) the eighteen individual communities. Aggregate electricity consumption is the same in each case. Table 1 summarizes total electricity growth for all eighteen communities by consumer classification. Table 2 provides greater detail by breaking out the projected number of consumers and electricity use per consumer for the central, seasonal! central, and noncentral community groups. Projections for individual communities are shown in Table 25 through 41 at the end of this report. As discussed above, we assume that electric space heating does not occur in this forecast. However, we calculate base year levels of fuel oil consumption and convert these estimates into electricity- 6 .. ,. .. .' .. .. .. ... .. .. .. .. .. .. .. • .. .. .. .. • • 1980 1982 1987 1992 1997 2002 1980-2002 Overall Average AnIlUal Rate of Growth (percent) TABLE 1 BRISTOL BAY POWER PLAN OVERALL ENERGY DEHAND PROJECTIONS (HEGAWATT HOURS/YEAR) Residential Conmlercial/Gov't trial % of % of % of Total Total Total Total Total Total Total 4,459 16 9;629 34 8,248 30 5,600 4,936 16 10,957 36 8,879 29 5,600 6,249 17 15,083 42 8,952 25 5,600 7,937 18 20,789 48 9,025 21 5,600 10,060 19 28,642 54 9,098 17 5,600 12,743 19 39,632 59 9,098 14 5,600 4.89% 6.64% 0.45% 0% % of Total Total 20 27,936 19 30,372 16 35,884 13 43,351 10 53,400 8 67,073 4.06% TABLE 2 BRISTOL BAY REGIONAL POWER PLAN ENERGY DE~IAND PROJECTIONS BY CUSTOl1ER Number of Customers Elect. Consu'"(l., (ler Customer (KWH) Total Electricity: ConsumEtion (HW'H) Seasonal Non-Seasonal Non-Seasonal Non- Central Central Central Total Cenlral Central Centra I Central Central Central Total --- Residenlial -~---~.-- 1980 810 68 82 960 5,152 1,308 2,401 4, f73 89 197 4,459 1982 859 71 90 1,020 5,175 3,027 3,062 4,445 215 276 4,936 1987 996 81 114 1.191 5.585 3.413 3,597 5.563 276 410 6,249 1992 1,154 91 145 1,390 6.046 3,829 4,222 6,977 348 612 7,937 1997 1,338 103 184 1,625 6,507 4,274 4.965 8,706 440 914 10,060 2002 1,551 117 234 1,902 6.969 4,808 5,857 10,809 563 1,371 12,743 Conlllle c£.!il I /Government 1980 355 19 69 443 22,473 13,092 20,322 7,978 249 1,402 9,629 1982 386 20 74 480 23,598 13,704 21,272 9,109 274 1,574 10,957 1987 476 22 88 586 26,569 15.362 23,845 12,647 338 2,098 15,083 1992 587 23 106 716 29,914 17,220 26,729 17,560 396 2,833 20,789 1997 724 25 126 875 33,680 19,303 29,963 24,3.84 483 3,775 28,642 2002 896 27 151 1.074 37,920 21,638 33,587 33,976 584 5,072 39.632 IllduslCl d 1 a -----~ .. --sll Camps & Fish Camps & Fish Camps & fan only Freeze ~~~L!i..ta lions Total Ca~ Freeze ~tations Can Only: Freeze Buy: Stations Total 19!10 3 10 40 53 486,000 583,000 24,000 1,458 5,830 960 8,248 1984 3 11 42 56 486,000 583,000 24,000 1,458 6,413 1,008 8,879 1987 2 12 41 55 486,000 583,000 24,000 972 6,996 984 8,952 1992 1 13 40 54 486,000 583,000 24,000 486 7,579 960 9,025 1997 0 14 39 53 0 583.000 24,000 0 8,162 936 9,098 2002 0 14 39 53 0 583,000 24,000 0 8,162 936 9,098 ----_ .. _----._---,---- " nol correspond to Village for residential and commercial/government. Dot·s graul's r , I , 1 J I , , I I , I I " , I , , , , I I • , I I I , I , . , I t I equivalent measures to show the comparable electricity load under the hypothetical case of 100 percent electric space heating. We allow for growth of electricity-equivalent space-heating consumption under housing-stock assumptions consistent with those used in the analysis of pure appliance demand, excluding conservation measures. The results are shown in Section VIII and in Tables 25 through 41. The following sections of the report discuss methodology in greater detail and present background information used in the analysis of base year levels and growth rates. The reader is reminded that these projections are preliminary. A final version forthcoming will incorporate possibly different assumptions about the supply of elec- tricity as well as different methods to calculate electricity use. 9 II. Residential Sector Energy demand in the residential sector is based on several important factors. They are: 1. 2. 3. 4. 5. 6. 7. Population growth Concentration of census division population in the eighteen-community study area Saturation of electric hookups Decrease in household size Village electrification Energy prices Household income 8. Saturation of electric appliances 9. Conservation potential Although to some extent the above factors are interdependent, the first four factors strongly relate to the number of residential cus- tomers. The remaining factors pertain more closely to the question of average electricity use per customer. Conservation potential applies primarily to electric space heat, which we assume does not occur in this preliminary forecast. Residential Customers. We assume that overall population growth in the eighteen-community study area will equal between 1.5 and 2.0 percent per year. This is less than the historical rate of 2.4-to-2.5 percent shown in Table 3. The historical rate reflects, in 10 • .. .i • .. • • .. .. .. .. • .. .. .. .. .. .. TABLE 3. HISTORICAL POPULATION GROWTH IN THE EIGHTEEN STUDY-AREA COMMUNITIES Civilian Population Central Station Dillingham Aleknagik Naknek King Salmon South Naknek Egegik Manokotak New Stuyahok All Villages 1960 424 231 249 227 142 150 149 145 1,717 Seasonal-Central Station Portage Creek Ekwok Koliganek All Villages Noncentral Station Iliamna Newhalen Nondalton Clarks Point Ekuk Levelock Igiugig All Villages Total All Villages o 106 100 206 47 63 205 138 40 88 o 581 2,504 914 128 178 202 154 148 214 216 2,154 o 103 142 245 58 88 184 95 51 74 36 586 2,985 1980 1,563 154 317 161 147 75 294 3,042 50 77 116 243 94 87 173 79 7 80 33 553 3,838 Average Annual Growth Rate (percent) 1960-1980 1970-1980 2.9 3.5 0.8 -0.1 -0.2 -0.6 2.2 2.6 SOURCE: U.S. Department of Commerce, Bureau of the Census, 1980. 11 part, the effects of rapid economic growth from fisheries expansion in the latter 1970s. We assume that the fish economy will stabilize at a maximum sustainable yield comparable to actual harvest levels recorded over the past few years. Population has also increased from regional shifts concentrating in the eighteen-community study area as well as non-Native in-migra- tion from outside the study region. We assume that population will continue to concentrate in the Central-Station communities. The average annual rate of population growth assumed for each community group was multiplied by a factor to account for the decline in average household size. As shown in Table 4, average household size fell dramatically, especially in rural communities. We assume this trend continues at a reduced rate of 1.0 percent per year over the projection period. This implies an average household size of 2.74 by 2002. The product of average annual rate of population growth and the annual rate decline in average household size yields an estimate of the growth in residential customers. These calculations are shown below for each category of village grouping. 12 II' .. .. .. ., .. .. .. -.. • .. • WI .. - III .. .. • - .. • lit .. .. • -.. TABLE 4. POPULATION AND HOUSEHOLDS IN THE BRISTOL BAY STUDY AREA Rate of Decline 1 9 7 0 8 0 in Avg Household Size (Eercent/~r) Central Station POE HH POE HH Dillingham 914 238 1563 467 Aleknagik 128 22 154 38 Naknek 178 45 317 King Salmon 202 62 161 246 South Naknek 154 34 147 Egegik 148 35 75 23 Manokotak 214 37 294 57 New Stuyahok 216 32 331 65 TOTAL 2,154 505 896 Avg. Household Size 4.27 3.40 2.3 Seasonal-Central Station Portage Creek NA NA 50 13 Ekwok 103 24 77 20 Koliganek 142 19 116 40 TOTAL 245 43 243 73 Avg. Household Size 5.70 3.33 5.5 Iliamna 58 15 94 35 Newhalen 88 14 87 18 Nondalton 184 29 173 42 Clarks Point 95 16 79 22 Ekuk 51 8 7 1 Levelock 74 14 80 28 Igiugig 36 8 15 TOTAL 586 104 553 161 Avg. Household Size 5.64 3.44 5.1 All Eighteen Communities Average 4.58 3.40 3.0 Household Size Source: U.S. Dept. of Commerce, Bureau of the Census 1970, 1980. 13 ., • Rates of Change Projected Rate -Decline in of Growth in Population Average Residential Forecast Village Grouping Growth Household Size Customers Period • Central 1.02 x 1. 01 = 1.03 1980-2002 Seasonal-Central 1. 015 x 1. 01 = 1.025 1980-2002 ., Noncentral 1. 015 x 1.01 x (1. 023) = 1.049 1981-2002 ... ., Growth in noncentral station residential customers was augmented -by an additional factor (1.023) to capture the positive effect of - village electrification. This growth factor was derived from the appliance saturation analysis (discussed below) for household lights, a proxy for the effect of village electrification on the number of ... residential customers. The introduction of this factor causes the number of noncentral-station residential customers to grow more rapidly than in central or seasonal/central communities. These growth -rates were applied directly to the number of base-year residential customers shown in Table 5 for 1980. Residential Appliance Saturation Analysis (Use per Customer). The .' projection of annual electricity use per residence is based on an analysis of appliance saturation rates for the forecast period in each village. Electricity use for space heating in the Bristol Bay study area is negligible for the residential sector. Therefore, the present and future electricity demand for this sector reflects only the owner- ship and use of appliances by each residence. • .. 14 .. TABLE 5. 1980 RESIDENTIAL CUSTOMERS IN EIGHTEEN STUDY-AREA COMMUNITIES Dillingham Aleknagik Naknek King Salmon South Naknek Egegik Manokotak New Stuyahok Portage Creek Ekwok Koliganek Iliamna Newhalen Nondalton Clarks Point Ekuk Levelock Igiugig 1980 Residential Customers 443 241 23 49 54 810 12 20 36 68 21 18 11 10 1 11 11 83 Hookup Saturation Rate a .88 .98 1.00 .86 .83 .90 .92 1. 00 .90 .93 .60 1. 00 .26 .45 1. 00 .39 .75 .52 Total Eighteen Communities 961 .85 a Equals the number of residential customers divided by households (census definition). SOURCE: U.S. Department of Commerce, Bureau of the Census, 1980. ISER Field Survey 15 Appliance saturation is defined as the number of residences in a particular village which own one or more of a given appliance divided by the number of residences in that village. With this definition, 100 percent is the maximum possible saturation rate. Appliance satu- ration levels for 1981 are based primarily on interviews and surveys in each village conducted by the ISER study team. A projected appli- ance saturation curve for 14 appliances with the greatest annual energy demand was constructed for each appliance in each village. 2 Construction of the curves was based on (1) historical and present use pattern in the Bristol Bay region, other rural areas in Alaska, and in each village; (2) present and expected percentage of residences with electricity in each village; (3) the desire for particular appliances in each village; and (4) specific plans for future development, such as installation of a satellite television station or a village water system. From the saturation curves, an average saturation rate at five- year intervals from 1982 to 2002 was calculated for the three village categories. Based on present and expected use patterns (hours!yr), appliance energy ratings (kw), the average number of the appliance per residence, and the calculated saturation rates, an estimate of annual electricity use for the average residence was calculated for each village category. It is assumed that all the communities will receive 2Appliances used for the analysis include home freezers, dish- washers, electric ranges, clothes washers, clothes dryers, televi- sions, refrigerators, lights, electric water heaters, radios, stereos, tapedecks, headbolt heaters, and miscellaneous small appliances. 16 • .. • .. .. • 'W ... '. '. ,Ii-. "' •• I., central station utility electricity within the forecast period. (This assumption explains the higher growth factors in the noncentral vil- lage category where the conversion to central-stateion electricity lowers the price and stimulates consumption.) From this analysis, a growth rate in electricity consumption per residence was calculated. A contingency factor of 0.25 percent was added to this calculated growth factor in each village category to account for new appliances. In the study area, a significant percentage of households are vacated for the fishing season. The 1981 consumption values derived from the appliance saturation analysis were corrected for this sea- sonality to reflect the decreased consumption of electricity during the two or three summer months in which either the village received no power or many of the village residents were gone. The projections for annual electricity consumption per residence for the three village categories are summarized in Table 6. The calculated number of residential customers and average annual electricity use per customer were multiplied to obtain annual residen- tial energy consumption for each village grouping (Table 2). Note that the appliance saturation analysis produced a significantly higher level of average consumption in 1981 than our field survey estimate for 1980. This discrepancy is under investigation, but in the 17 interim, we chose to use the higher figure derived from the appliance saturation analysis for forecasting purposes. The small relative size of this village category minimizes the effect of changing this average consumption figure. TABLE 6. PROJECTED APPLIANCE ELECTRICITY CONSUMPTION (kwh/yr/customer) Central Utilitya Central-Seasonal b NonCentral c 1981 5,124 2,968 2,973 1982 5,115 3,021 3,062 1981 5,585 3,413 3,591 1992 6,046 3,829 4 222 1991 6,501 4,214 4,965 2002 6,969 4,808 5,851 Average Annual Rate of Growth 1.48 2.31 3.21 (percent/year) aAleknagik, Dillingham, Egegik, King Salmon, Manokotak, Naknek, New Stuyahok, South Naknek. b Ekwok, Koliganek, Portage Creek. cClarks Point, Igiugig, Iliamna, Levelock, Newhalen, Nondalton. SOURCE: See text. 18 .. .. .. .. .. -.. • ., .. • ., .. • .. • .. Residential Energy Costs as a Proportion of Income. To illus- trate the implications of our analysis of residential electricity demand, we constructed several tables that compare future residential energy costs with future household income. The analysis is based on electricity prices adjusted to incorporate the subsidy implied by the Power Cost Assistance program, administered by the Alaska Power Authority. The Power Cost Assistance Program is designed to provide relief to customers of regulated electric utilities whose costs are inflated by their geographic or fuel supply situation. Application for assis- tance is made to the Alaska Public Utilities Commission (APUC) on a very detailed energy cost balance sheet. After the applicant verifies costs, the APUC establishes an assistance level. Requests for increases in cost assistance can be made at any time after initial award. For residential and small commercial consumers. the Power Cost Assistance Program will cover 95 percent of the cost between 12~ and 45~ per kwh up to a limit of 600 kwh/month/customer. In addition, communities receive a credit of 55 kwh/month/resident for each com- munity facility. An upper limit of 31. 35~/kwh has been established for the assistance level of the program. In December 1981, utilities in Ruby and Bettles were awarded this maximum amount. 19 In the Bristol Bay study area, four utili ties are receiving or have received power cost assistance under the present program and its predecessor, the Power Production Assistance Program. Levels of assistance for each utility are tabulated in Table 7. The Alaska Village Electric Cooperative (AVEC) is currently applying for a rate increase under the Power Cost Assistance Program. Nushagak Electric Cooperative (NEC) is the only utility in the study area which has already shifted to this program. In January 1982, NEC will receive assistance of 7.03C/kwh. 1980 1981 TABLE 7. POWER COST ASSISTANCE SUBSIDY IN BRISTOL BAY (C/kwh) Nushagak Electric Naknek Electric Alaska Village Cooperative Association Electric Cooperative Naknek Egegik New Stuyahok Oct. 14.59 Nov. 17.83 Dec. Jan. 5.00 Feb. 5.10 6.68 20.31 Mar. Apr. 5.70 May June July Aug. Sept. 6.73 23.70 Oct. Nov. 7.54 Dec. 5.83 26.93 20 .. .. .. .. .. • .. .. .. .. .. .. The overall effect of Power Cost Assistance in the eighteen study-area communities is shown in Table 8 for each village grouping. TABLE 8. BASE YEAR ELECTRICITY PRICES WITH AND WITHOUT THE POWER COST ASSISTANCE SUBSIDY (¢/kwh) 1980 1981 Village Category a Nonsubsidy Subsidy Nonsubsidy Central 24.5 24.3 26.6 Seasonal-Central 26.8 26.8 26.8 Noncentral b 124.0 124.0 132.0 19.2 26.8 132.0 aVillage prices weighted by total 1980 residential electricity consumption to derive average price (¢/kwh) for village groups. b N 1 . . b d h f 11 . . oncentra stat~on pr~ces are ase on teo ow~ng assumpt~ons: 1. 2. 3. 4. 5. 919 gallons/year x $1.20/gallon Operation and maintenance Depreciation ($5,000, 3-year life) Labor: 40 hrs/year @ $8.00/hr. Average annual electricity consumption = $1,103 = 200 = 1,666 = 320 $3,289 2,401 kwh 6. Average cost equals: $3,289 + 2,401 = $1.37/kwh 7. Since labor has an implicit wage that does not appear in household income, the labor cost is excluded from noncentral prices used in this analysis. 21 We allow the base year price of heating fuel and electricity (subsidy and nonsubsidy) to grow at an average annual inflation- adjusted rate of 2.6 percent per year. graphically in Figures 1 and 2. This is illustrated Average household income was calculated for each study area village as shown in Table 9. Household income was assumed to grow at 1 percent per year over inflation in each village category. This assumption captures the dampening effect of decreasing average house- hold size on average household income. As average household size declines, personal income is distributed over more households having fewer income-earning members than under conditions of stable or increasing household size. The results of our assumptions on the level and growth of energy price, household income, and on average residential heating fuel and electricity consumption are brought together in Tables 10, 11, and 12 for respective village groupings. These calculations were performed to compare our assumptions on future energy prices and on future energy consumption to reasonable estimates of average household income. Figures 3, 4, and 5 graphi- cally illustrate the comparisons shown in Tables 10, 11, and 12, respectively. 22 .. It> • ... • .. ., Il0l. ., .. - ., .. .. ., .. -.. $/KWH 3.00 2.50 2.00 .50 .269 .256 .243 .310 .231 o 1980 1981 FIGURE 1. 1985 PROJECTED ELECTRICITY IN BRISTOL BAY PRICES .530 .460 Central .400 central 1990 1995 2000 20 2 23 • - $/GAL ., .. 3.00 III! ?;,? FIGURE 2. PROJECTED HEATING FUEL PRICE '1,' ., IN BRISTOL BAY ... • .. 2.50 ., ')Ur '].. .. .' .. ... 2.00 .. .. .. &; 1.52 .. 1.50 .. 1.33 .. ., .. .. 1.00 ... ... .. . ' III .50 .. .. .. .. .. 0 1980 1981 1985 1990 1995 2000 2002 .. 24 .. "" •• TABLE 9. 1980 AVERAGE HOUSEHOLD INCOME IN THE EIGHTEEN BRISTOL BAY COMMUNITIES 1980 Est. Personal Number of Income ($) a Dillingham 15,679,040 480 Aleknagik 822,587 38 Naknek King Salmon 9,467,772 261 South Naknek Egegik 201,683 23 Manokotak 987,500 57 New Stuyahok 1,090,908 65 TOTAL 28,249,550 924 Portage Creek b NA NA Ekwok 214,291 20 Koliganek 381 ,422 40 TOTAL 595,714 60 Iliamna 1,286,416 35 Newhalen 18 Nondalton 322,257 42 Clarks Point 569,239 22 Ekuk 1 Levelock 172,326 28 Igiugig c NA NA TOTAL 2,350, 146 All Communities 31,195,441 1,130 Average Household Income ($/IDI) 32,665 21,647 36,275 8,769 17,325 16,784 30,573 NA 10,715 9,536 9,929 24,272 7,673 24,750 6,155 NA 27,607 SOURCE: Alaska Department of Revenue, "Individual Income Tax Paid in 1978 by Alaskan communities. U.S. Department of Commerce, Bureau of the Census, 1980. NOTES: On following page. 25 Notes: Table 9 apersonal income in 1980 is estimated from 1978 taxable income using the following adjustment from U.S. income statistics: 1. Taxable Income (U.S.) Adjusted Gross Income (U.S.) = 1063.3 1304.2 = .815 (1978 Statistics of Income) 2. Adjusted Gross Income (U.S) Personal Income (U.S.) = 406 0 = .817 1721.8 (BEe Survey of current business, Nov. 1981, pg. 24) 3. 4. S. Personal Income = Taxable Income 1 x .817 1 = 1.224 x 1.227 = I.S02 .81S Thus, 1978 taxable income by village was multiplied by I.S02 to derive an estimate of personal income in 1978. To calculate personal income in 1980, we multiplied 1978 income by 20 percent growth from 1978 to 1979 based upon BEA income data and by half that growth rate from 1979 to 1980. b Included in Dillingham figures. clncluded in King Salmon figures. 26 ., • .. • ., • ., Year 1980 1981 1982 N '-J 1987 1992 1997 2002 Average Household Income ($/HH) $30,573 30,879 31,188 32,778 34,450 36,208 38,055 TABLE 10. PROJECTED HOUSEHOLD INCOME AND RESIDENTIAL ENERGY CONSUMPTION FOR CENTRAL-STATION COMMUNITIES a Average Average Average Household Average Average Household Average Household Heating Heating Household Proportion of Electricity Electricity Electricity Fuel Fuel Heating Household Income Consumption Price Expenditures Consump. Price Expenditures Spent on (kwy/HH) ($/kwh) ($/HH) (gal./HH) ($/gal.) ($/HH) Electricity Heating Fuel 4,718 $.243 $1,146 1,053 $1. 33 $1,401 3.7% 4.6% 5,124 .231 1,184 1,064 1.55 1,649 3.8 5.3 5,175 .237 1,226 1,074 1.59 1,708 3.9 5.5 5,585 .269 1,502 1,129 1. 81 2,043 4.6 6.2 6,046 .306 1,850 1,187 2.06 2,445 5.4 7.1 6,507 .348 2,264 1,247 2.34 2,918 6.3 8.1 6,969 .396 2,760 1,311 2.66 3,486 7.3 9.2 aDillingham, Aleknagik, Naknek, King Salmon, South Naknek, Egegik, Manokotak and New Stuyahok. Electricity and Heating Fuel 8.3 9.1 9.4 10.8 12.5 14.4 16.5 Year 1980 1981 1982 N 00 1987 1992 1997 2002 Average Household Income ($/HH) $ 9,929 10,028 10,129 10,645 11 , 188 11 ,759 12,359 Average TABLE 11. PROJECTED HOUSEHOLD INCOME AND RESIDENTIAL ENERGY CONSUMPTION FOR SEASONAL/CENTRAL-STATION CO~ftruWITIESa Average Average Household Average Average Household Average Household Heating Heating Household Proportion of Electricity Electricity Electricity Fuel Fuel Heating Household Income Consumption Price ExpenJitures Consump. Price Expenditures Electricity and (kwh/HH) ($/kwh) ($/HH) (gal./HH) ($/gaJ.) ($/HH) Electricity Heating Fuel Heating Fuel 1,308 $.269 $352 1,001 $1.33 $1,331 3.5% 13.4% 16.9% 2,968 .269 798 1,011 1. 36 1,375 8.0 13.7 21.7 3,027 .276 835 1,021 1.40 1,429 8.2 14.1 22.3 3,413 .314 1,072 1,073 1.59 1,706 10.1 16.0 26.1 3,829 .357 1,367 1,128 1. 81 2,042 12.2 18.3 30.5 4,274 .406 1,735 1,185 2.06 2,441 14.8 20.8 35.6 4,808 .461 2,216 1,246 2.34 2,916 17.9 23.6 41.5 aportage Creek, Ekwok, and Koliganek. , , • I " I I ,. I , , • • , r , , • , , , , , , " ,. , , , , 'I 'I N \J:) Year 1980 1981 1982 1987 1992 1997 2002 Average Household Income ($/IIH) $16,098 16,259 16,442 17 ,253 18,140 19,066 20,037 TABLE 12. PROJECTED HOUSEHOlD INCOME AND RESIDENTIAL ENERGY CONSUMPTION FOR NONCENTRAL STATION COMHUNITIES a Average Average Average Household Average Average Household Average Household Heating Heating Household Proportion of Electricity Electricity Electricity Fuel Fuel Heating Household Income Consumption Price Expenditures Consump. Price Expenditures Spent on (kwy/HH) ($/kwh) ($/HH) (gal./HH) ($/gal.) ($/HH) Electricity Heating Fuel 2,401 1. 24 $1,608 1,421 1.52 $2,158 10.0% 13.4% 2,973 1.32 3,924 1,435 1.66 2,382 24.1 14.7 3,062 1.36 4,164 1,450 1. 70 2,465 25.3 15.0 3,597 1. 54 5,539 1,524 1.94 2,957 32.1 17 .1 4,222 0.357 b 1,507 1,601 2.20 3,522 8.3 19.4 4,965 0.406 2,016 1,683 2.50 4,208 10.6 22.1 5,857 0.461 2,700 1,769 2.85 5,042 13.5 25.2 aIliamna, Nondalton, Newhalen, Igiugig, Levelock, Ekuk and Clarks Point. bNoncentral-station conwunities adopt seasonal/central-station electricity prices after 1987, when all noncentral communities are assumed to be fully electrified. Electricity and Heating Fuel 23.4% 38.8 40.3 49.2 27.7 32.7 38.7 Dollars ($) 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000 o 1980 FIGURE 3 HOUSEHOLD INCOME, ELECTRICITY EXPENDITURES AND HOUSEHOLD HEATING EXPENDITURES FOR CENTRAL STATION COMMUNITIES a 1980 -2002 (See Table 10) $1 $1,146 Household Electricity EKpenditures $2,760 1985 1990 1995 2000 aDillingham, Aleknagik, Naknek, King Salmon, South Naknek, Egegik, Manokotak, and New Stuyahok. 30 .. .. .. • • .. .. • .. lit; .. .. .. .. .. .. .. .. .. .. .. .. • 2002 .. .. Dollars ($ 40,000 35,000 35,000 30,000 25,000 20,000 10,000 5,000 o 1980 FIGURE 4 HOUSEHOLD INCOME, ELECTRICITY EXPENDITURES AND HOUSEHOLD HEATING EXPENDITURES FOR SEASONAL CENTRAL-STATION COMMUNITIES a 1980 -2002 (See Table 12) $1 House Income HouseholdElectricity Expenditures Q 2 916 $2,216 1985 1990 1995 2000 2002 aEkwok, Koliganek, Portage Creek. 31 lollars ($) 40,000 35,000 30,000 25,000 20,000 15,000 10,000 16,098 FIGURE 5. HOUSEHOLD INCOME, ELECTRICITY EXPENDITURES, AND HOUSEHOLD HEATING EXPENDITURES FOR NONCENTRAL STATION COMMUNITIES a 1980-2002 (see Table 12) hold Income House 20,0 37 5,000 2,158 1,608 5 042 I ~~~~~~~~~ ____ --~::~~~~H:ou~~se~h~O~l~d~H~e~a~t~in::g:E~X:p:e:n:d~i:t:u:r:e:s~~::::~~ 2,700 Household Electricity 1,507 Expenditures o 1980 1985 1990 19 5 aIliamna, Nondalton, Newhalen, Igiugig, Levelock, Ekuk, Clark's Point 32 2000 2002 • .. .. • .. • .. .. .. • -... .. .. • .. .. • The analysis of the cost of residential electricity consumption as a proportion of income was conducted under the business-as-usual scenario. The key assumptions are reviewed below: 1. Electricity production remains regionally decentralized so that rising fuel prices are not offset by economies of scale in electricity generation. Fuel and elec- tricity prices escalate at a rate 2.6 percent higher than the general rate of inflation. 2. Inflation adjusted household income rises, but not as fast as energy prices. 3. Future residential energy-use patterns do not depart significantly from historical trends. That is, despite rising real energy prices, consumption per residential customer increases. 4. The future impact on electricity prices of state inter- vention is comparable to the effect of the Power Cost Assistance program in 1981. The combined effect of these assumptions suggests that the pro- portion of household income spent on electricity rises over the fore- cast period. The exact proportion of income spent on electricity depends on the community's economic outlook, reflected in average household income, and on the degree of electrification. Electricity expenditures were projected to be consistently less than heating fuel expenditures in all three community groups. Central-station communi- ties would pay proportionately less for electricity than either seasonal/central or noncentral communities in spite of higher average household electricity consumption. The relatively high household electricity budget for seasonal/ central-station communities reflects the single-resource, fishing economies. The higher average household 33 income of central-and noncentral-station community groups reflects economic opportunities from government services and recreation demand in addition to fishing. As noted in Table 11, we assume noncentral-station communities adopt seasonal/central-station prices after 1987, by which time they would all be electrified. 34 • .. .. Iii. .. .. .. .. .. .. .. .. -.. .. .. -.. .. ., • .. .. .. .. .. .. .. III. Commercial/Government Sector The Institute of Social and Economic Research survey data was used to derive baseline estimates of the number of commercial/govern- ment customers and average electricity use per customer for 1980. These estimates are shown in Table 13 for all villages, by village grouping. A breakdown of the type and number of commercial/government facilities in rural villages (excluding Dillingham, Naknek, and King Salmon) is shown in Table 14 for 1981. Commercial/Government Customers. The baseline estimates of number of commercial/government customers reflect a recent period of rapid growth from fisheries activity and from public spending. It would be unrealistic to extrapolate future commercial/government growth from historical patterns characterized by short-term upswings. As shown in Table 14, most villages have in place a services infra- structure covering utilities, health, education, and village adminis- tration. Some villages have much more. We expect more growth in the commercial/government sector over the next twenty years. However, in many cases, our assumptions about growth were tempered to reflect long-run possibilities under a scenario of moderate economic development. 35 TABLE 13. 1980 ELECTRICITY CONSUMPTION IN THE BRISTOL BAY COMMERCIAL/GOVERNMENT SECTOR Village Groups Central Stations Dillingham Aleknagik Naknek King Salmon South Naknek Egegik Manokotak New Stuyahok All Villages Total Electricity Consumption (kwh/yr) 4,774,318 2,793,166 82,092 126,118 202,302 7,977,996 Seasonal-Central Station Portage Creek Ekwok Koliganek All Villages Noncentral Station Iliamna Newhalen Nondalton Clarks Point Ekuk Levelock Igiugig All Villages Total All Villages 47,791 85,530 115,435 248,756 639,727 243,593 186,497 69,631 NA 125,685 137,082 1,402,215 9,628,967 SOURCE: ISER survey data Nushagak Electric Cooperative Naknek Electric Association Total Commercial/ Government Customers 194 136 355 6 5 8 19 31 9 10 6 1 8 5 70 443 a AII school facilities counted as one customer. 36 Average Electricity Use per Customer (kwh/customer/yr) 24,610 20,538 9,121 15,765 25,288 22,473 7,965 17,105 14,429 13 ,092 20,636 27,066 18,650 11 ,605 NA 15,711 27 ,416 20,032 21,687 ., ., • .. - ., .. - ., .. • -- - .. .. W -..J TABLE 14. COI1l1ERCIAL AND GOVERNMENT /COMl1UNITY BUILDINGS, 1960 Clarks ~~kllagik Point ~~ Ekuk Commercial Store 0 2 (a) 2 Bilr/Rest"uranl 0 0 I Lodge 0 0 Other 2 0 I Government/Con~unily Post Office Vi llage Council/ City Office C(Jfllfllun i t Y II" 11 0 0 Clinic I Clillic/Comm. Hall 0 Fire Station 0 0 0 Water & Sewer Utility 0 Electric Utility 0 0 Warehouse 0 Hangar 0 Ai rport Lights 0 0 Church 3 1 School Bldgs. 2 1 Teacher Housing 2 Gymnasium 0 RCAjAlascom Others (s) Seasonal (a) Oue store is seasonal {bl Hayor plans to open a coffee shop (1983) (cl Hdyor plans to build a laundromat (1983) (d) Utility building under construction (el Same building as co-op store 1 0 0 0 0 0 0 I (s) 0 0 0 0 0 0 0 0 0 0 Ekwok I 0 I 0 0 0 0 1 I 0 0 0 0 0 2 1 0 ~!i Il iamna Koligane! 0 2 2 0 0 8 (j) 7 0 0 0 0 0 0 1 0 0 0 2 0 0 0 0 2 0 2 0 1 0 1 1 1 1 0 2 1 3 0 1 (f) Residence in same building (g) One store is in residence (h) Corporation bldg -"Pool lIaU" (i) School generator bUilding (j) Across river ~Ianokotak 0 2 0 0 (b) I 0 0 0 (c) 0 0 I 0 0 0 1 0 2 2 6 0 New Portage So. Stuyahok Newhalen Nondalton Creek Naknek ---- 2 2 (g) 0 I 0 0 1 0 2 O=s) 0 0 0 0 (£) (e) 0 0 0 0 (5) 0 0 1 (5) 1 0 0 0 0 0 1 (d,i) (1) 0 0 1 0 0 0 0 0 0 0 0 1 1 (0 1 2 5 2 2 4 3 1 (h)(s) Use per Customer. Average electricity use per customer in the commercial/ government sector was assumed to grow at 2.4 percent per year for central station villages. This assumption is based on the historical pattern of nonresidential electricity consumption in several southwest Alaska utilities shown in Figures 6 and 7. Although use per nonresidential customer varied dramatically across utilities, the pattern of growth does exhibit a stabilizing trend toward a slower, more uniform average rate in the latter 1970s. As shown in Table 15, the average growth in use per customer in four utilities falls to 2.4 percent per year from 1976 to 1980, from 5.9 percent over an extended historical period. TABLE 15. HISTORIC GROWTH IN ELECTRICITY USE PER CUSTOMER FOR SELECTED UTILITIES (percent/yea r) 1970-1980 1976-1980 NEC 2.8 3.6 NEA -5.0 3.3 BUCI 23.0 2.4 (1977-1980) KEA 2.7 0.4 Average 5.9 2.4 We assumed that use per customer in the seasonal-central station and noncentral station villages equaled the growth rate derived from the appliance saturation analysis for residential use per customer in the seasonal-central station villages (2.31 percent). The commercial/ government sector exhibits similar characteristics in these two 38 • • ... ... ... ... • ... .. ... ... .. - • ... .. ... ... kwh/hr 76,000 70,000 60,000 50,000 40,000 30,000 20,000 14,000 FIGURE 6. NONRESIDENTIAL ELECTRICITY CONSUMPTION PER CUSTOMER FOR SELECTED SOUTHWEST ALASKA UTILITIES BUCI -Bethel Utility Cooperative, Inc. KEA -Kodiak Electric Association NEA -Naknek Electric Association NEC -Nushagak Electric Cooperative KEA NEC BUCI 1965 66 67 68 69 70 71 72 73 74 39 75 76 77 BUCI KEA NEA NEe 78 79 1980 kwh/hr 76,000 70,000 60,000 50,000 40,000 30,000 20,000 14,000 FIGURE 7. NONRESIDENTIAL ELECTRICITY CONSUMPTION PER CUSTOMER FOR SELECTED ALASKA UTILITIES IN THE RAILBELT REGION FMUS -Fairbanks Municipal Utility System CVEA -Copper Valley Electric Assn. SES -Seward Electric System , I / / CVEA ..1._------------, , S~/, / SE 1965 66 67 68 69 70 71 72 40 73 74 75 76 77 • ., .. - ., .. - • .. CVEA - • .. .. • • .. • ' . .. ... .. - 78 79 1980 .. .. village groups despite the important distinction in the method of power production. Furthermore, the noncentral commercial users already have relatively large generating facilities and are not expected to respond dramatically to electrification. Number of Customers. For central station villages, the growth in the number of commercial/government customers is equal to the residen- tial rate of growth plus an increment reflecting the difference in growth between residential and commercial customers for the combined Bristol Bay Utilities (see Table 16). The percentage change between commercial and residential customers for Bristol Bay communities (120 percent) was applied directly to the growth rate of residential customers for central station communities. TABLE 16. AVERAGE ANNUAL RATE OF GROWTH IN RESIDENTIAL AND COMMERCIAL CUSTOMERS: UNITED STATES, ALASKA, AND BRISTOL BAY UTILITIES (percent/year) Alaska Bristol Ba!{ (1960-1979) (1970-1980) Residential 4.5 4.9 6.1 Commercial 6.2 7.1 7.3 Difference 1.7 2.2 1.2 SOURCE: Statistical Abstract, 1980 Alaska Public Utilities Commission 41 A summary of growth rates calculated for the commercial/government sector appears in Table 17. TABLE 17. GROWTH IN USE PER CUSTOMER AND NUMBER OF CUSTOMERS IN THE COMMERCIAL GOVERNMENT SECTOR Use per Customer Number of Customers SOURCE: See text. (percent per year) Central Station 2.40 4.28 42 Community Groups Seasonal-Central Station 2.31 1.54 Noncentral Station 2.31 3.63 - • III .. .. .. -- .. • .. • IV. Industrial Sector Industrial activity in Bristol Bay is confined exclusively to seafood processors. In 1980, there were thirteen major shore-based processors operating in the Nushagak and Kvichak fisheries. There were also approximately 40 shore-based fish camps and fish buyers. Excluded from the forecast of industrial energy demand are the numer- ous offshore processors and buyers which move freely about Bristol Bay and do not directly contribute to electricity demand. Sho sors. ISER study team members surveyed all thirteen shore-based processors and developed a baseline estimate of average electricity use per processor in 1980. These estimates are shown in Table 18. They include electricity purchased from utilities and produced from processor-generating facilities. On average, proc- essors used about 69 megawatt hours from utilities and 660 megawatt hours from their own generators. generators for peak summer months. Most processors used their own Some also purchased electricity from utilities. Two processors depended entirely on the electric utility. These average electricity load estimates cover all forms of processing--canning, freezing, and packing--and a variety of seafood types--salmon, salmon roe, and herring. per processor is shown in Table 19. 43 Data on average production TABLE 18. ELECTRICITY CONSUMPTION BY BRISTOL BAY FISH PROCESSORS: 1980 Kvichak Fishery Nushagak Fishery Total Number 9 4 of Processors Self-Generating Number With Own Generator 7 4 Average MWH (2)a Produced/Year 913 572 (2) Number Without 0 2 Average MWH Year/Proc. 710 572 Utility Power Number Using 8 2 Average MWH (8)a (2)b Purchased/Year 97 62 Number Not Using 1 2 Average MWH 86 31 Year/Proc. Bristol Bay Study Region 13 11 2 660b 10 3 69 aNumber in parentheses indicates number of processors for which data was available. b Averages are weighted for number of processors in each fishery. SOURCE: Naknek Electric Association, Nushagak Electric Cooperative, Inc., and data supplied by fish processors. 44 .. .... • • • .. • ",,"'. - - • • • • .. .. • .. • ,.. TABLE 19. AVERAGE 1980 PRODUCTION AT NUSHAGAK AND KVICHAK BAY FISH PROCESSORS a Salmon Frozen Canned Herring (packed) (pounds) Salmon Roe (boxed and salted) Flown Out (processed elsewhere) Total Production 295,000 2,839,000 158,000 127,000 b 1,030,000 4,449,000 aAverages calculated for all processors including those that do not necessarily participate in a particular processing method. bEstimated from incomplete data from Alaska Department of Fish and Game and the processors. A recent shift toward freezing capacity is evident among Bristol Bay shore-based processors. In 1980, about ten out of fourteen proc- essors have both canning and freezing facilities. Average energy use per processor for this group was 583 MWH per year in 1980. Processors engaged only in canning used an average of 486 MWH in 1980. We assume that over the projected period, processors with canning operations only will eventually convert to canning and freezing. This shift toward a more energy-intensive technology would be the only source of increased electricity demand per processor in the industrial sector. We assume that with the exception of one additional processor coming on line in 1982, the number of processors and the general level of 45 fish harvesting activity remains constant at the 1980-81 levels. Based on discussions with officials from the Alaska Department of Fish and Game, this assumption is not overly conservative. Thus, the primary source of increased energy demand in the sea- food processing industrial sector is that resulting from a continued expansion of relatively energy-intensive freezing capacity. Electricity demand projections for the major shore-based proces- sors are shown in Table 20. We implicitly assume in these projections that the Power Cost Assistance subsidy is relatively unimportant. Future electricity prices are, therefore, close to the real marginal cost of oil. Fish Camps and Buy Stations. Average annual electricity con- sumption per user in this category (24 Megawatt hours) was derived from 1980 data on annual consumption from ten buyers and fish camps in the study area. Actual consumption varies greatly since operations range in size from small offices to a bunk house, mess hall, and ice facilities complex. We assume that average annual consumption will not change over the projection interval. We also assume that the number of buyers will peak in the mid-1980s. Some fish camps will retire during the forecast period and not be replaced (see Table 21). 46 .. • .. .. • -.. -.. .., .. l1li .. .. • .. -- • .. .. III .. • .. .. TABLE 20. BRISTOL BAY SEAFOOD PROCESSOR ELECTRICITY DEt-lAND PROJECTIONS Number of Customers Electricity Use per Customer Total Electricity Constumption Canning and/or Canning and/or Canning and/or Canning Only Canning Only Canning Only Freezing Total (NWH/Processor/Year) (HWH/Year) 1980 3 10 486 583 1,458 5,830 7,288 .po. -J 1982 3 11 1,458 6,143 7,871 1987 2 12 972 6,996 7,968 1992 13 486 7,579 8,065 1997 0 14 0 8,162 8,162 2002 0 14 486 583 0 8,162 8,162 1980 1982 1987 1992 1997 2002 TABLE 21. BRISTOL BAY FISH CAMPS AND BUY STATIONS ELECTRICITY DEMAND PROJECTIONS Customers 40 42 41 40 39 39 Electricity Consumption per Customer (MWH/customer/year) 24 24 48 Total Electricity Consumption (MWH/year) 960 1,008 984 960 936 936 • .. • .. .. .. • ., - • - • -• -.. ., .. - ., ., .. V. Military Sector The Alaska Air Command (AAC) station at King Salmon is the only military presence in the study region. Prior to November 1981, when the military tied into Naknek Electric Association (NEA), ACC gener- ated their own power. In December 1981, the military bought 520,800 kwh from NEA. According to NEA manager Gordon McCormick, the utility contract with the military station calls for annual military elec- trici ty consumption of about 5,600 MWH. The AAC Public Information Office projects no significant changes in the King Salmon station or the Bristol Bay region that would affect electricity consumption. ISER proj ections, therefore, assume constant annual consumption of 5,600 MWH for the military sector of the projection period. 49 VI. Electric Space Heating This analysis examines the economics of space heating by elec- tricity in Bristol Bay. Under the present relative price structure of electricity and diesel fuel in Bristol Bay, the cost of using electricity for residen- tial space heating is considerably greater than that of oil furnaces. There is only one home in the eighteen study-area communities that uses electricity for space heating.3 Nevertheless, the question of electric space heating is important for design of electricity plants under future conditions when the relative price structure could change. Although wood is becoming an increasingly popular fuel for space heating in Bristol Bay, most households still rely on fuel oil as their primary heating fuel. Our analysis of residential space heating requirements in Bristol Bay suggests that a typical urban or rural household having 800 square feet of Single-story floor space uses about 1, 000 gallons of heating fuel. Using 1981 fuel oil prices in Dillingham ($1.42/gal.), it would cost the homeowner about $1,420 to cover their annual heating requirement. After correcting for oil furnace seasonal efficiency, an equivalent amount of heat from elec- tric baseboard radiant heaters would be about 97 million BTUs, or 3In this case, the circumstances do not reflect the existing relative price structure. 50 • .. • -.. • .. .. - -.. .. .. 28,300 kwhs. If we apply an average price of $. 25/kwh, which is typical of electricity prices in the region, then the homeowner would incur an electric space heating cost of $7,075 per year, nearly five times the running cost of fuel-oil space heat. Putting aside the cost of the alternate heating systems for a moment, the above analysis shows that for electricity to compete with fuel oil for space heating, the price per kilowatt would have to be about $.05 ($1,420 + 28,300 kwh). This analysis is extended to incor- porate the purchase and installation cost of converting from a common, oil-fired heating system to radiant baseboard electric heaters (see Table 22). As the conversion cost increases, the break-even cost of electricity declines. The above analysis suggests that electric space heating would not occur under a tlbusiness-as-usual" scenario that assumes continued reli- ance on diesel-powered electricity with electricity prices rising in real terms. It would, nevertheless, be interesting to illustrate the maximum space heating contribution to pure appliance electricity consumption under hypothetical circumstances where 100 percent of space heat requirements was captured by electricity. We do this by converting total space-heating fuel-oil consumption projected in 2002 to an electricity equivalent measure for residential, commercial/government, and industrial customers. 51 TABLE 22. ELECTRICITY BREAK-EVEN PRICES FOR TYPICAL RESIDENTIAL HEATING SYSTEM CONVERSIONS IN BRISTOL BAY Purchase and Electricity Break-Even Prices (¢/kwh) Conversion Installation Cost 1981 2002 l. Fully Subsidize $0 5¢/kwh 8.8¢/kwh 2. Hydronic Baseboard in Place $2,500 0.2¢/kwh/year) 3.8 7.6 Assume: 1. 2. 3. 4. Household annual heating requirement = 97 million BTUs; 1,000 gallons heating fuel; 28,300 kwh Oil furnace efficiency = 70 percent 3,413 BTU/kwh 138,000 BTU/gallon 5. $1.42/gallon (Dillingham 1981) 6. Heating system life = 20 years; amortized at 12 percent interest rate The analysis of space heating energy demand is based exclusively on heating oil consumption. Wood, although increasing in demand, was supplemental as a source of residential space-heat energy. Its pri- mary use was for steamhouse heat, an active winter pastime in many Bristol Bay communities. Electricity was occasionally used for space heating under extenuating circumstances such as fuel shortages or extreme cold. Its contribution to total space-heat energy in 1980 was 52 • ., .. • • ., .. .. ., ., negligible, except in the industrial sector.' We ignore these elements of space-heat energy under the assumption that the base-year estimates of average heating oil use per customer applied to all customers, including those that may actually have used wood or electricity, capture a complete measure of space heat demand. Total base-year heating oil consumption by residential and com- mercial/ government, (G/G) consumers was estimated from survey data collected in each community. Data from fuel distributors was gener- ally incomplete and used mainly as a reliability check against the survey data. No attempt was made to net out that portion of annual 1980 heating oil consumption used for either cooking or water heating by residential and G/G consumers. We estimate that this component is about 7-to-10 percent of total heating fuel consumption in the resi- dential sector and possibly twice that amount in the commercial/ government sector. Residential. In the preliminary forecast, an estimate of average annual heating oil consumption per customer was calculated from the household survey data for each village and mUltiplied by the 1980 census count of households to derive an estimate of total village fuel oil consumption for space heating. These estimates are shown in Table 23. The village-by-village fuel consumption estimates are converted to an electricity equivalent by assuming: 1. 138,000 BTUs per gallon of fuel oil 2. Seasonal furnace efficiency of 70 percent 3. 3,413 BTU/kwh 53 TABLE 23. SPACE HEATING IN 1980 IN THE EIGHTEEN STUDY-AREA COMMUNITIES (1) (1) x (2) Average Total Fuel Consumption (2) Residen. Heating Per Customer a Number of Fuel Consumption (gal./household/year) Households (gal. /year) Dillingham 1,080 505 545,400 Aleknagik Naknek King Salmon 1,164 246 286,344 South Naknek Egegik 1,289 23 29,647 Manokotak 1,100 57 62,700 New Stuyahok 985 65 64 z025 All Villages 1,103 896 988,116 Portage Creek 1,035 13 13,455 Ekwok 1,083 20 21,660 Koliganek 930 40 37 z200 All Villages 991 73 72,315 Iliamna 1,033 35 36,155 Newhalen 1,033 18 18,594 Nondalton 1,033 42 43,386 Clarks Point 1,364 22 30,008 Ekuk 1,800 1 1,800 Levelock 2,009 28 56,252 Igiugig 1 z083 15 16,245 All Villages 1,257 161 202,440 Total All 18 Villages 1,118 1,130 1,262,871 aIncludes fuel for water heating and some cooking. 54 • .. ., • • • III ., .. • ., • • - • To forecast total residential space heating energy demand in 2002, we assume that use per residential customer grows at an average annual rate of 1 percent per year, reflecting an assumed increase in average floor area, with the base year levels of consumption per square foot remaining constant, Forecasted consumption per customer in each village was multiplied by the projected number of households to derive total space-heating demand. An electricity equivalent was calculated by assuming the same BTU conversion factors and furnace efficiency used in the base year. Commercial/Government. Space heating energy demand in the C/G sector was derived in the same manner as that of residential. An estimated base-year level of heating oil consumption per customer was multiplied by the number of customers to calculate 1980 C/G space heat demand and its electricity equivalent. As with residential consumers, electric space heating did not actually take place in any measurable quantity during the base year (see Table 24), The number of C/G consumers in each Village were allowed to grow in accordance with growth rate assumed for the corresponding village grouping (i.e., central, seasonal central, and noncentral). Consump- tion per consumer was assumed to grow at 1 percent per year over the forecast period. 55 • ... .. .. TABLE 24. SPACE HEATING BY COMMERCIAL/GOVERNMENT III' USERS IN 1980 "" Total 1980 Elec. Equiv. .., 1980 Heating Heating Fuel Total 1980 .. Fuel Consumption Number of Consumption for Heating Fuel per Customer Customers Space Heating Consumption II' (Gallons) 1980 (Gallons) (MWH) .. Dillingham 7,789 194 1,511,066 42,763 .. Aleknagik .' Naknek • King Salmon 7,789 136 1,059,304 29,978 South Naknek .. Egegik 3,201 10 32,013 906 • Manokotak 5,380 12 64,555 1,827 .. New Stuyahok 3,106 14 43 1 478 1 1 230 .. All Central-7,406 366 2,710,416 76,705 Station Villages .. Portage Creek 1,342 8 10,735 304 • Ekwok 1,417 8 11 ,338 321 ... Koliganek 1,348 14 18,866 534 .. All Seasonal 1,365 30 40,939 1,159 Central Villages .. Iliamna 2,360 31 73,149 2,070 • Newhalen 1,886 10 18,860 534 .. Nondalton 2,277 13 29,597 838 Clark's Point 1,796 7 12,576 356 -Ekuk 1,800 1 1,800 51 Levelock 2,514 9 22,630 640 ... Igiugig 3,815 4 15 1 261 432 flit All Noncentral 2,318 75 173,873 4,921 'II!i Villages .. All Eighteen • Villages 6,211 471 2,925,228 82,785 .. -.. III< --56 • .. Industrial. Industrial space-heat demand is based on energy-use data collected directly from the Bristol Bay shore-based fish proces- sors. Industrial space heat was required mainly for bunkhouses and offices. Fuel oil used for in-house electricity generation and for boiler operation was netted out of total processor fuel oil consump- tion. We estimated average processor space-heat demand (i. e., con- sumption per customer) from available data and applied this average to all thirteen base-year processors. We assumed that space heating consumption per customer was constant over the forecast period. Thus, the increase in total industrial, space-heat energy demand resulted from the addition of one new processing facility in Dillingham in 1982. A few processors indicated that they used some electric space heating. This represents residual load from self-generated elec- tricity which helps to raise the processor's plant factor but does not contribute to electricity load at the utilities. We, therefore, did not attempt to estimate the proportion of total industrial space heat that was furnaced by self-generated electricity in either 1980 or 2002. In summary, the key assumption regarding the estimates of space heating energy demand is that it remains nonelectric in the base plan preliminary forecast. The electricity-equivalent measure was calcu- lated to illustrate the maximum potential electricity energy demand if electricity prices were competitive with those of fuel oil. Under the 57 base-year structure of relative energy prices, the cost of 1 million BTUs of electric heat at $.25 per kwh is eight times greater than the cost of a comparable amount of fuel oil at $1.20 per gallon. Furthermore, we implicitly assume that conservation measures are not performed on either residential or C/G structures. 58 .. It> .. .. .. .. • • - • .. • .. .. VII. Load Curve Preliminary analysis indicates that the shape of the load curve in the future will be influenced by the three major components of the load as follows: 1. Fish processing -A very high summer peak occurring over a two-to-three month period. 2. Nonspace heating use - A winter peak. 3. Space heating -A very high winter peak. Load curves for Naknek Electric Association and Nushagak Electric Cooperative for 1980 depict the general shape of the first two com- ponents of load (see Figures 8 and 9). Space heating by electricity is virtually non-existent in the region. Because data from a single year may be subject to reporting errors and nonrepeating conditions, a more thorough historical analysis is underway to identify more pre- cisely the shape of the load curves. Preliminary results suggest that in the future the load curve will have a smaller summer peak as nonspace heating uses increase as a percentage of the total load. Also, the summer peak will partially be a function of the availability of excess capacity among the utilities which can be purchased by the fish processors. 59 FIGURE 8. NUSHAGAK ELECTRIC COOPERATIVE, INC. MONTHLY SALES -1980 (KWH) KWH 250,000 Residential 225,000 200,000 175,000 150,000 125,000 Lg. Power 100,000 Public Buildings 75,000 Jan Feb Mar Apr May Jun Jul Aug Sep SOURCE: Nushagak Electric Cooperative, Inc. 60 Oct Residential Small Large Power Public Nov Dec • .' - • .' - • • • - - KWH 450,000 425,000 400,000 375,000 350,000 325,000 300,000 275,000 250,000 225,000 200,000 175,000 150,000 125,000 Commercial FIGURE 9. NAKNEK ELECTRIC ASSOCIATION SALES 1980 (KWH) SOURCE: Alaska Public Utilities Commission, Naknek Electric Assoc. Small Commercial Large Commercial Large Commercial Residential Res. 100,OOO~--~----~--~----~--~----r----r----r---~----~--~----~ Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 61 VIII. Individual Community Projections In this section, electricity consumption is presented for indi- vidual communities in the base year and in the projection year: 2002. Fifteen tables follow, one for each community, plus a summary table for all eighteen communities. The projections are divided into the four major consumer categories used throughout this analysis. They are (1) Residential, (2) Commercial/Government, (3) Military, and (4) Industrial. The format of the tables follows the general method- ology of this study. The number of customers, consumption per cus- tomer, and total consumption are shown for both appliance electricity consumption and for an electricity-equivalent estimate of space- heating consumption. We remind the reader that, historically, elec- tric space heating did not occur in meaningful quantities in any of the study-area communities. The price assumptions used in this forecast do not permit electricity to compete with fuel oil or wood for space heat. The figures shown for space heating electricity are, therefore, provided to illustrate how much electricity would be required to meet 100 percent of the space-heating load. 62 III- • • .. .. .. .. .. .. .. .. .. .' fill .. ", .. .. ... TABLE 25. BRISTOL BAY ELECTRICITY CONSUMPTION ALL COMMUNITIES RESIDENTIAL 1. Customers 2. Appliance Consmp. per Customer (kwh) 3. Total Appliance Consmp. (lx2) (mwh) 4. Electric Space Heat Customer 5. Space Heat Consmp. per Customer (kwh) 6. Total Space Heat Consmp. (4x5) (mwh) 7. Total Residential Consmp. (3+6) (mwh) COMMERCIAL/GOVERNMENT 8. Customers 9. Appliance Consmp. per Customer (kwh) 10. Total Appliance Consmp. (8x9) (mwh) 11. Electric Space Heat Customer 12. Space Heat Consmp. per Customer (kwh) 13. Total Space Heat Consmp. (11x12) (mwh) 14. Total Commercial Consmp. (10+13) (mwh) MILITARY 15. Customers 16. Appliance Consmp. per Customer (kwh) 17. Total Appliance Consmp. (15x16) (mwh) 18. Electric Space Heat Customer 19. Space Heat Consmp. per Customer (kwh) 20. Total Space Heat Consmp. (18x19) (mwh) 21. Total Government Consmp. (17+20) (mwh) INDUSTRIAL 22. Customers 23. Appliance Consmp. per Customer (kwh) 24. Total Appliance Consmp (22x23) (mwh) 25. Electric Space Heat Customer 26. Space Heat Consmp. per Customer (kwh) 27. Total Space Heat Consmp. (25x26) (mwh) 28. Total Industrial Consmp. (24+27) (mwh) TOTAL Actual 1980 960 4,648 4,462 1,130 31,627 35,738 40,200 443 21,691 9,609 470 175,728 82,592 92,201 1 5,600,000 5,600 1 13,381,000 13,381 18,981 13 539,077 6,938 13 576,231 7,491 14,499 29. Total Appliance Consmp. (3+10+17+24) (mwh) 26,609 30. Total Space Heat Consmp. (6+13+20+27) (mwh) 139,202 31. Grand Total (7+14+21+28) (mwh) 165,881 63 2002 1,906 6,264 11 ,939 2,167 39,160 84,859 96,798 1,071 36,680 39,284 1,124 212,580 238,384 278,224 1 5,600,000 5,600 1 13,381,000 13,381 18,981 13 561,769 8,003 13 573,385 7,539 14,757 64,826 344,163 408,989 TABLE 26. BRISTOL BAY ELECTRICITY CONSUMPTION ALEKNAGIK/DILLINGHAM RESIDENTIAL 1. Customers 2. Appliance Consmp. per Customer (kwh) 3. Total Appliance Consmp. (lx2) (mwh) 4. Electric Space Heat Customer 5. Space Heat Consmp. per Customer (kwh) 6. Total Space Heat Consmp. (4x5) (mwh) 7. Total Residential Consmp. (3+6) (mwh) COMMERCIAL/GOVERNMENT 8. Customers 9. Appliance Consmp. per Customer (kwh) 10. Total Appliance Consmp. (8x9) (mwh) 11. Electric Space Heat Customer 12. Space Heat Consmp. per Customer (kwh) 13. Total Space Heat Consmp. (11x12) (mwh) 14. Total Commercial Consmp. (10+13) (mwh) MILITARY 15. Customers 16. Appliance Consmp. per Customer (kwh) 17. Total Appliance Consmp. (15x16) (mwh) 18. Electric Space Heat Customer 19. Space Heat Consmp. per Customer (kwh) 20. Total Space Heat Consmp. (18x19) (mwh) 21. Total Government Consmp. (17+20) (mwh) INDUSTRIAL 22. Customers 23. Appliance Consmp. per Customer (kwh) 24. Total Appliance Consmp (22x23) (mwh) 25. Electric Space Heat Customer 26. Space Heat Consmp. per Customer (kwh) 27. Total Space Heat Consmp. (25x26) (mwh) 28. Total industrial Consmp. (24+27) (mwh) TOTAL 29. Total Appliance Consmp. (3+10+17+24) (mwh) 30. Total Space Heat Consmp. (6+13+20+27) (mwh) 31. Grand Total (7+14+21+28) (mwh) 64 Actual 1980 443 5,112 2,265 505 30,564 15,434 17,699 194 24,610 4,774 194 220,000 42,680 47,454 2 283,842 568 2 48,110 96 664 7,607 58,210 65,817 2002 851 6,728 5,726 995 37,894 37,705 43,431 488 41,345 20,176 488 273,000 133,224 153,400 3 383,561 1,151 3 48,110 144 1,295 27,053 171,073 198,126 • .. • .. • .. .. ., - • TABLE 27. BRISTOL BAY ELECTRICITY CONSUMPTION NAKNEK, SOUTH NAKNEK, KING SALMON RESIDENTIAL 1. Customers 2. Appliance Consmp. per Customer (kwh) 3. Total Appliance Consmp. (lx2) (mwh) 4. Electric Space Heat Customer 5. Space Heat Consmp. per Customer (kwh) 6. Total Space Heat Consmp. (4x5) (mwh) 7. Total Residential Consmp. (3+6) (mwh) COMMERCIAL/GOVERNMENT 8. Customers 9. Appliance Consmp. per Customer (kwh) 10. Total Appliance Consmp. (8x9) (mwh) 11. Electric Space Heat Customer 12. Space Heat Consmp. per Customer (kwh) 13. Total Space Heat Consmp. (11x12) (mwh) 14. Total Commercial Consmp. (10+13) (mwh) MILITARY 15. Customers 16. Appliance Consmp. per Customer (kwh) 17. Total Appliance Consmp. (15x16) (mwh) 18. Electric Space Heat Customer 19. Space Heat Consmp. per Customer (kwh) 20. Total Space Heat Consmp. (18x19) (mwh) 21. Total Government Consmp. (17+20) (mwh) INDUSTRIAL 22. Customers 23. Appliance Consmp. per Customer (kwh) 24. Total Appliance Consmp (22x23) (mwh) 25. Electric Space Heat Customer 26. Space Heat Consmp. per Customer (kwh) 27. Total Space Heat Consmp. (25x26) (mwh) 28. Total industrial Consmp. (24+27) (mwh) TOTAL Actual 1980 241 5,328 1,284 246 32,941 8,103 9,387 136 20,538 2,793 136 220,000 29,920 32,713 1 5,600,000 5,600 1 13,381,000 13 ,381 18,981 7 587,858 4,115 7 755,324 5,287 9,402 29. Total Appliance Consmp. (3+10+17+24) (mwh) 13,792 56,691 70,483 30. Total Space Heat Consmp. (6+13+20+27) (mwh) 31. Grand Total (7+14+21+28) (mwh) 65 2002 463 6,737 3,119 485 40,837 19,806 22,925 342 34,504 11 ,800 342 273,000 93,366 105,166 1 5,600,000 5,600 1 13,381,000 13,381 18,981 7 628,977 4,403 7 755,324 5,287 9,690 24,922 131,840 156,762 .. ... ; .. TABLE 28. BRISTOL BAY ELECTRICITY CONSUMPTION . ' EGEGIK .. Actual .,. 1980 2002 .. RESIDENTIAL III l. Customers 23 44 • 2. Appliance Consmp. per Customer (kwh) 2,328 5,350 .. 3. Total Appliance Consmp. (1x2) (mwh) 54 235 ., 4. Electric Space Heat Customer 23 45 5. Space Heat Consmp. per Customer (kwh) 36,479 45,223 -. 6. Total Space Heat Consmp. (4x5) (mwh) 839 2,035 7. Total Residential Consmp. (3+6) (mwh) 893 2,270 .. .. COMMERCIAL/GOVERNMENT .. 8. Customers 9 23 9. Appliance Consmp. per Customer (kwh) 6,844 11,498 .. 10. Total Appliance Consmp. (8x9) (mwh) 62 264 ., 11. Electric Space Heat Customer 10 25 .. 12. Space Heat Consmp. per Customer (kwh) 90,600 44,920 13. Total Space Heat Consmp. (l1x12) (mwh) 906 1,123 • 14. Total Commercial Consmp. (10+13) (mwh) 968 1,387 ... MILITARY - 15. Customers .. 16. Appliance Consmp. per Customer (kwh) 17. Total Appliance Consmp. (l5x16 ) (mwh) ., .. 18. Electric Space Heat Customer 19. Space Heat Consmp. per Customer (kwh) • 20. Total Space Heat Consmp. (18x19) (mwh) 2l. Total Government Consmp. (17+20) (mwh) - INDUSTRIAL • .. 22. Customers 2 2 23. Appliance Consmp. per Customer (kwh) 534,500 583,000 • 24. Total Appliance Consmp (22x23) (mwh) 1,069 1,166 ... 25. Electric Space Heat Customer 2 2 26. Space Heat Consmp. per Customer (kwh) 674,285 674,285 JIll 27. Total Space Heat Consmp. (25x26) (mwh) 1,349 1,349 -28. Total industrial Consmp. (24+27) (mwh) 2,418 2,515 .. TOTAL •• 29. Total Appliance Consmp. (3+10+17+24) (mwh) 1,185 1,665 30. Total Space Heat Consmp. (6+13+20+27) (mwh) 3,094 4,507 .. 3l. Grand Total (7+14+21+28) (mwh) 4,279 6,172 .. 66 ., .. TABLE 29. BRISTOL BAY ELECTRICITY CONSUMPTION MANOKOTAK RESIDENTIAL I. Customers 2. Appliance Consmp. per Customer (kwh) 3. Total Appliance Consmp. (lx2) (mwh) 4. Electric Space Heat Customer 5. Space Heat Consmp. per Customer (khw) 6. Total Space Heat Consmp. (4x5) (mwh) 7. Total Residential Consmp. (3+6) (mwh) COMMERCIAL/GOVERNMENT 8. Customers 9. Appliance Consmp. per Customer (kwh) 10. Total Appliance Consmp. (8x9) (mwh) lI. Electric Space Heat Customer 12. Space Heat Consmp. per Customer (kwh) 13. Total Space Heat Consmp. (llx12) (mwh) 14. Total Commercial Consmp. (10+13) (mwh) MILITARY 15. Customers 16. Appliance Consmp. per Customer (kwh) 17. Total Appliance Consmp. (15x16) (mwh) 18. Electric Space Heat Customer 19. Space Heat Consmp. per Customer (kwh) 20. Total Space Heat Consmp. (18x19) (mwh) 2l. Total Government Consmp. (17+20) (mwh) INDUSTRIAL 22. Customers 23. Appliance Consmp. per Customer (kwh) 24. Total Appliance Consmp (22x23) (mwh) 25. Electric Space Heat Customer 26. Space Heat Consmp. per Customer (kwh) 27. Total Space Heat Consmp. (25x26) (mwh) 28. Total industrial Consmp. (24+27) (mwh) TOTAL 29. Total Appliance Consmp. (3+10+17+24) (mwh) 30. Total Space Heat Consmp. (6+13+20+27) (mwh) 3l. Grand Total (7+14+21+28) (mwh) 67 Actual 1980 49 9,504 466 57 31,130 1,774 2,240 8 15,765 126 12 152,250 1,827 1,953 592 3,601 4,193 2002 94 5,651 531 112 38,601 4,323 4,854 20 26,485 530 30 75,500 2,265 2,795 1,061 6,588 7,649 TABLE 30. BRISTOL BAY ELECTRICITY CONSUMPTION NEW STUYAHOK RESIDENTIAL 1. Customers 2. Appliance Consmp. per Customer (kwh) 3. Total Appliance Consmp. (lx2) (mwh) 4. Electric Space Heat Customer 5. Space Heat Consmp. per Customer (kwh) 6. Total Space Heat Consmp. (4x5) (mwh) 7. Total Residential Consmp. (3+6) (mwh) COMMERCIAL/GOVERNMENT 8. Customers 9. Appliance Consmp. per Customer (kwh) 10. Total Appliance Consmp. (8x9) (mwh) 11. Electric Space Heat Customer 12. Space Heat Consmp. per Customer (kwh) 13. Total Space Heat Consmp. (11x12) (mwh) 14. Total Commercial Consmp. (10+13) (mwh) MILITARY 15. Customers 16. Appliance Consmp. per Customer (kwh) 17. Total Appliance Consmp. (15x16) (mwh) 18. Electric Space Heat Customer 19. Space Heat Consmp. per Customer (kwh) 20. Total Space Heat Consmp. (18x19) (mwh) 21. Total Government Consmp. (17+20) (mwh) INDUSTRIAL 22. Customers 23. Appliance Consmp. per Customer (kwh) 24. Total Appliance Consmp (22x23) (mwh) 25. Electric Space Heat Customer 26. Space Heat Consmp. per Customer (kwh) 27. Total Space Heat Consmp. (25x26) (mwh) 28. Total industrial Consmp. (24+27) (mwh) TOTAL 29. Total Appliance Consmp. (3+10+17+24) (mwh) 30. Total Space Heat Consmp. (6+13+20+27) (mwh) 31. Grand Total (7+14+21+28) (mwh) 68 Actual 1980 54 1,944 105 65 27,876 1,812 1,917 8 25,288 202 14 87,857 1,230 1,432 307 3,042 3,349 2002 104 4,578 476 128 34,554 4,423 4,899 20 42,484 850 35 43,600 1,526 2,376 1,326 5,949 7,275 .. .' - ., -.. fiIJ· • -.. -... TABLE 31. BRISTOL BAY ELECTRICITY CONSUMPTION EKWOK RESIDENTIAL 1. Customers 2. Appliance Consmp. per Customer (kwh) 3. Total Appliance Consmp. (lx2) (mwh) 4. Electric Space Heat Customer 5. Space Heat Consmp. per Customer (kwh) 6. Total Space Heat Consmp. (4x5) (mwh) 7. Total Residential Consmp. (3+6) (mwh) COMMERCIAL/GOVERNMENT 8. Customers 9. Appliance Consmp. per Customer (kwh) 10. Total Appliance Consmp. (8x9) (mwh) 11. Electric Space Heat Customer 12. Space Heat Consmp. per Customer (kwh) 13. Total Space Heat Consmp. (11x12) (mwh) 14. Total Commercial Consmp. (10+13) (mwh) MILITARY 15. Customers 16. Appliance Consmp. per Customer (kwh) 17. Total Appliance Consmp. (15x16) (mwh) 18. Electric Space Heat Customer 19. Space Heat Consmp. per Customer (kwh) 20. Total Space Heat Consmp. (18x19) (mwh) 21. Total Government Consmp. (17+20) (mwh) INDUSTRIAL 22. Customers 23. Appliance Consmp. per Customer (kwh) 24. Total Appliance Consmp (22x23) (mwh) 25. Electric Space Heat Customer 26. Space Heat Consmp. per Customer (kwh) 27. Total Space Heat Consmp. (25x26) (mwh) 28. Total industrial Consmp. (24+27) (mwh) TOTAL 29. Total Appliance Consmp. (3+10+17+24) (mwh) 30. Total Space Heat Consmp. (6+13+20+27) (mwh) 31. Grand Total (7+14+21+28) (mwh) 69 Actual 1980 20 1,536 31 20 30,649 613 644 5 17,105 86 8 40,125 321 407 117 934 1,051 2002 34 4,854 165 34 38,007 1,292 1,457 7 28,223 198 11 36,182 398 596 363 1,690 2,053 .. .. • TABLE 32. BRISTOL BAY ELECTRICITY CONSUMPTION ., PORTAGE CREEK Actual II' 1980 2002 ., III' RESIDENTIAL lliI1 l. Customers 12 21 .. 2. Appliance Consmp. per Customer (kwh) 1,536 4,113 3. Total Appliance Consmp. (lx2) (mwh) 18 86 ., 4. Electric Space Heat Customer 13 22 ., 5. Space Heat Consmp. per Customer (kwh) 29,291 36,309 .. 6. Total Space Heat Consmp. (4x5) (mwh) 381 799 7. Total Residential Consmp. (3+6) (mwh) 399 885 • COMMERCIAL/GOVERNMENT .. 8. Customers 6 8 ., 9. Appliance Consmp. per Customer (kwh) 7,965 13,143 lIIIl" 10. Total Appliance Consmp. (8x9) (mwh) 48 105 .. ll. Electric Space Heat Customer 8 11 12. Space Heat Consmp. per Customer (kwh) 38,000 34,273 • 13. Total Space Heat Consmp. (llx12) (mwh) 304 377 14. Total Commercial Consmp. (10+13) (mwh) 352 482 .. .. MILITARY .. 15. Customers 16. Appliance Consmp. per Customer (kwh) .. 17. Total Appliance Consmp. (15x16) (mwh) .. 18. Electric Space Heat Customer .. 19. Space Heat Consmp. per Customer (kwh) 20. Total Space Heat Consmp. (18x19) (mwh) II' 2l. Total Government Consmp. (17+20) (mwh) .. INDUSTRIAL .. 22. Customers .' 23. Appliance Consmp. per Customer (kwh) 24. Total Appliance Consmp (22x23) (mwh) .. 25. Electric Space Heat Customer •• 26. Space Heat Consmp. per Customer (kwh) 27. Total Space Heat Consmp. (25x26) (mwh) .. 28. Total industrial Consmp. (24+27) (mwh) .. TOTAL IIIJ' 29. Total Appliance Consmp. (3+10+ 17+24) (mwh) 66 191 .. 30. Total Space Heat Consmp. (6+13+20+27) (mwh) 685 1,176 .. 3l. Grand Total (7+14+21+28) (mwh) 751 1,367 .. 70 .. .. TABLE 33. BRISTOL BAY ELECTRICITY CONSUMPTION KOLIGANEK RESIDENTIAL 1. Customers 2. Appliance Consmp. per Customer (kwh) 3. Total Appliance Consmp. (lx2) (mwh) 4. Electric Space Heat Customer 5. Space Heat Consmp. per Customer (kwh) 6. Total Space Heat Consmp. (4x5) (mwh) 7. Total Residential Consmp. (3+6) (mwh) COMMERCIAL/GOVERNMENT 8. Customers 9. Appliance Consmp. per Customer (kwh) 10. Total Appliance Consmp. (8x9) (mwh) 11. Electric Space Heat Customer 12. Space Heat Consmp. per Customer (kwh) 13. Total Space Heat Consmp. (11x12) (mwh) 14. Total Commercial Consmp. (10+13) (mwh) MILITARY 15. Customers 16. Appliance Consmp. per Customer (kwh) 17. Total Appliance Consmp. (15x16) (mwh) 18. Electric Space Heat Customer 19. Space Heat Consmp. per Customer (kwh) 20. Total Space Heat Consmp. (18x19) (mwh) 21. Total Government Consmp. (17+20) (mwh) INDUSTRIAL 22. Customers 23. Appliance Consmp. per Customer (kwh) 24. Total Appliance Consmp (22x23) (mwh) 25. Electric Space Heat Customer 26. Space Heat Consmp. per Customer (kwh) 27. Total Space Heat Consmp. (25x26) (mwh) 28. Total industrial Consmp. (24+27) (mwh) TOTAL 29. Total Appliance Consmp. (3+10+17+24) (mwh) 30. Total Space Heat Consmp. (6+13+20+27) (mwh) 31. Grand Total (7+14+21+28) (mwh) 71 Actual 1980 36 1,104 40 40 26,319 1,053 1,093 8 14,429 115 14 38,143 534 649 155 1,587 1,742 2002 62 4,670 290 69 32,630 2,251 2,541 11 23,808 262 20 33,100 662 924 552 2,913 3,465 TABLE 34. BRISTOL BAY ELECTRICITY CONSUMPTION ILIAMNA RESIDENTIAL 1. Customers 2. Appliance Consmp. per Customer (kwh) 3. Total Appliance Consmp. (lx2) (mwh) Actual 1980 21 3,200 67 2002 60 5,931 356 4. Electric Space Heat Customer See Iliamna, Newhalen, Nondalton 5. Space Heat Consmp. per Customer (kwh) 6. Total Space Heat Consmp. (4x5) (mwh) 7. Total Residential Consmp. (3+6) (mwh) COMMERCIAL/GOVERNMENT 8. Customers 31 68 9. Appliance Consmp. per Customer (kwh) 20,636 34,049 10. Total Appliance Consmp. (8x9) (mwh) 640 2,315 n. Electric Space Heat Customer 31 68 12. Space Heat Consmp. per Customer (kwh) 66,774 37,750 13. Total Space Heat Consmp. (11x12) (mwh) 2,070 2,567 14. Total Commercial Consmp. (10+13) (mwh) 2,710 4,882 MILITARY 15. Customers 16. Appliance Consmp. per Customer (kwh) 17. Total Appliance Consmp. (l5x16) (mwh) 18. Electric Space Heat Customer 19. Space Heat Consmp. per Customer (kwh) 20. Total Space Heat Consmp. (18x19) (mwh) 21. Total Government Consmp. (17+20) (mwh) INDUSTRIAL 22. Customers 23. Appliance Consmp. per Customer (kwh) 24. Total Appliance Consmp (22x23) (mwh) 25. Electric Space Heat Customer 26. Space Heat Consmp. per Customer (kwh) 27. Total Space Heat Consmp. (25x26) (mwh) 28. Total industrial Consmp. (24+27) (mwh) TOTAL 29. Total Appliance Consmp. (3+10+17+24) (mwh) 707 2,671 30. Total Space Heat Consmp. (6+13+20+27) (mwh) 31. Grand Total (7+14+21+28) (mwh) 72 ... ... .. .. .. .. .. -• .. ., .. ., .. -.. .. .. .. ., TABLE 35. BRISTOL BAY ELECTRICITY CONSUMPTION NEWHALEN RES IDENTIAL 1. Customers 2. Appliance Consmp. per Customer (kwh) 3. Total Appliance Consmp. (lx2) (mwh) Actual 1980 18 2,903 52 2002 51 5,782 295 4. Electric Space Heat Customer See Iliamna, Newhalen, Nondalton 5. Space Heat Consmp. per Customer (kwh) 6. Total Space Heat Consmp. (4x5) (mwh) 7. Total Residential Consmp. (3+6) (mwh) COMMERCIAL/GOVERNMENT 8. Customers 9 20 9. Appliance Consmp. per Customer (kwh) 27,066 44,659 10. Total Appliance Consmp. (8x9) (mwh) 244 893 ll. Electric Space Heat Customer 10 22 12. Space Heat Consmp. per Customer (kwh) 53,400 3,009 13. Total Space Heat Consmp. (llx12) (mwh) 534 66 14. Total Commercial Consmp. (10+13) (mwh) 778 959 MILITARY 15. Customers 16. Appliance Consmp. per Customer (kwh) 17. Total Appliance Consmp. (15x16) (mwh) 18. Electric Space Heat Customer 19. Space Heat Consmp. per Customer (kwh) 20. Total Space Heat Consmp. (l8x19) (mwh) 2l. Total Government Consmp. (17+20) (mwh) INDUSTRIAL 22. Customers 23. Appliance Consmp. per Customer (kwh) 24. Total Appliance Consmp (22x23) (mwh) 25. Electric Space Heat Customer 26. Space Heat Consmp. per Customer (kwh) 27. Total Space Heat Consmp. (25x26) (mwh) 28. Total industrial Consmp. (24+27) (mwh) TOTAL 29. Total Appliance Consmp. (3+10+17+24) (mwh) 296 1,188 30. Total Space Heat Consmp. (6+13+20+27) (mwh) 3l. Grand Total (7+14+21+28) (mwh) 73 TABLE 36. BRISTOL BAY ELECTRICITY CONSUMPTION NONDALTON RESIDENTIAL 1. Customers 2. Appliance Consmp. per Customer (kwh) 3. Total Appliance Consmp. (lx2) (mwh) Actual 1980 11 981 11 2002 31 4,782 148 4. Electric Space Heat Customer See Iliamna, Newhalen, Nondalton 5. Space Heat Consmp. per Customer (kwh) 6. Total Space Heat Consmp. (4x5) (mwh) 7. Total Residential Consmp. (3+6) (mwh) COMMERCIAL/GOVERNMENT 8. Customers 9. Appliance Consmp. per Customer (kwh) 10. Total Appliance Consmp. (8x9) (mwh) 11. Electric Space Heat Customer 12. Space Heat Consmp. per Customer (kwh) 13. Total Space Heat Consmp. (11x12) (mwh) 14. Total Commercial Consmp. (10+13) (mwh) MILITARY 15. Customers 16. Appliance Consmp. per Customer (kwh) 17. Total Appliance Consmp. (15x16) (mwh) 18. Electric Space Heat Customer 19. Space Heat Consmp. per Customer (kwh) 20. Total Space Heat Consmp. (18x19) (mwh) 21. Total Government Consmp. (17+20) (mwh) INDUSTRIAL 22. Customers 23. Appliance Consmp. per Customer (kwh) 24. Total Appliance Consmp (22x23) (mwh) 25. Electric Space Heat Customer 26. Space Heat Consmp. per Customer (kwh) 27. Total Space Heat Consmp. (25x26) (mwh) 28. Total industrial Consmp. (24+27) (mwh) TOTAL 29. Total Appliance Consmp. (3+10+17+24) (mwh) 30. Total Space Heat Consmp. (6+13+20+27) (mwh) 31. Grand Total (7+14+21+28) (mwh) 74 10 18,650 186 13 64,462 838 1,024 197 22 30,773 677 28 37,107 1,039 1,716 825 .. .. .. .. • .. .. .. .. .. .. .. .. .. .. .. RESIDENTIAL TABLE 37. BRISTOL BAY ELECTRICITY CONSUMPTION ILIAMNA, NEWHALEN, NONDALTON Actual 1980 2002 1. Customers See Sheets for Individual Villages 2. Appliance Consmp. per Customer (kwh) 3. Total Appliance Consmp. (lx2) (mwh) 4. Electric Space Heat Customer 5. Space Heat Consmp. per Customer (kwh) 6. Total Space Heat Consmp. (4x5) (mwh) 7. Total Residential Consmp. (3+6) (mwh) COMMERCIAL/GOVERNMENT 8. Customers 9. Appliance Consmp. per Customer (kwh) 10. Total Appliance Consmp. (8x9) (mwh) 95 29,234 2,777 163 36,252 5,909 11. Electric Space Heat Customer See Sheets for Individual Villages 12. Space Heat Consmp. per Customer (kwh) 13. Total Space Heat Consmp. (11x12) (mwh) 14. Total Commercial Consmp. (10+13) (mwh) MILITARY 15. Customers 16. Appliance Consmp. per Customer (kwh) 17. Total Appliance Consmp. (15x16) (mwh) 18. Electric Space Heat Customer 19. Space Heat Consmp. per Customer (kwh) 20. Total Space Heat Consmp. (18x19) (mwh) 21. Total Government Consmp. (17+20) (mwh) INDUSTRIAL 22. Customers 23. Appliance Consmp. per Customer (kwh) 24. Total Appliance Consmp (22x23) (mwh) 25. Electric Space Heat Customer 26. Space Heat Consmp. per Customer (kwh) 27. Total Space Heat Consmp. (25x26) (mwh) 28. Total industrial Consmp. (24+27) (mwh) TOTAL 29. Total Appliance Consmp. (3+10+17+24) (mwh) 30. Total Space Heat Consmp. (6+13+20+27) (mwh) 31. Grand Total (7+14+21+28) (mwh) 75 1,200 6,219 7,419 4,684 9,581 14,265 TABLE 38. BRISTOL BAY ELECTRICITY CONSUMPTION CLARK'S POINT RESIDENTIAL 1. Customers 2. Appliance Consmp. per Customer (kwh) 3. Total Appliance Consmp. (lx2) (mwh) 4. Electric Space Heat Customer 5. Space Heat Consmp. per Customer (kwh) 6. Total Space Heat Consmp. (4x5) (mwh) 7. Total Residential Consmp. (3+6) (mwh) COMMERCIAL/GOVERNMENT 8. Customers 9. Appliance Consmp. per Customer (kwh) 10. Total Appliance Consmp. (8x9) (mwh) 11. Electric Space Heat Customer 12. Space Heat Consmp. per Customer (kwh) 13. Total Space Heat Consmp. (11x12) (mwh) 14. Total Commercial Consmp. (10+13) (mwh) MILITARY 15. Customers 16. Appliance Consmp. per Customer (kwh) 17. Total Appliance Consmp. (15x16) (mwh) 18. Electric Space Heat Customer 19. Space Heat Consmp. per Customer (kwh) 20. Total Space Heat Consmp. (18x19) (mwh) 21. Total Government Consmp. (17+20) (mwh) INDUSTRIAL 22. Customers 23. Appliance Consmp. per Customer (kwh) 24. Total Appliance Consmp (22x23) (mwh) 25. Electric Space Heat Customer 26. Space Heat Consmp. per Customer (kwh) 27. Total Space Heat Consmp. (25x26) (mwh) 28. Total industrial Consmp. (24+27) (mwh) TOTAL 29. Total Appliance Consmp. (3+10+17+24) (mwh) 30. Total Space Heat Consmp. (6+13+20+27) (mwh) 31. Grand Total (7+14+21+28) (mwh) 76 Actual 1980 10 2,430 24 22 38,601 849 873 6 11,605 70 7 50,857 356 426 1 486,000 486 1 674,285 674 1,160 580 1,879 2,459 2002 29 5,490 159 38 47,855 1,818 1,977 13 19,148 249 15 29,400 441 690 1 583,000 583 1 674,285 674 1,257 991 2,933 3,924 .. .. .. .. .. .. .. - • .. -.. ., -.. .. ., .. -.. TABLE 39. BRISTOL BAY ELECTRICITY CONSUMPTION EKUK RESIDENTIAL 1. Customers 2. Appliance Consmp. per Customer (kwh) 3. Total Appliance Consmp. (lx2) (mwh) 4. Electric Space Heat Customer 5. Space Heat Consmp. per Customer (kwh) 6. Total Space Heat Consmp. (4x5) (mwh) 7. Total Residential Consmp. (3+6) (mwh) COMMERCIAL/GOVERNMENT 8. Customers 9. Appliance Consmp. per Customer (kwh) 10. Total Appliance Consmp. (8x9) (mwh) 11. Electric Space Heat Customer 12. Heat Consmp. per Customer (kwh) 13. Total Space Heat Consmp. (11x12) (mwh) 14. Total Commercial Consmp. (10+13) (mwh) MILITARY 15. Customers 16. Appliance Consmp. per Customer (kwh) 17. Total Appliance Consmp. (15x16) (mwh) 18. Electric Space Heat Customer 19. Space Heat Consmp. per Customer (kwh) 20. Total Space Heat Consmp. (18x19) (mwh) 21. Total Government Consmp. (17+20) (mwh) INDUSTRIAL 22. Customers 23. Appliance Consmp. per Customer (kwh) 24. Total Appliance Consmp (22x23) (mwh) 25. Electric Space Heat Customer 26. Space Heat Consmp. per Customer (kwh) 27. Total Space Heat Consmp. (25x26) (mwh) 28. Total industrial Consmp. (24+27) (mwh) TOTAL 29. Total Appliance Consmp. (3+10+17+24) (mwh) 30. Total Space Heat Consmp. (6+13+20+27) (mwh) 31. Grand Total (7+14+21+28) (mwh) 77 Actual 1980 2002 Included in Industrial 1 50,940 51 51 2 63,166 126 126 Included in Industrial 1 700,000 700 1 84,900 85 785 700 136 836 1 700,000 700 1 84,900 85 785 700 211 911 .. -~ .. TABLE 40. BRISTOL BAY ELECTRICITY CONSUMPTION ... LEVELOCK .. Actual I.e 1980 2002 .. RESIDENTIAL IIi!v L Customers 11 31 • 2. Appliance Consmp. per Customer (kwh) 1,453 5,552 iii' 3. Total Appliance Consmp. (lx2) (mwh) 16 172 .. 4. Electric Space Heat Customer 28 48 5. Space Heat Consmp. per Customer (kwh) 56,855 70,495 .. 6. Total Space Heat Consmp. (4x5) (mwh) 1,592 3,384 7. Total Residential Consmp. (3+6) (mwh) 1,608 3,556 • .. COMMERCIAL/GOVERNMENT .. 8. Customers 8 18 9. Appliance Consmp. per Customer (kwh) 15,711 25,923 .. 10. Total Appliance Consmp. (8x9) (mwh) 126 467 • 11. Electric Space Heat Customer 9 20 .. 12. Space Heat Consmp. per Customer (kwh) 71,111 39,700 13. Total Space Heat Consmp. (llx12) (mwh) 640 794 • 14. Total Commercial Consmp. (10+13) (mwh) 766 1,261 -MILITARY -15. Customers .. 16. Appliance Consmp. per Customer (kwh) 17. Total Appliance Consmp. (15x16) (mwh) .. 18. Electric Space Heat Customer .. 19. Space Heat Consmp. per Customer (kwh) .. 20. Total Space Heat Consmp. (18x19) (mwh) 2l. Total Government Consmp. (17+20) (mwh) .. INDUSTRIAL • 22. Customers ... 23. Appliance Consmp. per Customer (kwh) • 24. Total Appliance Consmp (22x23) (mwh) .. 25. Electric Space Heat Customer 26. Space Heat Consmp. per Customer (kwh) • 27. Total Space Heat Consmp. (25x26) (mwh) .. 28. Total industrial Consmp. (24+27) (mwh) TOTAL .. .. 29. Total Appliance Consmp. (3+10+17+24) (mwh) 142 639 30. Total Space Heat Consmp. (6+13+20+27) (mwh) 2,232 4,178 • 3l. Grand Total (7+14+21+28) (mwh) 2,374 4,817 .- 78 • .. - TABLE 41. BRISTOL BAY ELECTRICITY CONSUMPTION IGIUGIG RESIDENTIAL 1. Customers 2. Appliance Consmp. per Customer (kwh) 3. Total Appliance Consmp. (lx2) (mwh) 4. Electric Space Heat Customer 5. Space Heat Consmp. per Customer (kwh) 6. Total Space Heat Consmp. (4x5) (mwh) 7. Total Residential Consmp. (3+6) (mwh) COMMERCIAL/GOVERNMENT 8. Customers 9. Appliance Consmp. per Customer (kwh) 10. Total Appliance Consmp. (8x9) (mwh) 11. Electric Space Heat Customer 12. Space Heat Consmp. per Customer (kwh) 13. Total Space Heat Consmp. (11x12) (mwh) 14. Total Commercial Consmp. (10+13) (mwh) MILITARY 15. Customers 16. Appliance Consmp. per Customer (kwh) 17. Total Appliance Consmp. (15x16) (mwh) 18. Electric Space Heat Customer 19. Space Heat Consmp. per Customer (kwh) 20. Total Space Heat Consmp. (18x19) (mwh) 21. Total Government Consmp. (17+20) (mwh) INDUSTRIAL 22. Customers 23. Appliance Consmp. per Customer (kwh) 24. Total Appliance Consmp (22x23) (mwh) 25. Electric Space Heat Customer 26. Space Heat Consmp. per Customer (kwh) 27. Total Space Heat Consmp. (25x26) (mwh) 28. Total industrial Consmp. (24+27) (mwh) TOTAL 29. Total Appliance Consmp. (3+10+17+24) (mwh) 30. Total Space Heat Consmp. (6+13+20+27) (mwh) 31. Grand Total (7+14+21+28) (mwh) 79 Actual 1980 11 2,613 29 15 30,649 460 489 5 27,416 137 4 108,000 432 569 166 892 1,058 2002 31 5,839 181 26 38,007 988 1,169 11 45,236 498 9 59,556 536 1,034 679 1,524 2,203