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HomeMy WebLinkAboutKotzebue-Coal Fired Congeneration,District Heating And Other Energy Alternatives Feasibility Assessment-Volume Two 1982 KOTZEBUE Coal-Fired Cogeneration, District Heating and Other Energy Alternatives Feasibility Assessment VOLUME TWO by A JOINT VENTURE OF ARCTIC SLOPE TECHNICAL SERVICES, INC. RALPH STEFANO ASSOCIATES, INC. VECO, INC. ANCHORAGE , ALASKA NOVEMBER, 1982 ALASKA POWER AUTHORITY | KOTZEBUE Coal-Fired Cogeneration, District Heating and Other Energy Alternatives Feasibility Assessment VOLUME TWO by A JOINT VENTURE OF ARCTIC SLOPE TECHNICAL SERVICES, INC. RALPH STEFANO ASSOCIATES, INC. VECO, INC. ANCHORAGE , ALASKA NOVEMBER, 1982 ALASKA POWER AUTHORITY APPENDIX APPENDIX APPENDIX APPENDIX APPENDIX APPENDIX APPENDIX APPENDIX APPENDIX APPENDIX Qt woUoA wD Pp VOLUME II APPENDICES TABLE OF CONTENTS LITERATURE RESEARCH........6- AGENCY INPUT AND COMMENTS.... GEOTHERMAL TEST-WELL PROGRAM. TECHNOLOGY PROFILES........ CONSERVATION... ce eecccceee COST ESTIMATES DATA........ OPERATION AND MAINTENANCE. . FUEL DEMAND......ceeeeceeee CALCULATION OF PRESENT WORTH OF CAPITAL COST... cece cece ccc cceee COAL TRANSPORTATION ANALYSIS.... wecAnk sifetie = reise rere 1 -+-E-1 oj ous tii aio seoH-1 APPENDIX A LITERATURE RESEARCH 1.0 2.0 10.0 11.0 12.0 APPENDIX A LITERATURE RESEARCH TABLE OF CONTENTS PAGE General. ccrccccccsccvcccvccevscsccscsesesecseveseeecAml OVELVieW. ccccccrccccccvcccccvecccccccccsesevcecesese cAml Energy FOrecastS.ccccccccccrcrccecscsvesesesesesessvAn2 Coal Requirements For Electrical Energy.-.eeseeeeeeeA-5 Coal Requirements For Space Heating. -.seceecceseeveeeA-7 Waste Heat RECOVELYseeeeeseeereeressrerereseesveeeeeA“J9 Coal RESOULCES. coccccccccccccccccccevecccccesecesceA—ld GeotherMal.ccccccccccccccccvcscvscccsecssescscesees cAnm13 Wind erccccccccecsscscvevecccccsvesesescsevececsccecs cA@l5 HYGropOwerre cecceccccvcccsecccccceesessesesesessces sA-1l5 Coal-Gasification. ccccccccrcsescccccoscsvccccvcssessAWl6 Energy Conservation. ccccccccccccccscccccvccssevcccs cAWl6 LIST OF TABLES Table A.l Electrical and Heating Requirements for the City of Kotzebue..ccccccccccccccseveeeeevAn3 Table A.2 Coal Demand Forecast for the City of Kotzebue for Electrical Generation.......e+.A-6 Table A.3 Coal Demand Forecast for the City of Kotzebue for Space Heating, Direct Fired....A-9 APPENDIX A: 1.0 GENERA LITERATURE RESEARCH L A review of previous investigations of alternative energy resources for Kotzebue was conducted to identify power project alternatives applicabilit 2.0 OVERVI Past studies ° which had been examined and their possible y to this feasibility assessment EW and existing data reviewed were: Robert W. Retherford and Associates. Assessment of Power Generation Alternatives for Kotzebue. June, 1980. Energy Systems, Inc. Kotzebue Geothermal Project. October 1980. Energy Systems, Inc. Kotzebue Geothermal Project. January 1981. Dames and Moore. Assessment of Coal Resources of Northwest Alaska. Vols. I & II, December, 1980. Dames and Moore. Assessment of the Feasibility of Utilization of the Coal Resources of Northwestern Alaska for Space Heating and Electricity. Draft June, 1981. Arctic Slope Technical Services. District Central Heating System, Wainwright, Feasibility Study. 1980. Robert W. Retherford and Associates. Power Requirement Study. Draft, October, 1980. A-1 ° Robert W. Retherford and Associates. Financial Forecast. Draft, October 1980. ° Robert W. Retherford and Associates. Construction Work Plan. Draft, October 1980. ° Kotzebue Electric Association, Supply Substation Data for 1968 through 1981. Based on our review, it is noted that significant numbers of recent studies and reports exist. While some of this information is quite preliminary, other data are quite detailed. We judge from this that all practical energy sources have been considered. It should, however, be noted that without the detailed cost estimates provided in Section 8 of this report the question of whether alternatives had been sufficiently studied could not categorically be answered from the literature research. A minimum comparable level of study and cost estimate for each apparent usable alternative is provided in Section 10: Plan Evaluation. 3.0 ENERGY FORECASTS General Energy Review and Analysis Forecasts of the projected energy requirements for the City of Kotzebue had been performed by Robert W. Retherford Associates, Dames & Moore, and Louis Berger and Associates, Inc, |), The results of these forecasts are presented in Table A.1. An examination of Table A.1 indicated that Retherford and Associates shows an increase in the demand for electric energy of about 10 percent per year. Dames & Moore projects that the demand for electrical energy over the next 20 years will grow at a rate of 0.3 percent per year. Furthermore, they project a growth rate for space heating at 0.6 percent per year. Marna The information from Louis Berger and Associates has been requested; however, it has not been received in time for this evaluation. Some preliminary data have been taken from Energy Systems' report for use in this review. A-2 TABLE A.1 Electrical and Heating Requirements For The City of Kotzebue ELECTRICAL (energy in 1 x 10 !! Btu) Retherford (1) Dames & Moore (2,3) Louis Berger (5) 1980 0.403 0.292 0.37 1985 0.708 0.299 N/A 1990 1.101 0.302 N/A 1995 1.743 0.305 N/A 2000 2.756 0.308 N/A SPACE HEATING (energy in 1 x 10 !! ptu) Retherford Dames & Moore (274) Louis Berger ie 1980 0.91 1.179 0.72 1985 oo 1.241 N/A 1990 ---- 1.266 N/A 1995 “== 1.293 N/A 2000 -—-- 1.321 N/A (1) Converted from MWh to Btu (2) Converted from diesel fuel (130,952 Btu/gal) (3) Conversion efficiency = 18.6% (4) Direct combustion with conversion efficiency = 50% (5) Data obtained from Energy Systems, Inc. Report on Kotzebue Geothermal Project, Oct. 1980 to the Alaska Power Authority. A-3 The values presented by both Retherford and Associates and Dames & Moore appear to be at the two extreme ends of the spectrum, i.e.: o Retherford's projections were based on KEA projected power requirements of 10 percent per year for 10 to 15 years and this rate was assumed for the additional 5 to 10 years. Furthermore, they assumed that the Air Force base would be tied into the system by 1985 and this would add an additional 1750 MWH of power to the Kotzebue requirements. A system loss of 11 percent was included. Retherford also estimated the residential heat load using the following assumptions: (1) heating degree-days of 16,039; 2) a standard 30 x 30 x 12.5 ft. building; (3) R- 11 insulation (U = 0.09) four walls of 2" x 4" construction on 16" centers; (4) unheated attic with 4 inches of insulation; (5) 2 — 24" x 40" windows; and (6) two air changes per hour. Based on these assumptions, the residential heat load for 1980 was esimated to be 0.91 x 10!! Btu. o Dames and Moore stated that their energy projections for Kotzebue through the year 2000 were based on a combination of actual data and reasonable assumptions. These assump- tions were: (1) energy patterns would remain constant over the entire study period; (2) electrical generation and space heating requirements were based on projected diesel oil consumption; and (3) population growth was used as a basis for projecting energy demand in the residential and educational sectors. Dames & Moore did not present a methodology as to how they arrived at their projected values for electrical and space heating energy require- ments. Furthermore, they did not explain why they project nearly a zero energy growth rate for both electrical and space heating requirements over the next 20 years. A-4 Population statistics alone indicate an approximate growth rate of 5.3 percent per year, and KEA projects an increase in demand for electrical energy over the next 10 to 15 years at a 10 percent per year rate. Therefore, without further data or information and the methodology used in formulating these energy projections, these projections appear to be more conservative than the known information would suggest. 4.0 COAL REQUIREMENTS FOR ELECTRICAL ENERGY In analyzing the quantity of coal required to satisfy the stated energy requirements, the coals from the Kallarichuk River, Kobuk River, and Chicago Creek were used as potential sources. The Kallarichuk coal is a good grade bituminous type that has a heating value of 9200 to 10,500 Btu/lb. The Kobuk River coal is ranked as a high volatile "C" bituminous coal with a heating value of about 10,700 Btu/lb. The coal from the Chicago Creek mine is lignite that has a heating value of approximately 6500 Btu/1b. Using the energy forecasts presented in Table A.1l for Retherford, Dames & Moore, and Louis Berger, the coal equivalents are pre- sented in Table A.2. It should be noted that the heating value for both the Kallarichuk and Kobuk River coals will be the same at 10,000 Btu/lb. in the analysis and comparison. Furthermore, since Retherford, Dames & Moore and Louis Berger all have different system factors, an accurate direct comparison cannot be made. An examination of these coal requirements for electrical power generation shows that Retherford indicated that about 20,000 tons would be required (no year specified), whereas, Dames & Moore indicated that about 9,482 tons would be required. The low value for Dames & Moore is a direct result of their energy forecasts showing nearly zero growth electrical power over the next 20 years. TABLE A.2 Coal Demand Forecast for The City of Kotzebue for Electrical Generation Retherford Dames & Moore ‘2) Louis Berger (2) (Coal Equivalents in Short Tons) Kallarichuk & Kobuk River Coal (1!) 1980 er 5,840 7,400 1985 ee 5,980 ---- 1990 TI 6,040 (cone eee 1995 ——<= 6,100 ---- 2000 aaa 6,160 ——— Chicago Creek Coa1!3) 1980 ———— 8,994 11,396 L985) ---- 9,209 ---- 1990 ———— 9,301 <== 1995 ae 9,394 ---- 2000 oe 9,486 ---- (1) Heating value = 10,000 Btu/1b (2) System efficiency - 25% reported by Dames & Moore. 6500 Btu/1b (3) Heating Value 5.0 COAL REQUIREMENTS FOR SPACE HEATING It is assumed that the same coals used in the determination of the coal requirements for electrical generation will be used in the evaluation and analysis for space heating. Using the energy forecasts presented in Table A.l., the coal equivalents for space heating by direct combustion to produce warm air are presented in Table A.3. An examination of Table A.3 indicates Dames & Moore believes that in 1980 Kotzebue would require 18,000 tons of coal (using Chicago Creek coal), whereas Retherford and Louis Berger believe that only 14,000 tons and 11,100 tons respectively would be required. However, Dames & Moore shows that only 20,300 tons of Chicago Creek coal would be required in the year 2000, which is the result of a nearly zero energy growth rate over the twenty-year period. TABLE A.3 Coal Demand Forecast for The City of Kotzebue for Space Heating (1) Direct Fired Retherford Dames & Moore Louis Berger (Coal Equivalents in Short Tons) Kallarichuk & Kobuk River Coal (2) 1980 9,100 11,790 7,200 198500 ween 12,410 2 wee 1990 wane 12,660 ===== 1995 wae 12,930 2 =eeea 200000 ween 13,2100 mene Chicago Creek Coal (3) 1980 14,014 18,157 11,088 1985 0 =annn= 19,11. ween 1990 =e === 19,496 nm 1995 ----- 19,912 ween 200000 wen 20,343 een (1) Energy Forecasts from Table 1 (2) Heating value equal to 10,000 Btu/1b (3) Heating Value equal to 6500 Btu/1b 6.0 WASTE HEAT RECOVERY Waste heat recovery systems will recover the heat used to cool the diesel engine or the exhaust steam from a steam turbine to provide district space heating or perform other additional work. The quantities of coal required for space heating and electrical generation shown in Table A.3 appear to not take into account waste heat recovery. The more common practice would be to generate the electricity using a coal-fired boiler and a steam turbine. By recovering the waste heat from the turbine exhaust, hot water district heating for the city could be accomplished. Using this technique would substantially lower the coal requirements presented in Table A.3. Consequently, this analysis has been further discussed in Section 7 of this report. The scenarios chosen by Robert W. Retherford and Associates did not take waste heat utilization into account. Retherford indicated that this was not done because it would not allow for a valid comparison between the diesel base case and the coal utilization case. Eliminating the waste heat recovery from the diesel case and the energy recovery from the coal case is questionable logic for comparing the two scenarios, since in each case the quantity of fuel would be reduced and therefore the unit cost would be reduced. The heat recovery from each scenario is not equal; hence, an invalid comparison between the two scenarios exists. Dames & Moore did not address the issue of heat recovery. Retherford estimates noted that 317,000 gallons of diesel fuel could be saved annually by using waste heat recovery from the diesel generators and that 23-46 trillion Btu per year were available as waste heat. 7.0 COAL RESOURCES The Retherford study identified four coal provinces within the Kotzebue area for possible development. These areas are: (1) Chicago Creek; (2) Corwin Bluff; (3) Point Hope; and (4) Kobuk River. Of these identified areas the Chicago Creek coal was investigated for coal utilization. These coal provinces would merit further attention and analysis in terms of environmental and economic issues, The Dames & Moore Phase I study was to determine existing fuel utilization rates and patterns by villages within the study area, and identify coal resources in Northwest Alaska that might be suitable substitutes for petroleum-based fuels in village elec- trical and heating applications. Kotzebue was not included as one of the communities addressed in the Dames & Moore study area. The following Dames & Moore report conclusions are noted: o Shortfalls in fuel supply have occurred in many of the villages in the study area. o Total annual petroleum consumption by 27 villages within the study area in 1979-1980 was approximately 5.2 million gallons or an equivalent of more than 100,000 52-gallon drums. Of this quantity, 3.2 million gallons were used for heating and 2.0 million gallons for electricity generation. o The general attitude among consumers seems positive toward finding an alternative fuel source for the area that will provide adequate and reliable heat and power. Additionally, Dames & Moore's evaluation of those coal resources in the study area which were believed to have the greatest potential for development as fuel sources for the villages were ranked according to their overall suitability as targets for future exploration. The following report determinations are noted: o Of the 49 occurrences investigated, 36 were considered suitable candidates for the conduct of additional exploration work, ranging from spot checking of previously identified localities to more extensive mapping programs. o There are very few hard data (either quantitative or quali- tative) on the coal occurrences within the study area. What information is accessible is either outdated or does not specifically address itself to coal resources. Consequently, the total coal resource base of northwestern Alaska is generally unknown, and by and large remains virtually unexplored. o Nearly all of the coals occurring within the project area are of lignitic to bituminous grade and are 0of Mississippian, Cretaceous, or Tertiary age--the majority appearing to fall into the two latter age groups. Mississippian coals are generally bituminous to semianthracitic in grade, Cretaceous coals are mostly subbitumious to bituminous, and Tertiary coals’ are primarily lignitic. Dames & Moore noted that several coal occurrences are believed to warrant further investigation. The most promising occurrences are divided into three categories according to their apparent relative potential. Category I includes those occurrences that have a measured section of at least 10 feet total thickness, generally have indicated resource estimates, and generally have analytical data available. Category II have either measured sections or occurs as float, some have indicated resource estimates, and some have analytical data. Category III usually occurs only as float; where measured sections are identified, A-11 aggregate thickness is generally less than 4 feet; and generally no analytical data are available. The following Dames & Moore report conclusions are noted: o It appears feasible to supply the space heat needs for the majority of the study area with coal. o Electrical power can also be economically supplied by coal in the larger communities of Kotzebue, Nome, Unalakleet, and possibly Selawik. ° Any coal resource that met the following criteria was worthy of further evaluation. 1) Heat value of 10,000 Btu/lb.; 2) Reserves sufficient to supply 60,000 to 100,000 tons per year for 20 years; 3) Surface mineable and barge accessible -- either coastal or riverine, or within about 20 miles of such access. According to Dames and Moore's analysis, coal from such a resource could be mined and shipped by tug and barge to the majority of villages in the study area for approximately $80 to $208 per ton, depending on transportation distance. The principal factors which supported this statement are: ° The cost of transporting coal has significant impact on energy cost to the user. The best approach is to deliver coal by a 500-ton barge, which can be beached and off-loaded by a front-end loader. ° The energy content of its coal has a significant impact on consumer cost. An example is that Chicago Creek's 6500-Btu/1b A=12 resource is more expensive to the study area as a whole than the resources of the Cape Lisburne to Point Lay region, which have indicated values of 10,000 Btu/lb or higher. ° The cost of mining has relatively little impact on consumer cost if a single mine furnishes coal for the whole study area. ° Power plant capital and operating costs have significant impact, and currently only Nome, Kotzebue, Unalakleet, and perhaps Selawik could justify coal-fired village plants. ° The cost of transmission lines has significant impact on the price of electricity to consumers. ° The extent of the actual coal resource base is speculative. ° Those coal occurrences which are at or within 30 miles of the coast, are mineable by surface methods, and which have a heat value of at least 10,000 Btu should be explored. 8.0 GEOTHERMAL Existing literature relevant to the geothermal potential of the Kotzebue area was reviewed, i.e. reports prepared by Energy Systems, Inc. and Robert W. Retherford and Associates. Based on a recorded bottom-hole temperature of 162°F (72°C) at 6,300 feet in a hydrocarbon exploration well drilled by Chevron approximately 15 miles south of Kotzebue, Retherford and Associates (1980) concluded that utilization of a low-grade geothermal resource for district space heating is conceivable. However, it was recognized that additional geologic exploration A-13 would be required to determine whether sufficient water temperatures and flow rates exist in the subsurface near Kotzebue to allow any logical development to proceed. Energy Systems, Inc. (1981) noted that the projected costs for development of a geothermal district heating system were too high. However, the geologic data used to support this conclusion were limited. The geologic data consisted primarily of the results of geological and geophysical well logging, drill-stem tests, test water chemistry, and temperature surveys within two Chevron hydrocarbon exploration wells, the Nimiuk Point #1 and the Cape Espenberg #1. The regional geothermal gradient established from these two wells indicates an abnormally high geothermal gradient for the Tertiary sedimentary rocks overlying probable Cretaceous volcanics and probable middle Paleozoic metamorphics. Interpretation of reflection seismic data supplied by Chevron indicated only 2,000' of Quaternary and Tertiary sediments overlying the less permeable volcanics and metamorphics in the Kotzebue area. This interpretation is not consistent with older gravity mapping completed by the United States Geological Survey. The gravity interpretation, however, is known to be in error in the prediction of depth to bedrock at Cape Espenberg #1. The thickness of the permeable sedimentary column in the Kotzebue area is critical in determining if the regional geothermal gradient can develop sufficiently hot waters in adequate reservoir rocks near the district heating center. However, additional data are necessary if one is to determine if localized hot spots of even higher geothermal gradient may be present. The nearest known hot springs occur in the Seward Peninsula at Serpentine Springs (65°51' N, 164°42' W) and at Pilgrim Hot Springs (65°06' N, 164°55' W). The previous wells were not drilled to determine geothermal potential, and therefore may not be indicative of the maximum geothermal gradients in the area. 9.0 WIND The information presented on wind power potential, available wind systems, costs and power production appear to be outdated. For example, resource typing information on Kotzebue has_ been available since December 1980 which accurately gives wind power density data. Manufacturers have taken considerable strides in making their hardware more reliable and much experience has recently been gained in Alaska with wind generators. While these may be more appropriate for the villages, an update has been provided in section 7 of this report. 10.0 HYDROPOWER Based on a review of "Assessment of Power Generation Alternatives for Kotzebue" (Robert W. Retherford and Associates) it appears that the Buckland site, as represented, is a feasible energy alternative (based on acceptance of their costs and hydrology parameters). In consideration of this alternative the following preliminary concerns are noted: ° Potentially high environmental and technical problems associated with large shallow reservoir. ° Long exposed transmission line makes firm power questionable. ° Overall cost estimate appears low. A-15 11.0 COAL-GASIFICATION Retherford and Dames & Moore noted that coal-gasification technology and equipment are still in the development stage (assumed for small installations, i.e. less than 100 MW). Luigi, Winkler, Texaco, etc., all have had coal gasification plants operating successfully around the world. These plants are also being operated on a variety of coal types. While there is a tremendous amount of operation and maintenance, economic and technical data available to accurately assess above-ground coal gasification as a viable alternative for an energy source to produce electricity, there are few data on current state-of-the- art small power facilities. We believe this is because of the significantly high initial cost for small operating plants. Retherford indicates that in the operation of a coal gasification facility fewer problems are encountered than in a steam plant. Operation of a gasification facility requires less skilled personnel with lower maintenance requirements. In addition, the emissions from the facility are estimated to be less harmful than from a steam plant. These statements are questionable for an above-ground coal-gasification facility as currently defined by DOE. Coal-gasification facilities including all of the ancillary equipment are highly complex, requiring skilled personnel to operate them. Maintenance costs are significant and_ the environmental pollution could easily be greater. 12.0 ENERGY CONSERVATION The existing reports do not refer to energy conservation, e.g. increased insulation of existing structures by retrofit, weatherization, etc., even though it has proved to be a very cost-effective way to save energy. According to the reviewed reports, the energy demand for heating purposes in the Kotzebue area is presently approximately two to four times the demand for electrical power. Although buildings in Kotzebue seem to be of a rather good standard with respect to insulation (Energy Systems, Inc.: Kotzebue Geothermal Project), they probably do not meet today's requirements of economical insulation; nor would they satisfy an option like heat capture from ventilation air, which has not been considered. Application of features like increased insulation thicknesses, weatherization, heat capture from ventilation air, etc. will a schedule of improvements, listing improvements and their effects has been addressed in Section 7 of this report. reduce the energy demand for heating purposes considerably; APPENDIX B PUBLIC COMMENTS AND AGENCY INPUT APPENDIX B PUBLIC COMMENTS AND AGENCY INPUT TABLE OF CONTENTS Agencies and Organizations Contacted......cccccccccceee Bol Agency and Organization Responses (during report preparation) ....cccccccceccccccccscecvcccssseseeeBn4 Agency and Organization Responses (after review OL ArALC LEPOLE)) cio oleic, oi0:010, oisicielsicjeicsieis\c.s Miokerereleledeloieieleversisie 515 Responses to Agencies and Organizations (atter review of draft report) s/s\o.ci's\s.cliere sislele’s cielo © cieiele oe sieib= OO) APPENDIX B: di. PUBLIC COMMENTS AND AGENCY INPUT AGENCIES AND ORGANIZATIONS CONTACTED Below are listed the agencies and organizations contacted about our study. A sample of the information letter sent out requesting comments and a complete distribution list for the draft report appear on the following pages. Alaska Power Administration Federal Building Juneau, AK 99801 U.S. Corps of Engineers P.O.Box 7002 Anchorage, AK 99510 State of Alaska Department of Transportation and Public Facilities 4111 Aviation Drive Anchorage, AK 99502 State of Alaska Public Utilities Commission 338 Denali Anchorage, AK 99501 United States Department of the Interior 1675 "C" Street Anchorage, AK 99501 University of Alaska 3211 Providence Drive Anchorage, AK 99504 Alaska Center for the Environment 1069 W. 6th Avenue Anchorage, AK 99501 State of Alaska Department of Commerce and Economic Development Energy and Power Development 338 Denali Anchorage, AK 99501 City of Kotzebue Kotzebue, AK 99752 Division of Community Planning Regional Affairs 225 Cordova Street, Building B Anchorage, AK 99501 University of Alaska Institute of Social and Economic Research 707 "A" Street Anchorage, AK 99501 University of Alaska Arctic Environmental Information and Data Center 707 "A" Street Anchorage, AK 99501 United States Department of the Interior Bureau of Mines, Alaska Field Operations Center 2221 E. Northern Lights Blvd. Anchorage, AK 99504 Rural Community Action Program 327 Eagle Anchorage, AK 99501 Maniilag Association Box 256 Kotzebue, AK 99752 NANA Development Corporation, 4707 Harding Drive Anchorage, AK 99503 Ines Kotzebue District Heat Work Group Kotzebue, AK 99752 Kotzebue Electric Association Kotzebue, AK 99752 DRAFT REPORT DISTRIBUTION LIST The Honorable Ronald O. Skoog Commissioner Department of Fish & Game Subport Building Juneau, AK 99811 Colonel Neil Saling U.S. Army Corps of Engineers P.O.Box 7002 Anchorage, AK 99510 Director Environmental Protection Agency 701 C Street Anchorage, AK 99510 The Honorable John Katz Commissioner Department of Natural Resources Pouch M Juneau, AK 99811 The Honorable Ernst Mueller Commissioner Department of Environmental Conservation Pouch O Juneau, AK 99811 The Honorable Robert W. Ward Commissioner Department of Transportation and Public Facilities Pouch Z Juneau, AK 99811 Mr. George Matz Office of the Governor Division of Budget & Management Pouch AM Juneau, AK 99811 Mr. Bob Bowker U.S. Fish and Wildlife Service 733 West 4th Avenue Anchorage, AK 99501 Mr. Murray Walsh Coordinator Office of Coastal Management Pouch AD Juneau, AK 99811 Mr. Robert Cross Administrator Alaska Power Administration P.O. Box 50 Junueau, AK 99802 The Honorable Lee McAnerney Commissioner Department of Community & Regional Affairs Pouch B Juneau, AK 99811 Mr. Keith Schreiner Region Director U.S. Fish & Wildlife Service 1011 E. Tudor Road Anchorage, AK 99503 Mr, Reed Stoops Director Department of Natural Resources Division of Research & Development Pouch 7-005 Anchorage, AK 99503 Mr. Bob Martin Department of Environmental Conservation 437 E. Street Anchorage, AK 99501 Mr. Clay G. Beal Forest Supervisor United States Department of Agriculture, Forest Servi 22221 E. Northern Lights Blvd. Suite 238 Anchorage, AK 99508 Mr. Carl Yanagawa Regional Supervisor ‘Alaska Department of Fish and Game 333 Raspberry Road Anchorage, AK 99502 Ms. Mary Lynn Nation U.S. Fish and Wildlife Service 605 West 4th Avenue, Suite G-f. Anchorage, AK 99501 Mr. Lou Riggs REA Field Representative P.O. Box 7234 Bellevue, WA 98007 State Clearing House Pouch AD Juneau, AK 99811 Mr. Ronald Morris Director National Marine Fisheries Service 701 C Street Anchorage, AK 99513 Mr. Kurt Dzinich Hydro Development Specialist Alaska Senate Research Pouch V Juneau, AK 99811 Mr. Mark Stephens Department of Community & Regional Affairs 225 Cordova Street Bldg. B Anchorage, AK 99501 Mr. Allen Yost Operation Field Representative SRA Box 907 Anchorage, AK 99502 Mr. Ty L. Dilliplane State Historic Preservation Office Division of Parks 619 Warehouse Avenue, Suite 210 Anchorage, AK 99510 Mr. Robert W. McVey Director Alaska Region National Marine Fisheries Service P.O. Box 1668 Juneau, AK 99802 Mr. John E. Cook Regional Director National Park Service 450 W. Fifth Avenue Anchorage, AK 99501 Mr. Richard Tyndall Director U.S. Department of Interior Bureau of Land Management 4700 East 72nd Street Anchorage, AK 99507 Mr. William H. Beardsley Director Division of Energy & Power Development 338 Denali Street McKay Building, 7th Floor Anchorage, AK 99501 Mauneluk Association P.O. Box 256 Kotzebue, AK 99752 ATTN: Mr. Matt Conover Mr. John Schaeffer, President NANA Regional Corporation Box 49 Kotzebue, AK 99752 Mr. Pete Jorgensen NANA Development Corp. 4706 Harding Drive Anchorage, AK 99503 Director Kotzebue Technical Center P.O. Box 51 Kotzebue, AK 99752 Mr. Frank Sheldon General Manager Kotzebue Electric Association Kotzebue, AK 99752 ATTN: Mr. Don Fiscus Mr. Gene Moore City Manager P.O. Box 46 Kotzebue, AK 99752 Mr. Royal Harris Mayor City of Kotzebue P.O. Box 46 Kotzebue, AK 99752 ae AGENCY AND ORGANIZATION RESPONSES (During report preparation) A copy of a typical letter requesting comments from agencies and other interested entities, as well as copies of correspondence received in response to this letter, appear on the following pages. ANCHORAGE, ALASKA BARROW, ALASKA COPENHAGEN, DENMARK . , DENVER, COLORADO j arctic ce HOUSTON, TEXAS OSLO. NORWAY \ technical services SEATTLE, WASHINGTON ut INCOrporated 420 L STREET + ANCHORAGE, ALASKA 99501 * TELEPHONE (907) 276-0517 WASHINGTON, D.C. January 6, 1982 "TYPICAL LETTER SENT TO AGENCIES ET. AL." Alaska Power Administration Federal Building Juneau, AK 99801 Dear Sirs: The Joint Venture of VECO, R. Stefano and Arctic Slope Technical Services has been selected by the Alaska Power Authority to analyze for the city of Kotzebue their District Heat and Coal Utilization needs projected through the year 2002. During 1980 and 1981 reconnaissance studies of the energy potential and area needs were conducted. In part, these included studies of hydroelectric, coal, wind, geothermal, etc. We believe you are aware of these studies done for the State of Alaska Power Administration and Division of Energy and Power Development; they are: (1) Assessment of Power Generation Alternatives for Kotzebue, Robert W. Retherford Consulting Engineers, June, 1980. (2) Kotzebue Geothermal Project, Energy Systems, Inc., October, 1980. (3) Kotzebue Geothermal Project, Energy Systems, Inc., January 1981. (4) Assessment of Coal Resources of Northwest Alaska, (Vols. I & II), Dames and Moore, December, 1980. (5) Assessment of the Feasibility of Utilization of the Coal Resources of Northwestern Alaska for Space Heating and Electricity, (Draft), Dames and Moore, June, 1981. Kotzebue January 6, 1982 Page 2 We would be pleased to meet with you at your convenience to better brief you on our work efforts should you so desire. Additionally, we would appreciate any comments you may have on the above noted studies or other concerns which deal with electrical generation and district heating. If you have any comments, please furnish them to us by the middle of February. Your cooperation is appreciated. Sincerely yours, ARCTIC SLOPE TECHNICAL SERVICES, INC. Morris J. Turner, P.E. Project Manager MJT:cm KO-1 ARCTIC SLOPE TECHNICAL SERVICES INC. JAN2 11982 Department Of Energy Alaska Power Administration P.O. Box 50 Juneau, Alaska 99802 January 19, 1982 Mr. Morris J. Turner, P.E. Project Manager Arctic Slope Technical Services Incorporated 420 L Street Anchorage, AK 99501 Dear Mr. Turner: Thank you for your January 6 notice of investigation of District Heating and Coal Utilization for Kotzebue for the Alaska Power Authority. We did present comments to the Alaska Power Authority on the Assessment of Coal Resources of Northwestern Alaska for Space Heating and Electricity, Dames and Moore, December 1980. copy of our letter is enclosed. We have no other information to provide. é Sincerely, ” (3% AMM Robert J. Cross Administrator Enclosure Arctic Environmental Information and Data Center 707 A Street Anchorage, Alaska 99501 PHONE (907) 279-4523 ARCTIC SLOPE TECHNICAL SERVICES INC. JAN 2 11982 UNIVERSITY OF ALASKA Janaury 19, 1982 Mr. Morris J. Turner Project Manager Arctic Slope Technical Services, Inc. 420 L Street Anchorage, Alaska 99501 Dear Mr. Turner: This responds to your letter of January 6 relative to heat and coal utilization in the Kotzebue area. The subject studies are generally known to me. However, these reports have not been readily available to the natural resource and engineering profession. Thus, their efficacy has not been discussed widely. Moreover, these reports are only a small fraction of the available literature on coal, geothermal, and wind resources in northwest Alaska. Should you wish to examine other reports, references are available here at AEIDC and we would be happy to serve you. erely, are Heke E David M. Hickok Director DMH/pp January 27, 1982 Albert L. Swank VECO Inc. 5151 Fairbanks St. Anchorage, Alaska 99503 Dear Mr. Swank: - Enclosed are hand written comments on the study underway at Kotzebue. I must apolegize for the form as no typist is available to me that would do the work. I had planned on submitting the comnents at the public meeting, however, I was still busy. Thank You Sincerely, a Donald Fiscus The attached letter from Donald Fiscus was typed from handwritten copy referenced in the above letter. Submitted by letter on Page 1 January 27, 1982 WRITTEN COMMENTS BY DONALD FISCUS FOR KOTZEBUE DISTRICT HEATING AND COGENEPATION STULY From the original proposal and from the contract document Appendix B it is apparent that the intention was to use the coal in some form of boiler to either make steam for heat- ing water or to heat water directly for the purpose of heating the buildings in Kotzebue with the hot water. The question of electric cogeneration is a possibility only if steam is generated and therefore was thrown in to be con- sidered. At the insistence of a certain individual, consi- deration was given to include in the study the use of manufactured gas for home heating and electric genera- tion. The manufactured gas process to be considered is coal gassification. In comparing the two possible methods of using coal, we quickly find considerable dollar differences. Making a conservative estimate for steam, approximately $7,000,000 would be spent to install boilers, electric generators, heat exchangers, distribution facilities and building heating equipment. The annual depreciation and interest (30 years, 5%) would be $583,333 on equipment alone. For manufactured gas, the estimate is $2,100,000 with an annual depreciation and interest (30 years, 5%) of $175,000. These estimates would be about the same regardless of which coal (6500 Btu/ton or 10,000 Btu/ton) was used. When including the operational cost of coal, labor, and overhead, the consumer cost was calculated and showed that costs would rise about 6% if boilers were used and go down about 12% if manufactured gas was used. In the calculation of these estimates, reference was made to various engineering and chemical publications to derive the efficiency of all parts and pieces that would be necessary in each method. Page 2 Such as: Steam Equipment Efficiency Manufactured Gas Efficiency Boiler 80% Generator 70% Heat Exchanger 80% Dist. System 100% Dist. System 80% Generator 32% Generator 28% Home Heater 80% The availability of manufactured gas equipment is not widely known although it is readily available, if not in the United States then in Europe. Also, equipment designed to operate on manufactured gas is readily available, if not in the United States then in Europe. The question of using coal to replace other forms of energy in Kotzebue will be answered by this study. However, there are other more important questions this study will have unanswered for one reason or another. The first question is: what coal will be used? If the coal comes from outside the Nana Region regardless of the quality, then $3,220,000 would leave the area just as the money now spent for oil leaves the area. If instead, the coal used is from the Nana Region, then the money would stay in the hands of the residents of the Nana Region. The dollar value for inside ($100/ton) or outside $150/ton) would be about equal since the volume for Nana coal at 6,500 Btu/ton would be larger than North Slope coal at 10,000 Btu/ton. The second question is: how to use the coal? Some minor research was accomplished and determined that manufactured gas equipment is now available in small units sized to 100 homes. These were the sizes included in the above estimate since multiple small units provide much greater versatility and reduce operational problems. B-11 Page 3 Conversation indicates that some people are aware of manu- factured gas possibility but they are either misled or misinformed on required equipment and therefore believe the costs to be much highier than necessary. Another misconception of manufactured “gas is that it will not provide sufficient fuel to operate an internal combus- tion engine. In fact, the only modification to any gas engine necessary to have it operate on manufactured gas is to modify the carburation so that the fuel/air ratio is changed from 1:10 to 1:1 approximately. With this change, the burnables to nitrogen ratio in the firing chamber is Maintained. The only effect is to reduce the H.P. produced by about 25%. For diesels, the HP reduction is about 358%. In both gas and diesel engines all other operations remain the same. In the event that steam boilers are determined to be the most desirable method, then an entire new level of knowledge will be required since State licenses are required for the operation of the pressure vessels capable of developing pressures necessary to generate electricity with a steam generator. The time required to obtain the knowledge and experience for a boiler license precludes anyone in this area. Only imported persons with licenses could operate the boilers. Manufactured gas does not require any licenses since it is a different technology; therefore local people could operate the equipment with minimum training. The effect on local income would be approximately: Steam ~ Manufactured Gas Imported Labor $346,000 -- Page 4 Local Labor 604,000 $789,200 $950,000 $789,200 The sources of the coal would have considerable affect on the local bills for either process. Steam Manufactured Gas 10,000 Btu/ton + $238,131 - $512,905 6,500 Btu/ton + 412,155 - 836,508 When totalling the various monies, a local economic benefit would be realized by either process regardless of the source of the coal. The most important question is which process and which coal would have the greatest benefit. From my estimates: Economic Benefit to Present Nana Residents: Steam Manufactured Gas North Slope 10,000 Btu/ton $ 532,561 $ 943,071 Nana 6,500 Btu/ton 2,834,554 3,379,252 New Persons to Nana Region: 10,000 Btu/ton $346,000 -- 6,500 Btu/ton 346 ,000 == Total Money Retained in Region: 10,000 Btu/ton $ 878,561 $ 943,011 6,500 Btu/ton 3,180,554 3,379,252 I fully realize that the estimates I made are based on some questionable values; however, most figures are valid -- only the equipment required can be seriously questioned. My interest in making this estimate was only to determine the economic aspects because of the dollar problems that B-13 Page 5 exist in this area. However, I felt that preconceived ideas would dominate the engineering work performed under this contract and complete consideration would not be given manufactured gas possibilities unless there was some evidence presented. Signed Mr. Donald Fiscus 3k AGENCY AND ORGANIZATION RESPONSES (After Review of Draft Report) f N7 ALASKA GEOLOGICAL AND GEOPHYSICAL I CONSULTANTS Box 80162 ee Rt. 1, Box 2114 Fairbonks, Alaska 99708 Lopez, Wash. 98261 (907) 479-2878 Dr. Rober B:\Forbes (206) 468-2453 May 6, 1982 Dear Patti: I have reviewed the Kotzebue reports ana I jotted down a few comments on the attached pages. In general, I agree with the final conclusions involving the 2000' basement high under Kotzebue. Although a 2000' + test hole under Kotzebue would confirm or deny the depth to basement, confirmation would be a hollow victory as the resource which could be recovered at those depths would probably be unusable. I guess I would attempt to reprogram the money for a related project carrying @ better cost-benefit probability. I will be in Anchorage during the week of May 17-21, 1982 and I will check in with you then. I hope these comments are helpful. Robert B. Forbes Consulting Geologist ARCTIC SLOPE TECHNICAL SERVICES INC MAY 2 4 1992 RBF/ sg (1) I.e. referenced geothermal reports by other consultants, not the present Feasibility Assessment. [Authors' note] B-16 ye ALASKA GEOLOGICAL AND GEOPHYSICAL CONSULTANTS Box 80162 Rt. 1, Box 2114 Fairbanks, Alaska: 99708 Lopez, Wash. 98261 (907) 479-2878 Dr. Rober B. Forbes (206) 468-2453 COMMENTS ON THE KOTZEBUE GEOTHERMAL PROJECT REPORT (R.B. Forbes) (1) Page 4, para. 2: "volcanic rocks of probable Cretaceous Age". Comment: Unless A.E. has accessed radiometric age deter- minations unknown to me, the assignment of a Cretaceous. age +o the basal volcanic rocks in both test holes is dubious. Basaltic rocks associated with the Cape Espenberg maars and the ash deposited by the vents responsible for these maars, including North and South Kileakg Lakes, and Devil Mountain Lakes are of late Pleistocene and/or Holocene age. A.E.'s Cretaceous call on these rocks may be influenced by dated Cretaceous basalts to the last. The hasel molcameae in the Caenbeas ely wet (2) Page 5, para. 4: “it should be noted that these are not true basement rocks." Comment: Several of us (petrologists, geochemists and structural geologists), have been told of this comment by A.E., but this is my first opportunity to see it in print. I have no idea why A.E. thought that metamorphesed limestone and dolomite were not a part of the basement complex under- lying the Tertiary section. We have worked on these rocks where they are exposed at the sur- face, on the Seward Peninsula and north of Kotzebue Sound near Kiana, and the metamorphic complex in- cludes conformable layers of carbonate in addition to the more dominant quartz-mica schists, blue- schists, green schists and graphitic auartzites. This same sequence (The Nome Group Metamorphic Terrane), was cut by the recent petroleum test B-17 Comments on the Kotzebue Geothermal Project Report Page 2 (2) Page 5, para 4 cont.: hole which was drilled in the Norton Basin, where it was recognized and treated as "basement". I think that for geothermal and petroleum purposes, this sequence of metamorphic rocks is "true base- ment", as all of these units have experienced a common metamorphic history, and they are now (technically), "crystalline rocks" with little or no intersticial porosity and permeability. a a le (3) Page 7, para. 2: "insufficient data are available to deter- mine the cause for this anomalous condition." Comment: The difference in gradients between the two holes is probabily related to conductivity differentials controlled by lithology and the degree of water saturation in various aquifers. (4) Page 13, para. 2: ", . . temperature is more closely related to proximity to the marbles and schists than to actual depnth,"' Comment: I cannot think of any logical reason why this should be true, as the Uranium - Thorium - Potassium content of these rocks is ouite low, and heat (radiogenic) production would also be low. (5) Interpretation of the seismic section and gravity data, Comment: The profile certainly supports the presence of a "basement" high under Kotzebue. The gravity high on Espenberg is probably related to the rather thick sequence of volcanics at the base of the Tertiary section, above the metamorphic * basement. (6) General Comments: I agree that there is a high probability that metamorphic basement will be intersected by a 2000+ ft. test hole at Kotzebue, and that lower water temperatures will be en- B-18 Comments on the Kotzebue Geothermal Project Report Page 3 (6) General Comments cont.: countered; a rather unfavorable prognosis, unless large gquanities of warm briney water can be utilized and re- injected. At such low temperatures, the use of heat exchangers would be dubious. A sewage system could be sustained during all seasons with such a brine, but disposal would be a serious problem. * seismic velocity data held by Chevron could be matched against measured velocities for volcanic rocks WS metamorphic rocks .... to resolve this problem. B-19 401 E. FIREWEED LANE ANCHORAGE, ALASKA 99503-2197 (907) 276-3770 ANCHORAGE ° JUNEAU ° BETHEL June 8, 1982 Ms. Patti Dejong Project Manager Alaska Power Authority 334 West 5th Avenue Anchorage, Alaska 99501 Subject: Kotzebue District Heat and Coal Utilization Study Dear Ms. Dejong: In view of our phone conversation of June 4, 1982, I am forward- ing my comments. Though incomplete, they do cover some basic assumptions used in the subject report which would impact the end result and should be addressed early on to prevent some serious consequences on recommendations. Section 4.4. Present and future household size: The report uses a person per household size of 4.0 based on: - A November through January survey. - A comparison of Kotzebue to Barrow and Nome. A good portion of Kotzebue's population has origins from sur- rounding villages; consequently, the transient population has a large impact on the average household size. This is particular- ly true in summer months during fishing and construction season when the influx of people from surrounding villages is greatest. Our household survey in 1980 did in fact show an average of 4.88 persons per household, while the Leslie Foundation Survey showed 4.25 persons per household. However, through discussion with the head of the Leslie Founda- tion group, it was found that there were several homes occupied by one or two elderly persons. In view of the relatively small number of homes, it would take only a small percentage of single elderly couples to really bring the average down, which is what occurred in the Leslie Foundation Survey. Based on what information can be evaluated, the averace house- hold size will remain above the norm within the planning horizon if the lifestyle of Kotzebue is taken into account. Ms. Patti Dejong June 8, 1982 Page Two Page 4-18. The assumptions for schools, hospitals and commer- cial buildings per capita floor space are relatively constant or having a small increase over a period of time may prove in- valid. : 1. School facilities are impacted not only by Kotzebue's growth, but the growth of the entire Northwest region. Recent school and vocational training facilities have probably increased the square foot per capita. There are additional school facilities to be constructed this season. 2. The hospital facilities likewise fall into the same category as the schools in that it is a regional facil- ity. A recent call to the IHS revealed that native hospitals are designed to an eight-year life. Kotzebue is rated second highest in the State for replacement, Anchorage being number one. It is with relative cer- tainty that this hospital will be replaced in the near future. It is known that the State Legislature has considered funding hospital expansion. Though the fate of this funding is unknown, it is indicative of the need for expanded facilities. Additionally, newer med- ical facilities are more energy-intensive, due to high- er technologies employed. This fact deserves consider- ation. 3.. The assumption for commercial buildings is probably valid. Page 4-30. Water Consumption Table 4.14. Reference is made here to the "Water and Sewer Expansion Study" done in 1981, which provides water consumption projections through the year 2,000. The subject report fixes the water usage at 76 gallons per capital per day. This usage is not expected until the late 1980's which makes ASTS estimates high for the period to 1990. Beyond 1995 the water usage is low as shown in the subject re- port. Also not accounted for in the report is the water wast- age at the treatment plant as part of the treatment process. This water requires heating as well. The table below provides the water use projections from "The Water and Sewer Expansion Study". Ms. Patti Dejong June 8, 1982 Page Three 3-1 - Pros ir ic W D ; Adjusted Water Water w/present w/improved Year Population Demand Required Treatment Treatment (gpcd) (gpd) Plant Use Plant Operations ee 00 1980 2500 65 165,000 185,000 177,000 1985 2900 69 201,000 224,000 214,000 1990 3300 va 241,000 270,000 258,000 1995 3600 76 274,000 307 ,000 293,000 2000 4000 80 320,000 358,000 342,000 These comments are not complete by an means, but it is felt that they are of substance enough to impact any quantitative and qualitative analysis of energy requirements for Kotzebue. Thank you for allowing me the opportunity to comment on this report. Sincerely, fu Dunn, P.E. JD/jb3 cc: Gene Moore CALC NANA DEVELOPMENT CORPORATION, INC. 4706 HARDING DRIVE, ANCHORAGE, ALASKA 99503 TELEPHONE (907) 248-3030 August 11, 1982 Mr. Eric P. Yould Executive Director Altes 4 s005 Alaska Power Authority 334 West 5th Avenue BLAgts ere qner Anchorage, Alaska 99501 ATIN: Patti DeJong, Project Manager RE: Kotzebue District heat and Coal Utilization Feasibility Study Dear Patti; I appreciate the opportunity to review the draft volumes I and II of the above reference heading. In general, the study appears to be complete in all areas of research. A couple of minor infractions for note, are math discrepencies on page 4-16, 4-17, and 5-32. Also, Page 5-13 is omitted. Technology number 5.2 on page 6-9 is penalized in a point system because of a requirement for trained operators. All technologies require a degree of training and yet only this one was penalized for that specific reason. Technology number 5.16 is issued a maximum penalty for what appears to be an unsubstantiated reason. Rankine Cycle engines have been around almost as long as internal combustion engines, but probably because of their bulk, have not enjoyed the popularity of the internal combustion engine. The compact, Turn-Key simplicity of operation of the internal combustion engine virtually rendered the Rankin Cycle engine as being a dinosaur. However, the present fuel economy is rapidly changing in favor of the Rankine Cycle engine. Page 7-40 discusses the regions hydroelectric potential with a focus on the Buckland basin. Damming the Buckland river has two serious considerations. Case 1, because of the inefficiencies of electric to heat conversions, the expected load demand for four villages is 30 MW. Concurrently, the design output of the dam generator is only 16 MW. (page 7-42). Case 2, the Buckland Basin is used extensively as the primary grazing grounds for NANA's reindeer herd. Member Villages: Ambier, Buckland, Candle, Deering, Kiana, Kivalina, Kobuk, Kotzebue, Noatak, Noorvik, Selawik, Shungnak B-23 Mr. Eric P. Yould Page 2 The herd size presently is about 8,000 head with an expectancy to multiply by a factor of 2.5 by 1990. Any loss of feeding territory may prematurely saturate the life support capacity of the remaining lands. Page 7-74, the NANA Housing Authority is an agency for HUD and is in no way affiliated with NANA Regional Corporation. NANA, for Northwest Alaska Native Association, has not affixed its name to any housing project, nor has it endorsed any housing design or concept; hence the connotation "NANA" house is erroneous. In light of the preliminary findings of the DGGS with regards to the coal occurences in the NANA Region, (which appear impracticle for development), the only power strategy that offers regional inde- pendence is hydroelectric. Independence from any fuel importation must certainly out-weigh the initial negative impacts. The report states on page 7-42 that 4 potential damming sites were studied, yet only Buckland was made available. If this report is exclusive for Kotzebue, then the sites other than Buckland probably need not be reviewed. However, if Kotzebue and area or region is included, then the comparisions should be made available. This is particularly true if the NANA-Cominco Joint Venture develops a mining facility at Red-Dog deposit. The mine would virtually triple the regional power demand. If any part of this report becomes topic for discussion, I would appreciate being informed. Sincerely, bite fvyena— Pete Jorgensen Assistant to the President cc: John Schaeffer *PJ/rk Alaska State Degislature Advisory Council Members Senator Kerttula, Chairman Senator Bennett State Capital Senator Dankworth % Juneau, Alaska 99811 Senator Fahrenkamp Phone: (907) 465-3114 Pouch V SENATE ADVISORY COUNCIL August 16, 1982 Eric Yould Executive Director Alaska Power Authority 334 West 5th Avenue Anchorage, Alaska 99501 Dear Eric: Based on the review of your Kotzebue District Heat & Coal Utilization Feasibility Study, Volumes I and II, following comments are pertinent. 1. In general, the study is very comprehensive and well done. The title is somewhat misleading and should be changed to cover the broader range of the study scope - suggest Kotzebue Energy Alternatives Feasibility Study. 2. Given that the purpose of the study is to determine the most preferred practical and proven power generation and heating schemes, it is questionable whether geothermal or hydropower best fullfill that requirement. Substantial exploration is required to even determine if there is a geothermal potential warranting it as a solution. Equally, the hydropower solution requires an in-depth assessment of the ecological and environmental impacts to determine if they are acceptable or mitigable. 3. Based on the favorable wind data in the area, it is surprising that windpower - even in secondary thermal fuel saving mode - did not rate better. 4. Any alternative based on coal must specifically address the supply of same. There are only two basic scenarios: 1) coal is obtained from an existing mine and 2) coal is obtained from a yet to be developed mine. The study needs to address the practicality of the latter scenario much more rigorously and in detail equivalent to appendix "C", Volume II. Any coal plan must address where, who, how much, and how as a minimum and in sufficient detail to assess its viability as a fuel for power generation or heating. While above comments are not all inclusive, they are offered towards making the final product a more useful study. Sincerely, rt S. Dzinifh Senior Advis P.S. Page 5-13 was missing in my report. KD/1al DEPARTMENT OF THE ARMY ALASKA DISTRICT, CORPS OF ENGINEERS P.O. BOX 7002 ANCHORAGE, ALASKA 99510 Tear, 20 AUG 1982 NPAEN-PL-H Eric P. Yould, Executive Director Alaska Power Authority 334 West 5th Avenue Anchorage, Alaska 99501 Dear Mr. Yould: In response to your letter, dated 21 July 1982, concerning Volumes I and II of the Kotzebue District Heat and Coal Utilization Feasibility Study we have no comments to furnish. We appreciate the opportunity to provide input on this study. If you have any additional questions, please contact Mr. Baxter of our Planning Branch at 552-3432. Sincerely, A Chief, Engineering Division UNITED STATES DEPARTMENT OF COMMERCE National Oceanic and Atmospheric Administration National Marine Fisheries Service P.0. Box 1668 Juneau, Alaska 99802 August 19, 1982 Mr. Eric Yould Alaska Power Authority 344 West 5th Avenue Anchorage, Alaska 99501 Dear Mr. Yould: We have received the Kotzebue District Heat and Coal Utilization Feasibility Study. Due to other pressing demands on our Environ- mental Assessment Division staff, we will not be able to review this report. Sincerely, “>? Vem A WD. i obgrt W. McVey Diyector, Alaska Region fa JAY S. HAMMOND, GOVERNOR < (Ze DEPARTMENT OF FISH AND GA ME OFFICE OF THE COMMISSIONER JUNEAU, ALASKA pono August 18, 1982 Mr. Eric P. Yould Executive Director Alaska Power Authority 334 West 5th Avenue Anchorage, Alaska 99501 Dear Mr. Yould: The Department of Fish and Game has reviewed Volumes I and II of the draft "Kotzebue District Heat and Coal Utilization Feasibility Study" prepared for APA by a joint venture of Arctic Slope Technical Services, Inc., Ralph Stefano & Associates, Inc., and Veco, Inc. Due to the general and preliminary nature of the report, we have no substantive comments to offer. We do, however, suggest that subsistence values of fish and wildlife be considered in any assessment of environmental impact, not just the commercial and sport values mentioned in the report. Further, as you know, any serious consideration of a hydroelectric project on the Buckland River will be subject to extensive review. Thank you for the opportunity to comment. Jeanne Lfeona'd 0. Skoog Commissioner cc: Scott Grundy, ADF&G, Fairbanks Lance L. Trasky, ADF&G, Anchorage Sincerely, 1 1OLH STATE OF ALASKA JAY S. HAMMOND, GOVERNOR DEPARTMENT OF FISH AND GAME 1300 COLLEGE ROAD FAIRBANKS, ALASKA 99701 August 25, 1982 HECEIVED Mr. Eric P. Yould AUG 3 0 1982 Executive Director Alaska Power Authority ‘ALASKA POWER AUTHORITY 334 West 5th Avenue Anchorage, Alaska 99501 Dear Mr. Yould: The Department of Fish and Game has reviewed Volumes I and II of the Kotzebue District Heat and Coal Utilization Feasibility Study. We have no comments to add to this draft. Thank you for the opportunity to comment. Sincerely, Clan A sterner 2 _ Alan H. Townsend Interior Projects Review Coordinator Habitat Division MEMORANDUM TO: FROM: State of Alaska DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS Eric P. Yould DATE: September 1, 1982 Executive Director Alaska Power Authority FICE ING) ; ; TELEPHONE NO: (907) 264-2255 Pome Sevet fe. here ‘ s- Lawrence H. Kimball, Jr. (by) SUBJECT: Kotzebue District Heat Director : and Coal Utilization Division of Community Planning RECEIVED Feasibility Study Draft . Report SEP 33999 ALASKA POWER AUTHORITY In response to your July 21 request, the Division of Community Planning (DCP) has reviewed the Kotzebue District Heat and Coal Utilization Study Draft Report prepared for the Alaska Power Authority. The report appears to be a preliminary effort to identify the options available to meet Kotzebue's energy needs, and has used a generally acceptable methodology for analyzing the potential use of these alternatives in Kotzebue. The report also reaches an initial conclusion on the best alternative for the Kotzebue area, based on an analysis of its preliminary findings. The DCP will not comment on the specifics on each option analyzed, but does have several overall concerns. The hydropower with electric resistance heat or with geothermal district heating alternative relies on several rather major assumptions as is stated in the report. Certain assumptions are not well documented, which casts some uncertainty over its consideration as the preferred option. As an example, geothermal district heating assumes that a geothermal resource of 160° exists, and that this resource will be located within range of Kotzebue for its cost-effective use. The DCP realizes that this conclusion is based on preliminary findings, and is supportive of a planning process that thoroughly analyzes the potential use of each viable option. Several of the options presented, particularly geothermal hydropower, and coal extraction, involve regional environmental, socioeconomic, and land use concerns. Although the economic feasibility of these options is a primary concern, these considerations should not completely.overshadow related impacts associated with the use of this option. As an example, although hydropower may be more economically feasible than conventional energy systems, the amount of land and fish and game resources displaced may be of equal or greater consideration to the region. As these options have definite impacts that transcend Kotzebue's limits, the impacts need to be viewed from a regional perspective. The DCP emphasizes the need to evaluate socioeconomic impacts related with major resource development. Mr. Eric P. Yould September 1, 1982 Page 2 As the APA is aware, many of the energy options presented will require federal, state, and local governmental regulatory review. The DCP emphasizes the necessity for review through the Alaska Coastal Management Program for major energy facility siting. To achieve this end, the report preparation effort should continue to encourage interaction with the NANA Coastal Resource Service Area Coastal Management Program. If you have any questions on our comments, please contact Wayne Marshall of my staff. Thank you for the opportunity to review the report. cc: Mark Stephens, Planning Supervisor Division of Community Planning Murray Walsh, Coordinator Office of Coastal Management MEMO TO THE RECORD ALASKA | sussect Kotzebue Coalafired Congeneration ey PAD —___—pare_8/24/82 POWER ; ‘ SHEET NO._1 OF__] AUTHORITY iaiatiidniiieisal PROJECT Kotzebue~Coal—Fired— — — a 6 0-generation TELEPHONE TRANSMITTAL OF COMMENTS: George Matz, Office of the-Geverner——————— Division of Budget & Management Mr. Matz called to relay comments in time for their_incorporation— —————_— into the final report. In addition to some changes already requested - | _—by the Authortty the foTTowing concerns were expressed: 1) Page 4-13: the forecast appears to presume exponential growth “With no consideration of saturation. 2) He questions the validity of figure 7.1.4, Justify or—modify - as appropriate. 3) Bracket forecasts and make comments with ‘respect to ‘the reliability —_—of_the graphs. Give high, low-and-most-likelyforecasts—— ———-----— 4) He was concerned about the emphasis on the point system for making the final determination of preferred project(s). I assured him that _the final report would usea_point-system—for-sereening-onty and— would present the final economic analysis in quantitative terms and environmental and social considerations separately and in qualita- Jo tive terms. = = = en eee a 5) He expressed concern at the contractor's need to determine one — preferred plan. I told him that the Power Authority does not im- _______ pose this requirement on the contractor andthat—in-the-case of ————-——— this study, in particular, a single preferred plan would be in- appropriate. 7 - — ___6:) He expressed _concern_that-we-could-not—procede_tethe-detatled-———_ feasibility study on the basis of the information available at this point in time. I told him that it is the Authority's intent to |-_______-____ per fomr additional resource assessments-prior-—to-continuing- with ——— —— feasibility studies. Department Of Energy Alaska Power Administration P.O. Box 50 Juneau, Alaska 99802 RECEIVED September 27, 1982 SEP 30 3987 Mr. Eric Yould ALASKA POWER AUTHOAITy Executive Director Alaska Power Authority 334 West 5th Street, 2nd Floor Anchorage, AK 99501 Dear Mr. Yould: Here are our comments on draft Volumes I and II of the Kotzebue District Heat and Coal Utilization Feasibility Study by Arctic STope Technical Services, Inc., and Veco, Inc., transmitted by your July 21, 1982, letter and the addendum transmitted by your letter of September 8, 1982. The estimates of future energy and power requirements appear reasonable. The report section covering alternative plans and comparison of plans are difficult to follow and quite confusing. Although the results appear to favor hydropower with electric heating, followed by the alternative of coal-fired co-generation, we think the costs for both of these options may be significantly underestimated. We're particularly skeptical on prospects for the Buckland hydro site. We think costs for access and dam and powerplant construction are substantially underestimated. Sincerely, r o/ . Cun~ Robert J. Cross Administrator 4. RESPONSES TO AGENCIES AND ORGANIZATIONS (on letter responses to the draft report.) Copies of correspondence to clarify responses, when applicable, appear on the following pages. ALASKA POWER AUTHORITY 334 WEST 5th AVENUE - ANCHORAGE, ALASKA 99501 Phone: (907) 277-7641 (907) 276-0001 November 15, 1982 Mr. Jerry Dunn Quadra Engineering, Inc. 401 E. Fireweed Lane Anchorage, Alaska 99503 Dear Mr. Dunn: At the request of the Alaska Power Authority, Arctic Slope Technical Services Inc. has prepared the following response to your helpful comments with respect to load forecasting in Kotzebue. Their comments are printed verbatim below: "As explained in Section 4.4, in our endeavors to arrive at a reasonable present household size, we not only (as implied in the comments) used information provided by the energy auditors in their November - January 1982 survey and comparative figures for Nome and Barrow, but also Quadra's 1980 survey and that of the Leslie Foundation. Indeed we considered the two latter surveys our main sources of reliable data in this context. However, since we were in possession of more recent data (1982 vs. 1980) provided by the energy auditors, we felt it was appropriate to revise the previous survey results to reflect an apparent decrease in household size. While we acknowledge that the auditors' winter survey probably may not be totally representa- tive - and hence, it should be noted, we did not in fact use their indicated household size of only 3.8 - we did think it likely that, in view of the addition of new housing and the general trend towards lower birth rates, the household size certainly was smaller now than it had been and that it would continue to decline, a fact also borne out by trends in other Alaskan cities with similar relevant charac- teristics." "We agree that the average household size in Kotzebue will remain above the norm - and this, we believe, is adequately reflected in the projected year 2002 household size of 3.0 persons, which is significantly above the present state average. Thus, we are still of the opinion that the present average household size of 4.0 persons, which we arrived at, is a realistic estimate." Per Capita floor space for schools and hospitals: "While a near term rebuilding of school and hospital might cause an immediate increase in per capita floor space, since B-36 Mr. Dunn November 15, 1982 Page 2 one may assume improved standards and some early overcapacity, over a longer term, this would tend to even out." Water Consumption: "Taken together, we do not feel that there is any need to revise our calculations, since any variations in demand assumptions would be small and unlikely to have any effect on our final recommendations." As you know, the greatest uncertainties in this study are those associated with the costs to develop the energy alternatives considered. Once more reliable energy resource information can be obtained, we intend to update and refine the load forecasts along with further analysis in other areas prior to proceeding to design of an energy project for Kotzebue. Thank you for your comments. Sincerely, FOR THE EXECUTIVE DIRECTOR Pass Ver Patricia DeJong Project Manager PD:cb ALASKA POWER AUTHORITY 334 WEST 5th AVENUE - ANCHORAGE, ALASKA 99501 Phone: (907) 277-7641 ; ; (907) 276-0001 November 16, 1982 Mr. Pete Jorgensen Assistant to the President NANA Development Corporation, Inc. 4706 Harding Drive Anchorage, Alaska 99503 Dear Mr. Jorgensen: Thank you for your helpful review of the Kotzebue District Heat and Coal Utilization Feasibility Study. The following items are responses to your comments: 3rd_ paragraph, your letter: The Final Report has been significantly revised, edited and all calculations checked. Numeric errors have been corrected as necessary. 4th paragraph: While we and the consultant agree, in general, with your . observations, the degree of training required to operate a high pressure steam facility is considerably greater than for other technologies considered here. 5th paragraph: You are correct in stating that Rankine cycle technology has been around for some time. Organic Rankine cycle generation is, however, relatively untested in the size range of this particular application. For purposes of screening alternatives, it is probably more accurate to apportion the "penalty" to both the state-of-the-art and the cost for this technology. 6th paragraph: The Power Authority shares your concerns with respect to the potential environmental impacts associated with damming the Buckland River and installation of long transmission lines. 7th paragraph: The NANA reference has been eliminated. Mr. Pete Jorgensen November 16, 1982 Page 2 The Power Authority does not consider the results of this preliminary feasibility study to be definitive with respect to the identification of a single alternative for Kotzebue or the region. The DGGS investigations to which you refer do not rule out coal reserves within the NANA region. It is the intent of the Power Authority to obtain additional coal reserve and hydrologic and environmental data prior to proceeding with a detailed analysis of the feasibility of either project for Kotzebue and to review the economics of a regional project which will incorporate the NANA-Cominco load at the Red-Dog mine. We look forward to working closely with NANA to assure that further investigations are provide the best possible alternatives for the people of the NANA region. Ck Eric P. Yould Executive Director cc: John Schaeffer R=-39 ALASKA POWER AUTHORITY 334 WEST 5th AVENUE - ANCHORAGE, ALASKA 99501 Phone: (907) 277-7641 (907) 276-0001 November 16, 1982 Mr. Kurt Dzinich Senior Advisor Senate Advisory Council Pouch V Juneau, Alaska 99811 Dear Mr. Dzinich: Thank you for your helpful review of the Kotzebue District Heat and Coal Utilization Feasibility Study. The following items are presented jin response to your comments: 1. The title has been changed to more accurately reflect the scope of work accomplished. The wording of the report has been changed to explain what appears to be undue emphasis on the geothermal alternative. The findings of this analysis along with recent interpretation of geological evidence by Bob Forbes (letter included in this report) discourages us from pursuing the geothermal alterna- tive at this time. We intend to obtain more reliable hydrologic and coal reserve data prior to proceeding with a detailed feasibility study of alternatives for Kotzebue. The consultant's revised economic analysis found wind to rank higher than was presented in the draft report. However, any such analysis must presently be based upon gross assumptions with respect to the reliability of the technology and poten- tial penetration of wind generated power into the Kotzebue grid. We are eagerly awaiting results of the Division of Energy and Power Development demonstration at Kotzebue prior to planning a system in which wind generated electricity can displace fuel consumption. We cannot assume such power will displace other generating capacity until much more operational data is available. Appendix I of the Final Report is a more detailed assessment of the cost of coal transported from several potential re- serves. (This work was not available at the time the Draft Report was originally distributed. ) Eric P. Yould Executive Director ALASKA POWER AUTHORITY 334 WEST 5th AVENUE - ANCHORAGE, ALASKA 99501 Phone: (907) 277-7641 (907) 276-0001 November 16, 1982 Mr. Robert J. Cross Administrator Department of Energy Alaska Power Administration P.0. Box 50 Juneau, Alaska 99802 ‘Bob Dear Mr. Aross: Thank you for your helpful comments on the draft report, Kotzebue District Heat and Coal Utilization Feasibility Study. The consultant has reorganized the report to clarify the presentation of results. , We have reviewed cost estimates and have made several changes including the use of a higher contingency figure in the hydroelectric and other estimates. In spite of these changes, we share your concern with respect to the economics of the alternatives. The greatest uncer- tainties here are associated with the energy resources themselves, and we intend to obtain additional coal reserve and hydrologic data prior to proceeding with a detailed analysis of the feasibility of either of these alternatives for Kotzebue. Sincerely, Eric P. Yould Executive Director ALASKA POWER AUTHORITY Response to Letter from Mr. Don Fiscus, January 27, 1982 Mr. Fiscus' concerns were discussed with him in a meeting with Arctic Slope Technical Services, Veco and Stefano in mid-April, 1982. Coal gasification was discussed and additional work was performed by the consultant to fully investigate this technology. The consultant's findings may be summarized as follows: The basic processes of obtaining gas from coal are by destructive distillation, by forming coke and using water shift reaction, and using basic Fischer-Tropsch chemistry. The latter two techniques are complex engineering systems which probably are not applicable to Kotzebue, whereas, the destructive distillation has been a viable technique for many years. The major disadvantage to this technique is the poor utilization of the carbon in the coal. Coal gasification technology of the scale and type available today is not felt to be economically or technologically compatible with coal steam generation, waste heat utilization, and district heating systems in the sizes required. A review of coal gasification literature led to the conclusion that coal gasification is not a practical source of energy for Kotzebue at this time. B-42 APPENDIX C GEOTHERMAL TEST-WELL PROGRAM APPENDIX C GEOTHERMAL TEST-WELL PROGRAM TABLE OF CONTENTS 1.1 Phase I Test—Well...ccccccsccccesccsesvsccesseeses Col 1.2 Phase II TesSt—Well..ccccccccccscccccccesceceeesees C-6 Le Geochemical & Petrographic Sampling and Testing... C-7 1.4 CONCLUSIONS. ccccccccccccccccccscccccsscccssccsseee CHB LIST OF TABLES Table C.1 Cost of Phase I Drilling Program...ccccccssccee C-10 Table C.2 Cost of Phase II Drilling Program...........-. Cll APPENDIX C: GEOTHERMAL TEST-WELL PROGRAM 1.1 PHASE I TEST WELL The first phase of the geothermal test-well program in the immediate Kotzebue area should consist of drilling a well to the base of the sedimentary rock section (approximately 600 m). Upon completion of this well, appropriate preliminary testing should take place to determine the nature of the reservoir(s) and geothermal resource. Should the preliminary geothermal testing program indicate that a potentially feasible resource exists, a second well should be drilled in a Phase 2 program to further investigate the geothermal reservoir. A typical Phase 1 program will consist of the following work elements: 1. Land ownership and status -- The land ownership and status of the potential drilling sites within a 2 to 3 km radius of Kotzebue will have to be researched and determined. This information will be used to optimize the drilling sites based on possible leasing problems and the type of permits that are required for conducting the drilling program. 2. Locating the primary drill-site -- Based on the results of the land ownership and status search, a _ primary drilling site will be located. 3. Test-well permitting -- Upon location of the primary drill-site an analysis of the permits necessary to conduct an exploratory drilling program should begin. The land ownership will influence the nature and type of permits and leases required (i.e., federal, state, municipal, private). Once the necessary permits are identified the permit application procedure’ will begin. Since this phase of a typical program is often very lengthy, a timely initiation is required. Cc-1 Program refinement -- Based on permit stipulations and input from the selected drilling contractor, the preliminary test-well program may require changes. These should be made prior to the mobilization of crews and equipment to Kotzebue. Mobilization of drill-rig, drilling equipment and tools, and personnel to Kotzebue -- The mobilization of the drilling equipment to Kotzebue should include: © a rotary drill-rig capable of drilling to a depth of 3,000 feet (915 m; e.g., Fehling 2500 or equivalent. Blow-out prevention equipment may be required; therefore, a drill-rig capable of employing this type of equipment should _ be considered); o drilling fluids, either water or oil based depending upon discussions with the drilling contractor; © casing, including approximately 96 to 143 feet of 13-3/4 inch surface casing, 287 to 382 feet of 9- 5/8 inch casing, and 2,070 feet 6-5/8 inch casing. Cement, cementing equipment, and jet perforation equipment should also be included; o bits capable of drilling a hole suitable to set the appropriate size casing and drill-rod capable of going to a depth of 2,070 feet; © geophysical logging equipment capable of providing gamma-gamma, neutron-gamma, neutron- epithermal neutron, single point resistance, fluid resistivity, resistivity, natural gamma, caliper, and temperature logs; G—2 o drill-stem and pump-testing equipment; o drilling crew, including a drilling engineer, tool-pusher, driller, and helpers; © a geologist; and o miscellaneous equipment, including trailers for mud-logging, geological equipment, and on-site geological, geophysical, and engineering interpretations. Drill-site preparation/construction -- Prior to or concurrent with mobilization of the drilling equipment a drill-pad and access road will have to be constructed at the drill-site. Since the drilling equipment may be on- site for over a one-month duration and any _ thaw degradation of the pad would have severe impacts on project completion, the pad, mud-pits, and access road should be constructed in a suitable manner (e.g., a 3 to 5 foot thick gravel-pad) unless the drill site is ina previously stabilized permafrost area within the city limits or other thaw stable sits. Test-well drilling -- The actual drilling program will commence following set-up of the equipment. The drilling program will consist of: o drilling through the unconsolidated sediments to competent bedrock and setting the 13-3/4 inch surface casing; C=3 o continued drilling through the permafrost frozen bedrock into unfrozen rock and setting the 9-5/8 inch casing; o continued drilling through the sedimentary rock to the metamorphic basement rocks. Drill-stem tests will be performed at possible reservoir horizons determined by the drilling record. The hole will remain open until after the geophysical logging is completed. The casing is to be cemented in-place according to the USGS/State of Alaska permafrost standards. Samples of the rock strata penetrated should be collected at regular intervals and analyzed by the site geologist. Geophysical logging -- Upon completion of the hole to total depth, the geophysical logging program should commence to locate the suitable reservoir horizons and determine their approximate temperatures, These data are necessary prior to continuing with the remainder of the testing program. The logging program that will be attempted may include: natural gamma; gamma-gamma; neutron gamma; neutron-epithermal neutron; single point resistivity; resistivity; fluid resistivity; temperature; and 00000000 0 caliper. 10. Upon completion of the geophysical log data gathering, the data will be interpreted and the potential reservoir intervals (zones) identified. Setting of test casing -- Upon completion of the geo- physical testing program the hole will be flushed with water to reduce drilling mud contamination and infiltration of promising reservoir horizons. After cleaning the hole, the 6-5/8 inch test casing will be set to total depth. After cementing in-place according to the appropriate USGS/State of Alaska standards, jet perforations will be made (12 to 24 perforations per meter) at the previously identified potential reservoir horizons. After completion of the perforations, temperature measurements should be made at an appropriate interval, e.g., every 6 to 12 hours, and plotted on a graph to determine when the temperature changes at the testing horizons become asymptotic, thereby indicating the true temperature of the fluids in that horizon, Pump-testing -- Upon completion of drilling the primary well, and setting and perforating the casing, preliminary pump-tests will be performed. These tests will indicate the specific capacities that can be anticipated from the wells and will dictate the manner in which the final pump tests, if a suitable reservoir(s) is found, will be performed. After the well recovers sufficiently, a well performance test will be made. Pumping rate will be set according to the information derived from the preliminary test. 1.2 PHASE II TEST WELL If the results of the Phase 1 program indicate that a reservoir(s) of appropriate temperature and volume exists, the drilling of a second test-well similar to the one in the Phase 1 program should be made. In addition, observation wells may be necessary. Upon completion of the second test-well, as per the Phase 1 test-well, pump-tests will be performed. After both the wells recover sufficiently, a detailed well performance test will be made on each, using the other as an observation well. Pumping rates will be set according to the information derived from the preliminary tests. If the pumping tests show satisfactory values of transmissivity and storativity and do not reflect unsatisfactory boundary problems, work will proceed on well instrumentation and the additional drilling of observation wells. It is anticipated that an actual geothermal well program would require a re-injection well to isolate the large quantities of highly corrosive low-temperature geothermal waters from _ the surficial env..unment. The spacing of the production/injection doublet well system will be highly dependent on reservoir characteristics. For modeling purposes, one of the two test wells will be considered a production well, the other an injection well. The spacing of the two wells will be based on a preliminary assessment of the reservoir characteristics from the results of Test Well #1. It is possible, depending on preliminary model efficiency and actual system water requirements, that the test wells could become the actual production doublet-well system. This could not be guaranteed until a complete engineering analysis is performed at the end of the program. The injection and the production well will be equipped with appropriate headworks and pressure recording devices. In C-6 addition, each well will be fitted with thermistor temperature recording stations at intervals of ten feet along the bore. Observation wells will be installed according to an appropriate pattern to be determined at the time. These wells will be 4 inches (10 cm) in diameter and drilled by rotary wash methods. As in the exploratory work, a professional geologist will sit and log each hole. Ideally, each observation well should be geophysically logged at the completion of drilling to further define lithologic and stratigraphic relationships. The wells will be cased for their total length and _ perforated, appropriately, through the aquifer zone. Each observation well will be equipped with thermistor recorders on 20-foot centers below the free water surface and have weekly water stage recorders to monitor pressure heads. Extensiometer holes might also be required to provide monitoring of ground swell and subsidence. The confining bed and the aquifer in at least one hole should be rock-cored for subsequent petrologic and geochemical analyses. The information, so derived, will serve as baseline data for any geochemical changes taking place in the aquifer and cap rock resulting from injection or production periods. 13 GEOCHEMICAL AND PETROGRAPHIC SAMPLING AND TESTING In addition to the drilling and testing previously described for the Phase 1 and Phase 2 programs, the following should also occur: ° Detailed lithologic logging of the holes to determine stratigraphy, reservoir(s) characteristics, and temperature profiles. Coring specific intervals may be required during drilling. C-7 ° During the pump-testing, gas sampling should also occur to determine the nature of the geothermal system and the extent to which the flow may be gas driven. ° Water sampling and geochemical analyses of the geothermal waters including geothermometry and oxygen isotope studies to determine the reservoir temperatures and source of the water (seawater or connate). ° Detailed petrographic analysis of the cuttings to evaluate the possibility of hydrothermal cementation. These tests in conjunction with the other tests will provide the necessary geologic and geochemical data to evaluate the potential for use of the geothermal resource at Kotzebue. 1.4 CONCLUS IONS The Phase 1 program is designed to determine if a suitable geothermal reservoir exists underneath Kotzebue. Since only one hole is to be drilled, limited data on the reservoir(s) can be gathered. If a potential reservoir(s) is found underneath Kotzebue the continuation into the Phase 2 program may be justified. During this program additional and more detailed data on the reservoir(s) will be gathered. These data are necessary to make any engineering recommendations on the reservoir size. Should no reservoirs or combination of reservoirs of suitable size be found during the Phase 1 investigation, there is little justification to continue with Phase 2. Should the Phase 2 investigation be conducted and promising results are found, detailed modeling of the reservoir, geothermal system, and the engineering characteristics should be made prior to production development. c-8 Costs associated with phase I and II drilling programs are shown in Tables Cc.1 and C.2; these estimates are considered conservative. Table C.1 Cost of Phase I Drilling Program 1. Land Ownershipe Status $30,000 2. Locating Primary Drill Site 25,000 3. Test-Well Permitting 40,000 4. Program Refinement 20,00 5. Mobilization/Demobilization 200,000 (3 Here Loads, Inc. Load/Unload) 6. Drill Site Construction 60,000 (2,000 cy Gravel) 7. Drilling Casing, Cementing, Pumping 240,000 30 days @ $8,000/Day (Inc. Subsistence) Ja. Misc. Rentals 15,000 (Inc. Blow-Out Prevention) 7b. Casing 100,000 7c. Mud 20,000 7d. Cement (200 bags @ $30/Bag) 6,000 7e. Misc. Materials 12,000 (Inc. Bits, Fuel, Lube) 7£. Materials Shipment (By Barge) 40,000 8. Logging (480 MHR @ $65/HR) 50,000 (Inc. Equip. & Subsistence) $858,000 Cc-10 7a. 7b. 7c. 7d. Je. This Ja. wis 7c. ade Je. Ete 8. Table C.2 Cost of Phase II Drilling Phase Locating Second Test-Well Site Program Refinement Drill Site Construction Drilling, Casing, Cementing, Pumping 15 Days @ $8,000/Day (Inc. Subsistence) Misc. Rentals Casing 100,000 Mud 20,000 Cement 6,000 Misc. Materials Materials Shipment Loggings 50,000 (Observation Wells) Drilling, Casing, Cementing, Pumping 70 Days @ $8,000/day (Inc. Subsistence) Misc. Rentals Casing 140,000 Mud 40,000 Cement 12,000 Misc. Materials Material Shipment Logging 140,000 Instrumentation TOTAL PROJECT COSTS (PHASE I & ITI) Cart $50,000 20,000 60,000 240,000 15,000 12,000 40,000 $560,000 15,000 12,000 60,000 300,000 $1,893,000 $3,750,000 APPENDIX D TECHNOLOGY PROFILES APPENDIX D TECHNOLOGY PROFILES TABLE OF CONTENTS 1 INtrOduction.cecccccrccevcvrcscccvssssevsvesseeee 2 Diesel-Electric Generating Units (Base Case) ... 3 Steam-Electric Generating UnitS .w..cereeevvccvese 4 Cogeneration SySteMS ceseseceeecveeeeseecrveseees 5 Coal Gasification Combined Cycle wesseeceeceeees 6 Old Fashion Coal Gasification by the "Kopper - Totzek" Method wecvececceveerveevecsesvessecsees 7 Solar Energy cocceccccveveccvccscevevveesccvsees 8 Heat Pumps -- Individual Space Heating ......... 9 Coal-Fired Low Pressure District Heat .werveceeeese 10 Hydropower -- Buckland Site ceseccesssvessscvees 11 Wind Turbine Electrical GeneratorS wesseeeceeees 12 Geothermal Technology ceceecccccsevecccvvseseses 13 Peat Technology secsersecessesveseevsvssessecsee 14 Solid Fuel Stoves and FurnaceS ceeeeeceereeveres 15 Electrical Energy Conservation wecceesseecccsece 16 Thermal Energy ConServation ceseeeceeceerceveces 17 Organic Rankine Cycle wevececeseseecesesesecvees 18 Heat Pump System - District Heating ...seeeeeeee LIST OF FIGURES Figure D.1 Outline of a District Heating Scheme...... Figure D.2 Combined Cycle Power Flow Diagram......ee- (List of Figures, cont'd ) Figure Figure Figure Figure Figure Figure Figure Figure Figure Table Table Table Table Table Table Table Table Table D.3 D.4 D.5 D.8 D.9 D.10 D.1l D.1 D.2 4—Meter Turbine. .cccccccccesccsccccccccvere G—-Meter Turbine. ccecccecccsccccccvecsccece T-Meter Turbine. .ceccccccccccccccsccscccece 1O—Meter Turbine. cecccccccvcccccccscvcccnes 24.4—Meter TurDine..cccccccccvcccccccccces 24.5-Meter Turbine. .cccccccsccccccscccccece 2B=-Meter Turbine. .ccccccccccccevssvcsveves 38—-Meter Turbine. .ccccccccccsccvesesscvves 94.7—-Meter Turbine. ..ccccccccccccccccveces LIST OF TABLES Synthesis Gas Composition from Texaco GaSLELer.cecececvcvcecvcecvccevevesecves Utah Coal Feed CharacteristicsS....ccccecveee Summary of System Performance for a Large Scale Oxygen-blown Texaco Gasifier Integrated Combined Cycle Power Planteccececcecvecseessesecsceseve Material Balance Around Gasifier for a Large Scale Combined Cycle Power Plant.ccccccccccccccccccsvcccscscvecsccece Energy Balance for a Large Scale Combined Cycle Power Plantersereecsevees Energy Balance as Percent of Coal's Higher Heating Value for a Large Scale Combined Cycle Power Plant....eee. Availabilities of Gasifiers by Bed Type.... Cost Estimate for a 100 MW Combined Cycle Power Plant Using Oxygen Blown Texaco Gasifier (x 10° S)..weeeeee Capital Investment for a 1157 MW Combined Cycle Plant at 70% Operating Load Factor and $2.00/MM BTU Codaleccccccvcccccccceeccssvceecccece D-37 D- 37 (List Table Table Table of Tables, cont'd) D.10 Cost of Services for a 1157 MW D.11l D.12 Combined Cycle Plant at 70% Operating Load FactOresseccececcecceveee Peat and Coal ComparisSonS....ccccecccccevee Matching of Combustion Method with Peat Fuel ProductS.ervccccccevecccvevcvee APPENDIX D -- TECHNOLOGY PROFILES 1 INTRODUCTION 1.0 General Technology Profiles have been prepared for all energy alternatives known to be potentially viable in the context of Kotzebue. These profiles are oriented toward (1) electrical generation = and (2) space heating utilizing co-generation techniques, when practicable. The "pure" power generation and space heating technologies are included, because a combination of two or more of these might be the most favorable solution to the power and heating needs of Kotzebue. Each technical or resource profile is structured so that it can stand by itself. Each profile, as applicable, contains a General Description; Performance Characteristics; Costs; Special Requirements’ and Impacts; and a Summary. All profiles are, in turn, evaluated in accordance with the matrix outlined in Section 6 of this report. 1.1 Electrical Generation -- General Description Technology profiles are provided for the most likely systems possible for the Kotzebue area. Since diesel electric generation currently is the power source for Kotzebue, it will be taken as the base case; the other alternatives are addressed under separate topic headings. 1.2 District Heating -- General Description District heating is a collective heating system, supplying energy for space heating purposes and water heating in urban communities. The system is comprised of three elements: a central heat source, a piping system, and consumer equipment. The idea was born in the United States and has been in commercial use in many parts of the world since the beginning of this century. Having fewer fossil fuels, the Northern European countries have developed hot water district heating systems and proved them to be economical, efficient and profitable. Initially steam was distributed, but developments showed that hot water was a more convenient heat medium, offering many technical and economical advantages. The original background for establishing the schemes was a wish to achieve greater comfort, rather than conserving energy. How- ever, an important improvement of the environment was achieved, as a number of small and inadequate individual stoves were replaced by one single efficient heat source. For example, in Denmark today more than 400 schemes’ serve approximately 750,000 homes all over the country. Approximately 350 of these schemes are privately owned cooperatives serving mainly the small towns and villages. Thus, a great part of these serve less than a few hundred one-family houses. Also many communities in Greenland have district heating schemes utilizing waste heat from power plants. A district heating network consists of an insulated, double pipe system, connecting the individual users with one or more central heat sources. From the heating stations, hot water of approxi- mately 200° to 240°F is sent out through the flow pipe system. In the consumers' houses the heat content of the water is released in the heating systems, and water of approximately 100° to 120°F returns through the return pipe system for reheating in the station. Surplus heat from thermal power plants (diesel engines, gas or steam turbines) offers a big potential for district heating and is easy to recover at low cost, depending on the system and installation. Boiler stations can be designed for combustion of coal, oil, gas, wood waste, or even straw, if available. Opposed to small individual boilers, such stations can utilize cheaper qualities of fuels, e.g. heavy fuel oil, and they may be designed for a combination of fuels in order to reduce the dependency on one particular fuel. Also, incineration plants for household garbage or industrial waste offer a heating potential by which a double purpose is achieved: solving a refuse and an energy problem at the same time. A district heating scheme is capital intensive, but a community operating a utility which serves a large number. of consumers can, contrary to the individual, afford to install specialized equip- ment for utilization of various kinds of low-grade fuels, such as heavy fuel oil, local coal, waste products, or even waste heat. In other words, it is possible to reduce the consumption of imported, highly refined and consequently costly fuels (which are the types of fuel individual heat consumers use in their small heating plants), and replace these by local, low-grade, cheap alternatives, which can only be used in large-scale systems. In this way a higher degree of flexibility and independence can be achieved. 1.3 Performance Characteristics A modern low-temperature, water-based district heating system offers high flexibility, as almost any fuel, combustible waste material, or waste heat source may be converted into useful energy. The waste heat or central heat source is usually a heat- only boiler, or an electrical power plant which has been con- verted for cogeneration. Cogeneration allows the reject heat from electrical generation modes to be used for district heating. Cogeneration increases a power plant's efficiency from 30 percent to nearly 80 percent, resulting in substantial savings making the performance benefit ratio high for cogeneration district heating systems. 1.4 Costs District heating systems are capital intensive, and costs can vary widely when retrofit conditions are necessary in converting to cogeneration. A typical 500 GPM, 20,000,000 Btu/hr distribution system one mile in length utilizing extraction steam from existing steam generators including all three elements of a district heating system, heat source, distribution piping, and consumer equipment is expected to cost $265 per 1000 Btuh delivered, or $904 per kW. District heating systems in Alaska can be expected to cost from $146 to $585 per 1000 Btuh or from $500 to $2000 per kw. 1.5 Special Requirements There are usually no special hazards associated with a district heating system other than those attributed to installation in existing villages and cities where existing structures and utilities present planning and installation problems. On the attached schematic (Figure D.1) various heat sources of a hypothetical district heating scheme are illustrated. 1.6 Summary The eventual installation of a hot water district heating system in the village of Kotzebue may result in the savings of many dollars presently being expended for business and individual home heating. The existing diesel electric plant producing electricity may be more efficient with cogeneration, the joint production of thermal and electric products. District heating is not limited to a single fuel source. Therefore, individual boilers fired by oil, wood, coal and refuse could be considered for Kotzebue. District heating has the following additional advantages: 1. Elimination of consumer handling and storage of fuel. 2. Reduction of pollution from burning oil. 3. Reliability of heat delivery. mT 4 M a iD 7 | mr ite = Ts ( i | \ / 4 FIGURE D.1 OUTLINE OF A DISTRICT HEATING SCHEME HEAT INPUT FROM: is Power plant 2. Boiler station 3. Incinerator 4. 5 6 Industry . Geothermal energy . Sewage system/ heat pump Solar collector 2 DIESEL-ELECTRIC GENERATING UNITS (BASE CASE) 2.0 General Description The diesel-generator is an electric generating system that uses a diesel engine as a prime mover. The diesel engine is an intermittent, internal combustion engine with compression ignition. 2.1 Performance Characteristics The efficiency of 500 KW or larger units can approach 12 kWh/gallon which can be competitive with larger steam plants. Smaller units that are remotely located may have efficiencies as low as 8 to 9 kWh/gallon. 2.2 Thermal Efficiency Ranges from 18 - 30 percent. With waste heat recovery equipment efficiencies approach 70 - 80%. 2.3 Costs Varies considerably over size of equipment. Current 1981 costs are estimated to be 1250 to 1600 S/KW. 2.4 Special Requirements and Impacts None other than currently existing. 2.5 Summary and Critical Discussion Diesel power is widely used to generate electricity in Alaska due to its high reliability and easy maintenance; however, with the high cost of fuel and its high transportation cost, together with the low efficiency of the diesel electric generation station, alternate means of electrical generation now should_ be considered. Cogeneration technology can improve low thermal efficiency significantly at reasonable cost. 2.6 Bibliography Jet Propulsion Laboratory and California Institute of Technology, "Should We Have a New Engine? An Automobile Power Systems Evaluation," Volume I, Volume II, JPLSP 43-17, August 1975. Ayres, R. U., McKenna, R. P., Alternatives to _ the Internal Combustion Engine, The Johns Hopkins University Press, Baltimore, MD. Encyclopedia of Energy, McGraw-Hill Book Company, New York, N.Y., 1976. 3 STEAM-ELECTRIC GENERATING UNITS At the end of 1977, there was a total of 951 steam electric plants operating in the United States; an additional 320 will probably be built during the next decade. The current trend is towards larger-size units located near the coal source. 3.0 General Description In a steam plant, fuel is burned in large boilers to provide high pressure steam to drive turbines, which in turn drive generators to provide electric power. Low-energy steam leaving the turbines is condensed and pumped back to the boilers, where it is heated to steam again and the cycle repeated. 3.1 Performance Characteristics Boiler sizes for steam electric power plants in the United States range from less than 1,000 to about 3,000,000 1lb/hour, and most (about 65 percent) range from 100,000 to 1,000,000 l1b/hour. Furnaces in today's units generally are larger than those in comparable boilers built only a few years ago, allowing greater fuel flexibility. Turbines used in U.S. steam electric plants are rated from 100 to 900 MW, with about 40 percent rated from 500 to 699 MW. The current average thermal efficiency of steam electric plants is about 41 to 52.5 percent, using steam conditions from 600 to 4500 psi and higher with steam temperatures from 710 to 1000°F as practical design limits. Steam electric plants have heat rates of 8500 to 12,000 Btu of fuel value to produce 1 kWh of electricity. Heat rate (HR) is defined as 3413 Btu divided by the thermal efficiency. In establishing the performance of a steam electric plant the heat rate (HR), which is the heat supplied per unit of power output is generally preferred to thermal efficiency because it is more directly appliacable to fuel performance. With large boilers, 90 percent efficiency is not uncommon; medium sized units consistently operate above 80 percent efficiency; therefore, with 65-75 percent efficient turbines, 98 percent efficient generators, 7 percent plant auxiliary power, 2 percent water make-up, and a plant rationalization factor of .90 to .98 percent, thermal efficiency of a typical steam electric plant can range from 41.0 to 52.5 percent. In using correction factors and comparative data to determine and apply plant heat balance data, care should be exercised. In using generalized data (example, 2 percent plant make-up) relative values are more reliable than absolute values; accordingly, simplified values should be used with caution in estimating plant thermal efficiency. 3.2 Costs Estimated to be .272 $/kWh for today's standard operating facilities. 3.3 Special Requirements and Impacts Steam plants can be fueled with coal, oil, or gas. Government regulatory policies have a major influence on the selection of fuels for steam electric plants. Gas and oil have lower sulfur and ash contents than coal and thereby avoid sulfur oxide and particulate emission problems. Government energy policy, however, strongly encourages the use of coal, which is in more plentiful domestic supply . Therefore, many plants now burning these fuels are converting their boilers to coal burning. (A number of plants now burning oil and gas have burned coal in the past and have facilities for conversion depending on fuel avail- ability, costs, and environmental restrictions.) Converting oil and gas burning steam electric plants to coal involves extensive retrofitting of handling and storage facilities, boiler design, ash and other solid waste disposal, and flue gas treatment facilities. The cost of an air pollution control system alone may be as much as 50 to 60 percent of the apparent conversion cost. Hidden environmental costs, such as treatment for coal pile and ash pond leachate and runoff, may constitute another 12 to 15 percent of the conversion cost. 3.4 Summary and Critical Discussion In Alaska, steam plants should be totally enclosed. The enclosed plants have a significantly higher unit investment cost, but are overall cheaper from an operation, maintenance and reliability standpoint. Furthermore, plants burning low-grade coal have a higher investment in fuel, ash, and related environmental protection equipment than those which burn high-grade coals. 3.5 Bibliography Encyclopedia of Energy, McGraw-Hill Book Company, New York, N.Y. 1976. Cross, F. L., Jr., “Hidden Costs of Industrial Boiler Conversion to Coal," Pollution Engineering, February 1979. Schwieger, B., "Central-Station Design: Optimizing Efficiency, Reliability, and Cost in Plant Design and Construction," Power, Vol. 122, No. 11, November 1978. Edison Electric Institute, Statistical Yearbook, 1977, October 1978. U.S. Department of Energy, "International Coal Technology Summary Document," HCP/P-3885, December 1978. Considine, D. M., ed., Energy Technology Handbook, McGraw-Hill Book Company, New York, N.Y., 1977. D-11 4 COGENERATION SYSTEMS 4.0 General In cogeneration systems, electrical or mechanical energy and useful thermal energy are produced simultaneously. Such improved efficiency systems use a combination of mechanisms to utilize more of the heat energy produced when conventional fuels are burned than is possible with any existing single system. Using cogeneration rather than separate systems to produce heat and electricity will yield net fuel savings. of 10 to 30 percent. Production efficiency of generating electricity is 22 to 34 percent, and recoverable heat is 43 to 63 percent, permitting total system efficiency of 65 percent to 85 percent in cogeneration cycles. Cogeneration systems include dual-purpose power plants, waste heat utilization systems, certain types of district heating systems, and total energy systems. Such systems have been applied since the late 1880's and, in the United States, have been used much more widely in the past than they are today. In the early 1900's, most U.S. industrial plants generated their own electricity and many used the exhaust steam for industrial processes. Many utility companies supplied cogenerated steam to large industrial users and densely populated urban areas. By 1909, an estimated 150 utility companies were providing district heating. Cogeneration operations in the United States declined largely because of the availability and low cost of natural gas heating and of relatively low-cost reliable supplies of electrical power from large generation plants located in sites remote from densely populated areas. 4.1 Types of Systems There are two fundamental types of cogeneration systems -- topping and bottoming -- differentiated on the basis of whether electrical (or mechanical) energy or thermal energy is produced first. In a topping system, electricity or mechanical power is produced first, and the thermal exhaust from the turbine is used as industrial process heat, for space heating, or in other applications. The topping cycle is the common choice for utility and industrial applications. In a bottoming system, thermal energy for process use (such as steel-reheat furnaces, glass kilns, and aluminum-remelt furnaces is produced first, then the waste heat is recovered as an energy source for generating electricity or more mechanical power. Converting a large part of the low temperature process exhaust to useful work limits the application of bottoming cycles. Choosing a system depends on the balance of thermal energy and electrical (mechanical) power needed, and the level of waste heat available. 4.2 Performance Characteristics 4.2.1 Topping Systems Steam turbines (Rankine engines), gas turbines (Brayton engines), and diesel engines are the three primary heat engines used in cogeneration topping systems. A steam turbine system consists of a boiler and a backpressure turbine. The boiler can be fired by oil, natural gas, coal, wood, or industrial by-products and wastes. The turbine drives an electric generator and provides exhaust steam, still under pressure, for heating purposes. The overall efficiency of steam turbine cogeneration systems generally ranges from 65 to 85 percent; such systems require 4,000 to 6,000 Btu of fuel for each kWh produced. The amount of electricity produced increases in proportion to the pressure of the steam entering the turbine. A_gas_turbine combined cycle system consists of a gas turbine waste heat recovery boiler and steam turbine generator. Natural gas or light petroleum products (distillate oils) are used as fuels, and the combustion gases produced are used in the gas turbine to provide the mechanical shaft power that drives an electrical generator. The exhaust heat from the gas turbine (850° to 950°F) is recovered in the waste heat boiler to produce high pressure steam piped to the steam turbine generator. The steam turbine may be the back pressure or condensing type. Condensing of the turbine exhaust can be utilized in district heating systems or for process requirements. The combined cycle system produces heat rates comparable to steam turbine cogeneration systems typically ranging from 5000 to 8500 Btu/kWh. The efficiency of gas turbines is sensitive to inlet air temperature; the lower the ambient temperature, the higher the unit's power output, i.e., a simple cycle gas turbine that will produce 4000 kW at 60°F can produce 4750 kW at -20°F. A_ diesel system, consisting of a diesel engine and a waste heat recovery unit, uses natural gas or distillate oil. The combustion of fuel in the engine yields the mechanical power that drives an electrical generator. Of the three topping systems, this cycle is the least efficient in producing electricity, and requires 7800 to 9000 Btu of fuel for each kWh produced. The engine exhaust can provide process heat or low-pressure process steam, but requires carefully controlled water treatment equipment. For process heating applications, the exhaust (at about 500° F) has been used. Process steam of about 100 psi is generated in boilers that recover heat from the engine exhaust. In addition to the engine exhaust, heat can be recovered from the water- cooled engine jacket; low pressure steam is produced, or water for district heating can be generated at 180 - 200°F through a heat exchanger. Production of steam from exhaust and jacket water has not enjoyed much success in Alaska. Maintenance on steam waste heat recovery systems is higher than the other topping systems. Typically, minor repairs are required every 7,000 to 10,000 hours, and major overhauls every 20,000 to 30,000 hours. 4.2.2 RBottoming Systems All bottoming systems are based on the Rankine cycle for waste heat recovery. Two types of Rankine cycles are used -- steam and organic. Steam bottoming systems recover heat rejected from thermal processes at high temperatures. Steam systems operate within a heat temperature range of 300 to 1000° F with thermal efficiencies of 14 to 36 percent, and generally have capacities of over 500 kW. Bottoming systems that use organic working fluids to recover thermal energy are available in limited sizes, ranging to 1000 kW. Because these operate at lower temperatures (195 to 340°F), such systems can recover lower temperature waste heat. These systems have efficiencies of 13 - 18 percent. Work on bottoming systems is focused on further development of organic-fluid Rankine cycles, which may prove to be more flexible than steam Rankin cycles. Because the organic fluids vaporize at temper- atures below 212°F, and are more efficient than water at higher temperatures, it should be possible to develop high performance organic Rankine cycles. 4.2.3 Combined-Cycle Systems Combined-cycle systems are comprised of two or more different thermodynamic cycles connected together in a way to gain maximum efficiency from the primary heat source. In most cases, both cycles are used for the same purpose -- usually to generate electricity. However, turbine exhaust is readily used for district heating. Such systems using coal or coal-derived fuels offer significant improvements over conventional systems for electric power generation in terms of increased efficiency, potentially lower cost, and reduced environmental impact. The concept of this advanced system is to burn coal or coal- derived gaseous or liquid fuels in air to produce a _ high temperature gas 2600° F or higher before expanding it through the turbine to produce electricity. After expansion, remaining hot gases can be used to generate steam in a conventional steam turbine plant to produce additional electricity. The open-cycle gas turbine/steam system forms a combined-cycle power plant with potentially greater efficiency than today's standard steam plant. Integrating a combined-cycle system with a low-Btu coal gasifier appears to be most promising from the standpoints of efficiency, cost of electricity, and emissions. Advances in combined-cycle power plants focus on high-temperature gas turbines combined with steam systems. 1. Open-Cycle Gas Turbine Combined Cycles Open-cycle gas turbines that burn natural gas and distillate fuels are used commonly for utility peak load applications. Combined-cycle power plants couple such gas-turbines with steam- turbine technology to reduce the cost of electricity. There is one oil-fired and 2 gas-fired combined-cycle plants currently in utility service in Alaska. Relatively low capital investment/kwW, higher conversion efficiency, capability for base and inter- mediate load service, and ease of waste heat utilization are factors making investment in new combined-cycle units increasingly attractive to electric utilities. The advantage of combined-cycle systems is represented by reliability due to the use of two tried and proven technologies. System efficiencies can reach nearly 75 percent with waste heat utilization of the steam turbine exhaust in a district heating system or other heating process. Reliability can be improved by arranging the waste heat recovery boiler for auxiliary firing. Generating plants in the Anchorage area using combined cycle technology generating electricity and heating city water has a heat rate at full load on both units of 7400 Btu/kw. Without heating city water the rate is 8500 Btu/kW, and with the steam turbine out of the cycle, heat rate for the gas turbine is 11,800 Btu/kw. Combined cycle gas turbine steam turbine units with efficiencies approaching boiler steam turbine generator cogeneration systems should be invesetigated for Kotzebue. The combustion of coal will not be discussed because the technology has not been totally identified. The same is true for the closed-cycle turbine combined cycle using alkali-metal vapor turbines. 4.3 Special Requirements and Impacts None 4.4 Costs Costs are based on a 5000 kW plant $/kW Steam electric plants -- coal fired Condensing <s==9==99s-<===9353=9-3-$2s<+=-—= 3200 Non-Condensing ----------------------------- 2800 Steam electric plant -- oil fired Condensing =-#99==9—===3=$$==498<=3<==$<<s=<==== 2500 Non-Condensing 9-9-9999 3299 - 2150 Diesel electric plant ----------------------- 1250-1600 Combined cycle -- oil fired Gas turbine/steam turbine Cogeneration for district hot water ------------- 3500 Installed costs are difficult to determine for plant technology other than diesel electric in Northwest Alaska. There is no historical data. We have computed costs based on Anchorage prices and factored by 1.8. 4.5 Summary and Critical Discussion In the cogeneration system, the turbine topping systems will have an overall thermal efficiency of 65-85 percent; it requires 4000 to 6000 Btu of fuel for each kWh produced. The gas turbine topping system has a 53 to 62 percent thermal efficiency and requires 5500 to 6500 Btu of fuel for each kWh produced. The diesel topping cycle has a thermal efficiency between 49 and 53 percent and requires 8800 to 10,000 Btu of fuel for each kwh produced. The steam bottoming systems have an overall thermal efficiency of 14 to 36 percent when operating between 300°F and 1000°F. The organic Rankine bottoming system has a thermal efficiency of approximately 13 percent and operates between 195°F and 340°F. Topping systems under development include the use of Stirling engines, fuel cells, magnetohydrodynamics systems, and thermionic devices, as well as advanced Diesel engines and gas turbines. The goal is to develop multifuel capabiliites for systems currently restricted to one or two fuels (particularly scarce fuels) and to develop new systems with multifuel flexibility. New and improved systems with higher efficiencies and wider applicability also are being developed. Depending on the flow rate and temperature of the waste heat to be recovered and the type of bottoming system, installation costs vary over a wide range. Maintenance requirements and_ the reliability of organic systems generally are unknown because proved commercial experience is limited. However, the technology of component parts (for example, expansion turbines, fluid pumps, and heat exchangers) is proved. In addition, since organic systems operate at low temperatures, their reliability should be high. Closed-cycle turbine combined-cycle development is proceeding slowly in the United States and is generally limited to system definition and optimization studies and critical component investigations, particularly on the primary heat exchanger. Developments are underway or have been conducted in the past in the Federal Republic of Germany, Austria, Canada, Switzerland, and the Soviet Union. With current technology, closed-cycle turbine power systems are less efficient than open-cycle gas turbine combined-cycle plants. Achievement’ of improved performance and competitive economics depends on resolving a number of high-temperature component and materials problems. Commercial-scale coal-fired power system applications are not expected in the United States through 1990. 4.6 Biblography U.S. Department of Energy, "Cogeneration: Technical Concepts, Trends, Prospects," DOE/EFU-1703, September 1978. Bos, P. G., Williams, J. H., "“Cogeneration's Future in the CPI," Chemical Engineering, February 1979. Troop, P. Acs "Cogeneration in a Changing Regulatory Environment," Chemical Engineering, February 1979. U.S. Department of Energy, "Fossil Energy Program Summary Document, FY 1980, Assistant Secretary for Energy Technology," January 1979, Power Generation Alternatives, 2nd edition, Seattle City Light, Seattle, Wa., October 1972. 19 5 COAL GASIFICATION COMBINED CYCLE 5.0 Introduction A conceptual design of a combined cycle electrical generation power plant integrated with a coal gasification section is shown in Figure D.2. Briefly, raw coal is delivered to the plant site where it is cleaned, sized and dried to the consistency required by the gasification unit. The prepared coal is then fed into the gasifier with air or oxygen and steam where it is partially oxidized. The hot raw gas exiting the gasifier is predominantly made up of hydrogen and carbon monoxide as well as_ trace contaminants. These contaminants, which include particulates, tars, sulfur and nitrogen, are generally removed by a gas cleanup process before delivery to the gas turbines. In the gas turbine section the feed gas undergoes combustion. These hot combustion gases drive the turbine and usually exit at a temperature of about 1000°F. A waste heat recovery boiler is then used to generate steam from the combustion gas exhaust of the gas turbine. This steam in turn powers another turbine driven electrical generator to produce additional electrical energy. Combined cycle technology is current state-of-the-art. Numerous coal gasification plants incorporating Lurgi, Koppers-Totzek and Winkler technology have been commercially proven. Gas turbine technology coupled with a steam power plant has also been commer- cially proven in over 40 installations using natural gas or oil as the fuel source. Therefore, many of the system aspects of an integrated gasification combined cycle power plant have been commercially demonstrated. In addition, the entire combined cycle process has been commercially demonstrated in a 170 MW plant at Lunen, West Germany by Steag AG. This facility uses Lurgi coal gasification technology coupled with a gas turbine/steam turbine power plant and a supercharged boiler. In the United States, plans are underway for the construction of a 100 MW demonstration combined cycle facility using second generation coal gasification technology. Start-up of the Cool Water Facility by the Southern California Edison Company is expected before the end of 1983. Sulfur Removal Sulfur Recovery FIGURE D.2 COMBINED CYCLE POWER FLOW DIAGRAM Coal Handling Gas Particulate and Preparation Cooler Scrubber Oxygen Plant Exhaust Gas Heat Recovery and Steam Generator The key element in a combined cycle power plant is the coal gasification section. Selection of the gasifier is a crucial step which will determine not only the performance of the system but the economic feasibility of the project. Numerous coal gasifica- tion technologies exist and the selection of the technology must be based on such factors as: (1) production rate of energy (2) turndown requirements (3) heating value of the gas (4) pressure and temperature (5) allowed gas purity (sulfur, carbon dioxide, etc.) (6) allowed gas cleanliness (tars, soot, ash) (7) coal availability, type, and cost (8) gasifier/end-use locations and interactions, and (9) size constraints. The major factor affecting gasifier selection in the Kotzebue area will be the availability of coal. The rank of coal, its moisture, fixed-carbon, volatile matter, sulfur and ash content are all critical factors. Coal moisture content will affect the heating value of the raw gas in a proportional manner. This is especially true in fixed- bed processes because the moisture is removed by the hot gases rising through the drying and devolatilization zones; thus, the product gas contains more water vapor. In fluidized-bed units, an increase in the water content tends to cause greater production of carbon dioxide. Entrained beds are particularly sensitive to coal moisture content because moisture inhibits the overall gasification reaction which must take place quickly in this type of bed. Depending on the feed coal moisture content, some drying may be necessary for entrained- or fluidized-bed units. Fluidized and entrained beds, compared with fixed beds, are less sensitive to the volatile matter content of coal because these compounds are gasified very quickly. In fixed-bed units, however, increases in volatile matter content cause an increase in the heating value of the gases, because these components are driven off in the devolatilization zone. In single-stage units, this volatile matter also will be cracked and polymerized to heavy tars and pitch that must be removed if the gas is not used directly. Coal with high fixed-carbon content requires more oxygen and steam per pound of coal than do those coals with lower carbon content. This leads to an increase in the percentage of carbon monoxide and hydrogen produced (decreased CO, content), and thus increases the heating value of the gas. A trade-off exists in this, however, because higher fixed-carbon content usually means lower volatile-matter content. Sulfur in coal exists in three different forms: pyrites (FeSo), organic, or sulfates. During gasification, the organic sulfur and some of the pyritic sulfur will react with hydrogen (to form hydrogen sulfide) and with carbon monoxide (to form carbonyl sulfide), thereby lowering the heating value of the gas. Ash is the remaining inorganic material left after coal is subjected to complete combustion. Ash composition will determine the temperature at which its melting will occur. Because all commercially available, fixed-bed gasifiers remove the ash in a solid dry form, the maximum temperatures (and thus the product gas compositions) allowed will be governed by this ash-softening temperature. In a fluidized-bed (Winkler) gasifier, any softening of the ash will cause the bed particles to stick and produce a loss in fluidization. Conversely, in the entrained-bed units (Koppers-Totzek), the ash is liquified and removed as a run-off slag. Therefore, for proper operation and maximum heating value of product gases, high ash-softening temperatures are preferred for fixed and fluidized beds, whereas low values are preferred for entrained-bed units. There are four known coal deposits within reasonable economic distance of Kotzebue. These deposits are: 1) the Kugruk River deposit 2) the Corwin Bluff deposit 3) the Point Hope deposit and 4) the Kobuk deposit. These coals are predominantly bituminous and subbituminous in nature with the exception of the Kugruk River deposit which is lignitic. Preliminary reports indicate that the Kugruk River deposit may be the most economical to mine, but its exceptionally high moisture content (33.0%) and correspondingly low heating value make this the most unattractive of the four deposits. Selection of a coal deposit for use is necessary before selection of a gasification technology can be made. With this in mind the remaining descriptions of a combined cycle facility will have to be made in a generic way. The description and performance of the gasification section is representative of the technology state- of-the-art and does not necessarily represent the most appropriate gasifier selection for Kotzebue. This is beyond the scope of this effort. 5.1 General Description The following description is based on the 100 MW Cool Water Combined Cycle Project being built by Southern California Edison. This project will use the Texaco coal gasification process and standard General Electric combined-cycle gas and steam turbine equipment. In this project 1000 short-tons per day of coal on a moisture and ash-free basis will be gasified. The resulting synthesis gas will be cleaned and combusted in the combined cycle section to produce approximately 100 MW of net electricity. In the first stage of the plant, coal will be delivered and unloaded onto coal conveyors for subsequent transportation to coal storage silos. At the Cool Water facility two dedicated unit trains will deliver coal on a continuous basis and therefore storage is kept to a minimum. However, this may not be the case for a facility located at Kotzebue. From the silos, coal is then conveyed to the grinding section where it is sized and mixed into a slurry. This slurry is then temporarily stored in two tanks before it is heated and pumped into the Texaco gasifiers. The slurry is heated by low-level steam produced in other downstream processes. Adjacent ot the gasification section is the air separation plant which will provide the 1000 tons/day of oxygen necessary for gasification. This integrated facility will produce 99 percent pure oxygen at 820 psia for injection into the gasifier. The oxygen compressor driver is electrically motor driven. A fifteen minute reserve gaseous oxygen supply and one day liquid oxygen supply are provided for start-up, cool down and emergency use. The Texaco coal gasifier is a single stage, pressurized, down flow, entrained bed reactor which operates under’ slagging conditions. This type of reactor can utilize both caking and non- caking coals to produce high throughputs of gas which are relatively free of tars and other by-products. The Texaco process contains four main features which the developer feels essential for both technical and financial success. These features include high temperature operation, high reactor pressures, the utiliza- tion of pulverized coal and the slurry introduction of feed into the gasifier. The desirable gasification temperatures are greater than 1800°F for lignites and greater than 2300°F for higher ranking coals. These reaction temperatures will increase gas yields, increase carbon conversion efficiencies, and produce a gas which is relatively free of liquid by-products. Operation at these temperatures in the slagging mode also simplifies ash removal from the high pressure gasification vessel. The slag which is produced is glassy in nature and releases only traces of metal during leaching tests. The non-polluting aspects of the slag indicate that disposal or storage of slag will present no problems. The absence of liquid by-products due to high temperature operation results in waste water effluent levels far below other industrial processes. The Texaco gasifier is designed to operate at a pressure of 600 psig. This higher pressure facilitates high space/time velocities and reduces reactor size. This high pressure also reduces recompression costs for downstream process requirements. The use of pulverized coal in the Texaco process increases the range of feedstocks available to the process. The use of run-of- mine coals, which are increasing in fines content due to modern mining techniques, can be used without previous pretreatment. High coal conversion rates and carbon efficiencies are also produced due to the high specific surface area of the pulverized coal dust. The fuel design philosophy feature of the Texaco process is the use of a slurry to introduce coal into the high pressure gasifier. This slurry is a suspension of finely-divided coal in a liquid carrier such as water, organic liquids or even waste by- products. Wet run-of-mine coals therefore do not’ require pretreatment or drying in this process. However, slurry properties decrease carbon conversion but increase efficiency. This last fact is a result of less cabon dioxide formation which produces heat to evaporate the liquids from the slurry. This inturn results in a greater production of carbon monoxide and an increase in process efficiency. Since less carbon monoxide is converted into carbon dioxide to produce heat, specific oxygen consumption will decrease with increasing slurry concentration. However, this does not indicate the relative water content of the raw gas which must also be taken into consideration. Increased slurry concentrations will have the desirable effect of increasing carbon monoxide and hydrogen’ production’ while decreasing carbon dioxide and steam concentrations. Although increased carbon monoxide concentration increase the energy content of the exit gas, the corresponding decrease in carbon dioxide production (and hence heat) decreases the specific steam production of the gasifier. Decreases in gasifier steam production may warrant increases in boiler steam production, and hence increases in coal consumption elsewhere in the plant to supply the necessary process steam requirements of the facility. The synthesis gas produced in the gasifier is predominantly hydrogen and carbon monoxide with traces of carbon dioxide, hydrogen sulfide, nitrogen and ammonia (see Table D.1). This synthesis gas composition was produced using a Utah coal with the properties shown in Table D.2. The particulates, sulfides, ammonia and some carbon dioxide in the synthesis gas must be removed before delivery to the gas turbine section. Before cleanup however, the hot gas leaving the gasifier is cooled in a series of waste heat boilers to produce high pressure steam. The raw gas and slag which exit at the bottom of the refractory lined reactor vessel are deflected at the discharge end of the radiative waste heat boiler which is located below the gasifier reactor vessel. As the raw gas is cooled to below the ash fusion temperature of the coal, the slag is separated and granulated in a water bath at the bottom of the radiative cooler. The ash which settles in the water bath is collected for removal in a program- mable lock hopper. The radiative heat boiler is sized to take advantage of the high temperature syngas to the point where convective heat transfer is more economical. The partially cooled raw gas is then sent to the second stage convective waste heat boiler where additional process steam is generated. The cooled syngas which exits the waste heat boilers passes through a venturi or orifice type scrubber where any remaining particulate matter, as well as ammonia, is scrubbed out by direct contact with water. The wet scrubbing which takes place at near gasifier pressures is expected to remove over 99.9% of the entrained particulates and fly ash. The water which is removed from the quench section and scrubbing system is sent to a settling tank. The extracted particulate matter is then recycled to the wet grinding mill for reinjection into the gasifier. This step assures high process carbon conversion efficiencies. The gas leaving the scrubbing system has a particulate loading of typically less than 1 mg/Nm>. The wet gas exiting the scrubber is further cooled in a heat ex- changer by cooling water to condense water from the syngas. After this final cooling the gas is processed ina Selexol® unit where sulfur compounds, hydrogen sulfide and some carbonyl sulfide is removed. The sulfur removal step is expected to remove approxi- mately 97% of the sulfur compounds. The concentrated hydrogen sulfide stream from the Selexol® unit will be converted to ® elemental sulfur for sale or disposal in a Claus’ unit. Sulfur r . ® : : emissions from the Claus’ plant will be reduced by a tail gas treating section. Table D.1l Synthesis Gas Composition from Texaco Gasifier Vol.% Raw Clean Component Gas Gas H 34.48 35.67 cé 43.31 44.79 CO 19.83 17526 CHy 0.05 0.05 Ny + Ar 2.16 2523 HS 0.16 0.ppmv cos 0.01 60.ppmv Total 100 100 Table D.2 Utah Coal Feed Characteristics As Ultimate Analysis Received Moisture 10.0% Carbon 63.2% Hydrogen 4.3% Nitrogen 1.05% Chlorine 0.00% Sulfur 0.45% Ash 9.45% Oxygen 11.55% Proximate Analysis Moisture 10.0% Ash 9.45% Volatile 36.05% Fixed Carbon 44.50% Sulfur 0.45% Btu/1lb. 11,150 Grindability (Hardgrove Index) 48 The clean synthesis gas exiting the Selexol” scrubber section is then passed through a saturator, heat exchanger, pressure con- troller and a gas surge drum before entering the combined cycle gas turbine. In the saturation section, water is added to reduce NO, emissions during combustion. This additional water vapor also produces significant power in the combustion turbine. The saturated synthesis gas is then heated in the heat exchanger before entering the surge drum which helps to smooth out any minor load variations between the gas turbine and gasifier. Short excesses of synthesis gas are flared if they occur in this section. The gas turbine generator, heat recovery steam generator and turbine make up the combined cycle section. The saturated syn- thesis gas and additional steam are injected into the combustion gas turbine to generate approximately 65 MW of electricity. Additional energy is recovered by generating high pressure steam from the hot gas turbine exhaust gases in the steam generator.The cooled exhaust gases exit the steam generator at approximately 270°F and are vented to a 200 ft stack. The high pressure superheated steam from the steam generator is fed to the steam turbine where an additional 55 MW of electricity are generated. Thus, the gross electrical production capabilities of the Cool Water facility are approximately 120 MW. However, the net power produced is approximately 200 MW after in-plant electrical consumption is subtracted. 5.2 Performance Characteristics Energy and Material Balance The heat rate of the Cool Water combined cycle demonstration facility is anticipated to be approximately 10,500 Btu/kWh, which would translate into a 32.5 percent efficiency on a coal-to- busbar basis. This value is contingent on the quality of coal and the coal slurry preparation technique. A heat rate value of 10,000 Btu/kWh is possible if quality coal is available and optimum slurry preparation is achieved. These heat rates can be compared to a heat rate of 9,000 Btu/kWh for a "commercial size" (greater than 1000 MW) combined cycle power plant. This lower heat rate is based on the use of larger more efficient steam turbines with reheat. However, the Cool Water facility is expected to come close to the 9,900 Btu/kWh heat rate of conventional coal-fired steam plants which use wet scrubbing of stack gases. A detailed material and energy balance for the Cool water facility has not been published. However, detailed material and energy balances by a "commercial size" combined cycle plant using oxygen-blown Texaco coal gasification units has been published. Table D.3 presents a summary of the overall systems as well as the gasification and gas cleaning subsystem and the power generation subsystem. This large scale facility produces approximately 1,157 MW at a net heat release rate of 8,813 Btu/kWh and an overall system efficiency of 38.7% (coal -> electricity). Some of the values presented in this table will be somewhat different for smaller combined cycle installations such as the 100 MW Cool Water plant and the 10 MW to 50 MW plant which Kotzebue requires. Power system energy outputs can be expected to be somewhat lower due to the lower efficiencies of smaller steam turbines. Overall system efficiency for a small combined cycle plant near Kotzebue would probably be in the area of 35% (coal to electricity - % of coal HHV). A material balance around the gasifier is shown in Table D.4 for a commercial size plant using the oxygen-blown Texaco technology. This balance is for multiple gasifiers and therefore can be linearly scaled down for smaller size combined cycle installations. However, this material balance is for an Illinois #6 coal and will be somewhat different for other coal feedstocks. The overall energy balance for the commercial size combined cycle facility is shown in Table D.5. This energy balance is repre- sentative of an oxygen blown Texaco gasifier and again is related to the coal properties and plant size. Somewhat different values can be expected for Kotzebue area coal and a smaller plant size. Table D.6 presents the energy balance as a percent of the coal's higher heating value. As this table indicates, nearly 40% of the coal's generated heat is rejected from the cooling towers. The material and energy balance above are for a facility that rejects cooling water at approximately 100°F. However, this temperature can be increased for district heating application with a marginal decrease in overall plant efficiency. This would require plant redesign. TABLE D.3 Summary of System Performance for a Large Scale Oxygen-blown Texaco Gasifier Integrated Combined Cycle Power Plant Gasification and Gas Cleaning System Coal Feed Rate lbs/hr (m.f.) 798,333 Oxygen or Air (1)/Coal Ratio, lbs/lb m.f. 0.858 Oxidant Temperature, °F 300 Steam/Coal Ratio, lbs/lb m.f. (4) 0 Slurry Water/Coal Ratio, lbs/lb m.f. (5) 01.503) Gasification Section Average Pressure, psig 600 Crude Gas Temperature, °F 2,300-2,600 Crude Gas HHV (dry basis), Btu/SCF (2) 281.1 Temperature of Fuel Gas to Gas Turbine, °F 781 Power System Gas Turbine Inlet Temperature, °F 2,400 Pressure Ratio 17:1 Turbine Exhaust Temperature, °F 1,40 Steam Conditions, psig/°F/°F 1,450/900/1,000 Condenser Pressure, Inches Hg abs 2D Stack Temperature, °F 232 Gas Turbine Power (3), MW 745 Steam Turbine Power (3), MW 448 Power Consumed, MW 36 Net System Power, MW 1,157 Overall System Process Deaerator Makeup Water, gpm/1000 MW 362 Cooling Tower Makeup Water, gpm/1000 MW 7,588 Cooling Water Circulation Rate, gpm/MW 347 Cooling Tower Heat Rejection, % of Coal HHV 38.7 Air Cooler Heat Rejection, % of Coal, HHV 5.2 Net Heat Rate, Btu/kWh 8,813 Overall System Efficiency (Coal Power), % of Coal HHV) 38 7 (1) Dry Basis, 100% 0, (2) Excluding the HHV of H (3) At Generator Terminals S, COS and NH 2 3 (4) Includes moisture in oxidant air (5) Small Changes in this ratio do not significantly alter the results presented here. Coal Moisture Ash MAF Coal Carbon Hydrogen Oxygen Nitrogen Sulfur TOTAL COAL Oxidant (dry) Oxygen Argon Nitrogen TOTAL OXIDANT TABLE D.4 Material Balance Around Gasifier for a Large Scale Combined Cycle Power Plant FEEDS T(°F) lb/hr 163 35,000 80,000 554,985 42,525 80,022 9,985 30,816 833,333 1000 863,337 48,469 2,826,661 3,738,467 Water (including air moisture) TOTAL FEEDS 163 388,994 4,960,794 1b mol/hr 1,942.8 46,205. 21,094. 2,500. 356. 961. re PFaoanwo 26,979. 1,213. 100,894. WID & Ww 129 087.3 23,534.3 EFFLUENTS T(°F) Gasifier Effluent 2,300-2,600 cH, 2,828 H 39,672 cé 923,019 co 572,211 4,8 30,101 cs 4,674 N 2,834,153 aR 48,469 H,0 422,646 wh, 3,034 TOTAL GASIFIER EFFLUENT 4,880,794 2,300-2,600 Ash Carbon Nil Ash 80,000 TOTAL ASH 80,000 TOTAL EFFLUENTS 4,960,794 1b/hr 1b _mol/hr 176.3 19,678.6 32,952.0 13,001.6 883.2 77.8 101,162,0 1,213.4 23,459.5 178.1 192,781.9 mol % (wet) 0.09 10.21 17.09 6.74 0.46 0.04 52.48 0.63 U2 oh] 0.09 100.00 D-34 yeru TABLE D.5 Energy Balance for a Large Scale Combined Cycle Power Plant Basis: 60°F, water as liquid, 3,413 Btu/kWh. MM Btu/hr HHV SENSIBLE LATENT RADIATION POWER TOTAL HEAT IN Coal 10,196 5 10,201 Gas Turbine Suction Air -- 102 258 360 Demineralized and Raw Water 2 2 Auxiliary Power Inputs 149 149 TOTAL 10,196 109 258 0 149 10,712 HEAT OUT Ash Slurry 50 50 Gasifier Heat Losses 112 112 Gas Cooling 91 91 Sulfur Product 105 1 106 Air Coolers 82 82 Oxidant Compressor Interstage Cooling 70 70 Gas Turbines 1,871 1,871 Sulfur Plant Effluent Gas Zz 18 20 Steam Turbines 2,163 2,163 Power Block Losses 47 193 240 Turbo-Generator Condensers 4,171 4,171 HRSG Stack Gas 816 579 153995 Steam Heat and Power Losses 22 24 46 Selexol Overhead Condenser 68 68 Selexol Solvent Cooler 176 176 Waste Water Effluent 28 28 TOTAL 105 1,124 4,860 159 4,375 10,689 Input-Output _ 0.22% Input Sins Reliability Because gasifiers have been commercially available for several decades, plant availabilities (i.e., percent of the year the plant is operable) can be stated with some certainty. Table D.7 shows plant availabilities and the equivalent operating hours per year for the various bed types. Although plant life usually should be 20 to 25 years, some gasifiers installed in 1945 are still operating. The power section of the combined cycle system will have an availability of 90 %+ as well. Therefore, the total combined cycle plant could be expected to have a 90%+ availability. However, this should not be considered indicative of plant output energy. The facility will follow the load demand imposed on it by the city of Kotzebue and therefore power output will be lower on a yearly basis. 5.4 Costs The capital cost estimate for the 100 MW Cool Water Plant is shown in Table D.8. These installed costs have been updated from 1980 cost estimates to mid-1982 dollars using a 10 percent year inflation factor. It should be noted that these costs are representative of a plant constructed in California and that a similar facility constructed in Kotzebue may have an installed cost of 1.7 times the amount shown. However, the possibility exists of constructing the facility on barges on the west coast. These barges would then be shipped up to Kotzebue and permanently moored there. This technique could conceivably bring down the cost of even the California based plant since field erection cost would be eliminated. For a barge mounted plant the only site pre- paration at Kotzebue would be for coal preparation, storage, and handling and the necessary construction for permanent mooring of the barges. The possibility of implementing this technique is beyond the scope of this study but should be investigated at a later date. Table D.6 Energy Balance as Percent of Coal's Higher Heating Value for a Large Scale Combined Cycle Power Plant MM Btu/hr Percent IN Coal HHV 10,196 100.0 OUT Net Power 3,948 38.72 Sulfur 105 1.03 Ammonia Product, HHV 0 0 Selexol Sensible and Latent 171 at? Oxidant Interstage Cooling 568 5.57 Ash Slurry Sensible 81 0.79 HRSG Stack Gases 1817 17.82 Rejected at Condensers 3754 36.82 Other Sensible Losses (94) (.92) Other Latent Losses (288) (2.28) Gasifier Heat Losses 26 0.26 Power Block Losses 215 2.11 10,303 TOO.15 Table D.7 Availabilities of Gasifiers by Bed Type Bed Type Availability, % H/Yr Fixed 80-97 (avg = 95) 7000-8497 Entrained 90+ 7880 Fluidized 90+ 7880 Table D.8 Cost Estimate For a 100 MW Combined Cycle Power Plant Using Oxygen Blown Texaco Gasifier (x10°$) Description ____Total Coal Receiving, Storage and Preparation 28,800 Oxygen Plant 34,800 Coal Gasification 38,400 Sulfur Removal/Recovery 18,000 Steam, Condensate and Water 27,600 Power Generation Equipment 50,400 Supporting Systems and Facilities 27,600 Initial Operation - 12,000 Subtotal $237,600 E-C Engineering & Management 36,000 Other Program Expenses 31,200 Contingencies 45,600 $350,400 ($595,680) * * Installed plant cost in Kotzebue In addition to the Cool Water costs presented, the capital investment costs shown in Table D.9 assume a 70% operating load factor and coal costs of $2.00/MM Btu. Total capital costs for this size facility are roughly 1.5 billion dollars. With the cost of the 100 MW Cool Water Plant and the projected cost of this “commercial size" facility, one can calculate the appropriate scaling factor for estimating the cost of a smaller combined cycle plant for the city of Kotzebue. This scaling factor is: (Capital Cost of Large Facility) ee (Net Power Output of Large Facility )x Capital Cost of Small Facility Net Power Output of Small Facility ($1,538, 689,000 ) - (1156.8 MW)0.605 S$ 350,400,000 100 MW D-38 Therefore, the capital cost for a 50 MW combined cycle plant would be approximately $230,000,000 1982 dollars. Using a 1.7 scaling factor for construction in Alaska, this cost would increase to $391,000,000 for a combined cycle plant producing 50 MW of power in Kotzebue. However, as previously mentioned, this cost might be reduced if barge construction is practical. In the short term, the City of Kotzebue will probably require a combined-cycle power generation facility in the 10 to 30 MWe) size range. The installed cost of such a facility would be $147,900,000 and $287,500,000 for a 10 MW) and 30 MW (6) size plant respectively. The 10 MW) facility will probably require approximately 5 acres of land, excluding coal storage. The appropriate scaling factor for land requirement is: ( land size of large facility) = (net power output of large facility 0.25 land size of small facility net power output of small facility This is based on a 2000 MW(@) facility requiring 20 acres of land. Additional land requirements for coal storage are a function of reserve storage requirements and are included in the above equation. TABLE D.9 Capital Investment for a 1157 MW Combined Cycle Plant at 70% Operating Load Factor and $2.00/MM BTU Coal $1,000(1) S$/kW(2) Percent PLANT INVESTMENT Coal Handling 35,297 30-5 3.56 Oxidant Feed 187,822 162.37 18.95 Gasification and Ash Handling 38,817 i 3692 Gas Cooling 107,177 92.66 10.81 Acid Gas Removal and sulfur Recovery 45,736 39.54 4.61 Waste Water Treating - Steam, Condensate & BFW Lzo23 1.14 0.14 Support Facilities 88,328 6eS5) 8.91 Combined Cycle 486,649 420.70 49.10 Subtotal 991,152 856.82 100.00 Contingency 189,056 163.42 Total Plant Investment L, 80,208 | a,0 20824 SALES TAX 26,649 23.04 CAPITAL CHARGES Preproduction Cost 77,123 66.67 Paid-up Royalites 5,900 5,20 Initial Catalyst and Chemical Charge 824 0.72 Construction Loan Interest 147,408 27 a2 Total Capital Charges 25171250 199592 DEPRECIABLE CAPITAL 17438 ,1138 | 1,243.20 WORKING CAPITAL 100,576 86.94 TOTAL CAPITAL 1,538,689 1,330.14 NOTE (1) Mid-1982 Dollars (2) Based on 100% Operating Load Factor D-40 5.5 Maintenance Requirements Gasifiers normally are shut down once a year according to the requirements of the ASME Boiler Inspection Code. During this scheduled shutdown, the following items receive attention: {1} Ash Grate and Holder: Inspected and replaced. Usual lifetime of cast iron is 1 to 2 years; that of steel is indefinite. (2) Gasifier: Refractory linings are patched every 1 to 2 years, replaced every 5 to 10 years in single-stage; every 10 to 15 years in a two-stage, fixed bed. (3) Agitators: Checked for general wear, and agitator bearings are inspected. (4) Coal Feed and Ash Withdrawal Screws: Inspected and adjusted. (5) Piping: Cleaned and blown out; checked for deposits. In addition, tar and oil precipitators and coolers usually are steam cleaned every three months. 5.6 Operating Costs and Manpower Requirements The operating cost of a 1157 MW combined cycle plant is shown in Table D.10. This table assumes an operating load factor of 70% and coal costs of $5.00/10° Btu. The operating labor costs are based on a 28 person shift. Maintenance labor is approximately 82 persons per shift. Total labor requirements for the entire facility operating on a three shift basis is estimated to be approximately 400 people. The scaling factor to be used here for estimating the number of personnel as a function of plant size may be seen in the following relation: ( desired staff size ) = ( desired plant size ) 0.5 known staff size known plant size The exponent, 0.5 is only an approximation; its actual value requires much more operating data than is currently available. The actual value could vary between 0.3 and 0.8. Therefore, the staff requirement for a 50 MW combined cycle plant at Kotzebue would be approximately 84 people. However, this number could vary between 33 and 156. Table D.10 Cost of Services for a 1157 MW Combined Cycle Plant at 70% Operating Load Factor COAL COST, HHV $2/MM Btu NET PRODUCTION (1) Net Power, MW iL 56).3 By-product Ammonia ST/SD 0 By-product Sulfur ST/SD 301 OPERATING CHARGES, $1000/YEAR Coal 125,044 Operating Labor 4,307 Catalyst and Chemicals 419 Utilities 2,166 Maintenance, Labor 12,611 Maintenance, Materials 18,915 Administrative and Support Labor 5,075 General and Administrative Expenses 10,134 Ash Disposal 392.0 Property Tax/Insurance 29,505 By-product, Ammonia (0) By-product, Sulfur (0) Total Operating Charges, $1000/Year 208,568 NOTE (1) At 100% Operating Load Factor D-42 5.7 Bibliography McElmurry, B., Smelser, S., "Economics of Texaco Gasification Combined Cycle System" by Fluor Engineering and Construction, Inc. EPRI AF-753, April 1978. Blazek, C.F., Baker, N.R., Tison, R.R., "Low- and Medium-Btu Coal Gasification Processes" by the Institute of Gas Technology ANL/ CES/TE 79-1, January 1979. Walter, F.B., Kaufman, H.C., Reed, T.L., "The Cool Water Coal Gasification Program - A Demonstration of Gasification Combined Cycle Technology". Paper presented at the Conference on Synthetic Fuels: Status and Direction, San Francisco, October 13- 16, 1980. Larson, J.W., “Comparison of Coal-Gasification Combined Cycle Development in the USA," Modern Power Systems, pp. 39-45, January 1981. 6 OLD FASHIONED COAL GASIFICATION BY THE "KOPPER - TOTZEK" METHOD 6.1 General Description Because of the ever rising costs of oil-based fuels, new interest has been shown in coal-gasification. New processes have been developed in order to raise the thermal efficiency of the gasi- fication, and in order to get an output of higher Btu-value than the 125-500 Btu/scf normally found in "blue" or "water" gas. However, these new processes all involve high-technology components, such as high-pressure reactors working in the 300- 1500 psi and the 1200-2000°F range. This makes them less useful in remote areas with extreme climatic conditions where reliability and easy repair by local labor is essential. The Kopper - Totzek atmospheric gasification process has been utilized for more than a century in Europe and the U.S. Because of its rather uncomplicated technology it could be utilized in areas where coal is locally available and oil-based fuels must be imported at high costs. Almost all grades of coal can be gasified in the Kopper - Totzek process and a thermal efficiency of 50-60 percent can be expected. Part of the waste heat from the process can be utilized in heating nearby buildings. Before gasification the coal must be pulverized; together with low pressure steam and oxygen it is then blown into the gasifier where combustion takes place. Due to the limited amount of oxygen, the combustion is not completed and the combustion product thus consists of combustible gases such as hydrogen, methane and carbon monoxide. The latter is highly toxic, and to ensure early detection and tracing of leaks in the disribution system a small amount of odorous gas must’ be added. It remains, however, unknown whether authorities would allow local gas companies to distribute such toxic gases. This problem can be overcome by methanation, a process in which the methane content in the gas is increased by catalytic reaction of hydrogen and carbon monoxide. By this action the heating value of the gas is increased considerably, thereby reducing the required capacity of the distribution system. Thus distribution costs are lowered and a greater choice of standard equipment such as meters, burners and gas turbines are available. 6.2 Performance Characteristics Energy input is adjusted by the maintenance of the correct pressure in the distribution system. Energy output is adjusted by the individual consumer and by the power plant, where electricity is generated with gas turbines or gas engines. Based on the demand for electricity and space heating computed in Section 4 and on assumed conversion factors for coal-to-gas and gas-to-electricity processes of 50 percent and 25 percent respectively, the annual coal demand in 1982 and 2002 will be approximately 12000 and 75000 short tons. (These figures will be somewhat lower with waste heat utilitzation from the power plant.) 6.3 Reliability Due to the many years of experience accumulated with the Kopper - Totzek coal gasification process, it can be considered highly reliable. In the extreme climatic conditions of Northern Alaska however, any long lasting breakdown would have serious effects, and a 100 percent backup for all essential components must be provided. Backup could also be provided with an LPG storage for heating and cooking purposes and by maintaining the existing diesel generation. 6.4 Thermodynamic Efficiency Coal to gas conversion: 50 - 60% Distribution system 3 100% House installations 3 85% Power generation : 20 - 30% 6.5 Costs The capital costs are expected to be high. Based on an operating Danish plant, an estimate of approximately 600-800 $/ton coal handling capacity on a yearly basis has been made. This figure does not take into account the extra expenses involved in arctic construction work in remote locations. A work force of approximately one full time employee per 1000 tons of coal on a yearly basis has been estimated. With a working year of approximately 2000 hours, this will amount to 8 $/ton; costs will be around 32 $/million Btu. 6.6 Special Requirement and Impacts Due to a certain amount of foul odors from the gasification process the plant should be located where the prevailing winds do not carry these odors through the city. Coal would have to be transported from a source, which has not yet been determined. Construction for a coal gasification plant will require some highly specialized labor which is not expected to be locally available. The technology level of operative personnel would not have to be much higher than for the diesel generating and heavy road machinery in use in Kotzebue today. D-46 However, special trained key personnel will be required. Environmental residuals (smoke, ash and tar), will have to meet emission and other requirements. This should not present insurmountable difficulties. 6.7 Summary The use of coal gasification does not seem to be an economic way of providing Kotzebue with energy for space heating and power generation. ‘ Even with the assumption of coal being available at 100 $ per ton, the final price for coal gas will be almost three times that of diesel fuel. With distribution, interest and depreciation taken into account, the total costs will most likely be higher than the costs experienced with existing systems. 6.8 Bibliography Penner, S. S., Icerman, L., Non=nuclear Technologies. Energy, 1979, Volume 2. Considine, D. M., Energy Technology Handbook, 1977. Scientific American. Volume 230. March 1974. p. 19-25. Personal communication with Opton Hansen, President of "Strandvejsgasvaerket", Copenhagen, Denmark. (Copenhagen Coal Gasification Plant) 7 SOLAR ENERGY 7.1 General Description Little information is available to determine the applicability of solar technologies in northwestern Alaska. Kotzebue has no station recording solar radiation, and few installations have been in existence long enough to provide relevant performance data. Preliminary research has shown that there are a limited number of solar technologies that are feasible in Kotzebue. Using photovoltaic cells for conversion of sunlight into electricity is not cost effective, nor are large collector arrays for active solar space heating. The two applications that merit consideration are passive solar space heating and active solar hot water heating. Passive solar heating utilizes the entire structure as a simple solar collector. Sunlight is collected through the south glazing and generally stored in some form of thermal mass (water, rock, phase-change materials). The technology relies on the thermal envelope (insulation) to retain solar heat. Passive solar in its purest sense employs no mechanical equipment for distribution of heat, though in practice a small fan(s) is sometimes used, particularly in an isolated gain situation such as a greenhouse. Though there are several types of passive solar systems that have been used throughout the world, only two are really applicable to the Kotzebue area. These are direct gain, where sunlight enters directly into the living space via south glass, and isolated gain, where a greenhouse on the building's south side acts as a buffer zone for both heat gain and loss. Indirect gain systems employing significant storage masses at the south wall are impractical in northern Alaska, due to the high cost of concrete and the light suspended floor systems that are incapable of supporting the heavy mass required. D-48 Movable insulation that can be placed over the glazing at night is an integral part of a passive solar system in the north, Without it, most of the heat captured during the day will escape back out at night. In contrast to the simplicity of passive solar, active solar hot water heating requires a mechanical pump(s) to operate. Collectors with a metal or rubber absorber plate are mounted on the roof, with a distribution loop to and from the storage (hot water tank). There are several different system configurations possible; the most attractive for northern conditions would likely be a simple antifreeze system with a double jacket heat exchanger in the hot water tank to maintain separation from potable water. 7.2 Performance Characteristics Energy input will differ greatly depending on the installation, as the amount of solar radiation usable as heat is in direct relationship to area of glazing and conversion efficiency of a system. In passive solar heating, a south glass-to-floor-area- ratio of 10% has been determined as an average feasible by preliminary research (though not necessarily optimum; this will vary dependent on several factors). Typically, the glass area is increased as more thermal storage is added, but this latter item is of minor importance during most of the year at Kotzebue, as solar radiation is used up in heating the living areas before it ever reaches storage. Energy output for 100 square feet of south glazing on a 1000 square-foot structure would be about 17.6 MMBTU's annually. The solar fraction (percent of heating load supplied by solar) will vary depending on the annual heating load of the structure. Computer modeling done at the University of Fairbanks indicates that about 50% of the annual hot water load can be met by 120 sq. feet of active solar collector, assuming "typical" hot water usage by a family of four. Energy output is approximately 10-11 MMBTU's annually. The system would be drained down and unusable during the coldest months of the year. Systems adjustments on an active system are generally automatic through use of a differential controller (with manual override by the consumer possible). 7.3 Reliability The solar resource at Kotzebue is quite dynamic, ranging from a low of no appreciable gain in mid-winter to a high in late winter/early spring. Interpolated data show a smaller amount of radiation in the fall; this can likely be attributed to overcast conditions. As a result, solar systems performance is variable, and should be considered as a "fuel-saver" technology. There is a need for 100% backup in both space and water heating applications. Thermodynamic Efficiency - Efficiencies will vary with each individual installation, dependent on such factors as _ siting, orientation and care of design and installation. General figures can be given for the conversion efficiency of solar systems (percentage of available solar radiation converted to usable heat); thesé are listed below: - Passive Solar Direct Gain 75% - Passive Solar Greenhouse 40 - 60% - Active Solar Collectors 35 - 40% 7.4 Cost Installed costs for solar technologies in northern Alaska are difficult to determine, due to the lack of historical applications. Complicating this task is the fact that each installation may be vastly different due to such factors as orientation, architectural constraints and size of the living area or energy demands of the structure. Costs for a simple direct gain passive system need involve nothing more than south glazing and accompanying window insulation. If a new structure is designed and oriented correctly, much of the glazing that would exist in a "typical" structure could be placed on the south, adding no cost over a conventional home save for the shutter system For purposes of comparison, we will assume a cost of $25 per square foot for solar windows on the 100 square feet glazing/1000 square feet new house referenced earlier in this section. Installed cost would thus be $2500.00. Cost for adding windows to an existing house would be much higher, due to the remodeling required of an existing wall. Adding a greenhouse to a structure would cost about the same per square foot as new residential construction in the Kotzebue area; slightly higher if shutters are added. Lifetime of passive solar technologies are normally that of the building. As passive systems are an integral part of the structure, maintenance costs are limited to a possible replacement of weatherstripping and/or hardware for the movable insulation at mid-term or later of the useful life. The cost of active hot water systems is very difficult to determine, due to the lack of installations throughout Alaska. Preliminary research and application in the Fairbanks area (Seifert, 1981) suggest that site-built or locally manufactured n-&1 collectors might be built for $30.00 per square foot in Kotzebue. System "constant" costs (tank, pumps, etc.) are estimated at $1,000.00 dollars. Installed cost for a 120 square-foot system would thus be $4,600.00. Maintenance costs are not readily available for Alaska, but usually estimated at 1% of installed cost annually. Maintenance consists of system drain- down at winter's outset and recharging with glycol/water solution in the spring. Operation costs will vary with systems design (number and size of pumps), but may be significant in areas with high electrical costs. Useful life of an active system is estimated at 20 years, though replacement of components such as pumps may be necessary during that period. Economies of scale apply to both passive and active technologies, as bulk buying, and more efficient use of skilled labor should reduce installed costs. 7.5 Special Requirements and Impacts In order to be effective, a solar system must be oriented within about 20 degrees of due south and have a relatively unobstructed "window" to the sun. Active solar systems have some leeway in siting, as they can be placed anywhere on a roof. Passive systems are more site-specific; much of the existing housing stock is likely not properly oriented for solar gain. New housing can easily be oriented to the south, but concerted site planning will be necessary in a new housing development to assure that one building does not shade another. Required construction skills differ little from those of standard light construction, Typical light construction materials are used, with the exception of the collector array on the active system. All required resources are commercially available. D-52 Solar technologies have no known significant negative impacts on the environment. 7.6 Summary and Critical Discussion Practical application of solar energy in northwest Alaska are limited at this time. Based on the simple example herein, active hot water systems would cost approximately $21.00 per million BTU. This does not, however, include operation and maintenance costs. Generally, the only time active solar can compete with fossil fuels is in the case where an individual is using electricity to heat domestic water. However, it would likely be more cost effective to switch to oil fired hot water with energy conserving items included. Passive solar applications are largely limited to new structures: it is generally more cost effective to concentrate expenditures on energy conservation when considering existing buildings. Greenhouses are effective heat collectors, but are not as attractive an investment (from an economic standpoint) on a single family residence as other conservation or solar options. Larger community greenhouses using solar as supplemental heat offer greater benefits in terms of economics of scale. Simple direct gain passive solar systems show great promise in new construction, with preliminary calculations showing costs in the $5 - 8.00 per million BTU range. All solar systems in Alaska must be combined with energy conservation to achieve maximum effectiveness. Without the ability to retain captured solar heat, a structure will benefit little from solar technologies. 7.7 Bibliography Seifert, R.D., Solar Design Manual for Alaska. Bulletin of the Institute of Water Resources, July 1981. Barkshire, J., Solar Technical Profile for the Shungnak, Kiana and Ambler Reconnaissance Study of Energy Requirements and Alternatives. Wind Systems Engineering, May 1981. 8 HEAT PUMPS -- INDIVIDUAL SPACE HEATING 8.1 General Description A thermodynamic law of nature is for heat energy to flow from higher to lower temperature. A heat pump works against this natural flow by using a refrigerant to move heat from a cooler area to a warmer one. To do this, the heat pump uses an outdoor coil containing a low-pressure liquid refrigerant that is even cooler than the air. When a fan blows outdoor air across this coil, the cooler refrigerant absorbs the heat from the air, "boils", and turns into a vapor. The refrigerant vapor is then pumped through a compressor, where it becomes "superheated". The refrigerant vapor is next pumped through an indoor coil. As the vapor is now hotter than room temperature, it condenses (turns into a liquid), releasing heat. This heat is normally blown through a duct system for distribution to the structure. Once the liquid refrigerant has released its heat, it is pumped back outside to repeat the cycle. On the way, it passes through an expansion valve, which lowers the refrigerant's pressure again so that it can boil more easily in the outdoor coil. Operation can be reversed in the summer so that the unit becomes an air conditioner for cooling purposes; this is not expected to be a major need in the Kotzebue area. The ratio of thermal energy delivered inside the building at a high temperature as heat to the amount of external electric energy required to run the heat pump is called the coefficient of performance (COP). The COP is greater on mild days than on cold days because more heat is available in the outdoors air. The effectiveness of a heat pump on an annual basis is measured by its seasonal performance factor (SPF). The higher the SPF, the more efficient (and therefore cost effective) a unit is. 8.2 Performance Characteristics The heat pump is effective down to certain temperatures (varies by manufacturer), generally around 20-45°F. Below this temperature, alternate heat must be provided. Some units have electric resistance elements in the air make-up plenum of the heat pump that are staged to activate incrementally as needed. 8.3 Reliability Heat pumps in Kotzebue would require that 100% back-up heat be available. The unit will not operate without a source of electric power. Thermodynamic Efficiency - Varies with manufacturer and outdoor temperature. 8.4 Costs There are no heat pump installations in Kotzebue that can be used as a basis for comparison. Air-to-air heat pumps in the Juneau area currently average about $7,000 per installation; the figure is expected to be higher in the Kotzebue area. Maintenance costs are usually minimal for a heat pump, except in a cold climate where water (instead of air) is used as the heat source. Operating costs in an area with high electrical rates can be substantial, likely erasing any potential benefits. 8.5 Special Requirements and Impacts There are no special siting requirements or environmental impacts associated with the installation of heat pumps. Installation requires fairly simple mechanical skills. However, some training on the specifics of heat pumps would be required of technicians before any wide-scale implementation of the technology could take place. 8.6 Summary and Critical Discussion No cost per KWH (or MBTU) is available at this writing; it is likely that an actual installation would have to be monitored before such costs could be determined. It would appear, however, that the use of heat pumps in areas with prolonged cold temperatures during the heating season makes the conversion efficiency of these units questionable. Using electric resistance back-up heating for any length of time in the Kotzebue area will result in extremely high annual heating bills. In summary, the high cost of installation versus the energy savings makes it obvious that the money could be better spent elsewhere. 8.7 Bibliography U.S. Department of Energy, Heat Pumps Fact Sheet. Technical Information Center, May 1979. U.S. Alaska Power Administration et.al., Juneau Heat Pump Demonstration Progress Report, May 1980. D-56 9 COAL FIRED LOW PRESSURE DISTRICT HEAT The use of coal to fire a low pressure boiler to produce steam or hot water for district heating has been accomplished for many years. 9.1 General Description This technology relies on coal for energy to reheat’ the circulating heating fluid of a central district heating system. Coal would be used as fuel in low pressure water heaters, which would heat the return flow of a heating fluid from temperatures around 95°F up to the supply temperature of about 210°F. The pressure in the water heaters would be low -- around 15 psi -- and no licensed boiler operators would be required to run them. The pressure in the heating fluid mains would be no greater than that required to circulate the fluid in the system. The fluid can be water, where no frost-danger exists. Otherwise a mixture of water and a suitable antifreeze compound would be required. This technology has been perfected in Scandinavia during the last 20 years and is also used in Greenland. 9.2 Performance Characteristics Energy input is adjusted by the maintenance of the correct supply temperature and the flow in the system. Energy output is adjusted by the individual consumers. 9.3 Reliability In the harsh climatic conditions of Kotzebue, each component should, where applicable, have 100% backup. The components would comprise: -- Outside stockpile for coal -- Inside heated buffer storage -- Coal handling equipment to transport coal from stockpile to buffer to heater -- Low-pressure water heaters -- Cyclones or filters and stacks -- Distribution system -- House installations 9.4 Thermodynamic efficiency -- Water heaters 80% -- Distribution system 85 - 90% -- House installations 100% -- Overall thermodynamic efficiency 68-72% 9.5 Costs Costs will depend heavily on conditions. The best indication we can give for a technology which is new in Alaska derives from feasibility level assessments for a North Slope village of 400 inhabitants. Capital costs for this system from storage and coal handling through house installations are on the order of $650 per 1000 Btuh peak load in 1982 dollars. Operational costs are on the order of $20 per million Btu. The above is based on an assessed coal price of approximately $100 per ton. Economies of scale in Kotzebue would apply to the Central Heating Plant, but not materially to the distribution system. 9.6 Special Requirements and Impacts On account of coal dust from coal handling, the Central Plant should be sited so as not to impact the residential and public areas of Kotzebue. On account of the reasonably stable soil conditions of Kotzebue, it should be feasible to place the pre-insulated distribution piping underground, although special mitigation measures may have to be undertaken in some areas to prevent permafrost degradation. Coal would have to be transported from a source, which has not as yet been determined. Construction employment for the central plant would not be different from that utilized on existing larger facilities. For example, welders would not have to meet standards for high pressure piping. The technology level of operating personnel would not have to be higher than for the diesel generating and heavy road machinery in use in Kotzebue today. Environmental residuals would have to meet emission and other requirements, which would seem to present no insurmountable qgiffticul'ty . 9.7 Summary Subject to coal being available at the right price, the coal-fire low pressure central district heating appears to be a likely candidate for providing the bulk of Kotzebue's space heating requirements. If such a system were introduced, it could be combined with waste heat utilization, refuse-firing and wind-powered direct heating for energy input into the distribution system, in order to save on coal consumption. The technology is tried and proven even in circumstances quite similar to those of Kotzebue. Special attention will, nevertheless, have to be paid to adequate backup in the system. The level of operation technology required is not higher than that already in use in Kotzebue, which may be a favorable factor for this technology. 9.8 Bibliography Arctic Slope Technical Services, Feasibility Study of District Heating System for Wainwright. Pepared by North Slope Borough, July 1980. Bruun & Sorensen, A Description of Combined Heat and Power Supply For the City of Herning, Denmark. August 1981. Flemming Hammer, Typescript of a talk on the subject of Central District Heating held at the Alternative Energy Conference in Anchorage, November 1981. 10 HYDROPOWER -- BUCKLAND SITE 10.1 General Description This technology relies on annual runoff (precipitation) with sufficient energy gradient and volume of water to drive turbines and generators. The electrical power is then transmitted over power line from the energy source to the use area. Numerous hydropower facilities exist north of the Arctic Circle, in Scandinavia for example, yet none exists in this country. General reasons for this are: (1) since annual precipitation is low (arctic desert), large storage capacities (reservoirs) are needed to ensure year round operations; (2) often hydropower facilities without large storage reservoirs can only operate in periods of high runoff in summer and fall, i.e. run-of-river projects; (3) stream flows in most arctic streams and rivers either disappear or are greatly diminished during the winter months; (4) problems associated with finding adequate foundation conditions in the permafrost areas; (5) high construction costs associated with remote site construction and limited periods for certain work efforts, i.e. summer field season; (6) low need to date for large energy source; etc. 10.2 Performance Characteristics Energy output is controlled by the amount of water allowed to enter the turbines. The water flow is adjusted to meet power demands. With the exception of cold weather problems, i.e. ice formation, low flows into the reservoir, etc., few problems are expected in water management during the winter period. High inflows during the summer period may require spillage of water over spillway or through other gated structures to control the integrity of the storage area. Hydropower in the northern areas is a proven system whose performance characteristics are well known and_ understood ‘worldwide. 10.3 Reliability Because of the long transmission line from Buckland to Kotzebue and because of the unknown hydrological inflows, a 100% backup power system should be provided. Most likely, this would consist of a continuation and expansion of diesel electric generators. 10.4 Costs Hydropower is capital intensive for plant construction. There are no fuel costs, and operation and maintenance costs are less than with most other reliable energy systems. Additional evaluation of the costs associated with the Buckland hydropower site has been done in Section 8. Currently cost for hydropower in Alaska is running from $4,000 to $12,000 per KW of installed capacity (.18 to .40 $/kWh). Hydropower should be as, if not more, competitive as other energy forms if properly sited, designed, constructed and operated. 10.5 Special Requirements & Impacts As noted above in section 10.1: General Description, hydropower in the arctic, while practicable, involves’ significant and distinct concerns. This is especially true for the Buckland site which is remote from Kotzebue; which has a proposed relatively large shallow reservoir; which requires a long transmission line to bring the power from Buckland to Kotzeube; which, while it can and should be remotely controlled from Kotzebue, will still require operators and maintenance personnel at the project site; which does not have ground access (except in winter via snow/ice roads); which has not had an environmental assessment made; and whose possibility for expansion appears non-existent. 10.6 Summary While hydropower is a proven technology, even in the arctic, many unanswered questions exist about the Buckland site. Foremost in this evaluation are: (1) reliability and cost estimates; (2) is the site adequate from a geotechnical standpoint; (3) how reliable are the hydrological assumptions; (4) what problems can be expected with a large shallow reservoir; (5) what problems will be experienced because of limited access to the site and transmission route; (6) concern for type of transmission line. While hydropower is usually considered as the source for light and appliances, it provides almost a foolproof system for heating. Electric resistance heaters are reliable and relatively maintenance free (especially in the arctic where, for example, frozen pipes associated with hot water systems are always a concern). 10.7 References Retherford, R.W., Assessment of Power Generation for Kotzebue. June 1980. U.S. Army Corps”) of Engineers, Regional Inventory and Reconnaissance Study for Small Hydropower Projects in Northwest Alaska. May 1981. D-63 11 WIND TURBINE ELECTRIC GENERATORS 11.1 General Description There are three basic types of wind turbines which generate electricity that have applicability in Kotzebue. They are distinguished by the type of generator they employ and its characteristics. They all have in common a set of blades to capture the wind, called a _ rotor. The size of the rotor determines the amount of energy the machine is capable of producing. The rotor is connected by shaft to a speed increase, then to the generator. The induction generator type turbines are the most common found, especially in the 17-meter and smaller windgenerators. These are strictly utility intertie machines and produce good quality 60 cycle power. Because of their requirement for "reactive power" there is a theoretical limit to the level of penetration this type of turbine can have into a grid. A synchronous generator is usually found only in the 25-meter and larger units. This type provides utility grade power generating its own signal with no “reactive power" requirements. Synchronous generators can operate in a stand alone capacity and possess complex controls to maintain a 60 cycle output. The direct current generator which commonly is a_ rectified alternator feeds its power into a synchronous inverter which matches the utility grid signal. The configuration is found on only a few smaller turbines, and while compatible with 60 cycle AC power, there is, again, a limit to its penetration into a grid because of power quality problems. Other uses for the DC generated power are battery charging and resistive heating. Batteries are not presently considered cost-effective and resistive heating is very site specific, though practical in certain applications. 11.2 Performance Characteristics Most conventional wind turbine generators today start producing useful power in 9 mph (4 m/s) winds. The power output increases exponentially until the maximum or rated output of the turbine is reached. The power from the windgenerator is dependent on the winds and as such is only as reliable and constant as the winds are. The winds in Kotzebue are fairly persistent, and according to Mr. Jim Wise at the Arctic Environmental Information and Data Center (AEIDC), Kotzebue is in a wind power class of 6 (7.0 m/s annual mean wind speed). This corresponds to a wind power density of 400 watts/m?, The following table represents the annual energy output of representative commercially available windgenerators: rotor rated rated annual energy diameter power (kw) wind speed output in wind power (m/s) class 6 (102 kwh) 4 1.8 10.7 Ted 7 10.0 Lee) 40.0 10 25610 11216) 65.0 7 65.0 1216) 248.0 25 200.0 13.4 672.0 91 2500.0 16.1 9006.0 NOTE: Typical wind turbines are shown at the end of this section as Figures D.3 through D.11. 11.3 Reliability The reliability of windgenerators in the Kotzebue environment has been demonstrated with two systems tied into the grid. The demonstrations showed that while technical problems will be encountered, with a commitment to the project the "bugs" can be worked out and useful power generated. Until more demonstrations show different, 100% backup should be provided by the utility in event of turbine failure. Thermodynamic Efficiency - The conversion efficiency of available power in the wind (59% of the total energy in the wind) to useful power on the ground is variable, from a high of around 30% to a low of 5%, depending on the rotor design and power train efficiency. Most machines fall in the 15% - 25% conversion efficiency range according to DOE studies at Rocky Flats test center. 11.4 Cost The installed cost of wind turbines is very dependent on site specific parameters. For the turbines cited on pages D -.. through D -.. the following costs are given as best guesses: turbine diameter installed system installed system cost (lower ag) (1) cost (Kotzebue) (2) 4m $9,330 $14,000 7m 21,320 32,000 10 m 24,400 37,000 17 m 133,000 190,000 25 m 432,000 610,000 91m 6,000,000 8,200,000 (1) From: SERI/JBF Scientific, Inc. in Wind Energy Report, October 1981. (2) Using: Alaskan Construction Cost Index from HMS Inc., Anchorage, AK, March 1981. The operation and maintenance costs are difficult to define without more Alaskan experience on the larger turbines. Generally, 1% to 5% of installed cost per year is used; yet this may be low when logistics are factored in. The useful life is assumed by the Alaska Power Authority to be 15 years, yet DOE and most manufacturers use a 30-year life. Considering the Kotzebue environment and the developmental nature of the technology at present, the 15 year figure is perhaps more reasonable. Economics of scale in multiple installations, size of turbines, and number »f machines manufactured do exist, and were not taken into account in the costs given. The biggest reduction will occur with the larger utility scale machines as more are installed and built. 11.5 Special Requirements and Impacts Proper siting of a windgenerator in a location free from turbulence caused by nearby obstructions is essential. Siting can mitigate safety problems if properly fenced-off and installed by National Electric and Safety Code Requirements. Construction personnel need to be trained in tower work safety procedures and licensed electricians familiar with wind systems should be used. Other skills required would include heavy equipment operators and laborers. Operations personnel would need speciai training which locals should be able to assimilate. Radiomagnetic interference and aesthetics are two possible environmental impacts; proper planning can mitigate both. No other impacts of any significance are expected to occur. 11.6 Summary and Critical Discussion Windgenerators have a tremendous potential in Kotzebue to save significant amounts of fuel. With proper planning a wind program could provide low cost power and work with any base load facility. Used in conjunction with load management and resistive heat dumps, a significant portion of the grid could be supplied by wind generated electricity (30-70% penetration is possible). The larger turbines have not yet been proven reliable in the arctic environment, and demonstration projects would be required to gain more operating experience in Alaska. It is expected to be well within the study period that the larger turbines would come on line (the 25-meter turbine should be tested enough by 1987 to be considered ready for Kotzebue). 11.7 Bibliography Curtice, D., and Patton J. Operation of Small Wind Turbines on a Utility Distribution System. Wind Publishing Corporation, August 1981. Electric Power Research Institute. Proceedings of the Workshop on Economic and Operation Requirements and Status of Large Scale Wind Systems. Monterey, California, March 28-30, 1979. Electric Power Research Institute. Requirements Assessment of Wind Power Plants in Electric Utility Systems, Volume Two. Palo Alto, California, January 1979. Newell, M. A. ed. Bristol Bay Regional Power Plan-Wind Energy Analysis. Wind Systems Engineering, Anchorage, AK, February 1982, Park, G.L., et.al. Planning Manual for the Utility Application of Wind Energy Conversion Systems, Michigan State University, Division of Engineering Research. East Lansing, Michigan, June 1979. Reckard, M. and Newell, M. Alaskan Wind Energy Handbook. State of Alaska, Department of Transportation and Public Facilities, Fairbanks, AK, July 1981. U.S. Department of Energy, Bonneville Power Administration. Environmental Report-Goodnoe Hills Wind Turbine Generation. December 1979. U.S. Department of Energy. Environmental Assessment-Eighteen Prospective MOD-2 Wind Turbine Sites-The Goodnoe Hills Washington Installation Site. Klickitat County, Washington, December 1979. U.S. Department of Energy. Environmental Assessment - Installation and Field Testing of a Large Experimental Wind Turbine Generator System Near Kahuku Point on the Island of Oahu, Hawaii. December 1979. U.S. Department of Energy. First Semiannual Report: Rocky Flats Small Wind Systems Test Center Activities. RFP#2920/3533/78/6-1. N.T.1I.S., Springfield, VA, 1978. "WECS Potential Large at Federal Sites". Wind Energy Report. New York. October 1981. Wise, J.L., et.al. Wind Energy Resource Atlas: Volume 10 - Alaska. Pacific Northwest Laboratories. Richland, WA. December 1980. FIGURE D.3 4 METER TURBINE [ GENERATOR TYPE & INTERFACE MODE This unit uses a 115 VAC brushless induction gener- ator for direct utility intertie. CONTROLS The unit requires a utility derived reference to: 1. Operate. es Develop a 60 hz output. A tower mounted anemometer is used to monitor wind velocity and control the operating modes. Cut-in is 4 at 10 mph, cut-out at 40 Rie mph. / PRK GAN) ry Aina OPERATION/SAFETY The unit will not operate unless a utility reference is present. If utility power is lost, the unit disconnects from the utility line and an electro- hydraulic brake is applied, stopping the rotor. POWER OUT (watts) | Emergency stop due to a power train failure is performed by the automatic 40 deployment of spring loaded WIND speepim 7 centrifugally actuated rotor 7 tip-flaps. FIGURE D.4 6 METER TURBINE GENERATOR TYPE & INTERFACE MODE A 230 VAC, 60 hz induction motor/generator is used to provide a direct utility intertie. CONTROLS The unit requires a utility derived reference to: 1. Operate. 2. Develop a 60 hz output. A tower-mounted anemometer is used to monitor wind velocity and control the operating modes (cut-in at 8.5, cut-out at 45 mph. OPERATION/SAFETY The unit will not operate: Ls Unless the utility reference is present or, 2. When windspeed is less than 8.5 mph or greater than 45 mph. If utility power is lost, the unit disconnects from the grid and an electro- hydraulic brake is engaged. Emergency stop due to over speed (or brake engagement) is performed by the auto- matic deployment of rotor tip brakes (aerodynamic). The deployment of the tip brakes is also enabled by a power-train failure. MSG wa: —— ae te op. Wy ail POWER OUTPUT (kW) Oo 10 20 30 40 50 WIND SPEED (mph) FIGURE D.5 7 METER TURBINE GENERATOR TYPE & INTERFACE MODE Power is developed by a 3- phase alternator whose output is rectified and processed by a synchronous inverter. The output is in the form of "pulses" of energy timed to occur within the sine wave envelope. A "leading" power factor is claimed for the synchronous unit. CONTROLS The centrifugally operated governor at the propeller hub maintains srpm_ rates under normal conditions. The alternator output is controlled through its field windings whose excitation is monitored and adjusted by the synchronous inverter circuitry. High winds are overcome through the use of an offset tail-vane that turns’ the rotor out of the wind. OPERATION/SAFETY The synchronous inverter will disengage itself from the utility should: L. The windgenerator's output drop below preset limits or, 2. The utility line fails. a 3 = 2 E 2 36 c Ww = ° a The unit also has a manually engaged friction brake for WIND SPEED (mph) routine service or emergency shutdown. FIGURE D.6 10 METER TURBINE GENERATOR TYPE & INTERFACE MODE This unit utilizes an induction motor/generator to provide 440/220VAC 1-3 phase power directly to the utility. CONTROLS Rotor rpm is maintained by the aerodynamic/mechanical properties of the rotor design. The blades auto- matically stall in high winds to prevent overloading of the generator. OPERATION/SAFETY The unit has withstood winds in excess of 85 mph and specifications claim that it will operate at windspeeds of 100 mph. A unique tower design allows the entire unit to be "tilted" providing ground level maintenance on the windgenerator. POWER OUTPUT (kW) l iy) We <<a 8 Nn °o os ° 5 10 15 20 WIND SPEED (mph) 25 30 35 FIGURE D.7 24.4 METER TURBINE GENERATOR TYPE & INTERFACE MODE This model uses an induction generator of 55 KW capacity delivering 3-phase power at 480 VAC/60 hz. The interface is direct utility intertie. CONTROLS An anemometer monitoring average windspeed determines the cut-in and cut-out conditions. OPERATION/ SAFETY The system is operated hydraulically and reguires utility power to begin operation. A centrifugally operated switch on the rotor shaft will cause a loss of hydraulic pressure, shutting down the system and applying the brake. POWER OUTPUT (kW) 15 20 25 FIGURE D.8 24.5 METER TURBINE GENERATOR TYPE & INTERFACE MODE This unit has a 200 KW (continuous rated) syn- chronous generator providing power at 240/480 VAC 60 hz. The system is designed to operate either as a utility intertie or as a stand alone source of utility grade power. CONTROLS The unit utilizes a micro- processor based system for control and also provides data collection and acqui- sition as well as_ remote control and status display functions. OPERATION/SAFETY The microprocessor will allow the windgenerator to come up to synchronous speed and compares its output with the utility reference. When they are within 1% the main contactor is enabled. The relationship between wind- generator output and utility power is continuously monitored and synchro- nization is maintained by adjusting the TOtor tip flaps and/or phasing in auxiliary "dummy" loads. POWER OUTPUT (kW) 300 250 200 150 100 D=75. 15 20 26 WIND SPEED (mph) FIGURE D.9 28 METER TURBINE +— GENERATOR TYPE & INTERFACE MODE This unit has two = asyn- chronous generators rated at 265 and 58 KW that produce power at 480 VAC, 50/60 hz. The unit is designed for direct utility intertie. CONTROLS N/A OPERATION/ SAFETY The blade pitch is used to maintain synchronous’ speed as well as for emergency overspeed shutdown. The smaller capacity generator operates at low wind speeds while the larger unit comes on-line during periods of higher winds. POWER OUTPUT (kW) WIND SPEED (mph) FIGURE D.10 38 METER TURBINE GENERATOR TYPE & INTERFACE MODE This unit uses either induction or synchronous generators rated at 560 and 625 KVA_ respectively. The output is at a voltage of 4160 VAC, 3-phase 60 hz. This unit is designed for direct utility interface. CONTROLS System operation in controlled via a microprocessor that constantly monitors all operating parameters and maintains rotor rpm, syn- chronization, yaw, safety shut-down, and also allows remote control and remote system status reporting. OPERATION SAFETY Normal operation is initialized when wind speed reaches 14.3 mph. The unit is "motored" to synchronous speed and when synchronization is established the unit is place "on-line". Normal shut-down includes reducing the unit's power output to nearly zero; followed by the feathering of the rotor as brakes are applied. Emergency shutdown circuitry separate from the main con- troller disables the unit immediately upon receipt of an o 10 20 30 40 650 60 abnormal condition; Lelesy WIND SPEED (mph) overspeed, or microprocessor failure. s = « wi = 9° a FIGURE D.11 94.7 METER TURBINE GENERATOR TYPE & INTERFACE MODES This unit utilizes a 2.5 megawatt synchronous’ type generator producing power at 12.5 KV, 60 hz. CONTROLS A microprocessor maintains operation of the unit. Remote status, alarm, and control functions are also utilized. OPERATION/SAFETY The unit will produce power at windspeeds between 14 and 45 mph. The microprocessor will immediately shut down the unit should the windgenerator suffer damage or begin to malfunction. — wits e is Ld b POWER OUTPUT (megawatts) wi ® Oo 8 16 24 32 40 48 12 GEOTHERMAL TECHNOLOGY 12.1 General Description Geothermal energy is stored heat energy generated in the earth's interior and available to man from heated rocks or water within the upper 3100 ft. of the earth's crust. The heat escapes very slowly from the earth's core to the crust by conductive flow through solid rocks, by convective flow in circulating fluids, and by mass transfer of magma (molten rock generated from within the earth, termed lava when expelled at the earth's surface). Thermal gradient describes the rate at which temperature increases with depth below the earth's surface and is expressed as degrees per unit of depth. Normally, the earth's heat is diffuse, the thermal gradient averaging about 25C/km. In many areas, though, geologic conditions have created local thermal gradients much higher than the average; these areas usually are associated with young volcanism, thin crust, or tectonic plate boundaries. The thermal reservoirs contain enough concentrated heat to make up a potential energy source. 1262 Performance Characteristics Geothermal resources are classified according to the mode of heat transfer and the temperature and pressure of the geothermal system. A. Vapor-Dominated Systems In vapor-dominated systems, the geothermal steam can be used directly in a turbine generator. The technology for this type of system is well-known, largely because there are not as many technical dfficulties as there are for liquid-dominated systems. Most of the experience gained in the United States has been at The Geysers in California, the largest geothermal installation in the world. It is a Know Geothermal Resource Area (KGRA) consisting of 163,428 acres, of which 11,450 acres are federally owned. Total generating capacity is now 500 MWe. About 2 million pounds of steam per hour are needed for every 100 MWe generated at the Geysers, an amount supplied by about 14 wells delivering steam to the turbine generators. B. Liquid-Dominated Systems Liquid-dominated systems can be developed as energy sources for electrical power generation if fluid temperatures and pressures are adequate. Nonelectric applications, such as space heating and process heating, vary widely and occur’ throughout’ the world. Liquid-dominated reservoirs often contain minerals that can be extracted to provide raw materials and/or fresh water for agricultural use. The end use of energy from liquid-dominated geothermal systems depends largely on temperature. The temperature ranges, divided arbitrarily, are: about 300° F for generation of electricity (binary systems may allow use of somewhat lower temperatures for generating electricity), 195 to 300° F for space and process heating, and below 195° F for local use where better energy sources do not exist. Multipurpose applications occur where process heating, space heating, and electric power production have been integrated in the same overall system. C. Flash-Steam Systems When high-pressure hot water is brought to the earth's surface, the pressure reduction can cause 13 to 25 percent of the hot water to flash into steam. (Simple flash systems are probably useful only for reservoir temperatures exceeding 390 to 500°F.) The water-steam mixture that flows to the wellhead is separated and the steam is piped to the steam turbines of a power plant. Additional steam can be produced from flashing again at a lower pressure, and the steam then can be introduced to a low pressure section of the power turbine to increase total power output. The residual hot water can be reinjected into the reservoir, desalted, or used for process heating. The first electric power generator in the world using geothermal energy was from a vapor-dominated system. It began operating in 1904 in Larderello, Italy, and commercial production began in 1912. The present electrical power capacity of the area is 38 MWe. Commercial flashed-steam systems began operating in New Zealand in 1958. About 180 MWe are being generated in the Wairakei- Broadlands field where the fluid temperatures are about 500°F and around 20 percent is flashed to steam for power production. A plant to produce 150 MW also is being built at Broadlands. Two 37.5 MWe turbogenerators are operating in a geothermal field in Mexico near the volcano of Cerro Prieto. Fluid temperatures are 570°F or more, and salinities are 15,000 to 25,000 ppm. This facility is in the same geothermal resources area as the Imperial Valley of California (Salton Trough) and is important’ for providing data on operating with highly corrosive geothermal brine. An ultimate capacity of 400 MWe is expected there. Japan has numerous active geothermal regions. Five of these are producing electricity using flash-steam systems: Otake (13 MW), Matsukawa (22 MW), Onuma (10 MW), Onikobe (25 MW), and Hatchoboru (50 MW). Japan's "Sunshine Project" is an aggressive program of geothermal investigation, which has a goal of 1,000 MW geothermal generating capacity by 1982 and 2,000 MW by 1985. A 60 MW power plant has been in operation since 1976 in the Ahuachapan field in El Salvador; the plant will soon be increased to 80 MW capacity through the development of a secondary flash system. A 6 MW power station utilizing a steam-hot water mixture was completed in 1967 in the Pauzhetka River Valley on the Kamchatka peninsula of the USSR. In Chile, a multipurpose, wet- steam geothermal facility is being developed. Electricity will be produced, minerals extracted from brine, and fresh water produced by desalting the hot water. In the United State, a 5 MW plant is planned as part of the Hawaii Geothermal Project (HGP) in the Puna district. D. Secondary Fluid Systems When the steam from a hot water reservoir is too corrosive to use directly in a turbine, the steam can be used to boil water in a heat exchanger. The clean steam can then be used in the turbine. Compared with flashed-steam systems, such systems cost more (because of the cost of heat exchangers) and are less efficient. Another type of secondary fluid system uses a binary cycle. In this system, the hot water from the geothermal well is prevented from flashing to steam by maintaining pressure, then pumping the water to a heat exchanger where it heats a liquid, boils it, and superheats it. The vapor from the secondary fluid (usually a low- boiling-point liquid such as one of the freons or isobutane) drives the power turbine. The working fluid is then cooled, condensed, and recycled. Binary-cycle systems have an estimated efficiency of 10 percent or more and may be more efficient thermodynamically than flash systems for geothermal reservoirs with temperatures ranging from 300°F to 400°F. Because it is a closed-loop system, the possibility of releasing noncondensable gases or brine chemicals is reduced greatly. A disadvantage is that the binary system requires an additional external water supply or a dry cooling tower. The first geothermal power plant using a binary-cycle system was the Paratunka Station (0.68 MWe) on the east coast of Kamchatka, USSR, which operates on Freon. The reservoir temperature there is 180° F and the salinity of the fluids is low. D-82 In Niland, California, a geothermal loop experimental facility has been operated since May 1976 by San Diego Gas and Electric Company with government support. Although the turbine and generator are not present, the facility is sized to generate 10 MWe using a flash/binary cycle. By April 1977, the facility had operated successfully for 2,600 hours using high-temperature, high-salinity brine. Long-term tests will provide the engineering data needed to design commercial plants. Magma Power Company, San Diego Gas and Electric Company, and Standard Oil Company are working jointly to design, install, and operate an 11,200 kW (net- dual-cycle binary plant at East Mesa, California. E. Total-Flow Systems In a total-flow system, a two-phase working fluid, hot water and steam, is expanded through a nozzle into a turbine, making use of mechanical as well as heat energy. Theoretically, it could produce significantly more power than other systems given the same reservoir temperature. Although this is not a new concept for converting geothermal energy to electric power, there have been no practical applications studied until recently. The Lawrence Livermore Laboratory is developing the total-flow concept. In 1977, it reported a new two-phase expander had been developed successfully. Generally, the program focuses on the development of systems for the recovery and conversion of energy stored in hot water deposits containing more than 3 percent total dissolved solids. These high-salinity brines pose formidable problems because of precipitation, scaling, corrosion, erosion, and brine handling and disposal. The goal of the program is a full 10 MWe experimental power plant system. Recently, Biphase Energy Systems successfully operated a two- phase rotary separator for 117 hours in a_ high-salinity environment. They concluded that, when applied to a two-stage flash system, the design would show a 20 percent increase in power output with a 12 percent specific cost reduction. F. Extraction from Magma Technologies for extracting energy from magma. are at_ the preliminary stage of development. Techniques being studied include: o Insertion of a heat exchanger into a magma source with surface conversion to electric power. o Use of the reducing nature of magma to produce transportable fuels such as hydrogen and methane. Most hot dry rock deposits are more than 10 miles deep. Some shallow deposits exist, however, and are being studied at Coso Hot Springs, California and on the Lemez Plateau of New Mexico near Los Alamos. Since 1972, the Los Alamos’ Scientific Laboratory of the University of California, under the auspices of DOE, has been developing methods to extract energy from hot dry, impermeable rock, such as the granite of the western and northern United States. In the Los Alamos concept, a man-made geothermal reservoir would be formed by drilling into hot rock, then creating a large surface area for heat transfer within the rock by using large-scale hydraulic fracturing techniques developed by the oil industry. After a circulation loop is formed by drilling a second hole into the top of the fractured region, the heat contained in the reservoir would be brought to the surface by the buoyant circulation of water, with no need for pumping. The water in the loop would remain liquid due to pressurization at the surface, thereby increasing the rate of heat transport up the withdrawal hole compared with the rate possible with steam. D-84 Preliminary experiments and analyses indicate that thermal stresses created by cooling the hot rock in such a man-made reservoir may gradually enlarge the fracture system so that its useful lifetime will be extended far beyond the planned 10 to 15 years provided by the original reservoir. If these thermal-stress cracks grow preferentially downward and outward into hotter rock, as seems probable, the quality of the geothermal source may actually improve as energy is withdrawn. The Los Alamos concept is being demonstrated in an area about 20 miles west of Los Alamos, New Mexico. The well reached a depth of 1000 ft. The bottom hole temperature was 390° F. A near vertical, 400 ft. radius fracture was created with hydraulic pressure near the bottom of the hole. A second hole intersected the fracture at a depth of a little over 1000 ft. with a bottom hole temperature of 400°F. Cold water was circulated through the fractures at 1,000 psi to be heated, then flowing from the second hole at 260°F. Installation of a 10 MWe heat exchanger in the closed-loop pressured water system was done. 1253) Summary and Critical Discussion The use of geothermal energy as an energy source to supply either heat and/or electricity to the city of Kotzebue is under study. The equipment that would be required to utilize this resource in the city of Kotzebue depends on the nature and availability of the resource and its physical and chemical characteristics. An overall cost analysis is provided in Section 8 to determine if this resource, if extensive enough, could be used to provide district heating. 12.4 Bibliography U.S. General Accounting Office. Problems in Identifying, Developing, and Using Geothermal Resources. 6 March 1975. White D.E. Characteristics of Geothermal Resources. Geothermal Energy (Stanford University Press, 1973). Swanson, C.R. San Diego Gas and Electric Company's Geothermal Program, In Geothermal Resources Council Annual Meeting Transaction, 25-27 July 1978, Vol. 2. Chappel, R.N., et.al. The Multi-Purpose Geothermal Test and Experimental Activities at Raft River, Idaho. In Geothermal Resources Council Annual Meeting Transaction, 25-27 July 1978, vol. 2. Addoms, J.F., Breindel, B., Gracey, C.M. Wellsite Verification Testing of an Advanced Geothermal Primary Heat Exchanger. In Geothermal Resources Council Annual Meeting Transaction, 25-27 July 1978, Vol. 2. Sperry to Develop Geothermal System. Energy Research Digest, 23 October 1978. Electric Power Research Institute. Geothermal Energy Prospects for the Next 50 Years. Preliminary Report to the World Energy Conference, ER-611-SR, February 1978. Austin, elses et.al. The Lawrence Livermore Laboratory Geothermal Energy Development Program Status Report, January 1975 through August 1975. UCID-16954, September 1975. Cerini, D.J. Geothermal Rotary Field Tests. In Geothermal Resources Council Annual Meeting Transaction, 25-27 July 1978, vol. 2. Los Alamos Scientific Laboratory. Los Alamos’ Scientific Laboratory Dry Geothermal Source Demonstration Projects, 1975. Los Alamos Scientific Laboratory. Los Alamos Dry Geothermal Source Demonstration Project -- Mini-Review 76-1. March 1976, Stoller, H.M., Colp, J.L. Magma as a Geothermal Resource -- A Summary. In Geothermal Resources Council Annual Meeting Transaction, 25-27 July 1978, Vol.2. 13 PEAT TECHNOLOGY 13.4 General Description A. Resource Characterization The United States has an estimated 52.6 million acres of peat lands containing approximately 120 billion tons of peat (35% by wt moisture). Approximately half of this quantity is in the State of Alaska. Within the contiguous United States, the deposits in Minnesota, Michigan, Florida, and Wisconsin are the largest. The proximate analysis and heating value of peat as compared to coals are presented below in Table D.11 TABLE D.11 Peat and Coal Comparisons Volatile Fixed Carbon Heat of Combustion Matter -M.A.F. Basis- -M.A.F. Basis- Resource (Wt. Percent) (Wt. Percent) (Btu/1b.) Peat 71 29 9,200 Lignite 44 56 12,200 Subbituminous 40 60 13,300 Bituminous 35 65 15,000 Anthracite 3 97 15,100 Peats are classified into three general categories according to the degree of decomposition: fabric, hemic, and sapric. Of the three types, hemic peats are the most widely distributed and are best suited for energy use. The peat resource in Kotzebue is only a thin layer of organic soil which overlies the permafrost. Removal of the overburden and the organic layer can cause severe degradation; however, the thin layer of organic material may be sufficient to be used for space heating in a family home. B. Peat Extraction Due to the water-saturated environment associated with peat resources, peatlands must undergo various levels of preparation prior to any harvesting activities. The first steps in preparing a peat bog for harvesting (by European methods) are to dredge, clear surface vegetation, and provide roads for access. A care- fully designed network of ditches and waterways through the bog collects much of the water and routes it away from the harvesting area. If surface streams are associated with the peat bog, these must also be rerouted. As the bog dries, it can be cleared of debris and leveled. This initial bog preparation activity can take up to several years to complete. However, once the bog is prepared, four different methods can be used for harvesting. These methods are: (1) manual; (2) sod peat; (3) milled peat; and (4) hydraulic harvesting. C. Peat Dewatering Peat's high affinity for water presents significant technical difficulties in removing the water by mechanical solid-liquid separation techniques. Even the best of filter press-type dewatering processes can only reduce the moisture content to 60- 70 percent by weight. Thermal drying alone, other than that resulting from in-field drying by milled or sod peat harvesting, would require more heat input per pound of raw peat than is available in the resulting moisture free fuel product. Unless this large heat requirement is met by solar heating or exhaust heat from a nearby industrial process, thermal drying of peat is not practical except when used downstream of other dewatering processes. As an alternative to conventional dewatering (and its limita- tions), there is a family of wet processing technologies that convert peat to more useful forms while it is contained in a water slurry. These processes utilize elevated temperatures and pressures to attack the colloidal bonds which bind the water to the peat solids. Structural changes occur, gaseous and liquid products and by-products are evolved, and the resultant slurry can be mechanically dewatered to a much greater extent than a raw peat slurry. Technologies considered as alternative wet technologies include: wet oxidation, wet carbonization, and solvent extraction. It is important to note than these wet technologies do not necessarily elminate the need for mechanical (and sometimes thermal) dewatering processes; rather, they alter the peat's chemical structure so as to make mechanical dewatering much more effective. The current goals for moisture reduction operations are dependent on the particular use for the peat fuel: for direct combustion of peat, 60 wt. percent moisture in the peat fuel feedstock repre- sents the approximate maximum percentage of water allowable; for the production of substitute natural gas (SNG), a peat fuel with less than 35 wt. percent moisture content is preferred. 13.2 Performance Characteristics A. Peat Combustion Peat has been used successfully as a feedstock for various types of furnaces. The choice of sod peat, milled peat, peat briquettes, or pellets depends upon the furnace, be it stoker, pulverized, or FBC. In Table D.12 peat combustion methods are roughly selected according to the design capacity and the type of peat fuel. TABLE D.12 Matching of Combustion Method with Peat Fuel Products Method Capacity Type of Peat! Pulverized Firing 30 - 200 MW milled peat Grate Firing 3 - 60 MW milled or sot peat Grate Firing - 3 MW peat briquettes or pellets Cyclone Firing 3 - 15 MW milled peat Fluidized Bed Firing 10 - 100 MW milled or sod peat Generally, sod peat and peat briquettes are produced for small grate-fired boilers, although they can be burned in different types of boilers constructed for solid fuels other than peat. In large plants, peat is pulverized and burned in suspension boilers. On the bottom of the furnace there is often an after- burning grate, and fuel oil is used to complete combustion of the peat fuel. Cyclone burners have proved to be one of the best combustion methods in medium-sized peat-fired plants because of their ability to handle variations in milled peat quality and moisture content. Fluidized bed combustors offer additional advantages due to extremely effective heat release and relatively low furnace temperatures. All of these combustion technologies are discussed in the following paragraphs. lpeat fuel produced by the previously discussed alternative wet technologies can be formed and burned like sod peat or briquettes. Other possibilities include grinding and blending in fuel oil and burning as a slurry. We Grate Firing Grate firing of peat occurs in stoker furnaces, where the fuel peat is introduced to the combustion zone on a grate allowing air to mix with the peat from below. Furnace grate designs are generally similar to those used with other solid fuels (coal). However, peat fuel requires slight modifications to the grate design. The modified grate design usually results in high fuel layer thicknesses, up to four feet on traveling grates and the need for steeper angles of inclination with inclined grates. The main concern is not only to reduce the fouling of boiler passes and particle emissions, but specifically to minimize the danger of a dust explosion in the furnace. The temperature of primary air and the overall thermal load must be kept low in order to avoid fusion which, among other inconveniences, also leads to extreme wear of moving grate parts. The high luminousity of the flame which is characteristic of combustion of peat, combined with the low fusion point of flyash, produces a high but rather narrow furnace column. Furnaces fired with pulverized peat often require an afterburning grate at the bottom of the furnace because of incomplete pulverization of larger wood particles in the fuel. Narrow traveling grates and stationary grates with dumping grate sections have been used. Grate firing of peat does not require a pretreatment of the fuel because all the necessary treatment for final combustion takes place on the grate. 2. Cyclone Firing Cyclone furnaces designed for milled peat firing have been developed over the last 10 years by Kymi Kymmene Metalli in Finland. Presently, most of the medium-sized district heating plants in Finland firing with milled peat are delivered by Kymi Kymmene. The cyclone furnace is a cylindrical chamber with the inside surface either coated with a refractory lining or made completely of firebrick. Milled peat and combustion air are _ blown tangentially into the cylinder, creating a swirling combustion flame. Cyclones are classified into two types, dry or molten ash, depending on whether the slag from peat melts in the cyclone or whether it remains dry. The oldest cyclones were dry ash fur- naces. The slag accumulating on the cyclone walls had to be removed by raising the combustion temperature beyond the slag melting point and draining the molten slag from the furnaces. Another problem with the dry cyclone furnace was the wide variation of moisture in peat. Peat with over 49 percent moisture did not burn satisfactorily because the temperature in the cyclone could not be raised sufficiently. Excessively dry peat, on the other hand, caused the temperature to exceed the ash-softening point, which resulted in slagging. These problems are avoided by using molten ash cyclones. Gas temperatures within the cyclone reach up to 3000° F, which is sufficient to melt the ash into a liquid slag. The centrifugal forces created by the swirling air and fuel maintain a thin layer of slag on the furnace walls, which in turn holds incoming peat particles as they become combustion products and molten ash, The heat release rate per cubic foot in a cyclone furnace is very high, but the small furnace area is partially insulated by the covering slag layer. The combination of high heat release and low heat absorption assures the high temperatures necessary for complete combustion and for maintaining the liquid slag layer on the furnace walls. Reaching and maintaining the necessary combustion temperature of 2250-2730° F is not consistently possible without pre-drying the peat. Flash drying with flue gases has proved to be the best solution, according to Kymi Kymmene. With flash-drying, the flue gases of a peat-fired boiler may be cooled nearly to the dewpoint because the sulphur content of the peat is low (0.2%). The efficiency of the boiler is at about the same level as that of an oil-fired boiler, i.e. 85-90 percent. 3. Pulverized Firing For pulverized peat firing, peat must be dried and equalized in one or more stages. Chunks of wood, always present in peat, must be screened out and eventually crushed. Flue gas or hot air is used to reduce the moisture content from the delivered 40 to 55 wt. percent down to the 20 to 25 wt. percent suitable for firing. When ordinary pulverizer equipment is used, the drying takes place in the pulverizer and the peat-gas suspension is blown to the burners. The pulverizers used are of the hammer types, either combined with a blower or equipped with a separate fan. One of the recent improvements has been the removal of the pulverizer. In this modified system, peat is dried in a flash dryer and blown to the burners with primary air. 4. Fluidized-Bed Combustion The fluidized-bed combustor (FBC) is a versatile unit and can well be used for peat. As with pulverized coal firing, FRC provides large fuel surface area and a long contact time between gas and solid particles. Complete combustion of the fuel can thus occur at temperatures below ash softening temperatures, and the "fluidized" nature of the bed eliminates hot spots that could initiate slag formation. There are two primary types of fluidized bed combustors; atmospheric and pressurized. The objective of the PFBC system is to utilize the energy of the hot, pressurized flue gas to drive a gas turbine for additional power generation and higher thermodynamic efficiency. AFBC systems, which are closer to commercial utilization, provide conventional steam turbine power only. B. Thermal Gasification Ths production of gas from peat has received much experimental attention since the mid 1800's, when sod peat was gasified under normal presure in Russia. After the Second World War about 2 million tons of sod peat a year was gasified in the USSR by a process resembling the Wellman-Galusha process. This process may be considered a commercial one, as it is offered by several manufacturers. No other peat gasification processes are considered commercial at this time. However, prior to the 1960's peat has been gasified in the laboratory or in pilot plants using both gasifier pro- cesses in commercial use with other feed stocks and experimental processes not yet considered commercial. The "commercial" gasi- fier processes studied include: Lurgi, Koppers-Totzek, Winkler, and the Soviet sod peat gasifier. The "non-commercial" group includes processes designed for peat gasification with research results obtained from experiments in the laboratory or on a pilot plant scale. Tests were made in Germany with Irish peat in pilot plants for the Lurgi, Koppers-Totzek, and Winkler processes. The Lurgi and Koppers-Totzek reactors performed successfully with peat feed- stocks, but difficulties were experienced in maintaining a fluidized bed in the Winkler reactor. Successful fluidized bed peat gasificiation has been reported from English and Russian experiments. Tests in England were conducted to produce water- gas using indirect heat by fluidizing with steam at temperatures up to 1650° F and fluidization velocities of 1 to 2 feet per second. The Institute of Gas Technology (IGT) has been conducting a peat gasificiation program since 1976. Supported by funding from DOE and the Minnesota Gas Company, IGT has proposed a hydrogasifi- cation system consisting of a three-zone reactor vessel. In this reactor, termed a PEATGAS reactor by IGT, peat would be slurried (with toluene or water) and fed into the fluidized bed slurry dryer, to be heated by the product gases coming up from the hydrogasifier. The heated peat would be picked up by synthesis gas generated in the fluidized bed char gasifier and entrained into a vertical cocurrent dilute-phase hydrogasifier with a residence time of a few seconds. Char produced in the hydrogasifier would be gasified with input steam and oxygen in the lower fluidized bed char gasifier section. A simplified PEATGAS process would yield the following products: 10,500 Cu. Ft. SNG at 950 Btu/scf One Ton = 33.2 gallons residual oil 3.9 lbs. sulfur 37.2 lbs. ammonia 13.3 Bibliography Proceedings of Second International Peat Congress, 1963. Kopstein, M. Peat Prospectus. U.S. DOE, Division of Fossil Fuel Processing, July 1979. U.S. Department of Agriculture, Soil Conservation Service. Conservation Needs Inventory. 1967. Fraser, J.S. Assessment of Peat Mining Methods Considered for Proposed Canadian Fuel Peat Operations. Presented at the Management Assessment of Peat as an Energy Resource Conference, Arlington, Virginina, July 22-24, 1979. Johnson, B.V., et al. An Environmentally Sound Peat Harvesting Technique. Presented at the Management Assessment of Peat As an Energy Resource Conference, Arlington, Virginia, July 22-24, 1979. Virginia Polytechnic Institute. Analyzing Excavation and Materials Handling Equipment. Research Division Bulletin 53, February 1970. Cancross, C.A. Transport of Peat Moss Slurry in a Pipeline. Presented at the Management Assessment of Peat As An Energy Resource Conference, Arlington, Virginia, July 22-24, 1979. Minnesota Department of Natural Resources. A Report on European Peat Technology. Reprinted August 1978. Campbell, R.N., Jr. First Colony Farms, Inc., Experimental Peat Harvesting Program. Presented at the Management Assessment of Peat As An Energy Resource Conference, Arlington, Virginia, July 22-24, 1979. Brooks, K.N., Predmore,' S.R. Hydrologic Factors of Peat Harvesting, Phase II -- Peat Program. College of Forestry, University of Minnesota, and the Minnesota Department of Natural Resources, May 1978. Minnesota Department of Natural Resources. Potential of Peat as a Power Plant Fuel. November 1977. Martin, J. Briquetting of Peat Fuel. In Proceedings of the Institute for Briquetting and Agglomeration, Vol. 14, 1975. Otava, K.J., ed. Minnesota Peat Mission to Europe. Office of Tron Range Resources and Rehabilitation, St. Paul, Minnesota, August 1958. Myreen, B. The Peat Fuel Process, Ra-Shipping Ltd. Oy, SF-21600, Pargas, Finland, undated (ca. 1979). Pier, Me, Kroenig, W. Pressue Hydrogentation of Solid Carbonaceous Material. German (FRG) patent 725,603, filed July BMS Tie Glinka, K. Treatment of Fuels of High Moisture Content, German (FRG) patent 1,048,378,filed January 8, 1959. Bull, W., Stevenson, L. Kloepper, D.L., Rogers, T.F. Salvation Process for Carbonaceous Fuels, U.S. patent 3,341,447, September 12, 1967. Cavalier, J.C., Chornet, E. Conversion of Peat with Carbon Monoxide and Water. Fuel, Vol. 56, No. 1, January 1977. Leppa, K. Direct Combustion of Peat for Electric Power Generation. Presented at the Management Assessment of Peat As An Energy Resource Conference, Arlington, Virginia, July 22-24, 1979. Asplund, D. Peat As a Source of Energy in Finland. Technical Research Center of Finland, Fuel and Lubricant Research Laboratory, undated (ca. 1978). Alander, O. Combustion of Milled Peat in a Cyclone Furnace. Kymi Kymmene Metalli Heinola, Finland, undated (ca. 1978). Laukkanen, T., MHanni, J. Peat Coking and Fluidized Bed Combustion of Peat. Outokumpu Oy, Finland, undated (ca. 1978). Puwani, D.V. Synthetic Fuels from Peat. Presented at the Management Assessment of Peat As An Energy Resource Conference, Arlington, Virginia, July 22-24, 1979. Leppamaki, E., Asplund, D., Ekman, E. Gasification of Peat -- a Literature Review. (Technical Research Center of Finland), paper presented at the Management Assessment of Peat As An Energy Resource, Arlington, Virginia, July 22-24, 1979. Kelly, J.J. Peat Gasification. A paper presented at the International Peat Symposium, Dublin, July 1954. MacDougall, D. Production of Water-Gas from Milled Peat in a Fluidized Bed. A paper presented at the International Peat Symposium, Dublin, July 1975. Sundgren, A., Ekman, E., Komonen, P. Manufacturer of Water-Gas from Milled and Powdered Peat. A paper presented at the International Peat Congress, Leningrad, 1963. Punwani, D.V. Status of the PEATGAS Process. Presented at the 10th Synthetic Pipeline Gas Symposium, Chicago, Illinois, October 30 - November 1, 1978. Punwani, D.V., Arora, J.L., Tsaros, C.L. SNG from Peat by the PEATGAS Process. (IGT), Paper first presented at Fifth Annual International Conference on Coal Gasification, Liquefaction and Conversion to Electricity, Pittsburgh, Pennsylvania, August 1-3, 1978; then presented at Management Assessment of Peat As An Energy Resource, Arlington, Virginia, July 22-24, 1979. Punwani, D.V., Rader, A.M. Gas from Peat -- A Good Source of Heat. Presented at Management Assessment of Peat As An Energy Resource Conference, Arlington, Virginia, July 22-24, 1979. 14 SOLID FUEL STOVES AND FURNACES Solid fuel may be coal, peat or wood. For the purpose of this report and as per tradition it will be referred to as coal and/or wood, although peat could be used as well. Individual coal and wood fired units for space heating have long been in existence, and have enjoyed increased popularity as fuel prices continue to rise. This technical profile examines the range of available units. 14.1 General Description There is a myriad of coal and wood burning units on the market, each with different degrees of efficiency. Standard built-in fireplaces are the least efficient for burning solid fuel (mainly paper waste and wood). Efficiencies are typically less than 10%. While the addition of glass doors and an outside combustion air source will increase the fireplaces' reliability, they are generally regarded as "energy losers". There are several types of free standing coal and wood stoves available, ranging from inexpensive box stoves with low efficiencies to airtight units of heavy construction which give long life and high conversion of coal and wood to usable heat. On the simpler stoves, positive draft control is not present, and combustion air is introduced under the fire, allowing large amounts of unburned gas (and heat) to be carried up the chimney. The better units normally incorporate both primary and secondary air; some employ a second chamber for better combustion of gases. This type of unit is known as the "airtight" variety, and includes positive draft control. A third type of unit gaining some popularity is the multi-fuel or mixed fuel system, where coal or wood and another fuel (oil or gas, for instance) may be burned alternately in the same unit (never at the same time). While offering the user more flexibility, these units are very expensive to purchase and install. They are typically designed as central furnaces distributing heat by means of a forced-air system or a water-glycol filled baseboard system. 14.2 Performance Characteristics Energy output of a solid fuel stove will vary tremendously dependent on several factors, including efficiency of the heating unit, quality and heat output of the resource used, and proper operation by the user. Typical residential units are sized in the 30,000-75,000 BTU per hour range for the stove type, while the furnace type typically will yield 100,000-150,000 BTU per hour, some even up to 200,000. Amount of heat output is adjusted manually by the individual, or automatically by damping down the fire. 14.3 Reliability Theoretically, coal and wood heat could satisfy all of the space heating requirements of a residence during the heating season, provided that the resource is readily available and an occupant is always there to tend to the fire. However, in practice, and for the time being, coal and wood are used as a "fuel saver", requiring 100% backup for times when the structure might be unoccupied or shortage of solid fuel supply exists. A storage area that will protect the solid fuel from the elements and provide for proper seasoning of the wood is required. The size of storage generally hinges on frequency of resource use and the dynamics of availability to the consumer. D-100 Thermodynamic Efficiency - varies with the type of stove or furnace as well as properties of the fuel, e.g., the moisture content of the wood, BTU-value of the coal, etc. General percentages of conversion efficiency are given below: Standard Fireplace up to 10% With glass doors and outside air 15 - 20% Simple Box Stoves (sometimes airtight) 20 - 45% Quality airtight stoves 45 - 65% Mixed fuel units 50 - 70% 14.4 Costs Costs for the units and associated hardware typically range from $500 - $2,000 dollars (not installed). Mixed fuel stoves and furnaces approach $6,000 (installed) in Anchorage prices. Installation costs for most units are not available, but can be expected to approach those of capital costs. Adding stoves to existing units will likely cost more than new buildings, due to modifications to structural members. Operation costs revolve around the coal or wood resource. There are no current cost figures for coal or cordwood at Kotzebue. Presently options consist of driftwood gathered from the waterfront or felled timber from stands 30 miles or more from the town, while coal is not available on a commercial basis right now in Kotzebue. Maintenance consists of cleaning of both firebox and flue. The latter should be cleaned at least once a year. Professional chimney cleaning can cost up to $100.00 per visit. D=LOx Useful life of coal and wood stoves ranges from under 5 years on inexpensive models with thin-wall construction to a potential 20 years or more on quality units. Economics of scale are difficult to assess, although bulk shipping and installation would certainly reduce costs. 14.5 Special Requirements and Impacts A solid fuel resource, be it coal, peat or wood, is necessary for solid fuel utilization on any scale. Visual impacts include smoke from coal and wood fires and storage of the solid fuel. Air quality could be impacted with a large number of coal or wood burning units, though this is difficult to assess at present with relation to the Kotzebue area; it would depend on the level of penetration and local wind patterns. Health and safety aspects include keeping all combustibles a proper distance from the stove or furnace, maintaining air quality inside the structure by ventilation, and preventing chimney fires by cleaning the flue on a regular basis. 14.6 Summary and Critical Discussion Cost per million BTU for coal or wood space heating in Kotzebue cannot be established without further knowledge of resource cost to the consumer. Peat and coal heating technology is currently available but, due to non-available resources for the time being, is rarely used in Kotzebue. D-102 Wood heating technology is also currently available and is used in the Kotzebue area. It is highly likely that it will continue to be an attractive supplemental heat source to fuel oil and even to a coal-fired central district heating system, in the event that it should be introduced. However, before an analysis of penetration into the community can be performed, further assessment of the future availability of the resource must be done. 14,7 Bibliography Barkshire, J., ed. Western Sun Energy Workshop Manual - Wood Section. Alaska Renewable Energy Associates Anchorage. December 1981. Baumbach, C.L. Fyring i To-Kammerkedler (Combustion in Multifuel Furnaces) Fyring No.4, 1979. (Danish Publication). Kerr, C., and Richardson, J. Technology Profile: Wood Fuel for Space Heating in Alaska's Railbelt Region. Alaska Renewable Energy Associates, Anchorage. February 1981. Krzeminski, E.R. Central Heat from Wood and Coal. In New Roots, 1981. Rice, E. Building in the North. Geophysical Institute of the University of Alaska, Fairbanks. 1975. Sullivan, A.M. Coal Heats Homes as Oil Prices Rise. Coal Age, August 1980. 15 ELECTRICAL ENERGY CONSERVATION Electricity conservation can be implemented in many forms; from plastic wall stickers that announce: "Turn off the lights when you leave" to sophisticated microprocessor based controllers with D-103 distributed networks of "mini" controllers under their command (though ready to take over should the master fail) .Another approach is in the increasing of end use efficiency of discrete components that use electrical energy. 15.1 General Description Electricity conservation generally entails the increasing of the efficiency of devices that utilize electrical energy to perform a given function. Devices found in the study area include lighting and inductive motor loads. Load "management" is another form of electricity conservation. However, it can be thought of as increasing "system" efficiency rather than dealing with discrete components. Load management systems actively "pursue" the conservation of electrical energy. Duty cycling , thermostat "setback", light monitoring, and load "shedding" are among the processes undertaken by Load (or Energy) Management systems. This could be described as the "active" mode of electricity conservation. Lighting can be made more efficient through replacement of incandescent fixtures with the more efficient fluorescent devices. There have recently appeared on the market high efficiency fluorescent fixtures that improve the energy-to-light conversion process even more (high efficiency ballasts/tubes). Other directions taken in the area of lighting conservation are "task" lighting and the use of "available" light to allow the reduction of electrically supplied illumination. Induction motors have seen a rapid increase in operating efficiency and the technology is continuously updating advances in high efficiency motor design. There is a certain aspect D-104 inherent in the operation of the induction motor that cannot be altogether corrected through efficient design. This is its "power factor" or the ratio of actual power produced to power consumed. The NASA-LEWIS power factor controller has gone a long way in reducing this power consuming facet of the induction motor. 15.2 Performance Characteristics Lighting controls entail the use of circuitry that allows the user to establish a specific illumination level in each area of concern. The circuitry then maintains that level of illumination, taking full advantage of other sources of light such as available light from windows on sunny days or even as individual desk or work area lights are turned on. The savings take place in two distinct areas: First, the general methods in lighting design utilize a "degradation" factor that tends to provide more illumination than is required when the lights, fixtures, etc. are new. Then as the fixtures age and bulbs deteriorate the lighting levels are always above the required level - and never below. The ability to preset the required light level and allow the circuitry to increase power as the system "matures" presents an opportunity for significant savings. The advantage of using available light is obvious though less quantifiable. Manufacturers have claimed lighting loads reductions of up to 50%, however this value can vary considerably in the study area due to a distinct lack of "available" light during the winter months. D-105 High efficiency ballasts are actually high quality transformers built to "tighter" specifications than standard units. Up to 10% reduction in energy usage is claimed by manufacturers of these units when used with standard fluorescent tubes. High efficiency fluorescent tubes use newer phosphorescent compounds in order to increase their efficiency. The combination of high efficiency ballasts and tubes does not reduce the lighting load in an additive sense. The use of high performance tubes reduces the losses in even a standard ballast. The efficiency of a combination of the high quality ballast and tube is in the vicinity f 18-24%. Power factor controllers operate by sensing the- phase relationship of current and voltage. In a lightly loaded motor this phase difference can produce a significant increase in the motor's power factor which in turn reduces the motor's conversion efficiency. When detected by the controller unit, the input voltage is reduced in proportion to the out of phase component. This in effect reduces the motor's energy usage. The reduction in energy usage with controllers depends, then, on the loading and cycle time of any given motor. Load management plays a supervisory role in the use of electrical energy. It can, when properly planned and programmed, reduce peak demands and ensure that unused energy consuming devices are turned off and then turned on only when certain conditions exist. The simplest type of the load "manager" is a clock that has been promoted to controller with the addition of a few relays. The levels of sophistication possible through the use of programmable microcomputers in Energy Management can provide the tools to alter operating parameters on a real-time basis maximizing the energy savings in large scale applications. D-106 15.3 Reliability The light controls and fluorescent components are all off-the- shelf proven hardware. They are typically more reliable and have a longer life than the components they replace. The power factor controllers in the single phase units have not been satisfactorily demonstrated in Alaska to date and therefore have an indeterminate reliability. The load management hardware, while well proven in the Lower 48, is untested in the arctic, but is expected to be reliable with the ability to switch totally over to a manual system in the event of a failure. 15.4 Thermodynamic Efficiency A complete energy saving fixture is approximately 13% to 22% more efficient than a standard fixture. The addition of a power factor controller to a motor circuit will improve the motor efficiency, but the amount of improvement is dependent upon motor size and loading. Typical motor efficiencies will improve 5% to 20%. Load management in a commercial application should save between 5% to 25% depending on the very site specific circumstances. 15.5 Costs for Typical Unit Installed No costs for the Load Management System were available. 1) Capital $63.60 per four tube fluorescent fixture $140.00 per 5 HP power factor controller (PFC) 2) Assembly and Installation $22.00 per four tube fixture $50.00 per 5 HP PFC 3) Operation and Maintenance No cost, to be performed by home owner or normal maintenance personnel D-107 4) Cost per Kw Installed N/A 5) Economies of Scale Capital costs could be reduced through bulk buying (dependent upon number of units’ purchased). Assembly and installation costs could be reduced through a blanket contract for a village-wide retrofit. 15.6 Special Requirements and Impacts 1) Siting No special siting requirements 2) Resource Needs a) Renewable None b) Non-renewable Materials required to manufacture units. 3) Construction and Operating Employment by Skill The original installation and calibration should be performed by a licensed electrician. No maintenance to the fluorescent components or the Power Factor Controller should be required, except recalibration if (and only if) the motor is replaced with another. 4) Environmental Residuals Lower fossil fuel usage due to lower electrical demand. 5) Health and Safety Aspects None 15.7 Summary These electricity conservation technologies are straightforward, relatively benign, and easily applied to village lifestyle. Used in conjunction with any power source they can improve the utility's power characteristics, reduce peak loading, and pay for D-108 themselves quickly. An example of savings is the power factor controller used on a motor which runs 24 hours per day (as a water plant circulation pump does) where the total power savings per year would be 1,472 kWh. This is equivalent to a savings of $294.40 per year based upon a utility rate of $0.20 per kWh. A typical Power Factor Controller for this size motor costs $140 plus $50 for installation. In this case the unit would pay for itself in about six months. It should be noted that the implementation of these electrical conservation strategies may not produce an cumulative energy savings. 16 THERMAL ENERGY CONSERVATION 16.0 General Thermal conservation is defined here as those measures which increase the thermal efficiency and decrease the heating loads in a building. They are not user-oriented (e.g., turning down the thermostat). Rather, they are "technical fixes"; one-time improvements such as increasing insulation and reducing infiltration. Additional information on overall conservation through insulation et.al. is covered in Appendix E. 16.1 General Description There are a myriad of conservation options available to the consumer. Many are "gadgets" that do not give an appreciable return on investment. The options have been limited here to those that provide the most dramatic increase in fuel savings. Commonly referred to as "superinsulation", these measures typically consist of very high levels of insulation (usually requiring some structural modifications to a more conventional building), very low air changes per hour, and an air-to-air heat exchanger to ensure that controlled ventilation is kept to levels that will not have an adverse effect on occupants' health. D-109 Conservation measures (and thus energy savings) will likely be different in new and existing buildings. With new structures, one has the option of designing construction systems capable of containing greater levels of insulation. In existing buildings, "retrofitting" is often limited by existing structural members. The most common measures employed in retrofits include caulking and sealing holes in the building envelope (doors, windows, electrical and plumbing penetrations), adding ceiling insulation, and applying movable insulation over the windows. Increasing insulation thickness in the walls is generally not cost effective due to the large expenditure in tearing out and replacing finishes. For this same reason, adding insulation to the suspended floor systems on pilings that are prevalent in the Kotzebue area is often not feasible. Only when chicken wire or some other inexpensive finish on the underside of the floor system is used does added insulation become cost effective. As mentioned, new construction does not have these restraints. A wall system can be any thickness to accommodate increased insulation. Often, a "double-wall" method is used, with separate 2 x 4 walls at the exterior and interior. The space between the two walls is filled with fiberglass insulation, often reflecting values of R-40 and above. Structural floor systems are usually deep enough to accommodate insulation of R-40 and above. For example, a 12-inch deep floor joist could be completely filled to achieve the figure stated above. Special roof trusses ("Arkansas" truss) are used so that deep layers of insulation can be extended to the roof edges while still maintaining room for ventilation through the attic. Typically, R-values of 60 or more are used in the roof. D-110 Other options used in new construction are basically the same as in retrofits; movable insulation over glazing and caulking of the building envelope. A great amount of detail work usually goes into sealing the vapor barrier, as well as all cracks where air infiltration occurs. When infiltration has been dramatically reduced, a potential problem can occur. Ventilation in the building may not be sufficient to expel moisture and air pollutants that occur as a part of daily living. A small air-to-air heat exchanger using low power fans is employed to provide proper ventilation levels. The device exhausts stale air and replaces it with outside air; a series of baffles transfers heat from outgoing to incoming air. The efficiency of this transfer varies depending on several factors, among them outside air temperature and indoor humidity levels. Even at relatively low efficiencies (40-50%), substantial energy savings can be had. Several other low cost conservation options not necessarily related to superinsulation can produce a significant return on investment over a period of time. Two of the more effective are setback thermostats on central heating systems and insulation jackets around domestic hot water tanks and hot water supply lines. 16.2 Performance Characteristics Thermal conservation measures' performance is "constant" in the sense that once installed they are not directly influenced by such factors as fuel availability. Obviously, the effectiveness of fuel savings hinges on the care of installation and the variance in outside weather conditions. A few conservation measures - most notably movable insulation over the windows - require manual operation by the occupant. Daa LL 16.3 Reliability Conservation is reliable in that once installed it will continue to conserve fuel throughout the useful life. As it is not a supply option, 100% backup space heating is required. In new construction, furnace or boiler sizing can be reduced if conservation measures that significantly reduce the peak heating load are applied. Thermodynamic or conversion efficiencies do no directly apply to most conservation measures. 16.4 Costs Installed costs will vary considerably depending on many factors; chief among them are the levels of conservation installed, who actually does the work (paid labor versus homeowner), and whether the work is new construction or retrofit. There is little historical information on installed costs for these measures in the Kotzebue area. However, extrapolation of Anchorage costs using a construction multiplier developed for Alaska (HSM, Inc., 1981) suggests that conservation expenditures will vary from about $250.00 for simple weatherization materials to $10,000.00 for a full "superinsulated" package on an average Sized residence. Theoretical fuel savings range from 13 to 43% annually. Operation and maintenance costs do not apply to the majority of conservation investments, as they are an integral and nonmechanical part of a _ structure. Items such as_ setback thermostats and air-to-air heat exchangers would be the exception, although O&M on even these options is generally minimal. Replacement costs are generally restricted to thermostats, fans for the heat exchangers, and some cheaper grades of caulking materials when they are directly exposed to D-112 the environment (such as around windows or doors). Manufacturers of many of the newer caulking compounds claim useful lives of 20 years or more. Economies of scale apply to conservation investments, as bulk purchasing, shipping, and installation can be utilized. A large scale conservation program could conceivably result in lower prices and better quality control than isolated and incremental installations. 16.5 Special Requirements and Impacts There are no special siting needs for conservation technologies, although proper orientation and placement of south glazing on new structures should be taken into account to provide solar radiation into the living area. Resource needs are limited to the specific conservation products; the majority would have to be shipped into the Kotzebue area. Thermal conservation technologies have no appreciable impact on the external environment. Care must be taken to ensure that proper ventilation is present in a tightly sealed structure to avoid the buildup of indoor pollutants; the air-to-air heat exchanger discussed herein is used for that purpose. Skills required for installation generally consist of carpentry, mechanical, electrical and/or labor trades. No special skills are required beyond an understanding of the details needed to achieve energy efficiency. Potential energy savings are discussed in the next section. D-113 16.6 Summary and Critical Discussion The savings in energy and subsequent reduction in fuel bills when employing conservation stategies are theoretical at present, as there has been no monitoring done Kotzebue. In addition, these savings will vary widely depending on the level of conservation implemented and the size and original condition of a particular structure. Some examples can, however, be given by drawing on other research work in Alaska. A brief study of conservation in northwest Alaska done in 1981 (see bibliography) theorized that the annual heating load of an average sized residence could be reduced from 92 million BTU to 53 million BTU by adding a full “superinsulated" package. Simple weatherizing (caulking and weatherstripping) accounted for an 11.8 million BTU reduction. As stated earlier, these represent a range of 13 to 43%, with other options falling somewhere between the two. Preliminary cost per million BTU in the Kotzebue area ranges from under $1.00 per million BTU for weatherization done by a homeowner to about $11.00 per million BTU for a retrofit on ceiling insulation that is contractor applied. Conservation cost for new structures ranges from $4.00 - $8.50 per million BTU, depending on the level of investment. Thermal energy conservation is readily available in the Kotzebue area today. It is in most cases competitive with fuel oil, and can result in substantial annual savings to the consumer. Conservation is reliable in the sense that it will reduce fuel demand throughout its useful life. A large investment in thermal conservation could result in a significant reduction in space heating requirements in the Kotzebue area. D-114 16.7 Bibliography Barkshire, J. Energy Conservation Technical Profile for the Shungnak, Kiana and Ambler Reconnaissance Study of Energy Requirements and Alternatives. Wind Systems Engineering, May 1981. Barkshire, J. Energy Conservation, Solar and Wood for Space and Water Heating: A Preliminary Report on Costs and Resources in Alaska's Railbelt Region. Alaska Renewable Energy Associates, September 1981. D-115 17 ORGANIC RANKINE CYCLE 17.1 Generation Description The Rankine process forms the thermodynamic basis for steam engines and steam turbines and the process is the oldest one used for power generation. The first steam engine was constructed in 1705 by Newcomen and since then working temperatures and pressures have been greatly increased yielding thermal efficiencies of almost 50 percent in laboratory tests. Derived from the commonly used power plant Rankine process using water as working medium is the Organic Rankine Cycle (ORC) using an organic fluid as working medium. The use of such working media permits power generation from low temperature waste heat or from heat supplied by simple low pressure boilers. The obtainable thermal efficiencies are 8-15 percent depending on ambient temperatures. As efficiency is increasing with decreasing ambient temperatures, arctic locations would be favorable. However, only few makes and sizes are commercially available at this time and accumulated time in service is rather limited. 17.2 Performance Characteristics Energy input for an ORC is in the form of heat in the temperature range of 200-300°F. In Kotzebue this would be supplied from coal fired low pressure boilers or from geothermal heat if sufficient temperature can be obtained from geothermal wells. The process also requires the availability of natural cooling capacity such as air or water with a temperature not exceeding 60-80°F. D- 116 Output from the ORC is electricity with a selected voltage, and heat delivered at a temperature slightly above ambient temperature. Efficiency and output reach the highest values during the winter, which also is desirable due to seasonal load differences. 17.3 Reliability As ORC systems are completely sealed units working at moderate temperatures with non-aggressive working media, a high degree of reliability can be expected. The rather limited operating experience gathered with ORC systems makes back-up generating capacity essential and for this purpose the existing diesel fueled generating capacity should be kept in serviceable condition. 17.4 Thermodynamic Efficiency Coal fired boiler 3 80% Organic Rankine Cycle 2 8 - 15% Overall efficiency of power generation : 6 - 12% 17.5 Costs Capital costs are expected to be high. Based on the electrical power needs for 1985 a generating capacity of 3000 kW will be needed at a price of approximately 11 million dollars. At $100/ton coal, electricity costs will be around $0.3/kWh with an expected lifetime of 25 years and an interest rate of 12 percent. D= Al? However, there is a rather large degree of uncertainty concerning capital costs of a complete system. Assuming that the above mentioned price of 11 million dollars can be reduced by 50 percent the price of 1 kWh of electricity will be approximately $0.25. 17.6 Special Requirements and Impacts One of the main reasons for employing the ORC technique is the offering of coal based power generation without the use of high pressure steam. Under normal conditions the use of high pressure steam is not considered a disadvantage, because the technique is well proven after many years of commercial use. However, some highly skilled labor is essential for operation and maintenance, and this could represent a problem in remote areas with limited availability of such highly skilled labor. While the construction of an ORC system will require some skilled labor, the operation and maintenance should not require personnel of higher skill than is locally available in the Kotzebue area today. The ORC should not pose any health or safety hazards due to the limited pressures and temperatures of the process. The working media, such as Freon 12 or propylene, are rather harmless when handled in appropriate ways. 17.7. Summary and Critical Discussion Considering the price of generated power of 31 cents/kWh, the ORC does not seem to be a practical solution to the problems of high energy prices in the Kotzebue area. If coal was locally available at very low prices, a utilization of the ORC process should be considered. At $100/ton, which is approximately 44 percent of the D= 178 price of diesel fuel, the same proportion between thermal efficiencies would be required to make such utilization feasible. However, the thermal efficiency of the complete ORC is only 25-33 percent of that of the corresponding diesel process and with the relatively high capital costs of the ORC, its economy becomes less than favorable. The satisfaction of Kotzebue's power needs in the year of 1985 would require almost 24,000 tons of coal, and in the year 2000 - 100,000 tons, if an ORC system were to supply these power needs. As only few makes and types of ORC systems are available, the chance of the appropriate system being readily available is limited. Thus, few systems with outputs greater than 300 kW can be found. In Kotzebue 14 such units will be required if needs are to be met, and the maintenance and coordination of 14 small separate power generating systems are likely to increase to unacceptable levels. 18 HEAT PUMP SYSTEMS -—- DISTRICT HEATING 18.1 General Description The working principle of a heat pump is basically the same as the well known principle found in a normal household refrigerator. Heat is extracted from a source at a low temperature and delivered to a heating system at a higher temperature. This requires a certain amount of energy input in the form of high temperature heat or mechanical energy. The output from the heat pump is the sum of two inputs, and it is delivered as heat at a selected temperature. The amount of high temperature heat or mechanical energy needed to extract a certain amount of heat from a low temperature source increases with the difference in temperature between the source and the heating system. D- 119 Thus, it is favorable to keep the temperature of the heating system as low as possible. The source may be air or water from rivers, lakes or the sea. Geothermal energy may also be used. The highest efficiencies in commercially available heat pumps have been obtained with diesel driven units, where the waste heat from the diesel engine is recovered. A coal fired heat pump has been designed using proven components only, and it is commercially available at this time. However, installation of a coal fired unit will not make sense in locations with local coal fired production of electricity due to the availability of waste heat from coal based power generation. The waste heat will normally be sufficient to satisfy the demand for space heating and thus there will be no need for a heat pump. Due to the climatic conditions of Kotzebue, only air and sea water can be used as a heat source. With sea water utilization, heat will be extracted from a freezing process. The use of air simplifies the process; however, this in turn causes a decrease in thermal efficiency. The heat pump can be coupled with a generator to provide a city or district with space heating delivered through a district heating system and with electricity. 18.2 Performance Characteristics In the Danish town of Frederikshavn, a diesel driven heat pump/ generator was installed in 1979. D-120 This plant delivers 24 million Btu/h electricity and 38 million Btu/h heat. (700 kw electricity and 11000 kw heat.) Total input in the form of heavy fuel oil is 7400 kw or 25.2 million Btu/h. Thus, 15.2 million Btu/h is extracted from a low temperature heat source which in Frederikshavn is purified sewage water. Thermal efficiencies of such a plant will be lower in Kotzebue due to lower heat source temperatures. For a plant of this kind an input of approximately 8500 kw or 29 million Btu/h can be expected. The system used in Frederikshavn is unique by its efficiencies at partial loads. At loads above 50 percent, efficiencies can be considered constant. 18.3 Reliability All major components are of heavy duty design and should be highly reliable. However, due to the effects of a longer lasting breakdown in remote locations with severe climatic conditions, a backup system is essential. This can be provided by maintaining the existing diesel power plant and by installing a normal oil fired boiler with appropriate capacity. 18.4 Thermodynamic Efficiency Diesel driven heat pump (Kotzebue conditions) : 150% Coupled power generation : 35% Waste heat recovery from coupled power generation : 85% 18.5 Costs The cost of a diesel driven heat pump unit with a backup boiler is estimated at $2,325 per kW or $681 per 1000 Btu/h peak load D121, capacity. Power generating capacity is estimated at $1,280/kw capacity. Based on the computations for required capacity in 1985, a diesel driven heat pump/generator plant will cost around $10 million. For the diesel driven heat pump, heat and electricity prices will be $23 million/Btu and $0.14/kWh based on a price of $1.50/gallon for diesel oil. 18.6 Special Requirements and Impacts A diesel driven heat pump will have basically the same requirements and impacts as a normal diesel power plant. In Kotzebue the emissions will be normal diesel exhaust and rather large amounts of ice that should be left in piles to melt during summer or led to the sea in pipes permitting dual-phase flow. Construction employment for the heat pump plant would only differ slightly from that of a normal diesel power plant. Operating personnel would require special training. The technology level of the required personnel should represent no problem in the Kotzebue area. 18.7 Summary In areas with adequate low temperature heat sources, a heat pump system seems to be an attractive solution to the problems caused by the high prices of energy. The technology is rather uncompli- cated and thus high reliability could be expected. Heat and electricity prices are low and investments are moderate. At the same time only few plants are operating and experience is limited. This could cause some breakdowns due to minor technical D= 122 problems, as is known to happen at other projects involving untraditional designs. In particular the ice making technique in connection with the heat extraction from sea water could create problems, and thus a heat pump plant cannot be recommended for Kotzebue unless another low heat source can be found. The use of air does not seem realistic due to the extremely low winter temperatures. If, however, geothermal energy could be utilized in connection with a heat pump, economy could be promising. It is known that water at a temperature of 100°F is present at a depth of approximately 2,000 feet under the Kotzebue area and if this could be pumped to the surface in adequate amounts, production of heat could take place. The costs of such utilization of geothermal energy are not known, and experience gathered is very limited. Even if access to low temperature geothermal energy were better in the Kotzebue area than in most other areas, the isolated location of Kotzebue would make it less than recommendable to employ such a new technology here. D=i2)3 APPENDIX E CONSERVATION APPENDIX E CONSERVATION TABLE OF CONTENTS 1.0 Thermal Conservation. .cccccccccccccccsccsescessevcescesbnl 2.0 InSulation Of FLlOOLFS..ccrcccrcvcvcvvecvcssvecsseseseses bs 3.0 Insulation Of Walls.ccccccecvcccvcevesecsvvvscsecvescvesebul3 4.0 Insulation Of ROOFS. .ccccccccescvecvecevcesesevevesesebm23 5.0 Windows and Shutters.ccerveccccccceccvccvssvvsesecveevenms4 6.0 Ventilation and Infiltration. ccecccrsececevevsccevseseeb=40 7.0 Night Set-Back of Temperature..cececcccccccccccsecseeebo4l 8.0 Conservation in Existing StructureS..ccccccccccccceeeebn42 LIST OF FIGURES Figure E.1 -— Floor Type lLeeseeccccsccvcccccccescessssseeveebn4 Figure E.2 — F100r Type 2occecccccvecccvceccvesveccvceseccseeb—O Figure E.3 -— Floor Type 3 and 4eeeeeeceeccccceccescesveseeeb—9 Figure E.4 -— Floor Type 5 and 6.ecesecrcccreesevecvesesevebnl2 Figure E.5 — Wall Type 1 and 2.ecceeeececeeceseceesecseee eb lb6 Figure E.6 - Wall Type 3 and 4..ccecseccccccccvcsevevseeeebnl9 Figure E.7 -— Wall Type 5 and 6ereecceccccvcccccvecvseseeeseb—22 Figure E.8 - Roof Type 1 and 2.cccecececnvccccevcccveveeeebm26 Figure E.9 - Roof Type 3 and 4ececrevccccccccseveveveeves ebm 29 Figure E.10 — Roof Type S.cccccccccvccvcccccccveccvesesesesebmsl Figure E.11 — Roof Type 6.ccrccccccvevvcvccvvccccveceseeseebn33 Figure E.12 = Typical Window....ccereccccccccccccecvevsesevebn30 Figure E.13 - Graph of Daylight and Darkness......e.e+eeeeeE- ol APPENDIX E CONSERVATION 1.0 THERMAL CONSERVATION In this appendix a number of calculations have been included to establish a basis for comparison of different insulation standards in respect to construction cost, heat loss and present value for construction and heat loss over a 20-year period. This has been performed for: (1) walls and floors in the 3.5" - 15.5" insulation range, (2) for roofs in the 3.5" = 21.5" insulation range, (3) for single, double and triple pane windows (as well as combinationsof single and double pane windows), and (4) for using external thermal shutters. Additionally ventilation and infiltration losses have been dealt with, and the use of a heat exchanger in connection with a central ventilation system has been investigated. Also, the possible gain from night set-back of temperature has been determined. For an existing typical new home in Kotzebue a cost and benefit analysis has been made of a complete retrofit aimed at conserving energy. Cost estimates in this appendix are based on R. S. Means: Building Construction Cost Data 1982. Thus multipliers of 1.22 and 1.481 are used from the lower 48 to Anchorage for materials and labor respectively. Multipliers from Anchorage to Kotzebue have been estimated at 2.0 and 1.5 for materials and labor respectively, thus giving the following multipliers: Lower 48 to Kotzebue for materials: 1.22 x 2 2.44 Lower 48 to Kotzebue for labor : 1.48 x 1.5 = 2.22 As some uncertainties in these multipliers do exist, it will be reasonable to use an average value of 2.33 as a common multiplier for materials and labor from the lower 48 to Kotzebue. Also, a common multiplier of 1.75 for labor and materials is used from Anchorage to Kotzebue. E-1 Construction costs are anticipated to be depreciated over a period of 20 years at an interest rate of 3% over current inflation rate. Current price of heating oil is set at $1.46 per gallon and the oil price is anticipated to rise with the normal inflation rate plus 2.6 per cent. All calculations are performed using the metric system. Final results are provided in U.S. units. 2.0 INSULATION OF FLOORS Summary of results: Type Insulation Construction Oil Consumption Present Valur (inches) ($/sq.ft.) (gal/sq.ft.x yr) ($/sq.ft.) 1 355 9.40 0.285 17.40 2 5.5 9.65 0.216 15.69 3 8.0 10.45 0.163 15.01 4 10.0 10.90 0.136 14.70 5 12.0 11.44 0.107 14.44 6 15.5 12.70 0.086 152510 Floor type 1 45/406 = 11% wood/89% insulation 1/k = 0.048 Air space between layers 1/k = 0.11 x 0.12 + 0.89 x 0.3 = 0.28 i 1/k R Surf. films Ol? 3/4" plywood 0.19 Onl 2 0.16 Insulation/frame 0.089 0.048 1.85 Space/frame 0.050 0.28 0.18 1/2" plywood 0.013 0.12 On kL Total R value = 2.47 k = 0.40 Cond. loss = 0.40 x 215,000 = 86 kwh/m* year With a furnace efficiency of 70%, oil consumption is 123 kwh/m2year = 3.07 gal/m? year (1 gallon of oil equals 40 kwh) = 0.285 gal/SF year Construction costs 3/4" plywood 1 sq.ft. at $1.75 ao 1/2" plywood 1 sq.ft. at $1.35 635) 2° x 6") 0075 £t- = 0575 board |ft.) 50.75 0.56 3¥j' fiberglass 0.875 at $0.32 0.28 0.006" polyethylene 0.04 Total $4.03 Cost in Kotzebue $9.40 per SF FIGURE E.1 FLOOR TYPE 1 3/4" PLYWOOD 6 MIL POLYETHYLENE 2°x 6" 3 1/2" FIBERGLASS 1/2" PLYWOOD Floor type 2 Construction like type l. However, empty space filled with fiber glass (5 4"). Total R value 1/k = 0.17 + 0.16 + 2:14 + 0.11 = 3.36; k = 0.30 0.048 Cond. loss = 0.30 x 215,000 = 65 kwh/m year With a furnace efficiency of 70%, oil consumption is 93 kwh/m@year = 2.32 gal m2 ear 0.216 gal/SF year Construction Costs 6" fiberglass - 34" : 0.875 (0.44 - 0.3) = 0.11 Floor type 1 4.03 Total $4.14 Cost in Kotzebue $9.65 per SF FIGURE E.2 FLOOR TYPE 2 RTL ce. Ln... cc 4" PLYWOOD Ber ( oy 6 MIL POLYETHYLENE 2°x6" hed Le a pe ee ad aed dee en eae 5 1/2” FIBERGLASS 1/2” PLYWOOD Floor type 3 Outer layer 7% wood. 1/k = 0.048. Inner layer 11% wood. 1/k = 0.045. Surf. films 3/4" plywood Ins./frame Ins./frame 1/2" plywood Conduction loss 0.23 x 215,000 1/k 0.019 0.12 0.140 0.048 0.045 0.045 0.013 0.12 Total R value k = 49 kwh/m2 year With a furnace efficiency of 70%, oil consumption is 70 = int gal/m? year 0.163 gal/SF year Construction Costs 3/4" plywood 1/2" plywood 2" x 6" 2" x 2" 0.5 £t/sq ft 0.17 board ft at $0.75 6" Fiberglass 0.875 x 0.44 2" Fiberglass 0.92 x 0.23 Polyethylene Total Cost in Kotzebue Le75 t.39 0.56 0.13 0.39 0.21 0.09 $4.48 kwh/m2year $10.44 per SF Floor type 4 Constructed like type 3 with 4" layer substituting previous 2" layer of insulation. Total R value = 4.36 - 1.00 + 02089 = 5,34 k = 0.19 0.045 Cond. loss 0.19 x 215,000 = 41 kwh/m2 year With a furnace efficiency of 70%, oil consumption is 59 kwh/m2year = 1.46 gal m2 ear. 0.136 gal/SF year Construction Costs 3/4" plywood 1.75 1/2". plywood Vs 3D a° « 6" 0.56 2" x 4" 0.5 ft/sq ft = 0.33 board ft 0.25 6" Fiberglass 0,39 3s" Fiberglass 0.92 x 0.32 0.29 Polyethylene 0.09 Total $4.68 Cost in Kotzebue $10.90 per SF FIGURE E.3 FLOOR TYPE 3 I / AEE REI LEE A eG i LEAR Yor as (NOT Er Bo EB a a ge hala 16" (406 mm) PEE 3/4" PLYWOOD —— 6 MIL POLYETHYLENE 2"x6" 5 1/2” FIBERGLASS 2"x2” PER 24" (610 mm) 2° FIBERGLASS 1/2” PLYWOOD 3/4" PLYWOOD 6 MIL POLYETHYLENE FLOOR TYPE 4 2"x6”" 6 1/2” FIBERGLASS 2"x4" PER 24° (610mm) 3 1/2” FIBERGLASS 1/2°PLYWOOD Floor type 5 Constructed like type insulation. Surface films 3/4" plywood Ins./frame Ins./frame 1/2", plywood 3 with 6" 0. 0. 0. 0. Conduction loss 0.15 x 215,000 = 32 layer substituting 2" layer of 1/k 019 0.12 14 0.048 14 0.045 013 0.12 Total R value k kwh/m2 year With a furnace efficiency of 70%, oil consumption is 46 = 1.15 gal m2 ear. = 0.107 gal/SF year Construction costs 3/4" plywood 1/2" plywood Os x 6" 2" x6" 0.5 ft/eq £E = 6" Fiberglass 6" Fiberglass Polyethylene Cost i E-10 0.50 board feet at 0.75 Total n Kotzebue et 1.35 0.56 0.38 0.39 0539 0.09 $4.91 kwh/m?year $11.44 per SF Floor type 6 Constructed like type 5 with 3.5" insulation added. Total R value = 6.47 + (0.089 x 1/0.045) = 8.42 k 0.12 Conduction loss 215,000 x 0.12 = 26 kwh/m? year. With a furnace efficiency of 70%, oil consumption is 37 kwh/m2year = 0.92 gal/m? year 0.085 gal/SF year Construction Costs Floor type 5 4.91 Additional 2" x 4" 0.25 Additional 3.5" Fiberglass 0.29 Total $5.45 Cost in Kotzebue $12.70 per SF URE E.4 FLOOR TYPE 5 DY OO MEET IF SAE I AEE YES EE A tm =————— 3/4" PLYWOOD MIL POLYETHYLENE ei ARYA ae NO ML LE i OP ta EL RM ee acres 1/2" PLYWOOD ca f — a Oe Sama ee 1/2" PLYWOO! 3.0 INSULATION OF WALLS Summary of results Type Insulation Construction Oil Consumption Present Value (inches) (S/sq.ft.) (gal/sq.ft.x yr.) (S$/sq. ft.) iL 3.5 8.05 0.3121 17.06 2 DieD 8.61 0.200 14.22 3 9.0 9.85 0.129 13.47 4 LOS 10.05 0.106 13.02 5 12.0 10.40 0.099 12.19 6 155. 1re7/S 0.073 13.81 Wall type 1 45/406 = 11% solid wood and 89% insulation. 1/k = 0.89 x 0.039 + 0.11 x 0.12 = 0.048 tC 1/k R Surface films Or Exterior plywood 0.013 0.12 0.11 Insulation/frame 0.089 0.048 185) Interior plywood 0.013 0.12 0.11 Total R value = 2. = 0 24 2 k 245 w/m*°C 16,151 °F days = 8,955 °C days = 215,000 °Ch Conduction loss = 0.45 x 215,000 = 97 kwh/m2 year. With a furnace efficiency of 70%, oil consumption is 139 kwh/m2year = 3.46 gal/m? year. 0.321 gal/SF_ year Construction costs 2" x 4", 0.75 ft. per sq. ft. = 0.5 board ft. at $0.75 per board ft. = 0.38 1/2" plywood, 2 sq. ft. per sq. ft. at $1.35 per sq. ft. = 2.70 3p fiberglass, 0.875 sq. ft. per sq. ft. at $0.32 per sq. ft. = 1.28 0.006" polyethylene, 1.10 sq. ft. per sq. ft. at $8.00 per 100 sq. ft. = 0.09 Total $3.45 Total, Kotzebue 2.33 x 3.45 = $8.05 per SF Wall type 2 45/610 = 7% solid wood. 1/k = 0.93 x 0.039 + 0.07 x 0.12 Surface films Ext. plywood Insulation/frame Interior plywood = 0.045 L 1/k 0.016 0.12 0.140 0.045 0.013 0.12 Conduction loss = 0.28 x 215,000 = Total R value 60 kwh/m2 year R 0.17 0.13 3<1l 0.11 = 3.52 k_= 0.28 w/m2°c With a furnace efficiency of 70%, oil consumption is 86 kwh/myear = 2.15 gal m2 ear. 0.200 gal/SF_ year Construction costs 2" x 6", 0.50 ft. per sq. 5/8" plywood, 1 sq. 1/2" plywood, 1 sq. 6" fiberglass, 0.92 0.006" polyethylene ft. ft. sq. per sq. ft. per sq. ft. et. per sq. Total Total, E-15 at $1.47 at $1.35 ft. at $0.44 Kotzebue ft. = 0.50 board ft. at $0.75 $0.38 $1.47 $1.35 $0.40 $0.09 $3.69 $8.61 per SF FIGURE E.5 WALL TYPE 1 a RT ae gt gh rn ae Das CL ER tL BR a gle a te B |, (610mm) | 5/8" PLYWOOD 2"x 4" 3 1/2" FIBERGLASS 6 MIL POLYETHYLENE 1/2" PLYWOOD WALL TYPE 2 si Wc GR ae (OV 6/8" PLYWOOD 2°x6" 5 1/2" FIBERGLASS 6 MIL POLYETHYLENE 1/2” PLYWOOD Wall type 3 45/610 = 7% wood in both layers. 1/k = 0.93 x 0.039 + 0.07 x 0.12 = 0.045 L 1/k R Surface films 0.17 Ext. plywood 0.016 0.12 0.13 Insulation/frame 0.152 0.045 3.38 Insulation/frame 0.152 0.045 3.38 Int. plywood 0.013 0.12 0.11 Total R value = 7.17 k = 0.14 Conduction loss = 0.14 x 215,000 = 30 kwh/m2 year With a furnace efficiency of 70%, oil consumption is 43 kwh/m2year = 1.07 gal m2 ear. 0.099 gal/SF year Construction costs 2" x 6", 1.0 ft. per sq. ft. = 1.0 board ft. at $0.75 $0.75 5/8" plywood 1 sq. ft. at $1.47 $1.47 1/2" plywood 1 sq. ft. at $1.35 $1.35 6" fiberglass 1.84 sq. ft. per sq. ft. at $0.44 = $0.81 0.006" polyethylene 0.09 Total $4.47 Total, Kotzebue $10.40 per SF E-17 Wall type 4 Surface films Ext. plywood Insulation/frame Insulation/frame Int. plywood 0. 0. 0. 0. Conduction loss = 0.18 x 215,000 = 1/k 016 0.12 140 0.045 089 0.045 013 0.12 Total R value k 39 kwh/m2 year. 0.17 0.13 30h 1.98 0.11 5.50 0.18 With a furnace efficiency of 70%, oil consumption is 56 kwh/m2year = 1.39 gal/m? year. 0.129 gal/SF year Construction costs 2" a2 6", 0.5 £&. per sd. Et. 2" x 4", 0.5 ft. per sq. ft. 5/8" plywood 1/2" plywood 6" fiberglass e) 0.92 sq. ft. at $0.44 0.5 0.33 board ft. board ft. at $0.75 syst fiberglass (54) 0.92 sq. ft. at $0.32 = 0.006" polyethylene Total Total, E-18 Kotzebue at $0.75 $0.38 $0.25 $1.47 $1.35 $0.40 $0.29 $0.09 $4.23 $9.85 per SF FIGUREE.6 = 2 | »—~gsr8'pLywoop FIBERGLASS MIL POLYETHYLENE WALL TYPES =| —s J | | | pa" ptywooo ee ae Sar poh VY ex 6 1/2" FIBERGLASS 2"x4" PE -3 1/2" FIBERGLASS MIL POLYETHYLENE /2" PLYWOOD Wall type 5 Outer and inner layer: 2(45 + 13) = 10% wood. 1219 1/k = 0.047 . 2 x 13 = 2% wood. Core: Ti 1/k = 0.041 L 1/k Surf. films Ext. plywood 0.013 0.12 Ins./frame (1) 0.045 0.047 Ins./frame (2) 0.304 0.041 Ins./frame (3) 0.045 0.047 Int. plywood 0.010 0.12 Total.R value k Conduction loss = 0.10 x 215,000 = 22 kwh/m2 year. With a furnace efficiency of 70%, oil consumption is 31 kwh/m2year = 0.79 gal/m? year. 0.073 gal/SF year ul Construction costs 1/2" plywood, 1.65 sq. ft. at $1.35 3/8" plywood, 1.00 sq. ft. at $1.13 15.5 3.5 Insulation 3.5" = 4.5 sq. ft. per sq. ft. at $0.32 2" x 2", 1 ft. per sq. ft. = 0.33 board ft. at $0.75 Total Total, Kotzebue E-20 $2.23 1.13 1.44 0.25 $5.05 11.75 : er SF Wall Type 6 Surface films Ext. plywood Ins./frame (1) Ins./frame (2) Ins./frame (3) Int. plywood 0. 0. QO. 0. 0. Conduction loss = 0.15 x 215,000 = 1/k 016 0.12 089 0.045 089 0.039 089 0.045 013 0.12 Total R value k 32 kwh/m2 year. With a furnace efficiency of 70%, oil consumption is 46 = 1.14 gal/m2 year. 0.106 gal/SF year Construction costs 2" x 4", 1 ft. per sq. ft. 5/8" plywood 1/2" plywood syst fiberglass, 2.84 sq. ft. per sq. ft. at $.032 0.006" polyethylene = 0.67 board ft. Total Total, Kotzebue at $0.75 kwh/m? year $0.50 1.47 1.35 0.91 0.09 $4.32 $10.05 per SF 4.0 INSULATION OF ROOFS Summary of Results Type Insulation Construction Oil Consumption Present Value (inches) (S/sqef£t.)) (gal /sqJGtix, yr) (Ssqatt.)) 1 3.5 9.80 0.313 18.58 2 7.0 10.35 0.164 14.96 3 9.5 10.85 0.122 14.26 4 15.5 11.85 0.084 14.19 5 18.0 12.19 0.062 13.94 6 21.5 12.88 0.057 14.47 Roof type 1 45/914 = 5% solid wood. 1/k = 0.95 + 0.039 + 0.05 x 0.12 = 0.043 L 1/k Surf. films Sheet rock 0.010 0.17 Support for sheet rock (discrete lathing) 0.025 Insulation/wood 0.089 0.043 Attic and roof Total R valu e k Conduction loss = 0.38 x 215,000 = 82 kwh/m2 year. 15% added for radiation to clear skies yields 94 kwh/m? year. With a furnace efficiency of 70%, oil consumption is 135 kwh/m2year = 3.37 gal/m? year. 0.313 gal/SF year Construction costs 2" x 4", 0.33 ft. per sq. ft. 0.22 board ft. at $0.75 0.17 2" x 6", 1.10 x 0.33 ft. per sq. ft. 0.37 board Diagonals, etc. 30% of 0.17 + 0.20 1" x 4", 1 ft. per sq. ft. = 0.33 board ft. Sheet rock 3/8" 0.32 + 0.10 0.006" polyethylene 3" fiberglass 0.94 sq. ft. at 0.32 Roofing 1.10 x 0.74 3/4" plywood 1.10 x 1.59 = Total Multiplier of 2.33 for Kotzebue yields E-24 ft. 0.28 0.14 0.25 0.42 0.09 0.30 0.81 1.75 $4.21 $9.80 per SF Roof type 2 iF 1/k R As type l 2.66 3¥" insulation 0.089 0.039 2.28 Total R value = 4.94 k = 0.20 Conduction loss = 0.20 x 215,000 = 43 kwh/m2 year. 15% added for radiation to clear skies yields 49 kwh/m? year. With a furnace efficiency of 70%, oil consumption is 71 kwh/m2year = 1.77 gal/m? year. 0.164 gal/SF year Construction costs Same as type l $4.21 3V3' fiberglass 0.32 Total $4.53 Cost in Kotzebue $10.56 per SF E=25 FIGURE E.8 ROOF TYPE 1 3 1/2” FIBERGLASS 6 MiL POLYETHYLENE Beco ae SRS OE 1" DISCRETE LATHING 7 ei ee 1/2" GYPSUM BOARD ROOF TYPE 2 3 1/2” FIBERGLASS 3 1/2” FIBERGLASS —— 6 MIL POLYETHYLENE = 1" DISCRETE LATHING —————. 1/2". GYPSUM BOARD Roof type 3 6" insulation added to type l. L 1/k R Same as type l 2.66 6" insulation 0.152 0.039 3.90 Total R value = 6.56 k = 0.15 Conduction loss = 0.15 x 215,000 = 32 kwh/m2 year. 15% added for radiation to clear skies yields 37 kwh/m2 year. With a furnace efficiency of 70%, oil consumption is 53kwh/m2year = 1.31 gal/m2 year. 0.122 gal/SF year Construction costs Same as type l $4.21 6" 0.44 Total $4.65 Cost in Kotzebue $10.85 per SF E-27 Roof type 4 2 x 6" insulation added to type l L 1/k R Same as type l 2.66 2 x 6" insulation 0.305 0.039 7-82 Total R value = 10.48 k = 0.10 Conduction loss = 0.10 x 215,000 = 22 kwh/m2 year. 15% added for radiation to clear skies yields 25 kwh/m2 year. With a furnace efficiency of 70%, oil consumption is 36 kwh/m2year = 0.90 gal m2 ear. 0.084 gal/SF year Construction costs Same as type l $4.21 2x 6" 0.88 Total $5.09 Cost in Kotzebue $11.85 per SF E-28 FIGURE E.9 ROOF TYPE 3 6" FIBERGLASS 3 1/2" FIBERGLASS 6 MIL POLYETHYLENE 1" DISCRETE LATHING 1/2” GYPSUM BOARD ROOF TYPE 4 6” FIBERGLASS 1/2" FIBERGLASS 6 MIL POLYETHYLENE 1" DISCRETE LATHING 1/2" GYPSUM BOARD Roof type 5 L 1/k R Same as type l 2.66 3 x 6" added 0.77 0.039 9.49 Total R value = 12.15 k = 0.08 Conduction loss = 0.08 x 215,000 = 18 kwh/m2 year. 15% added for radiation to clear skies yields 20 kwh/m2 year. With a furnace efficiency of 70%, oil consumption is 29 kwh/m2year = 0.73 gal/m? year. 0.068 gal/SF year Construction costs Same as type 1 insulated with 18" fiberglass instead of yy. Same as type l $4.21 3 x 6" fiberglass added 1.32 3Y3' fiberglass subtracted -9.30 Total $5.23 Cost in Kotzebue $12.19 per SF E-30 B53) Roof type 6 L 1/k R Same as type l 2.66 3 x 6" plus 1x34" 0.457 0.039 11,72 Total R value = 14.38 k = 0.07 Conduction loss = 0.07 x 215,000 = 15 kwh/m2 year. 15% added for radiation to clear skies yields 17 kwh/m year. With a furnace efficiency of 70%, oil consumption is 25 kwh/m2year = 0.61 gal/m? ear. 0.057 gal/SF year Construction costs 3 x 6" of insulation added to type 1 Same as type l $4.21 3 x 6" added 1.32 Total $5.53 Cost in Kotzebue $12.88 per SF E-32 FIGURE E.11 ROOF TYPE 6 6" FIBERGLASS 6” FIBERGLARSS 6" FIBERGLASS 3 1/2" FIBERGLASS 6 MIL POLYETHYLENE 1" DISCRETE LATHING 1/2” PLYWOOD 5.0 WINDOWS AND SHUTTERS Summary of Results Type Construction Oil Consumption Present Value (S\V/sq [ft (gal/sq.ft.x yr) (S$/sq.ft.) 1 pane 31.70 4.59 PON si, 3, 2 pane 40.60 2.08 98.95 3 pane 52.10 1.51 94.56 2 pane + 1 pane 72.30 WeOW LO 23! 2 pane + 2 pane 81.17 0.84 104.56 1 pane + shutter 46.70 25 118.80 2 pane + shutter 55.60 1.24 90.45 3 pane + shutter 67.10 0.90 92.71 Known prices in Anchorage of shutters are approximately $8.50 per sq. fics With multiplier from Anchorage to Kotzebue of 1.75, the price in Kotzebue will be approximately $15 per square foot. E-34 FIGURE E.12 TYPICAL WINDOW PANE WOOD FRAME Windows: Base price per sq. ft. Single Double Triple Prices Single Double Triple Materials pane 9.00 pane 12.00 pane 16.00 Install O& P 2.50 2.00 2615 2.50 3.00 3.00 in Kotzebue per sq. ft. (Multiplier 2.33) Materials pane 21.80 pane 29.00 pane 38.70 Depreciation over 20 years on same E-36 Install o&P 5.50 4.40 6.10 5.50 6.70 6.70 terms as walls, etc. Total 13.350 17.25 22.00 Total 31.70 40.60 52.10 1) Single pane window Base size 3' x 4' and wooden frame k(glass) = 6.0 w/m?°c k(wood) = 1.6 w/m*°C k = 6 x 0.88 + 1.6 x 0.12 = 5.47 w/m2°c Conduction loss = 5.47 x 215,000 = 1176 kwh/m2year With a furnace efficiency of 70%, oil consumption is 1680 kwh/m2year = 212 gal/ m*year 3.902 gal/SF year Thermal shutter with 2" of urethane foam. Es L/k R Window 0.16 Surface film 0.17 1/2" plywood outer and inner layer 0.025 0.12 0.21 2" urethane foam 0.05 0.03 lie Total R value = 2.24 k = 0.45 As complete tightness to the window frame may not be obtainable, the air space between window and shutter has not been taken into account. The shutters are estimated to be closed for a _ period equivalent of half the heating degree hours. Conduction loss: With shutters closed 0.5 x 215,000 x 0.45 = 48.4 kwh/m* year. With shutters open 0.5 x 215,000 x 6.44 = 692.3 kwh/m? year. Total 740.7 kwh/m? year With a furnace efficiency of 70%, oil consumption is 1058 kwh/m2year = 26.45 gal/m2 year. 2.457 gal/SF year E-37 2) Double pane window: Base size 3' x 4' and wooden frame. k(glass) = 3.1 w/m*°C (1/2 inch separation) k(wood) = 1.6 w/m“°C k = 3.1 x 0.88 + 1.6 x 0.12 = 2.92 w/m2°c Conduction loss = 2.92 x 215,000 = 897 kwh/m? year. With a furnace efficiency of 70%, oil consumption is = 32.04 gal/lm? year. 2.977 gal/SF year/ Addition of thermal shutter of 2" urethane foam. L 1/k Window Surface film 1/2" plywood outer and inner layer 0.025 0.32 2" urethane foam 0.05 0.03 Total R value k 1281 kwh/m@year Conduction loss = 215,000 x 1/2(2.92 + 0.41) = 358 kwh/m2 year. With a furnace efficiency of 70%, oil consumption is = 12.78 gal/m? year. 1.187 gal/SF year E-38 511 kwh/m@year 3) Triple pane window: Base size 3' x 4'x and wooden frame. k(glass) = 2.2 w/m?ec (3/8" separation) k(wood) = 1.6 w/m“°C k = 2.2 x 0.88 + 1.6 x 0.12 = 2.13 w/m2ec Conduction loss = 2.13 x 215,000 = 458 kwh/m2 year. With a furnace efficiency of 70%, oil consumption is 654 kwh/m2year = 16.34 gal/m* year. 1.518 gal/SF year Thermal shutter with 2" urethane foam. it 1/k R Window 0.47 Surface film 0.17 1/2" plywood outer and inner layer 0.025 0.12 0.21 2" urethane foam 0.05 0.07 Ted Total R value = 2.55 k = 0.39 Conduction loss = 1/2(2.13 + 0.39) x 215,000 = 271 kwh/m2 year. With a furnace efficiency of 70%, oil consumption is 387 kwh/m2 year = 9.68 gal/m? year. 0.899 gal/SF year E-39 6.0 VENTILATION AND INFILTRATION In a well insulated house the average air change can be limited to 0.£& air changes per hour totally (infiltration + ventilation). 40% by infiltration 60% by controlled ventilation with app. 60% heat recovery. Thus totally 36% heat recovery from infiltration and ventilation. Per cu. ft.: Air change 0.50 cu.ft. per hour 36% of 0.50 = 0.18 cu. ft. with full heat recovery 64% of 0.50 = 0.32 cu. ft. with no heat recovery 1 cubic foot = 0.0283 m? Heat loss = 0.5 x 0.0283 x 1.2 x 6.5 x 4.187 x 8760 x 1 = 1.12 kwh/cf. x yea- 2600 Recoverable heat 36% = 0.40 kwh/cf. year With a furnace efficiency of 70%, oil consumption is reduced by 0.58 kwh/cf. x year = 0.014 gal/cf x yea For a 960 sq. ft. house with 8' ceiling and 90% free space, the savings will be 960 x 8 x 0.9 x 0.014 = 9.95 gal/year At a price of $1.46 per gallon this amounts to $145.27 per year. Construction costs Heat exchange unit $s 700 Ductwork, etc. and installation $ 400 Total $1100 Cost in Kotzebue $2563 Power consumption 50W on a yearly basis 428 kwh at $0.20 per kwh $87.60 With these figures payback time is 49 years, and thus it cannot be recommended for residential use. E-40 7.0 NIGHT SET-BACK OF TEMPERATURE Number of degree days with indoor temperature of 65°F: 16,151 Number of degree days with indoor temperature of 56°F: 12,866 If night set-back is made from 65°F to 56°F 8 hours a day, the resulting number of degree days will be: 8/24 x 12,866 + 16/24 x 16,151 = 15,056 15,056/16,151 = 93% i.e., 7% of the total heat loss can be saved by using a night set-back temp. (8 hours) of 9°F below normal 65°F. E-41 8.0 CONSERVATION IN EXISTING STRUCTURES 8.1 Structure's Heatloss: This particular house is insulated with 5.5" of fiberglass in walls and floors and with 6" of fiberglass roofs. Doors are 1 3/4" solid wood. 45 sq. ft. of double pane windows are used together with 46.5 sq. ft. of single pane windows. Walls: 2" x 6" per 24" with 5.5" fiberglass 1) 1/k R Surface films 0.17 Ext. plywood 0.016 0.12 0.13 Insulation/frame 0.140 0.045 Soll Interior plywood 0.013 0.12 0.11 Total R value 3.52 k = 0.28 w/m2°c Floor: 2" x 6" per 24" with 5.5" fiberglass 2 Same construction as walls: k = 0.28 w/m“°C Roof: 2" x 6" per 24" with 6" fiberglass L 1/k R Surface films 0.17 Sheet rock 0.010 0.17 0.06 Discrete lathing 0.025 0.16 Insulation wood O.LS2 0.045 5.38 Attic and roof 0.20 Total R value 3.97 k = 0.25 w/m2°c Single pane windows: k = 6.0 w/m2°c Double pane windows: k = 2.8 w/m2°C Doors: 1 3/4" (44 mm) solid wood L 1/k R Surface films 0.17 Core 0.044 0.12 0.37 Unheated space 0.20 Total R value = 0.74 k = 1.35 Walls towards unheated space: Total R value = 3.52 + 0.20 = 3.72 thus k = 0.27 w/m2°c Infiltration: ASHRAE 1972: Sash-frame non-weatherstripped, average height Si?) cuakt./hr.£e. = (1.5 1/s.m) frame structure 29) ‘cu.£t./hr.ft. = (0.7 1/s.m) Heatloss, Floor: A = 27' x 23' = 621 sq. ft. = 57.7m2 ti = 70°F = 21°C to = -36°F =_-38°C k = 0.28 w/m2°c Loss = 0.28 x 57.7 x (18 + 38) = 905 W Heatloss, roof: Loss - 1.15 x 0.25 x 57.7 x (18 + 38) = 928 W E-43 Heatloss, walls: 1) A(total) = (2 x 27 + 23 - 6) x 8 = 568 sq. ft. = 52.7 A(windows) = 3 x 4.5' x 5' + 3 x 2' x 4' = 91.5 sq. ff A(wall) = 52.7 -8.5 = 44.3 m@ k = 0.28 Loss = 0.28 x 44.3 x (18 + 38) = 626 W Heatloss, walls: 2) A(wall) = (23 + 6) x 8 = 2 x 3' x 6.5' = 193 sq. ft. k = 0.27 Loss = 0.27 x 17.9 x (18 + 38) = 273 W Heatloss, doors A(doors) = 2 x 3 x 6.5 = 39 sq. £t. = 3.6 m2 k = 1.35 Loss = 1.35 x 3.6 x (18 + 38) = 272 W Heatloss, windows A(double pane) = 2 x 4.5 x 5 = 45 sq. ft. = 4.2 m2 k = 2.8 Loss = 2.8 x 4.2 x (18 + 38) = 659 W A(single pane) = 3 x 2 x 4 + 4.5 x 5 = 46.5 sq. ft. = k = 6.0 Loss = 6.0 x 4.3 x (18 + 38) = 1445 W Total Conduction Loss: Floor 905 Roof 928 Walls, (626 + 273)w 899 Doors & windows, (272 + 659 + 1445) 2376 Total Loss 5108 E-44 m2 8.5 m2 te 17.9 m2 4.3m = |2=zz=Ez Infiltration, doors Sash frame, 2 x (3' + 6.5') x 57 = 1083 cu.ft./hr. Frame struct., 2 x (3' + 6.5') x 29 = 551 cuskts sir. Total = L634) cus ft./hr. 46.3 m3/hr. Infiltration, windows: Sash frame: {2 x (2° - 20) x 3) 4 2x (455 4 2.5) x 31] x) 57 Frame structure: 3 x (2 x (4 + 2) + 2x (4.5 + 5)) x 29 3672 cu.ft./hr. 2697. cunft. /hr. Total 6459 cu.ft./hr. 182.9 m3/hr. 1634 + 6459 229 m3/hr. 8093 cu.ft./hr. House total = 24 x 28 x 8 = 5376 cu.ft. Airchanges per hour = 8093/5376 = 1.5 INFILTRATION LOSS = 0.36 x 229 x (18 +38) = 4.617 W TOTAL HEAT LOSS = 5108 + 4617 = 9725 W at -38°F Average load (65 - 21)/(65 +36) x 9725 W = 4236 W Annual heat loss 8760 hours x 4236 = 37,112 khw/year With a furnace efficiency of 70%, oil consumption is 53,016 kwh/year = 1325 gal/year An oil consumption of this size may seem high for a house of this type and the actual consumption may often be less due to: a) actual heat loss to the unheated shed will be less’ than computed because of the somewhat higher temperature in the shed and because of the lack of wind influence. b) the heat generated by electrical applicances and people is not taken into account. c) solar heat received during summer months is not taken into account. However, the purpose of these calculations is to show the possible savings by improving insulation standards, and thus calculations for an improved house are to be performed in the same manner to ensure that the differences show actual savings. 8.2 Improved structure's heatloss: Net area, existing (28 - 2 x 0.5) x (24 - 2 x 0.5) = 621 sq. ft. Net area, improved (28 - 2 x 10/12) x (24 - 2 x 10/12) = 586 sq.ft. = 94% of exist. 1) Walls to have added horizontal 2' x 4'x per 24' with 3 1/ fiberglass 2) Roof to have added 6' fiberglass 3) Floor to have added 2' x 4' and 3 1/2" fiberglass 4) Windows to be double-pane, weatherstripped and caulked. 5) Doors to above core of 1 1/2" (38mm) fiberglass. All vapo- barriers to be changed or inspected. 0.18. Walls: Total R value = 3.52 + 0.089 . 5.50 thus k 0.045 Floor: As walls thus k 0.18). Roof: Total R value = 3.97 + 9-152 = 7.87 thus k = 0.13 0.039 0.089 _ 5.79 0.045 Walls towards unheated space: Total R value = 3.72 + thus k = 0.18 0.17 + 9:006 4 0-038 4 9,20 = 1,39 0.12 0.039 Doors: Total R value thus k = 0.72 Infiltration: sash frame weatherstripped average fit: 30 cu.ft/ft.he. frame structure caulked: 0 cu. €t/£t,hr, Floor: Loss = 0.18 x 54.4 x (18 + 38) = 549 W Roof: Loss = 1.15 x 0.13 x 54.4 x (18 + 38) = 456 W Walls; 1) Loss = 0.18 x 45.0 x (18 + 38) = 454 W 2) Loss = 0.18 x 18.2 x (18 + 38) = 183 W Doors: Loss = 0.72 x 3.6 x (18 + 38) = 145 W Windows: 1) Loss = 2.8 x 4.2 x (18 + 38) = 659 W 2) Loss = 2.8 x 4.3 x (18 + 38) = 674 W Total Conduction Loss = 3120 W E-46 Infiltration, Doors: = 2 x (3 + 6.5) x 30 = S70 .cusfts/hrs Infiltration, Windows: {2 x (2 + 2) x 3 +2 x (4.5 + 2.5) x 3) x 30 = 1980 cu.ft./hr. Total Infiltration 2550 cu.ft./hr = 72.2 m?/hr. Airchanges per hour = 2.550 = 9,47 = 0.5, i.e. additional mechanical 5376 ventilation not to be considered. INFILTRATION LOSS = 0.36 x 72.2 x (18 + 38) 1.456 W TOTAL HEAT LOSS = 3.120 + 1456 = 4576W Per year 24x 4576 x 16,151 x 5/9 = 17,597 kwh/year 18 + 38 With a furnace efficiency of 70%, oil consumption is 25,178 kwh/year = 628 gal/year. Thus savings of 697 gallons per year are accomplished. 8.3 Costs of improvements The cost of retrofitting this house as described in 8.2 (above) has been established using R. S. Means: "Building Construction Cost Data 1982". The value of the 6 percent of the previously available space lost to added insulation has not been added to the total cost as this is considered to be offset by the improved thermal comfort experienced in a well insulated house. Walls: VT) | 2% |x 4", | 2) x (28) ee) 24) |x 'S =//520 £ts 2) 2". x) 2") 20 118) 14) x 16.5 +12) 3) 3x) (12) + 19) =|) 285 Ife... 3) 3 1/2" fiberglass 745 -(2x3x6.5+3x4x A ej5) | 1S8)ix) 12:4) xe 4) 628 sq.ft. 0.006" polyethylene 9 x 2(28 + 24) x 1.10 1/2" plywood 8 x 2(28 + 24) - (2 x 3 x 6.5 + 1030 sq.ft. ue —~ Sea U4 S esi Sc 2 Sa c4ie) = 715 sq.ft. 6) Trimming 7) Painting 715 isq.£. 8) Demolition TLS (Sq tro E-47 E-48 1) 2/3 x 520 = 347 board feet at $0.75 = $ 260 2) 1/3 x 285 = 95 board feet at $0.75 = 71 3) 628 sq.ft. at $0.32 = 201 4) 1030 sq.ft. at $0.08 = 82 5) 715 sq.ft. at $1.35 = 965 6) 10% of operations 1 - 5 = 158 7) 715 sq. ft. of painting at $0.27 = 193 8) 715 sq. ft. of demolition at $0.31 = 222 Total $2152 Roof 1) 6" fiberglass 672 sq.ft. 2) 0.006" polyethylene 1.50 x 672 = 1008 sq.ft. 3) Remove and replace existing fiberglass 616 sq.ft. 1) 672 sq.ft. at $0.44 = $296 2) 1008 sq.ft. at $0.08 = 81 3) 616 sq.ft. at $0.20 = 123 Total $500 Floor 17 2) x43) xa 28) = 364 ft 2) 3 1/2" fiberglass 11/12 x 24 x 28 = 616 sq.ft. 3) 0.006" polyethylene 1.50 x 672 = 1008 sq.ft. 4) Remove and replace existing fiberglass 616 sq.ft. 5) Remove and replace existing plywood 672 sq.ft. 1) 2/3 x 364 at $0.75 = $ 182 2) 616 sq.ft. at $0.32 = 197 3) 1008 sq.ft. at $0.08 = 81 4) 616 sq.ft. at $0.20 = 123 5) 672 sq.ft. at $0.82 = 551 Total $1134 Windows 1) Caulking in and outside, 2 x 3 x [2 x (4 + 2) + 2.x (4.5 +75) )-= 186 ft. 2) Weatherstripping, 2 x (2 + 2) x 3 + 2x (4.5 + 2.5) x 3/= 66 EE. 3) Double pane, 4.5x5+3x2x 45 46.5 ft. 1) 186 fe. at 0.56 + 1.53 = 2,09 $389 2) 66 ft. at $3.20 = aa 3) 46.5 sq.ft. at $8.20 = 381 Total $981 Doors 1) Caulking in and outside 2 x 2 x (3 + 6.5) 2) Weatherstripping 3) Insulated door 1) 38) £e. at Os56)cr Lass 2) 28) fit. at, $3.20 3) 2 pes. at $165 = Total Costs: Walls Roof Floor Window Doors Total (Anchorage prices) = 2.09 Total Multiplier Anchorage - Kotzebue Cost in Kotzebue Pay—back time 8.4 Discussion of Duration of Shutter Closure 38) Ets, 38 Et 2 pes. $2,152 500 1,134 981 531 $5,298 Le 7D $9,272 9.3 years If shutters are closed at all times during darkness, the number of heating degree days with shutters closed can be calculated. Month January February March April May June July August September October November December Degree Days 2130 1940 2031 1560 1060 645 372 443 717 1283 1719 2136 Darkness, Percentage E-49 80 63 49 23 LS 0 0 ES 48 66 83 99 Total Degree Days Closed 1704 1222 994 359 159 0 0 66 344 847 1427 2195 9297 58% These figures do not take into account the fact that the temperature generally is lower during the dark hours than during the hours of daylight, and that thus the shutters could be expected to be closed during 60% of the heating degree days. However it seems reasonable to assume that stronger winds during the daytime to some extent would compensate for this, and a rough estimate points to the shutters’ being utilized during 50% of the heating degree days. E-50 FIGURE E.13 aa [2 —. eS: . Coe “ee “En APPENDIX F COST ESTIMATES DATA APPENDIX F COST ESTIMATES DATA TABLE OF CONTENTS General...... Wel 8} 1 8115) sie ie ieie vl eisicieie . Base Case..... obotntiel ofenesieieis) s1si scree eee Cogeneration (Alternative A).... Coal-Fired Low-Pressure District Heating System (Alternative B)......... Seer ite Geothermal (Alternative D)...... F-14 F-25 F-35 F-44 APPENDIX F COST ESTIMATES DATA l. GENERAL This appendix provides general cost data to support the cost estimates of Section 8, Volume I for the Alternative plans ("A", "B", "cl", "p" plus the Base Case). General costs are provided such as: ° Labor rates in major populated areas, Kotzebue and Buckland River locations ° Equipment data ° Climatological data in the Kotzebue area Additionally specific cost data on each of the Alternative plans are provided. LABOR RATES MAJOR POPULATED AREA Classification Carpenter Electrician $ $ A. Base Pay 21.50 23.15 B. Overtime Factor 5.60 6.00 (84 hr/wk) -26 x A Cc. Burden 8.15 8.75 -30 x (A+B) D. Fringe Benefits 3.80 5.05 E. Subsistence -0- -0- Room $35/day Board $30/day $65/12 hr. F. Subtotal 39.05 42.95 G. Local Labor Factor -0- -0- (20% of work force at 50% efficiency) -ll x F TOTAL $39.05 $42.95 F-1 LABOR RATES MAJOR POPULATED AREA (Cont 'd) Classification Base Pay Overtime Factor (84 hr/wk) -26x A Burden -30 x (A+B) Fringe Benefits Subsistence Room $35/day Board $30/day $65/12 hr Subtotal Local Labor Factor (20% of work force at 50% efficiency) -ll x F TOTAL Ironworker Laborer Painter $ $ $ 22.00 17.90 22.40 5.75 4.65 5.80 8.35 6.75 8.45 4.90 5.15 3.50 -0- -0- -0- 41.00 34.45 40.15 -0- -0- ~0- $41.00 $34.45 $40.15 F-2 LABOR RATES MAJOR POPULATED AREA (Cont'd) Classification A. Base Pay B. Overtime Factor (84 hr/wk) 26x A Cr Burden -30 x (A+B) D. Fringe Benefits E. Subsistence Room $35/day Board $30/day $65/12 hr Fie Subtotal G. Local Labor Factor (20% of work force at 50% efficiency) -llxF TOTAL Equipment Plumber Operator Truck Driver $ $ $ 227.59) 20.40 17.65 5.85 5.30 4.60 8.50 7.70 6.65 4.95 4.90 6.65 -0- -0- -0- 41.85 38.30 35.355) -0- -0- -0- $41.85 $38.30 $35.55 LABOR RATES KOTZEBUE LOCATION Classification A. Base Pay B. Overtime Factor (84 hr/wk) -26 x A c. Burden -30 x (A+B) D. Fringe Benefits E. Subsistence Room $35/day Board $30/day $65/12 hr F. Subtotal G. Local Labor Factor H. (20% of work force at 50% efficiency) -ll +F TOTAL Carpenter $ 21.50 5.60 8.15 3.80 5.40 44.45 4.90 $49.35 Electrician $ 23.15 6.00 8.75 5.05 5.40 53.65 LABOR RATES KOTZEBUE LOCATION (Cont'd) Classification A. Base Pay B. Overtime Factor (84 hr/wk) -26 x A c. Burden -30 x (A+B) D. Fringe Benefits E. Subsistence Room $35/day Board $30/day $65/12 hr F. Subtotal G. Local Labor Factor H. (20% of work force at 50% efficiency) oll x F TOTAL Ironworker Laborer Painter $ $ $ 22.00 17.90 22.40 5.75) 4.65 5.80 8.35 6.75 8.45 4.90 Dist) 3.50 5.40 5.40 5.40 46.40 39.85 45 55 5.10 4.40 00 $51.50 $44.25 $50.55 F-5 LABOR RATES KOTZEBUE LOCATION (Cont 'd) Classification A. Base Pay Bx Overtime Factor (84 hr/wk) tO Nah: Cc. Burden -30 x (A+B) D. Fringe Benefits E. Subsistence Room $35/day Board $30/day $65/12 hr Es Subtotal Gs Local Labor Factor Rs (20% of work force at 50% efficiency) oll) x, F TOTAL Equipment Plumber Operator Truck Driver $ $ $ 22.5% 20.40 17.65 5.85 5.30 4.60 8.50 7.70 6.65 4.95 4.90 6.65 5.40 5.40 5.40 47.25 43.70 40.95 5.20 4.80 4.50 $52.45 $48.50 $45.45 LABOR RATES BUCKLAND RIVER LOCATION Classification Base Pay Overtime Factor (84 hr/wk) 26x A Burden -30 x (A+B) Fringe Benefits Subsistence Room $115/day Board $60/day $175 day/12 hr Subtotal Local Labor Factor (20% of work force at 50% efficiency) ell x F Rotation 9w/2w $415/756 hr TOTAL Carpenter $ 21.50 5.60 8.15 3.80 14.60 53.65 +55 $54.20 Electrician $ 23-15 6.00 8.75 5.05 14.60 57.55 -55 $58.10 LABOR RATES BUCKLAND RIVER LOCATION (Cont'd) Classification A. Base Pay B. Overtime Factor (84 hr/wk) -26 x A (oe Burden -30 x (A+B) Dé Fringe Benefits E. Subsistence Room $115/day Board $60/day $175 day/12 hr F. Subtotal G. Local Labor Factor (20% of work force at 50% efficiency) eal oc i H Rotation 9w/2w $415/756 hr I. TOTAL Ironworker $ 22.00 5.45 8.35 4.90 14.60 55.60 339 $56.15 F-8 Laborer $ 17.90 4.65 6.75 5.15 14.60 49.05 a> $49.60 Painter 22.40 5.80 8.45 3.50 14.60 54.75 <3) $55.30 LABOR RATES BUCKLAND RIVER LOCATION (Cont 'd) Classification A. Base Pay Be Overtime Factor (84 hr/wk) -26xA Ce Burden -30 x (A+B) D. Fringe Benefits E. Subsistence Room $115/day Board $60/day/12 hr $175 day/12 hr F. Subtotal G. Local Labor Factor (20% of work force at 50% efficiency) a exe: H. Rotation 9w/2w $415/756 hr Die TOTAL Equipment Plumber Operator Truck Driver $ $ $ 22.55 20.40 17.65 5.85 5.30 4.60 8.50 7.70 6.65 4.95 4.90 6.65 14.60 14.60 14.60 56.45 52.90 50.15 -0- -0- -0- -55 D> 55 $57.00 $53.45 $50.70 EQUIPMENT DATA TABLE Monthly Rental Monthly Rental Maintained Major Non-maintained Maintenance Weight Populated Areas Major Populated Maintenance Labor Parts Lubricants Fuel Description (1,000 1b (312_hr/month) Area (312 hr/mo) _labor/hr Cost/hr cost/hr __gal/hr__ gal/hr Dozer - large 115 17,600 9,900 ad 24.26 12.43 2.84 15.04 Dozer - intermediate 31 8,200 5,700 25 7.88 3.96 +95 5.85 Loader - large 45 9,600 5,600 34 10.71 9,38 1.13 6.15 Rock Hauler - 140 15,500 8,400 58 18.27 15.72 2.27 13.75 intermediate Auger - intermediate 30 12,000 6,800 59 16.69 8.75 1.67 12.96 Backhoe - large 40 8,700 5,800 35 11.03 3.50 71” =2..93 Backhoe - small 20 4,200 3,200 ol 3.46 1.88 233 1.85 Crane - small 50 10,600 7,400 +34 10.71 4.96 1.13 5.42 Crane - large 200 21,000 9,900 1.15 36.23 18.46 3.18 10.00 Dump Truck - small 30 6,000 4,400 a3 4.10 3.70 65 4,73 Flatbed Truck - 15 2,100 1,500 03 +95 1522 74 793 intermediate Compactor - large 20 6,300 4,100 224 7.56 3.49 ole 3.94 Compactor - small 1 800 600 02 -63 -10 05 25 Manlift 5 3,000 2,100 12 3.97 86 +24 1.43 Air Compressor - Z 1,600 1,300 -03 95 -41 eae 73 intermediate Welder - intermediate 2 800 600 02 -63 09 18 1.71 Heater - large z 1,200 1,200 -005 16 -09 -- 3.50 Cement Mixer - 2 1,200 900 04 1.26 -58 -12 1.00 intermediate Water Trailer 4 500 500 --- -- aoe a a 130,900 5.06 159.45 89.58 17.09 98.59 F-10 Cost estimations for the Buckland River Hydroelectric Project are based on a multiplication factor for labor rates on a comparative basis to a major populated area. The following outlines the establishment of these rates. Ls LABOR Major Populated Area Buckland River Classification Labor Rates Location Carpenter on in Electrician 42.95 58.10 Ironworker 41.00 56.15 Laborer 34.45 49.60 Painter 40.15 55.30 Plumber 41.85 57.00 Equipment Operator 38.30 53.45 Truck Driver 35 «95 50.70 TOTAL $313.30 $434.50 Average Labor Multiplication Factor $434.50/$313.30 = 1.39 2. EQUIPMENT (Refer to Equipment Data Table, Page F-10) Major Populated Area Buckland River Classification Labor Rates Location $ $ Monthly Rental Rate Subtotal ($130,900) less (Maintained Labor Cost Total ($159.45) x 312 hr/month) 81,152 81,152 Maintenance Labor Cost Total ($159.45) x 312 hr/month 49,748 x 1.39 labor 69,150 factor Fuel and Lubricants Total ($115.68) x 312 hr/month x 6 1b./gal x $0.29/1b x 1.1 handling factor -0- 69,050 Parts Total ($89.58) x 312 hr/month $2 lb x $0.29 1b x 1.1 handling factor -0- 4,458 Subtotal $130,900 $223,810 Average Equipment Multiplication Factor $223,810/$130,900 = 1.71 F-11 Three major work areas will be evaluated on a percent basis for labor, equipment and material involvement. Note that material involvement does not have a multiplier due to it being covered within the freight mobili- zation of the project. The previous labor and equipment multiplication factors will be utilized in these three areas for the establishment of three work area mutliplication factors. Reservoirs, Dams and Waterways Typical Buckland River Buckland River Percent Location Multi- Location Involvement cation Factor Percent Project Involvement Labor 40% x 1.39 = 55.60 Equipment 55% x 1.71 = 94.10 Material 5% x 1.0 s 5.00 TOTAL * y00% 154. 65% Work Area Multiplication Factor $154.65%/100% = 1.55 Building Structures Labor 40% x 1.39 = 55.60% Equipment 15% x 1.71 = 25.65% Material 45% x 1.0 = 45.00% TOTAL 100% — 126.25% Work Area Multiplication Factor 126.25%/100% = 1.26 Transmission Plant Labor 35% x 1.39 = 48.65% Equipment 35% x oLa = 59.85% Material 30% x 1.0 = 30.00% TOTAL 100% 138.50% Work Area Multiplication Factors 138.50%/100% 1.39 F-12 Average Temperature Heating Degree Days seine, ue Year] Jan |Feb | Mar | Apr] May Season] July] Aug |Sept| Oct [Nov] Dec Feb| Mar] Apr| May [June| Total 1962 | | ! | seq 7 ord 1316] 1763) 1638) 2186] 2223] 1598 ee7/ 15635 ieee esged za “2q 378] OSS 1362] 1738) 2063 1622] 1923 1580 ese} 1s923 ee Hrenzal Bs zea] 347] 769 1273) 1720] 2100) amis} 2212) 1832 e27]issis jae s] 64) 513] e694 1652] 2090] 1792] 2232| 2502] 2334 1772] Yes} 17810 Ss} 451) 36 54 1264) 1715) 240C) 2235) 2217) 1662) 1506) 25) 1e3scz ’ Raa S24] Seo} 039 1498] 1449] 2291 194i] 2391) 1675 770 lose 1 or 372) 4 1327) 1839) 2259 1894) 1685) 1356 $62 1988 1967-08] 373) 6H 1774) 1765/1948) 2397) 2026) 1631 746 eve 207] 242] 753) 1299] 1776] 2171 1ac3| 1986] 1939 450 #02) 663, S8q 1041) 1909) 1733 1710) 1823) 1626 soe 95 : ieee 1970-71] 342} weal 165] 1859] 2083) 2384/2236] 1658 s3s ass? 71-72] 276) 133€] 1757] 2014] 2154) 2181] 2638) 1725 bee) 16638 lass 1972-73 192) 308) 1204| 1653] 1964) 2328] 17C2) 2177] 1663) 1c60}- 680] 15530 q9se 1873-78] ses SU 1382] 1779] 1953] 2129/2363] 2025 1559] 1078] 756] 16626 1976-7! 3890 26 1806) 2SSC) 2323/1928) 16S 1678) 1129) BIe)te7IS 95 Hees 197S-74 asi} «1S asq i302 2176] 2803] 1998 1771] 1c7e) 762 ed 1976-77, 33g 26 bod 1237 2610] 1703] 2434 1843] 1063] 627 ese 1977-71 2c 18 24 1287) 1612) 1807] 1808) $37 tes 1978-74 184 764 S5q 1379) 1953] 1639] 2083] 1773 1340] sas 197 33 2b O89 1164] 2372] 2207) 167%) 1679 1464) $20) 14595 ze asi} 77q 1119) 2336 Cooling Degree Days Feb | Mar| Apr | May |June| July; Aug |Sept| Oct | Nov | Dec | Total 1969 q qd qg ¢ of 6of 6 | of 6of So ° 1970 x5 of JF 3x Gl ce} 0} oo 3 1972 9} qd of of af 2 of of of 16 1972 | of =f «ott of cf of as 1973 of «of «of 6g o} 6c] oo c 1978 | of of of Ql o} of 0 ° 1975 6} 36} tg o| cl oo ° 1976 q Cr, rr rr o} of o ° 1977 | of «oof =o} aa] o} of of as 1978 of a} oof =f «ag o} of 0 1 1979 q a of of af gl o} of oo 1 1980 of «of 6} 6g o} of oo ° | wse4] -coa] aes 23.5 ze.9 | 78 ages 2.6 278 ooi8 37.5) 3ee1] dese] 265] -10.3) eee Precipitation Snowfall Feb June| July | Aug | Sept | Oct July | Aug |Sept! Oct | Nov | Dec | Jan | Feb | Mar| Apr| May|June| Total 0.52 0.10 1.00] O.13 o.g 9. 25.8 9.28) 9.80 2.34] 1.22 od 2. 31.8 0.28 0.57 0.75] 0.82 od 1. 222 ota 0.70 1.78] 1.22 o.g 2. 23.8 0.37 0.38 1.27] 0.21 ad c. rery 0.17 ove? 0.37] 0.50 og 7 29.8 0.32 0.78 1.07] 0.33 c.d 0. 30.5 0.28 1.12] 2017] 0.76 1980-51) o.g 7. 33.6 13 0.28 0.79) coat 1981-52) 0. Cc. 7.6 o.28 o.2c 0.35] Ost 1952-53 c.g a. 2a.8 0.17] 1.32 1.06] 625 1953-54] c.g OL are outs 0.29] 2.60] 0.0% 1954-55] Cc.) A. ates o.te a.72 2.76] seu 1958-so c.g oT zen 0.39 0.01 0.96) 0.22 1956-57] a. Tt a0 0.36] 0.17 1.67] 1628 1957-58] 0.0 oy $6.0 o.c3 0.93 2eae| 0.71 =s} ond ce gis Ores) 0.82] 0.65] 0.53 ona] a. 2901 reery 0.78) 1.53 o.g 0. se.0 9.08) 0.83 0.37 og 2. 65.3 o.3e 1.06 O.38 Le ce. $6.7 o.25 o.ss 1.26 og ce 60.2 o.ea| ove 0.59 Go 9. ace 0.26 o.13 0.30 od + ees 1 | o.18 0.18) o.we og oan? on cose 0.33 3.0 0. o1.3 0.37 0.53 one a. 2. 3al8 ove 0.82 oss oa ft 2906 one o.as| 0.77 rera-71| c.g 9. 0.17 o.26 0.76 1971-77 o.d oF 9.c2| 2.50] 1.60 1972-79 ond 9. O.s1 a.52 11S 1973-76] Ondo 0.39) 0.13 0.05 isre-73 Oud Ce O65) o.66 oes 197S-74 O.d cy. iste 9.21! o.er o.as 1976-79 Tt | 8 1977 | 0.26 c.ce| aad 1977-72 o.d 0. a.10] 0.30 1978-74 o.d 9. o.ce| dees O.ee 1978-8 O10 0. o.6c) 0.82 | | ieeo-ail cy eecone ercoro wean | 0.34] 0.29) 0.33) 0.31] C33] 0-58] 1-49] 2610] 1.47 a.ee| cose] 8.066 roan 1 sse8 # Indicates a station move or relocation of instruments. See Station Location table. r for the period beginning in Record mean values above are means through the current ye 1943. ¥=15 2. BASE CASE Item Description Crew Size Man-hours Description Material Equipment Equipment Hours No. of Task Time Labor Rate, of Material Cost, Weight Requirements Rate and Cost Required and Cost a Al MOBILIZATION OF EQUIP- MENT AND WORKFORCE TO THE SITE Cost of material, Crew size 2688 mhr @ freight, and equipment! dependent $50.00, standby as delineated on tasks $134,400 by the following described items, will be incurred during mobilization Bl SITE PREPARATION 2 | Grubbing & Surveying | 2 men, 1 wk | 168 mhr @ T $50.00 $8,400 a Dirt Work 8 men, 2 wk 1,344 mhr @ 6,000 yds. gravel $2.00/yd, CAT, Loader, 168 hours each $46.78 (1.1 acres) $12,000 2 dumps, $62,900 water trailer 4 | Land Cost 1.1 acres $11,000 (for + info. only) cl BUILDING FOUNDATION 2 Install Piling 6 men, 1 wk | 504 mhr @ 36 piles, 30'x60lb. $0.35/1b, Mixer, auger,| 84 hours each $47.08, $22,700; backhoe ,water $23,700 64,800 lb. trailer,crane 3 | Slab Steel, Pans & 6 men, 1 wk | 504 mhr @ 5,400 sq.ft. pan $3.00/eq.ft.,| Crane, 84 hours each Beams $48.08, $16,200 welder $24,200 27,000 1b. torch 350 ft. beam, $0.35/1b, 100 1b./fe. $12,300; | 35,000 Ib. [Va 4 Slab Insulation (Included in 11,000 BF styrofoam $0.40/BF, Item C3) $4,400; 1,400 1b, 5 Slab Reinforcement (Included in 17,500 ft. #5 rebar $0.40/ft., | Item C3) $7,000; _|_17,500 1b. | 6 Slab Concrete Pour 10 men,l wk | 840 mhr @ 200 yds. gravel $2.00/yd, Mixer, crane,| 84 horus each $46.16 $400 bucket, $38,800 1,000 sacks cement $6,00/sack, loader, water $6,000; trailer, dump 90,000 1b. 7 | Generator Supports (included in 1,000 ft. beam, 60 1b] $0.35/1b, (Included in Items C3 and $21,000; Items C3 and C6) 60,000 1b. 40 yds. gravel $100 C6) 200 sacks cement $6.00/sack $1,200; 18,000 1b. | BASE CASE | | | | Item| Description | Crew Size | Man-hours | Description | Material | Equipment | Equipment Hours No. | of Task | Time | Labor Rate, | of Material | Cost, Weight | Requirements | Rate and Cost | |_Required |__and Cost | | | | T T T T I T T c9 | Material Handling [Crew size | 280 mhr @ | 2 bottles oxygen, | $100, | | | (15%) |dependent on | $44.25, | 1 bottle acetylene, | 500 1b.; | | | |tasks | $12,400 | fasteners and | $400, | | | ldescribed in | | rebar chairs | 200 1b. | | | [this section | | | | | T T I T T T D1 | BUILDING ERECTION | | I | | | 2 | Steel Frame T 4 men, 1 wk | 336 mhr @ | Steel frame T $45,400, T Crane, T 84 hours | (Walls Only) | | $47.13, | | 90,000 1b.; | welder | | | | $15,800 | Siding & insulation | $36,300 (wt. | | | | | | |_incl. above) | | 3 | Siding, Insulation, | 4 men, 2 wks| 672 mhr © | Fasteners T $1,000, | Crane, T 84 hours, | and Overhead Doors | | $47.13, | | 500 1b.; | man lift | crane; | | | $31,700; | | | | 252 hours, | | 4 men, 1 wk | 336 mhr @ | 2 Overhead doors | $30,000 (wt. | | man lift | | | $47.88, | | incl. with | | | | |_ $16,100 | | Item 2) | | 4 T Roof (Including T4 men, 1 wk | 336 mhr @ | Fasteners T $800, T Crane T 84 hours | Purlins & Insulation) | | $47.13, | | 500 1b. | | | | |_ $15,800 | | | | 5 | Overhead Crane [3 men, 2 wks| 504 mhr @ T Crane T $200,000, T T | (Installed in | | $48.08, | | 20,000 1b. | | |_Building) | |_ $24,200 | | | | 6 | Material Handling “| Crew size | 168 mhr @ T T T Air compres- | 168 hours each | (7%) | dependent | $44.25, | | | sors, | | | on tasks | $7,400 | | | 2 pneumatic | | | described | | | | guns | | | in this | | | | | | |_section I | | | | T I T I T T T E1 | FUEL STORAGE TANKS | | | | | | 2 | Slab Annulus | 2 men, 4 wks| 672 mhr @ T 5,000 ft. #5 rebar [| $0.40/ft. T Torch | 84 hours | Reinforcement | | $48.08, | | $2,000, | Crane (1 wk) | | | |_$32,300 | [5,000 1b. | | 3 7 Slab Annulus T 6 men, 1 wk | 504 mhr @ | 150 yds. gravel T $2.00/yd. | Mixer, crane,[ 84 hours each | Concrete Pour | | $46.16, | | $300; | bucket, | | | | $23,300 | 750 sacks cement | $6.00/sack | loader, water| | | | | | $4,500, | trailer, dump| | | | | [67,500 1b. | | 4 7 Oil Sand Base [10 men,1 wk | 840 mhr @ | 350 yds. sand T $2.00/yd. T Loader, dump,] 84 hours each | Inside Annulus | | $45.65 | | $700; | cat | | | | $38,300 | 400 gallons oil | $600, | | | | | | | 3,300 1b. | | 5 | Tank Erection | 8 men, 6 wks| 4,032 mhr @ | 5 - 1 million gallon | $650,000, T Crane, T 504 hours each | | | $48.08, | tanks | 1,000,000 1b.| 2 man lifts | | | |_ $193,900 | | | | 6 | Tank Painting [2 men, 3 wks] 504 mhr @ T 250 gallons paint T $5,000, T Man lift, | 84 hours each | | | $50.55, | | 2,100 1b. | air compres- | | I | $25,500 | | |_sor F-15 BASE CASE | | | | | | | Iten| Description | Crew Size | Man-hours | Description | Material | Equipment | Equipment Hou No.| of Task | Time | Labor Rate, | of Material | Cost, Weight | Requirements | Rate and Cost | |_ Required |__and Cost | | | | T T al T ] T T E8 | Material Handling | Crew size | 960 mhr @ | | | | | (15%) | dependent on] $44.25, | | | | | | tasks | $42,500 | | | | | | described | | | | | | | in this | | | | | | |_section | | | | | T ] T al) Tal F1 | GENERATOR ERECTION | | | | | | 2 | Installation | 8 men, 4 wks| 2,688 mhr @ | 2 - 2,000 kw T $1,700,000, | Crane, welder] 336 hours eac | | | $47.13, | generator | 200,000 1b.; | | | | | $126,700 | 1 - 1,200 kw | $350,000, | | | | | | generator | 80,000 1b. | | 3 7 Jacket Water Heat | 6 men, 1 wk | 504 mhr © [3-7 million Btu/hr | $105,000, T Welder, torch] 84 hours | Exchanger | | $48.08, | heat exchangers | 60,000 1b. | | | | |_ $24,200 | | | | 4 7 Air-to-Glycol Heat [4 men, 2 wks] 672 mhr @ T Ducting, fans T $15,000, T Welder, torch] 168 hours | Exchanger | | $48.08, | | 60, 000 1b. | | | | |_$32,300 | | | | T Exhaust System | 4 men, 2 wks| 672 mhr © | Stacks, silencers T $15,000, | Welder, torch] 168 hours | | | $48.08 | | i 000 1b. | | | |_ $32,300 | | | 6 | Auxiliary Boiler T 5 men, 3 wks] 1,260 mhr @ | 60 million Btu/hr $172,500, T Crane, 1 wk ie hours | | | $47.96, | Boiler 1 45,000 1b. | crane; | | | $60,400 | | | Welder | 252 hours, | | | | | | welder 7 T Auxiliary Boiler T 4 men, 4 wks| 1,344 mhr @ | Piping T $36,800, | Welder 336 hours | Piping | | $47.96, | | 4,900 1b. | | | |_ $60,400 | | | | T al T T T T G1 | PROCESS EQUIPMENT | | | | | | 2 T Engine Glycol Piping | T al T | Existing & | 6 men, 4 wks| 2,016 mhr @ | Piping | $57,900, | Welder, torch] 756 hours | 1200 kw Generator | | $47.88, | | 7,500 1b. | | | i | $96,500; | | | | | New Systems | 6 men, 5 wks| 2,520 mhr @ | Piping | $72,600, | Welder, torch] | | | $47.98, | [12,100 1b. | | | | |_$120, 900 | | | | 3 T Expansion Tank and [2 men, 1 wk | 168 mhr © | Expansion tank and | $7,500, | Pumping (Engine | | $47.88, | pumps | 4,000 1b. | | he Coolant) | |_ $8,000 | | | | mgine Lubrication T T T T T T mi ee Piping | 3 men, 3 wks| 756 mhr @ | Piping | $21,600, | Welder, torch| 672 hours | | | $47.88, | | 1,400 1b. | | | | | $36,200; | | | | | New Equipment | 3 men, 2 wks| 504 mhr @ | Cooling system | $10,000, | Welder, torch| | | | $47.88, | | 2,500 1b. | | | | | $24,000; | | | | | Existing & 1200 kw | 3 men, 2 wks| 504 mhr @ | Piping and equipment | $20,800, | Welder, torch| | Generator | | $46.88, | | 2,700 1b. | | | | | $24,000; | | | | | Pumps and Filter | 2 men, 1 wk | 168 mhr @ | Pumps | $15,000, | Welder | | Press | | $47.88, | | 1,000 1b. | | | | |_ $8,000 | | | | F-16 BASE CASE | Crew Size | Man-hours | Iten| Description Description Material Equipment | Equipment Hours No. | of Task Time Labor Rate, of Material Cost, Weight | Requirements | Rate and Cost Required and Cost | T G5 | Fuel System | | | | | | | ! | | | | | | | | | | | | I ' I T T T | | | | | | | Existing & 1200 kw | 3 men, 1 wk | 252 mhr @ | Piping and equipment | $9,400, | Welder, torch| 336 hours | Generator | | $47.88, | | 1,400 1b.; | | | | | $12,100; | | | | | New Systems (incl. | 3 men, 2 wks| 504 mhr @ | Piping and equipment | $15,800, | Welder, torch] | Day Tanks) | | $47.88, | | 2,700 1b. | | | | | $24,000; | | | | | Pumps | 1 man, 1 wk | 84 mhr @ | Pumps | $15,000, | Welder | | | | $47.88, | | 2,000 1b. | | | | |_ $4,000 | | | | 6 | Fuel Storage Area T T T T T is | Supply Piping | 7 men, 4 wks| 2,352 mhr @ | Piping | $61,800, | Welder, torch] 504 hours | | | $47.88, | | 11,400 1b.; | | | | | 112,600; | | | | | Fill Piping | 4 men, 1 wk | 336 mhr @ | Piping | $10,300, | Welder, torch] | | | $47.88, | 11,900 1b.; | | | | | $16,100 | | | | | Pumps | 2 men, 1 wk | 168 mhr @ | Pumps | $20,000, | Welder | | | | $47.88, | | 3,000 1b. | | | | | $8,000 | | | | | Heating System (incl. | | | | | | | Auxiliary Building | | | | | | | Heating) | | | | | | | Boiler | 3 men, 1 wk | 252 mhr @ | Boiler | $15,400, | Crane, welder| 84 hours each | | | $47.96, | | 3,400 1b. | | | | | $12,100; | | | | | Piping | 3 men, 1 wk | 252 mhr @ | Piping | $8,100, | Welder, torch] 84 hours | | | $47.88, | | 600 1b. | | | | [$12,100 i | | | 7 T Water and Glycol ~ | 6 men, 1 wk | 504 mhr @ T Equipment T $75,000, T T | Treatment and Mixing | | $48.35, | | 50,000 1b. | | | | | $24,400 | | | | | | | | 75,000 gallon Glycol | $4.00/gal., | | | | | | | $300,000, | | | | | | 622,500 1b. __| | 8 | Pumps (Distribution 6 men, 1 wk | 504 mhr © T Pumps T $15,000, | Welder, torch] 84 hours | System) | | $47.88, | | 10,000 1b. | | | | |_ $24,100 | | | | 9 T Expansion Tank T 4 men, 1 wk | 336 mhr © T Tank ~T $30,000, T Crane, T 84 hours each | (Distribution System) | | $48.35, | | 30,000 1b. | welder, torch| | | |_ $16,200 | | | | 10] Heating & Ventilating T T I T | Heating System | 1 man, 1 wk | 84 mhr @ | Ducts, coils | $10,000, | Man lift | 84 hours | | | $52.45, | | 2,000 1b.; | | | | | $4,400; | | | | | Ventilating System | 2 men, 4 wks| 672 mhr @ | Ducts, fans | $30,000, | Man lift | 336 hours | | | $52.45, | | 40,000 1b. | | | | |_$35,200 | | | | 11] Material Handling T Crew size | 1,140 mhr @ | 10 bottles oxygen T $600, T T | (9%) | dependent | $44.25, | 5 bottles acetylene | 2,500 1b. | | | | on tasks | $50,600 | | | | | | described | | | | | | | in this | | | | | | |_section l | | | | F-17 BASE CASE | | | | | | Item| Description | Crew Size | Man-hours’ | Description | Material | Equipment | Equipment Hour: No. | of Task | Time | Labor Rate, | of Material | Cost, Weight | Requirements | Rate and Cost I | Required |__and Cost | | | : | T T T T T T T H1 | CARPENTRY, PLUMBING, | | | | | | INTERIOR FINISH WORK: | | | | | | REMODELING OF EXISTING] | | | | | |_PLANT AND OFFICE | | | | | 2 | Framing, Doors, T 4 men, 3 wks] 1,008 mhr @ [| Lumber and plywood | $2,700, | Air Compres- | 252 hours | Sheet Rock | | $49.35, | | 20,000 1b.; | sor | | | | $49,700; | Doors and windows | $4,700, | | | | | | | 1,600 1b.; | | | | | | Sheet Rock | $1,300, | | | | | | 15,000 1b; | | | | | | Nails and fasteners | $2,500, | | | | | | |_100 1b. | | 3 | Plumbing (Bathroom, [4 men, 4 wks] 1,344 mhr @ | Pipe and fittings T $5,300, T Backhoe T 84 hours | Drains, and Utility | | $49.72, | | 2,700 1b.; =| (1 wk) | | Connections) | | $66,800 | Fixtures | $1,300, | | ! | | | | 100 1b. | | 4 T Heating & Ventilation | 4 men, 2 wks| 672 mhr @ | Heater, ducts, and [| $10,000, in T | | | $52.45, | fans | 2,700 1b. | | | | |_ $35,200 | | | | 5 | Painting & Finishing 5 men, 2 wks| 840 mhr © | Paint $4,000, | | | $50.55, | | 2,000 1b. | | | | |_ $42,500 | | | | 6 | Material Handling | Crew size | 270 mhre@ | T T T | (7%) | dependent | $44.25, | | | | | | on tasks | $11,800 | | | | | | described | | | | | | | in this | | | | | | |_section | | | | | Taal T T I ia pa T I1 | CARPENTRY, PLUMBING, | | | | | | INTERIOR FINISH WORK; | | | | | |_NEW OFFICE | | | | | | 2 | Turnkey Job (Costs T 10 men, | 2,520 mhr © | Lumber, doors, sheet | $180,000, | Air compres- | 252 hours, air | Based on 2,500 sq.ft. | 3 wks | $50.00, | rock, pipe, fittings,| 100,000 1b. | sor, backhoe,| compressor; | @ $125/f£t) | | $126,000 | fixtures, heater, | | cat, dump, | 84 hours, all | | | | ducts, fans, paint, | | crane | others , | | | |_and fasteners | | | i 3 7 Material Handling | Crew size | 150 mhr @ T T ae T | (6%) | dependent | $44.25, | | | | | | on tasks | $6,600 | | | | | | described | | | | | | | in this | | | | | | |_section | | I | | F-18 BASE CASE | | | | | | Iten| Description | Crew Size | Man-hours | Description | Material | Equipment | Equipment Hours No. | of Task | Time | Labor Rate, | of Material | Cost, Weight | Requirements | Rate and Cost | |_ Required |__and Cost | | I | T T T I T T T J1 | ELECTRICAL WORK | | | | | | 2 7 Lighting [2 men, 1 wk | 168 mhr@ | Lights, wire, T $6, 300, | Man lift | 84 hours | | | $53.65, | conduit | 800 1b. | | | | |_ $9,000 | | | | 3 T Power | 1 man, 1 wk | 84 mhr © | Fixtures, wire, T $1,300, T | | | $53.65, | conduit | 300 1b. | | | | |_ $4,500 | | | | | 4 7 Site Lighting T 2 men, 2 wks| 336 mhr © | Lights, wire, T $3,800, [Man lift | 168 hours 1 | | | $53.65, | conduit | 300 1b. | | | | |_ $18,000 | | | | | 5 | Process Electrical 2 men, 3 wks| 504 mhr @ | Starters, wire, T $10,500, T T | | | $53.65, | conduit, panels | 5,300 1b. | | i | | |_ $27,000 | | | | | 6 | Motor Control | 2 men, 3 wks] 504 mhr @ T Starters, controls, [| $35,500, T T ! | | | $53.65, | wire, conduit, | 4,000 1b. | | | | | |_ $27,000 |_panels | | | | 7 7 Material Handling | crew size | 80 mhr ©@ T T T T 1 | (5%) | dependent | $44.25, | | | | | | | on tasks | $3,600 | | | | | | | described | | | | | | I | in this | | | | | | | |_section | | | | i | T T T T T T T | Kl | ELECTRIC GENERATION | | i | | | | 2 T Switch Gear | 4 men, 4 wks] 1,344 mhr @ [| Switch gear T $150,000, T T 1 | | | $53.65, | | 30,000 1b. | | | | | |_ $72,100 | | | | | 3 T Substation T 3 men, 3 wks] 756 mhr @ | Transformers T $150,000, T Crane | 252 hours I | I | $53.65, | 175,000 1b. | | | | | |_$40,600 | | | | | 4 | Material Handling | Crew size | 105 mhr @ | | | l | | (5%) | dependent | $44.25, | | I | ! | | on tasks | $4,600 | | | | | | | described | | | I | | | | in this I, | | | | | | |_section | | | I | | I I l I | | I | Ll | EXTERIOR FINISHING | | | | | | | 2 T Fence Erection [2 men, 1 wk | 168 mhr @ | Chain link fence T $5,000, T Backhoe T 84 hours if | | | $45.31, | | 5,000 1b. | | | | | |_ $7,600 | | | | | 3 | Miscellaneous and [2 men, 2 wks] 336 mhr @ T T T Loader, T 84 hours each | | Cleanup | | $45.31, | | | dump | | | | |_ $15,200 | | | | | 4 | Material Handling T Crew size [| 50 mhr @ T T T T | | (10%) | dependent | $44.25, | | | I | | | on tasks | $2,200 I | | | | | | described | | I | | | | | in this | | | | | | | | section | | | | I | T I ] ] T T | M1 | DEMOBILIZATION | Crew size | 2,016 mhr@ | | | | | | | varies | $50.00, | | | | | | I |_ $100,800 | | | | I TOTAL $2,436,300 $4,536,800 $2,201,100 <less Mobe/Demobe> F=19 3,027,800 1b. BASE CASE DISTRICT HEATING DISTRIBUTION SYSTEM | Material | Equipment | Equipment Hours | | | | Iten| Description | Crew Size | Man-hours’ | Description | No.| of Task | Time | Labor Rate, | of Material | Cost, Weight | Requirements | Rate and Cost I | Required |__and Cost | | | I T I T T T T T Al | MOBILIZATION OF | | | | | | | EQUIPMENT AND WORK- | | | | | | | FORCE TO THE SITE | | | | | | 2 T Cost of Material, T Crew size [| 2,016 mhr @ [| T T T | Freight, and Equipment| dependent | $50.00, | | | | | Standby, as delineated] on tasks | $100,800 | | | | | by the following | described | | | | | | items, will be | | | | | | | included during | | | | | | |_mobilization | | | | I | T I T I T T T Bl | INSTALLATION | | | | | | _ 2 T Surveying T 6 men, 5 wks] 2,520 mhr @ [| T T 7 | | | $50.00 | | | | | | |_ $126,000 | | | | : 3 J Ditching | 2 men, 4 wks] 672 mhr © T T T 2 Backhoes | 672 hours | | | $48.50 | | | (large) | | | |_ $32,600 | | | | 4 | Utility Conflicts | Crew size | 840 mhr @ T T T T | | | $48.50, | | | | | | |_ $40,700 | | | | 5 | Bedding & Compacting | 4 men, 3 wks] 1,008 mhr @ | 8,500 yds. T $2.00/yd., | Dump, loader,[ 252 hours, | | | $43.41, | | $17,000 | 2 compactors | dump and com- | | | $43,800 | | | | pactors, | | | | | | | loader included | | | | | | | with plant 6 | Laying Pipe T 6 men, 8 wks] 4,032 mhr @ | 2 in., 4,100 ft. T $36,100, | Flatbed, T 672 hours, | | | $43.79, | | 20,500 1b.; | 1 backhoe, | flatbed, | | | $176,600; | 2-1/2 ins, 14,000 ft.| $14,400, | 4 welders | backhoe; | Welding | 8 men, 9 wks| 6,048 mhr @ | | 70,000 1b.; | | 3,024 hours, | | | $47.88, | 3 in., 2,000 ft. | $23,800, | | welder | | | $289,600 | | 30,000 1b.; | | | | | | 4 in., 8,100 ft. | $136,900, | | | | | | | 121,500 1b.; | | | | | | 6 in., 2,900 ft. | $73,100, | | | | | | | 72,500 1lb.; | | | | | | 8 in., 13,700 ft. | $464,400, | | | | | | | 479,500 1b.; | | | | | | 10 in., 3,500 ft. | $156,800, | | | | | | | 192,500 1b.; | | | I | | 12 in., 900 ft. | $54,200, | | | | | | | 58,500 lb; | | | | | | 14 in., 300 ft. | $23,400, | | | | | | [24,000 1b. | | 7 T Backfilling | 2 men, 4 wks] 672 mhr © T T | 2 CATS T 672 hours | | | $48.50, | | | | | | |_ $32,600 | | | | 8 | Compacting |4 men, 3 wks] 1,008 mhr @ | T | 2 Compactors | 252 hours | | | $44.18, | | | | | | |_ $44,500 | | | | 9 | Material Handling | Crew size | 840 mhr @ T T T T | (5%) | dependent | $39.85, | | | | | | on tasks | $33,500 | | | | | | described | | | | | | | in this | | | | | | |_ section | | I | | T T T T T T T C1 | INDIVIDUAL HOUSE | | | | | | |_TIE-IN | | | | | | a 2 | Estimate for 1,400 | 12 men, “| 11,200 mhr @ | Heat exchangers T $700,000, T T | individual connections] 11 wks | $50.00, | | 84,000 1b.; | | | | | $560,000 | Valves and Fittings | $84,000, | | | | | | [21,000 1b. | | . T I T T T T T D1 | DEMOBILIZATION | Crew size | 1,512 mhr @ | | | | | | varies | $50.00, | | | | | | |_ $75,600 | i I too _. TOTAL $1,556,300 $1,784,100 $1,379,900 <less Mobe/Demobe> 1,174,000 1b. F-20 PROJECT EQUIPMENT COST SUMMARY BASE CASE Monthly Project Rental Operation Maintenance Replacement Fuel & Lube Item Weight Rate Length Cost Hours Cost Parts Cost Air Compressor 2,000 1b. 1,300 13 months 16,900 672 hrs. 900 300 600 gal, $ 800 Auger 30,000 1b. 6,800 s 88,400 84 hrs. 2,000 800 1,200 gal, 1,700 Back Hoe 20,000 1b. 3,200 i" 41,600 336 hrs. 1,600 700 200 gal, 300 Compactor (one 21,000 1b. 4,700 : 61,100 336 hrs. 3,900 1,300 1,600 gal, 2,100 large, one small) CAT 31,000 Ib. 5,700 a 77,100 336 hrs. 3,700 1,500 2,300 gal, 3,100 Crane 200,000 Ib. 9,900 = 128,700 1,176 hrs. 59,600 23,900 15,500 gal, 20,900 Oump Truck x 2 30,000 1b.x2 4,400x2 . 114,400 756 hrs. 4,300 3,100 4,100 gal, 5,500 Loader 45,000 1b. 5,600 a 72,800 504 hrs. 7,600 5,200 3,700 gal, 5,000 Man Lift 5,000 1b. 2,100 ba 27,300 2,016 hrs. 11,200 1,900 3,400 gal, 4,500 Mixer & Water 6,000 Ib. 1,400 s 18,200 252 hrs. 400 200 300 gal, 400 Trailer Heater 1,000 1b. 1,200 a 15,600 840 hrs. 200 100 2,900 gal, 4,000 Welder 2,000 1b.x4 600x4 a 31,200 3,612 hrs. 3,200 400 6,800 gal, 9,200 TOTALS 215 tons $ 690,300 $ 98,600 $ 39,400 $ 57,500 TOTAL COST $885 800 F-21 PROJECT EQUIPMENT COST SUMMARY BASE CASE DISTRICT HEATING DISTRIBUTION SYSTEM Monthly Project Rental Operation Item Weight Rate Length Cost Hours Sa) ae Backhoe (large) 40,000 1b.x2 5,800 6 months 69,600 672 hrs. Backhoe (small) 20,000 Ib. 3,200 . 19,200 672 hrs. Compactor (one 21,000 1b. 4,700 = 28,200 504 hrs. large, one small) CAT (large) 115,000 Ib.x2 9,900 i, 118,800 672 hrs. Dump Truck 200,000 1b. 9,900 ® 59,400 252 hrs. (large) Flatbed 15,000 Ib. 1,500 * 9,000 672 hrs. Welder 2,000 1b.x4 600x4 , 14,400 3,024 hrs. TOTALS 287 tons $318,600 F-22 Maintenance Cost 9,600 3,000 5,400 21,200 12,000 700 2,500 $54,400 Replacement Parts 2,600 1,400 2,000 9,200 5,100 900 300 $21,500 TOTAL COST Fuel & Lube Cost 2,400 gal, 1,500 gal, 2,400 gal, 3,200 2,000 3,200 12,000 gal, 3,300 gal, 16,200 4,500 5,700 gal, 5,700 gal, 7,700 7,700 $44,500 * $439,000 CONSTRUCTION SCHEDULE BASE CASE | x 5 2 8 ra) ee <= — — — — — — — — — — = a 2 q “ 3 Se ae ee eee 3 2 4 7 | a | | ee eee ” | | | 9 a | dy 2 2 i BI Py)! g | 1 i a a ee eee 5 1 | |’ | | a ‘| | , | ea ee ee et es 5 177 i a 1 ' el | | ee ee ee g Le gs3h go «BBS bog aie E 3 g §4 bob ag Sifi , «8 88 eea,k 9 g38 Ue Ba. 8 8h ‘ fou Seddbes 5 Baei gh gt Ss ge | 2 BRE gee Bsstees. o Geek 2 28 Fdeeetd FEL § 2 2 28 gaz ghed 28 2 5 Qn? Seu ,8S FS Bee § 828 Ags shaghsFs Begesse*. of Fa geeehse aos Fog. 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Fekades Lea geteakegasas Isaa shes & gg gman en ginmem ga nee Gam em gam ene Reg ganen ga game a en gan gam g w FwWNr N CONSTRUCTION SCHEDULE - BASE CASE DISTRICT HEATING DISTRIBUTION SYSTEM WEEK 123 415 6 7 8/9 10 11 12/13 14 15 16|17 18 19 20/21 22 23 24 | INSTALLATION| Surveying -------|-- Ditching ---|-- Utility ---|-- | Conflicts | Bedding & — | | | | Compaction Laying Pipe —— Welding Backfilling Compacting |) ite | hE HOUSE | TIE-INS Connections ee F-24 3, COGENERATION (ALTERNATIVE ''A") ro Pee eee orem Size Man-hours Description Material Equipment Equipment Hours . ime Labor Rate, of Material Cost, Weight Requirements Rate and Cost Required and Cost Al MOBILIZATION OF EQUIPMENT AND WORK~ FORCE TO THE SITE 2 [Cost of Material, Crew size | 2,688 mhr @ Freight, and Equipment| dependent $50.00, Standby, as delineated| on tasks $134,400 by the following described items, will be included during mobilization Bl SITE PREPARATION 2 | Grubbing and Surveying] 4 men,1 wk 336 mhr @ $50.00 $16,800 a Dirt Work *12 men, 4,032 mhr @ 20,500 yds. gravel $2.00/yrd. CAT, loader, 672 hours each 4 wks $46.75 (3.1 acres) $41,000 2 dumps, $188,600 water trailer 4 | Land Costs 3 acres $30,000 (For info. only) cl BUILDING FOUNDATION 2 Install Piling *14 men, 2,352 mhr @ 146 piles, 30'x60 1b.| $0.35/1b, Mixer, auger,| 336 hours each 2 wks $47.08 $92,000 backhoe, $110,800 263,000 1b. water trailer crane 3] Slab Steel, Pans & ¥14 men, 1,176 mhr @ 24,750 eq.ft. pan $3.00/aq.ft. Crane, 168 hours, Beams 1 wk $48.08 $74,300, 2 welders, crane and $56,500 123,800 1b.; torch welders 1,600 ft. beam, $0.35/1b., 100 1b./ft. $56,000, 160,000 1b. 4 7] Slab Insulation (Included 49,500 BF Styrofoam $0.40/BF, in Item C3) $19,800, 6,200 1b. 5 | Slab Reinforcement 6 men, 1 wk | 504 mhr @ 80,000 ft. #5 Rebar $0.40/ft, Crane, torch | 84 hours, $48.08, $32,000, crane and $24,200 80,000 1b. welders 6 | Slab Concrete Pour *30 men,l wk | 3,192 mhr @ 900 yds. gravel $2.00/yd, Mixer, crane,| 252 hours each 8 men, 1 wk | $46.16, $1,800 bucket, $147,300 | 4,500 sacks Cemen $6.00/sack, loader, water $27,000; truck, dump 405,000 1b. 7 ] Boiler Support and (Included 1,500 ft. beam, $0.35/1b, (Included in Steam Turbine Support in Items 60 Vb. //£tis $31,500, Items C3 and C3 and C6) 90,000 1b.; C6) 40 yds gravel 200 sacks cement $6.00/sack, $1,200, 18,000 1b. * Double Shift COGENERATION (ALTERNATIVE “A") | | | | | | Item| Description | Crew Size | Man-hours | Description | Material | Equipment | Equipment Hours No. | of Task | Time | Labor Rate, | of Material | Cost, Weight | Requirements | Rate and Cost | | Required |__and Cost | | | T T ] T T Ty C8 | Material Handling | Crew size | 1,080 mhr @ | 12 bottles oxygen, | $700, | | | (15%) | dependent | $44.25 | 5 bottles acetylene | 2,800 1b.; | | | | on tasks | $47,800 | Fasteners and rebar | $2,000, | | | | described | | chairs | 1,000 1b. | | | | in this | | | | | | |_section | | | | | T T T T T I T D1 | BUILDING ERECTION I | I | | | 2 7 Steel Frame | 4 men,4 wks | 1,344 mhr @ | Steel frame $242,000, | Crane**, T 336 hours, | (Walls Only) | | $47.13 | ‘30, 000 ibe; | welder | welder | | | $63,300 | Siding and Socio $161,700 | | | | | | | (weight incl. | | | | | | |_above) | | 3 | Siding, Insulation, T*8 men,4 wks | 2,688 mhr @ | Fasteners T $2,000, T Crane**, | 756 hours, | and Overhead Doors | | $47.13, | | 1,000 1b.; | welder | man lift | | | $126,700 | | | | | | | 336 mhr @ | 2 Overhead doors | $30,000 | | | | | $47.88, | | (weight incl. | | | | |_ $16,100 | |_in Item D2) | | 4 T Roof (including T*8 men,2 wks | 1,344 mhr @ | Fasteners T $1,500, | Crane**® T | perlins and | | $47. 13 | | 1,000 1b. | | |_insulations) | |_ $63,400 | | | | 5 T Overhead Crane [6 men,2 wks | 1, 008 mhr @ | Crane T $300, 000, T T | (installed in | | $48.08, | | 35,000 1b. | | |_ building) | |_ $48,500 | | | | 6 | Material Handling | Crew size | So mhr T T 2 Air T 640 hours each | (10%) | dependent | $44.25 | | | compressors | | | on tasks | $28,300 | | | 4 pneumatic | | | described | | | | guns | | | in this | | | | | | |_section | | | | | T T T T T T T El | BOILER ERECTION | | | | | | 2 T Installation, Bolting, |*30 men, T 25,200 mhr @ | 1 —- 130xl0 million | $2,400,000, | Crane, T 1,680 hours | Welding | 10 wks | $47.96, | Btu/hr boiler | 400,000 1b. | 2 welders | each | | |_$1,208,600__| | | | 3 7 District Heat System | 5 men,2 wks | B40 ahr @ T 25,000 1b. steam/hr $115,000, T Crane**, T 168 hours, | Auxiliary Boiler | | $47.96, | boiler | 30,000 1b. | welder | welder | | |_ $40,300 | | | | __ al. T ] T T I Fl | PROCESS EQUIPMENT | | | | | | 2 T Coal Pulverizer and | *8 men,7 wks] 4,704 mhr @ Pulverizer and screen! $150,000, ‘| Crane**, | 672 hours, | Screening System | | $47.88, | | 75,000 1b. | welder | welder | | |_ $225,200 | | | 3 | Coal In-Feed System | *8 men,5 wks| 3,360 mhr @ Silo, hopper, T-$650,000, | Crane**, T 840 hours, | | $47.88, | conveyor | 150,000 1b. welder | welder 160,900 4 T Ash Conveyor and | 3 men,2 wks | 504 Dhr é | Ash conveyor and $130,000, T Crane**, 168 hours, | Hopper | | $47.88 | hopper | 80,000 1b. | welder | welder | | [$24,100 | | | | _ * Double Shift ak F-26 Crane operation simultaneous with boiler installation. COGENERATION (ALTERNATIVE “A™) | | | | | | Item| Description | Crew Size | Man-hours | Description | Material | Equipment | Equipment Hours No. | of Task | Time | Labor Rate, | of Material | Cost, Weight | Requirements | Rate and Cost | |_ Required |__and Cost | | | | T T T T T" F5 | Stockpile In-Feed Box,| 5 men, 3 wks! 1,260 mhr @ | In-feed box, | $185,000, | Crane** | 252 hours, | Conveyor, and Supports| | $48. 00, | conveyor, and | 62,000 1b. | (2 wks), | welder | |_ $60, 500 |_supports | |_welder | 6 | Piping T*12 men, [35 104 mhe @ 7 Piping T $372,500, | 2 welders | 2,184 hours, | | 13 wks | $47. 88 | | 51,200 1b.; | | welder (x2) | | | $627,400 | Expansion tank | $45,000, | 2 torches | | | | | | 45,000 lb.; | | | | | | 10 hp air compressor | $10,000, | | | | | | | 1,000 1b. | | 7 T Pumps *12 men, | 2,016 mhr @ | Pumps T $330,000, | 2 welders | 3 hours, | 2 wks | $47.88, | | 220,000 1b. | 2 torches | welders (x2) | |_ $96,500 | | | | 8 | Air Condensor *12 men, T 3,026 mhr @ | Condensor T $550,000, | 2 welders T 504 hours, | | 3 wks | $47.88, | | 100,000 1b. | 2 torches | welder (x2) | | |_ $144, 800 | | | | 9 | Heat Exchangers | 6 men, 3 wks| 1, 312 mhr @ [7 2 = 50x10 million T $222,000, | Welder, | 252 hours, | | | $47. 88, | Btu/hr each | 110,000 1b.; | torch | welder | | |_ $72,400 | | | | 10] Water and Glycol 4 men, 1 wk | 336 mhr @ | Equipment T $150,000, T T | Treatment and Mixing | | $48.35, | | 100,000 1b.; | | | | | $16,300 | | | | | | | | 75,000 glycol | $4.00/gal., | | | | | | | $300,000, | | | | | | | 625,000 1b. | | 11] Boiler Water [6 men, 1 wk | 504 mhr @ | Injection system T $75,000, T T | Treatment | | $48.35 | | 50,000 1b. | | | |_$24 400 | | | | 12] Boiler-Feed Water 5 men, 1 wk | 420 mhr © | Make-up system T $100,000, T T | System | | $48.35, | | 20,000 1b. | | | | |_ $20,300 | | | | 13] Feed Water Heater, 8 men, 2 wks] 1,344 mhr @ [| Feed water equipment | $80,000, | Crane**, T 168 hours, | Deaerator, and | | $48.35, | | 40,000 1b. | welder | welder | Evaporator Make-u} | |_ $65,000 | | | | 14] Equipment Structural T T T | Stands and Service | | | | | | | Platforms | | | | | | | Structural Stands | 4 men, 4 wks| 1,344 mhr @ | Steel beams and | $50,000, | Crane**, | 336 hours, | | | $48.00, | plates | 40,000 1b. | welder | welder | | | $64,500 | | | | | Platforms | 4 men, 6 wks| 2,016 mhr @ | Steel beams and | $62,500, | Crane **, | 336 hours, | | | $48.00, | plates | 50,000 1b. | welder | welder | | |_ $96,800 | | | I 15] Steam Turbines [*12 men, T 10,080 mhr @ | 2 - 5 MW turbines T $2,700,000, | Crane**, “| 1,680 hours, | | 10 wks | $47.88, | | 180,000 1b. | welder | welder | |_ $482,600 | | | 16] Oil Storage Tanks 4 men, 2 wks] 672 mhr @ T 2 - 25,000 gal. tanks| $40,000, T Crane **, 168 hours, | | | $48.35,, | | 40,000 1b. =| welder | welder | | |_ $32,500 | | | | * Double Shift ** Crane operation simultaneous with boiler installation. F-27 COGENERATION (ALTERNATIVE "A™) | | | | | | Item| Description | Crew Size | Man-hours | Description | Material | Equipment | Equipment Hour: No. | of Task | Time | Labor Rate, | of Material | Cost, Weight | Requirements | Rate and Cost | : Required and Cost | | | - T T T 17| Material Handling | Crew size | 1,100 mhr @ | Fasteners | $5,000; | | | (3%) | dependent | $44.25, | | 2,500 1b.; | | | | on tasks | $48,700 | 40 bottles oxygen, | $2,500, | | | | described | | 20 bottles acetylene | 10,000 1b. | | | | in this | | | | | | |_ section | | | i | T T T T T T T G1 | CARPENTRY, PLUMBING, | | | | | | | INTERIOR FINISH WORK | | | | | | 2 7 Framing, Doors, | 3 men,3 wks | 756 mhr © Lumber and plywood | $2,000, T Air T 252 hours | Sheet Rock | | $49.35 | | 15,000 1b.; | compressor | | | | $37,300 | Doors and windows | $3,500, | | | | | | 11,200 1b; | | | | | Sheet rock | $1,000, | | | | | | | 5,000 1b.; | | | | | | Nails and fasteners | $2,500, | | | | | | | 100 1b. | | 3 7 Plumbing (Bathroom, | 3 men,3 wks | 756 mhr © | Pipe and fittings T $4,000, | Backhoe T 252 hours | Drains, and Utility | | $49.72, | | 2,000 1b. | (1 wk) | | Connections) | | $37,600 | Fixtures | $1,000; I | | | | | |_100 1b. | | 4 T Heating & Ventilation: | T T T T . | Office | 3 men,2 wks | 504 mhr @ | Heater, ducts, fans | $7,500, | | | | | $52.45, | | 2,000 1b. | | | | | $26,400; | | | | | Plant | 3 men,5 wks | 1,260 mhr @ | Ducts, auxiliary | $150,000, | | | | | $52.45 | heaters | 15,000 1b. | | | | |_$66,100 | | | | 5 | Painting and Finish | 5 men,2 wks | 840 mhr © T Paint T $3, 800, T T Work | $50.55, | | 1,900 1b. 42,500 6 | Material Handling T Crew size 225 mhr@ | T T T | (5%) | dependent | $44.25, | | | | | | on tasks | $10,000 | | | | | | described | | | | | | | in this | | | | | | |_section | | | | | T T T I I I T H1 | ELECTRICAL WORK | | | | | | 2 7 Plant Lighting | 4 men,2 wks | 672 mhr @ | Lights, wire, T $25,000, | Man lift 672 hours | | | $53.65 | conduit | 3,000 1b. | | | | |_ $36,000 | | | | 3 7 Plant Power | 4 men,2 wks | 672 mhr @ | Fixures, wire, T $10,000, T | | | $53.65 | conduit | 2,000 1b. | | | | |_ $36,000 | | | | 4 T Process Electrical 3 men,6 wks | 1,512 mhr @ | Starters, wire, T $30,000, | | | $53.65, | conduit, panels [15,000 1b. | | | | |_ $81,100 | | | | 5 7 Motor Control 2 men,? wks | 1,176 mhr Starters, controls, | $101,300, T T I | | $53.65, | wire, conduit, panels} 11,300 1b. | | | | |_ $63,100 | | | * Double Shift ** = ©6Crane operation simultaneous with boiler installation. F-28 COGENERATION (ALTERNATIVE “A") $5,290,100 <less mobe/demobe> F-29 4,313,200 1b. | | | | | | Item| Description | Crew Size | Man-hours | Description | Material | Equipment | Equipment Hours No. | of Task | Time | Labor Rate, | of Material | Cost, Weight | Requirements | Rate and Cost | | Required and Cost | I | | I I I I T T 6 | Site Lighting | 4 men, 2 wks| 672 mhr @ | Lights, wire, | $15,000, | Man lift | 672 hours | | | $53.65, | conduit | 1,100 1b. | | ! | |_$36 000 | | | | 7 | Material Handling | Crew size | 235 mhr @ T T T T | (5%) | dependent | $44.25 | | | | | | on tasks | $10,400 | | | | | | described | | | | | | | in this | | | | | | |_section | | | | | T T I T T I T I1 | ELECTRIC GENERATION | | | | | | 2 7 Switch Gear T 8 men, 6 wks| 4,032 mhr @ | Switch gear T $400,000, T T | | | $53.65, | | 30,000 1b. | | | | |_ $216,300 | | | I 3 | Substation T 6 men, 3 wks| 1,512 mhr @ | Transformers T $300,000, T Crane | 252 hours | | | $53.65 | | 150,000 1b. | | | | |_ $81,100 | | | | 4 | Material Handling | Crew size | 280 mhre@ | T T T | (5%) | dependent | $44.25, | | | | | | on tasks | $12,300 | | | | | | described | | | | | | | in this | | | | | | | section | | | | | T I I T T T J1 | EXTERIOR FINISHING | | | | | | 2 7 Fence Erection | 4 men, 1 wk | 336 mhr @ | Chain link fence T $10,000, | Backhoe T 84 hours | | | $45.31, | | 10,000 1b. | | | | |_ $15,200 | | | | 3 T Miscellaneous and 1 4 men, 2 wks] 672 mhr @ T T | Loader, dump | 168 hours | Cleanup | | $45.31, | | | | | | |_ $30,400 | | | | 4 T Material Handling | Crew size | 50 mhr © T T T T | | dependent | $44.25, | | | | | | on tasks | $2,200 | | | | | | described | | | | | | | in this | | | | | | |_ section | I | | | T T T T T T Kl | DEMOBILIZATION | Crew size | 2,016 hr@ | | |: | | | varies | $50.00, | | | | | | |_$100, 800 | | | | TOTAL $5,525,300 $10, 907,600 COGENERATION (ALTERNATIVE “A") DISTRICT HEATING DISTRIBUTION SYSTEM Cl | INDIVIDUAL HOUSE |_ TIE-IN | | | | Item| Description | Crew Size | Man-hours | Description | Material | Equipment | Equipment Hours No.| of Task | Time | Labor Rate, | of Material | Cost, Weight | Requirements | Rate and Cost | | Required |__and Cost | | | | T T T T ~T Al | MOBILIZATION OF | | | | | | | EQUIPMENT AND WORK- | | | | | | |_ FORCE TO THE SITE | | | | | | 2 T Cost of Material, T Crew size | 2,016 mhr © | T | Freight, and Equipment | dependent | $50.00, | | | | | Standby, as delineated] on tasks | $100,800 | | | | | by the following | described | | | | | | items, will be | | | | | | | included during | | | | | | |_mobilization | | | | | | T T T T T T T Bl | INSTALLATION | | | | | | 2 T Surveying T 6 men, 5 wks] 2,520 mhr @ | T T T | | | $50.00 | | | | | | [$126,000 | | | | 3 7 Ditching | 2 men, 4 wks! 672 mhre@ | 2 Backhoes 672 hours | | | $48.50 | | | (large) | | | |_$32,600 | | 47 Utility Conflicts | Crew size T 840 mhr | | | $48.50, | | | | | | |_ $40,700 | | | | 5 | Bedding & Compacting | 4 men, 3 wks| 1,008 mhr @ | 8,500 yds. T $2.00/yd., | Dump, loader,] 252 hours, | | | $43.41, | | $17,000 | 2 compactors | dump and com- | | | $43,800 | | | | pactors, | | | | | | | loader included | | | | | | |_with plant 6 | Laying Pipe | 6 men, 8 wks| 4,032 mhr @ | 2 in., 4,100 ft. T $36,100, | Flatbed, T 672 hours, | | | $43.79, | | 20,500 1b.; | 1 backhoe, | flatbed, I | | $176,600; | 2-1/2 in., 14,000 ft.| $14,400, | 4 welders | backhoe; | Welding | 8 men, 9 wks| 6,048 mhr @ | | 70,000 1b.; | | 3,024 hours, | | | $47.88, | 3 ine, 2,000 ft. | $23,800, | | welder | | | $289,600 | | 30,000 1b.; | | | | | | 4 in., 8,100 ft. | $136,900, | | | | | | | 121,500 1b.; | | | | | | 6 in., 2,900 ft. | $73,100, | | | | | | | 72,500 1b.; | | | | | | 8 in., 13,700 fr. | $464,400, | | | | | | | 479,500 1b.; | | | | | | 10 in., 3,500 ft. | $156,800, | | | | | | | 192,500 1b.; | | | | | | 12 in., 900 ft. | $54,200, | | | | | | | 58,500 1lb.; | | | | | | 14 in., 300 ft. | $23,400, | | | | | | |_24,000 1b. __| I 7 T Backfilling [2 men, 4 wks! 672 mhr @ | T [2 cats T 672 hours | | | $48.50, | | | | | | |_$32,600 | | | | 8 | Compacting T 4 men, 3 wks| 1,008 mhr @ | T | 2 Compactors | 252 hours | | | $44.18, | | | | | | | $44,500 | | | | T T T T 9 | Material Handling | Crew size | 840 mhr @ | | | | t (5%) | dependent | $39.35, | | | | | | on tasks | $33,500 | | | | | | described | | | | | | | in this | | | | | I |_ section | | | | | Tt T T T T | | | 2 | Estimate for 1,400 12 men, T 11,200 mhr @ | Heat exchangers $700,000, | | | | I T | individual connections| 11 wks | $50.00, | | 84,000 1b.; | | | | | $560,000 | Valves and Fittings | $84,000, | | | | | | [21,000 1b. | | I an TT T T T D1 | DEMOBILIZATION | Crew size | 1,512 mhr@ | | | | | | varies | $50.00, | | | | | | |_$75,600 | | | do. = TOTAL $1,556,300 $1,784,100 $1,379,900 <less Mobe/Demobe> 1,174,000 1b. F-30 PROJECT EQUIPMENT COST SUMMARY COGENERATION (ALTERNATIVE "A") Fuel & Lube Item Weight Rate Length Cost Hours Cost Parts Cost Air Compressor 2,000 Auger 30,000 Back Hoe 20,000 Compactor (one 21,000 large, one small) Tb. Tb. Tb. lb. CAT 31,000 Ib. Crane 200,000 1b. Oump Truck 30,000 1b.x2 Loader 45,000 1b. Man Lift 5,000 1b.x2 Mixer & Water 6,000 Ib. Trailer Heater 1,000 1b. Welder 2,000 1b.x7 TOTALS 220 tons F-31 Monthly Project Rental Operation Maintenance Replacement 1,300 13 months 16,900 892 hrs. 1,200 400 6,800 " 88,400 336 hrs. 7,800 3,200 3,200 " 41,600 672 hrs. 3,200 1,400 4,700 " 61,100 672 hrs. 7,200 2,700 5,700 bs 74,100 672 hrs. 7,400 2,900 9,900 ® 128,700 3,864 hrs. 182,000 78,500 4,400x2 s 114,400 1,764 hrs. 9,400 7,200 5,600 “ 72,800 1,092 hrs. 16,300 11,300 2,100x2 " 54,600 2,856 hrs. 15,800 2,700 1,400 " 18,200 588 hrs. 1,000 400 1,200 * 15,600 1,680 hrs. 300 200 600x7 = 54,600 15,120 hrs. 12,400 1,500 $741,000 $264,000 $112,400 TOTAL COST 800 gal, $ 1,100 5,000 gal, 6,700 1,500 gal, 2,000 3,200 gal, 4,300 4,600 gal, 6,200 50,900 gal, 68,700 9,500 gal, 12,800 7,900 gal, 10,700 4,800 gal, 6,500 700 gal, 1,000 5,900 gal, 8,000 28,600 gal, 38,600 $166 ,600 $1,284,000 PROJECT EQUIPMENT COST SUMMARY COGENERATION (ALTERNATIVE "A") DISTRICT HEATING DISTRIBUTION SYSTEM Monthly Project Rental Operation Maintenance Replacement Fuel & Lube Item Weight Rate Length Cost Hours Cost Parts Cost 3 z 3 $ Backhoe (large) 40,000 1b.x2 5,800x2 6 months 69,600 672 hrs. 9,600 2,600 2,400 gal, $ 3,200 Backhoe (Small) 20,000 1b. 3,200 . 19,200 672 hrs. 3,000 1,400 1,500 gal, 2,000 Compactor (one 21,000 1b. 4,700 . 28,200 504 hrs. 5,400 2,000 2,400 gal, 3,200 large, one small) CAT (large) 115,000 1b.x2 9,900x2 * 118,800 672 hrs. 21,200 9,200 12,000 gal, 16,200 Oump Truck 200,000 1b. 9,900 “ 59,400 252 hrs. 12,000 5,100 3,300 gal, 4,500 (large) Flatbed 15,000 Ib. 1,500 . 9,000 672 nrs. 700 900 5,700 gal, 7,700 Welder 2,000 1b.x4 600x4 : 14,400 3,024 hrs. 2,500 300 5,700 gal, 7,700 TOTALS 287 tons $318,600 $54,400 $21,500 $44,500 TOTAL COST $439,000 F-32 CONSTRUCTION SCHEDULE - COGENERATLON (ALTERNATLVE _ WEEK 123 4)5 67 8/9 10 11 12/13 14 15 16/17 18 19 20/21 22 23 24/25 26 27 28/29 30 31 32/33 34 35 36/37 38 39 Al MOBE nennene|------- Bl SITE PREPARATION 2 Surveying, Clearing 3 Dirt Work ferserien | te cl BUILDING FOUNDATION 2 Piling ale 3 Steel * 4 Ineulation we 5 Reinforce~ -- ment 6 Pour * 7 Equipment + Supporte Dl BUILDING ERECTION 2 Frame =| -------- 3 siding eis | ik 4 Roof yori | 5 O/M Crane all ered | El BOLLER | ERECTION | 2 Installation EEO IER TODS II IO. toto 3 Auxiliary Salons Boiler FL PROCESS EQUIPMENT | zi Coal Sek telcioirioioioioioiOn | toto Pulverizer 3 Coal In-Feed JOOIIIOIION | sot Rt 4 Ash Conveyor 2s |S Hopper Bi Stockpile awones. | Conveyor | 6 Piping Jetieinio | innidtioinii inion | onde ieee | inion 7 Pumps fi 8 Air Seto toon Conditioners | 9 Neat | | wn---|--- Exchangers 10 Water —— Treatment | is Boiler — Treatment 12 Boiler Feed - Water | | 13. Feed Water Jo ee Heater 14 Struccural | | | fo |) ‘e=asuunn| anno wenee | ----=--. -< Stands 15 Steam FEISS JOTI II II FOCI IACI In Turbin 16 Oil Storage --- Tanks GL FINISH WORK Zi Framing a Plumbing 4 Heating & aon---2-= Vene 5 nting & mane Finish HL ELECTRICAL | z ie we |--- Lighting S Plant Power wo---- 4 Process eonnsnennen arenes Electrical 5 Motor -- | ----------- Control | 6 Site od Lighting 1 ELECTRICAL GENERATLON 2 Switch Gear 3 Substation | ff enn J EXTERIOR 2 Fence _- 3 Cleanup — KL Demobe __ | Le L ti _ | ----- Single shift weet Double Shift CONSTRUCTION SCHEDULE COGENERATION (ALTERNATIVE "A") DISTRICT HEATING DISTRIBUTION SYSTEM WEEK 123 4/5 6 7 8/9 10 11 12]13 14 15 16/17 18 19 20/21 22 23 24 Al INSTALLATION 2 Surveying 3 Ditching 4 Utility Conflicts a Bedding & -|---- Compaction 6 Laying Pipe -----| ---------- --- Welding SS eS 7 Backfilling scan _— 8 Compacting —---|--- Bl HOUSE TIE-INS 2 Connections --~ | -———-——=-——-- | ----_—_----- a F-34 4. COAL FIRED LOW-PRESSURE DISTRICT HEATING SYSTEM (ALTERNATIVE "B") Item Description Crew Size Man-hours Description Material Equipment Equipment Hours No. of Task Time Labor Rate, of Material Cost, Weight | Requirements | Rate and Cost Required and Cost Al MOBILIZATION OF EQUIP- MENT AND WORKFORCE TO - THE SITE { Cost of material, Crew size 2688 mhr @ freight, and equipment) dependent $50.00, standby delineated by | on tasks $134,400 the following items, described will be incurred .below. during mobilization Bl SITE PREPARATION 2 |] Grubbing & Surveying 4 men, 1 wk | 336 mhr @ $50.00 $16,800 3] Dirt Work * 12 men 4,032 mhr @ | 20,000 yds. gravel $2.007yd, CAT, Loader, | 672 houre each | 4 wks $46.78 (3 acres) $40,000 2 dumps, $188,600 water trailer 4 | Land Cost 3 acres $30,000 (for info. only) { cl BUILDING FOUNDATION 2 Install Piling * 12 men, 2016 mhr @ 130 piles, 30'x60 1lb.| $0.35/1b, Mixer, auger,| 336 hours each 2 wks $47.08, $81,900; backhoe ,water $94,900 234,000 1b. trailer,crane S Slab Steel, Pans & * 12 men, 1008 mhr @ 22,000 sq.ft. pan $3.00/7sq.ft.,| Crane, 2 168 hours, Beams 1 wk $48.08, $66,000 welders crane and $48,500 110,000 1b.; torch welders 1,400 ft. beam, $0.35/1b, 100 1b. $49,000; 140,000 1b. 4 7 Slab Insulation (Included in 44,000 BF styrofoam $0.40/BF, Item ¢3) $17,600 5,500 1b. 5 | Stab Reinforcement 6 men, 1 wk | 504 mhr @ 70,000 ft. #5 rebar $0.407£t., Crane, torch | 84 hours, crane $48.08 | $28,000; (simultaneous $24,200 70,000 1b. with Item C3) 6 | Slab Concrete Pour *28 men,l wk | 2856 mhr @ 815 yrds. gravel $2.00/yd, Mixer, crane,| 252 hours each 6 men,l wk | $46.16 $1,700 bucket, $131,800 100 sacks cement $6,00/sack, loader, water $24,600; trailer, dump 369,000 1b. 7 | Boiler Supports (included in 750 ft. beam, 60 1b. | $0.35/1b, (included in Items C3 and 20 yds. gravel $15,800; Items C3 and C6) 45,000 lb. C6) 100 sacks cement $6.00/sack $600; 9,000 1b. * Double Shift COAL-FIRED LOW PRESSURE DISTRICT HEATING SYSTEM (ALTERNATIVE “B”) | | | | | | | Item! Description | Crew Size | Man-hours | Description | Material | Equipment | Equipment Hours No. | of Task | Time | Labor Rate, | of Material | Cost, Weight | Requirements | Rate and Cost | | Required |__and Cost | | | T T T C8 | Material Handling [Crew size | 960 mhr @ | 10 bottles oxygen, | $600, | | | (15%) ldependent on | $44.25 | 4 bottles acetylene, | 2,300 1b.; | | | | tasks | $42,500 | fasteners and | $2,000, | | | ldescribed in | | rebar chairs | 1,000 1b. | | | [this section | | | | | I T 1 | BUILDING ERECTION | | | | | 2 7 Steel Frame | 4 men, 4 wks| 1344 mhr @ | Steel frame $181,500, Crane **, 336 hours, | (walls Only) | | $47.13 | | 360,000 1b. | welder | welder | | | $63,300 | Siding & Insulation | $121,300 | | | | | | | (we. incl. | | | | | | |_above) | | | 3 | Siding, Insulation *8 men,4 wks| 2088 mhr © Fasteners $2,000, Crane **, 756 hours, | and Overhead Door | | $47.13 | | 1,000 1b. | man lift | man lift | | | | $126,700 | 2 Overhead doors | $30,000; | | | | 4 men,1 wk | 336 mhr @ | | (wt. inel. | | | | | $47.88 | | with Item 2) | | | | |_ $16,100 | | | | | 4 | Roof (including *8 men, 2wks 1344 mhs Fasteners $1,500; Crane ** | purlins & insulation) | | $47.13 | | 1,000 1b. | | | | |_ $63,400 | | | | | 5 Overhead Crane 6 men,2 wks 1008 mhr Overhead crane T $300, 000 Crane ** (Installed in | $48.08, ! 35,000 1b. | building) $48,500 | 6 | Material Handling T Crew size 640 mhr T 2 air 640 hours each | (10%) | dependent on| $44.25 | | | compressors | | | tasks | $28,300 | | | 4 pneumatic | | | described in| | | | guns | | | this section| | | | | El | BOILER ERECTION 2 Installation, eee *28 men, 28,224 mhr _ 3-30x10 million or 240,000, — 2016 hours cach | Welding | 12 wks | $47. 96 | Btu/hr Boilers | 450, 000 lb. | 2 welders | | | |_ $1,353,600 __| | | | | Fl | PROCESS EQUIPMENT | | | | | | | 2 Coal Conveyors *8 men,/7 wks| 4704 mhr Coal Conveyors $525,000; Crane **, 1176 hours, | | | $47.88 | | 150,000 lb. | welder | welder | | | |_ $225,200 | | | | | 3 | Coal Pulverizer T *6 men,4 wks| 2016 mhr © | Pulverizer and $150,000; Crane **, 672 hours, | | | $47.88 | screen | 75,000 1b. | welder | welder | | | |_ $96,500 | | | 4 | Coal Silo/Hopper 3 men,1l wk 252 mhr @ Coal silo and hopper | $25,000; Crane **, 84 hours, i | | | $47.88 | | 50,000 lb. | welder | welder | | | |_ $12,100 | | | | | 5 | Ash Conveyor/Hopper G men,2 wks | 672 mhr © Ash conveyor and $150,000; Crane **, 168 hours, ! | | | $47.88 | hopper | 100,000 1b | welder | welder | | | |_$32,200 | | | | | 6 Stockpile In-feed 5 men,3 wks 1260 mhr @ In-feed box, conveyor] $185,000; Crane ** 252 hours, | | Box, Conveyor, and | | $48.00 | and supports | 62,000 1b. | (2 wks) | welder | |_Supports | |_ $60,500 | | |_welder l | * Double Shift ** Crane operation simultaneous with boiler installation. F-36 COAL-FIRED LOW PRESSURE DISTRICT HEATING SYSTEM (ALTERNATIVE "B") | | | | | | | Item| Description | Crew Size | Man-hours§ | Description | Material | Equipment | Equipment Hour No. | of Task | Time | Labor Rate, | of Material | Cost, Weight | Requirements | Rate and Cost | |_ Required |__and Cost | | | | T TT ian ia T TT F7 | Piping & Pumps [*12 men,8 wks| 8064 mhr @ | Piping | $226,400, | 2 welders | 1344 hours, | | | $47.88 | | 23,200 lb. | 2 torches | welder | | | $386,100 | Pumps | $30,000; I | | | | | | 20,000 1b.; | | | | | | Expansion tank | $45,000; | | | | | | | 45,000 1b.; | | | | | | 10 hp air compressor | $10,000, | | | | | | | 1,000 1b. | | 8 Heat Exchangers 6 men,3 wks 1,512 mhr e 2 - 50 x 10 million | $220,000, Welder, 252 hours, | $47. 88, | Btu/hr each | 110,000 1b. | torch | welder | | $72,400 | | | | 9 | Water and Glycol 4 men, 1 wk | 336 mhr © Equipment T $150,000, | | | | $48.35, | | 100,000 1b. | | | | | $16,300 | | | | | | | | 75,000 gal glycol | $4.00/gal, | | | | | | | $300,000, | | | | | | | 625,000 1b.__| | 10| Material Handling Crew size 550 mhr @ | Fasteners ~T $3,000; | (3%) | dependent | $44.25 | | 1,500 1b.; | | | | on tasks | $24,300 130 bottles oxygen, | $1,900, | | | | described | |15 bottles acetylene | 7,500 lb. | | | | in this | | | | | | |_section | | | ee | G1 | CARPENTRY, PLUMBING, | | | | | | | INTERIOR FINISH WORK | | | | | | 2 | Framing, Doors, 3 men,3 wks | 756 mhr © Lumber & plywood $2,000, Air 252 hours | Sheet Rock | | $49.35 | | 15,000 1b.; | compressor | | | | $37,300 | Doors & windows | $3,500, | | | | | | | 1,200 ib.; | | | | | | Sheet rock | $l, 000, | | | | | | |_100 1b. | | 37 Plumbing (Bathroom, 3 men,3 wks | 756 mhr © Pipe and fittings T $4,000, T Backhoe 252 hours | Drains, and Utility | | $49.72 | | 2,000 1b.; =| (1 week) | | Connections) | | $37,600 | Fixtures | $1,000, | | | | | | [100 1b. | | 4 | Heating & Ventilation:] T T T T | Office | 3 men,2 wks | 504 mhr @ | Heater, ducts, fans | $7,500, | | | | | $52.45 | | 2,000 lb; | | | | | $26,400 | ducts, auxiliary | $100, 000, | | | Plant | 3 men,3 wks | 756 mhr @ | heaters | 10,000 1b. | | | | | $52.45 | | | | | | |_ $39,700 | | | | 5 | Painting & Finish Work] 4 men,2 wks | 672 mhr @ Paint T $3,000, T T | | | $50.55 | | 1,500 1b. | | | | | $34,000 | | | | 6 Material Handling Crew size 200 mhr @ | (7%) | dependent | $44.25 | | | | | | on tasks | $8,900 | | | | | | described | | | | | | | in this | | | | | | |_ section | l | | | * Double Shift F-37 COAL-FIRED LOW PRESSURE DISTRICT HEATING SYSTEM (ALTERNATIVE "B”) | | | | | | | Item| Description | Crew Size | Man-hours | Description | Material | Equipment | Equipment Hour No. | of Task | Time Labor Rate, | of Material | Cost, Weight | Requirements | Rate and Cost | | | | | | Required and Cost H1 | ELECTRICAL WORK | | | | | | 2 | Plant Lighting | 4 men,2 wks | 672 mhr © | Lights, wire, conduit T $25,000, Man lift 672 hours | | | $53.65 | | 3,000 1b. | | |_ $36,000 | | | 3 Plant Power 4 men,1] wk 336 mhr © Fixtures, wire, $5,000, | | | $53.65 | conduit | 1,000 1b. | | | | |_$18, 000 | | | | 4 Power Feeder 6 men,1] wk 504 mhr © Poles, wire trans- $30,000, | | | $53.65 | former, distribution | 10,000 1b. | | | | |_$27,000 |_ panel | | | 5 Process Electrical 2 men,6 wks 1,000 mhr Starters, wire, $20,000, | | | $53.65 | conduit, panels 110,000 1b. | | | | |_$54,100 | | | | 6 Motor Control 2 men,6 wks 1,008 mhr Starters, controls, $90,000, | | | $53.65 | wire, conduit, panels| 10,000 1b. | | | | |_ $54,100 | | | | 7 | Site Lighting | 4 men,2 wks | 672 mhr @ | Lights, wire, conduit| $15,000, | Man lift | 672 hours | | | $53.65 | | 1,000 1b. | | | | |_$36,100 | | | | 8 | Material Handling Crew size 200 mhr © | (5%) | dependent | $44.25 | | | | | | on tasks | $8,900 | | | | | | described | | | | | | | in this | | | | | | |_ section | | | | | Hg is SMT edad eft nt at aaa Ta a aa os a | ee | | | | | | 11 | EXTERIOR FINISHING Fence Erection 4 men,1 wk 336 mhr Chain link fence $10,000, Backhoe 84 hours | | $45.31 | | 10,000 1b. | | |_ $15,200 | | | 3 | Miscellaneous and 4 men,2 wks | 672 mhr Loader, Dump | 168 hours | Cleanup | | $45.31 | | | | |_$30,400 | | | | ' 4 | Material Hanlding Crew size 50 mhr | (5%) | dependent | $44.25 | | | | | | on tasks | $2,200 | | | | | | described | | | | | | | in this | | | | | | | | | | | |_section Jl | DEMOBILIZATION | Crew size | 2016 mhr@ | | | | | | varies | $50.00 | | | | | |_ $100,800 I | | l | TOTAL $3,873,900 $6,542,400 $3,638,700 <less mobe/demobe> 3,279,900 lb. F-38 COAL FIRED LOW-PRESSURE DISTRICT HEATING SYSTEM (ALTERNATIVE "B") DISTRICT HEATING DISTRIBUTION SYSTEM | | | | | | Item| Description | Crew Size | Man-hours | Description | Material | Equipment | Equipment Hours No. | of Task | Time | Labor Rate, | of Material | Cost, Weight | Requirements | Rate and Cost | |_ Required |__and Cost | I | | T T I T l T T Al | MOBILIZATION OF | | | | | | | EQUIPMENT AND WORK- | | | | | | |_FORCE TO THE SITE | | | | | | 2 T Cost of Material, T Crew size | 2,016 mhr @ | T T T | Freight, and Equipment| dependent | $50.00, | | | | | Standby, as delineated| on tasks | $100, 800 | | | | | by the following | described | | | | | | items, will be | | | | | | | included during | | | | | | |_mobilization | | | | | | T T I T T I T Bl | INSTALLATION | | | | | | 2 T Surveying | 6 men, 5 wks] 2,520 mhr @ | T T T | | | $50.00 | | | | | | |_$126,000 | | | | 3 7 Ditching | 2 men, 4 wks| 672 mhr © T T | 2 Backhoes | 672 hours | | | $48.50 | | | (large) | | | |_ $32,600 | | | | 4 7 Utility Conflicts T Crew size | 840 mhr @ T T T T | | | $48.50, | | | | | | |_ $40,700 | | | | 5 | Bedding & Compacting | 4 men, 3 wks| 1,008 mhr @ | 8,500 yds. T $2.00/yd., | Dump, loader,| 252 hours, | | | $43.41, | | $17,000 | 2 compactors | dump and com- | | | $43,800 | | | | pactors, | | | | | | | loader included | | | | | I |_ with plant 6 | Laying Pipe | 6 men, 8 wks] 4,032 mhr @ [| 2 in., 4,100 ft. T $36,100, | Flatbed, | 672 hours, | | | $43.79, | | 20,500 1b.; | 1 backhoe, | flatbed, | | | $176,600; | 2-1/2 in., 14,000 ft.| $14,400, | 4 welders | backhoe; | Welding | 8 men, 9 wks| 6,048 mhr @ | | 70,000 1b.; | | 3,024 hours, | | | $47.88, | 3 in., 2,000 ft. | $23,800, | | welder | | | $289,600 | | 30,000 1b.; | | | | | | 4 in., 8,100 ft. | $136,900, | | | | | | | 121,500 1b.; | | | | | | 6 in., 2,900 ft. | $73,100, | | | | | | | 72,500 1b; | | | | | | 8 in., 13,700 ft. | $464,400, | | | | | | | 479,500 1b.; | | | | | | 10 in., 3,500 fr. | $156,800, I | | | | | | 192,500 1b.; | | | | | | 12 ins, 900 ft. | $54,200, | | | | | | | 58,500 1b.; | | | | | | 14 in., 300 ft. | $23,400, | | | | | | [24,000 1b. | | 7 | Backfilling | 2 men, 4 wks| 672 mhr @ T T T 2 caTs T 672 hours | | | $48.50, | | | | | | |_ $32,600 | | | | 8 T Compacting [4 men, 3 wks] 1,008 mhr @ | T | 2 Compactors | 252 hours | | | $44.18, | | | | | | |_ $44,500 | | | | 9 | Material Handling | Crew size | 840 mhr @ T T T T | (5%) | dependent | $39.85, | | | | | | on tasks | $33,500 | | | | | | described | | | | | | | dn this | | | | | I |_section | | | | | I T I I T T T Cl | INDIVIDUAL HOUSE | | | | | | |_TIE-IN | | | | | | 2 | Estimate for 1,400 [12 men, T 11,200 mhr @ | Heat exchangers T $700,000, To T | individual connections] 11 wks | $50.00, | | 84,000 1b.; | | | | | $560,000 | Valves and Fittings | $84,000, | | | | | | [21,000 1b. | | T T T I T T T D1 | DEMOBILIZATION | Crew size | 1,512 mhr@ | | | | | | varies | $50.00, | | | | i | [$75,600 | | | | TOTAL $1,556,300 $1,784,100 $1,379,900 <less Mobe/Demobe> Tr20 1,174,000 1b. PROJECT EQUIPMENT COST SUMMARY COAL FIRED LOW-PRESSURE DISTRICT HEATING SYSTEM (ALTERNATIVE "B") Monthly Project Rental Operation Maintenance Replacement Fuel & Lube Item Weight Rate Length Cost Hours Cost Parts Cost Air Compressor 2,000 Ib. 1,300 13 months 16,900 892 hrs. 1,200 400 800 gal, 1,100 Auger 30,000 1b. 6,800 i 88,400 336 hrs. 7,800 3,200 5,000 gal, 6,700 Back Hoe 20,000 Ib. 3,200 . 41,600 672 hrs. 3,200 1,400 1,500 gal, 2,000 Compactor (one 21,000 Ib. 4,700 61,100 252 hrs. 2,700 1,000 1,200 gal, 1,600 large, one small) CAT 31,000 1b. 5,800 % 75,400 672 hrs. 7,400 2,900 4,600 gal, 6,200 Crane 200,000 Ib. 10,000 i 130,000 2,856 hrs. 143,800 58,000 37,600 gal, 50,800 Dump Truck 30,000 1b.x2 4,400x2 i 114,400 1,764 hrs. 9,400 7,200 9,500 gal, 12,800 Loader 45,000 Ib. 5,600 " 72,800 1,092 hrs. 16,300 11,300 7,900 gal, 10,700 Man Lift 5,000 1b.x2 2,100x2 = 27,300 2,856 hrs. 15,800 2,700 4,800 gal, 6,500 Mixer & Water 6,000 Ib. 1,400 = 18,200 588 hrs. 1,000 400 700 gal, 1,000 Trailer Heater 1,000 1b. 1,200 s 15,600 1,260 hrs. 300 100 4,400 gal, 6,000 Welder 2,000 1b.x4 600x4 a 31,200 8,652 hrs. 7,600 800 30,300 gal, $40,900 TOTALS 217 tons $692,900 $216,500 $89,400 $146,300 TOTAL COST $1,145,100 F-40 Monthly PROJECT EQUIPMENT COST SUMMARY COAL FIRED LOW-PRESSURE DISTRICT HEATING SYSTEM (ALTERNATIVE “B") DISTRICT HEATING DISTRIBUTION SYSTEM Project Replacement Fuel & Lube Item Weight Rate Length Cost Hours Cost Parts Cost Backhoe (large) Backhoe (Small) Compactor (one large, one small) CAT (large) Oump Truck (large) Flatbed Welder TOTALS 40,000 1b.x2 5,800x2 20,000 1b. 3,200 21,000 1b. 4,700 115,000 1b.x2 9,900x2 200,000 1b. 9,900 15,000 1b. 1,500 2,000 Ib.x4 600x4 287 tons 6 months Rental Operation Maintenance 69,600 672 hrs. 9,600 19,200 672 hrs. 3,000 28,200 504 hrs. 5,400 118,800 672 hrs. 21,200 59,400 252 hrs. 12,000 9,000 672 hrs. 700 14,400 3,024 hrs. 2,500 $318,600 $54,400 F-41 2,600 1,400 2,000 9,200 5,100 900 300 $21,500 TOTAL COST 2,400 gal, $ 3,200 1,500 gal, 2,000 2,400 gal, 3,200 12,000 gal, 16,200 3,300 gal, 4,500 5,700 gal, 7,700 §,700 gal, 7,700 $44,500 $439,000 vren Veron wo on were rnveseun suneuunn COAL-FIRED LOW PRESSURE DISTRICT HEATING SYSTEM (ALTERNATIVE "B") WEEK {12.34/56 7 Bly 10 11 12/13 14 15 16) 18 19 20/21 22 23 24/25 26 27 28/29 30 31 32/33 34 35 36/37 36 39 MOBE = Jnnnanne ereeee- SITE PREPARATION Surveying, |=- Clearing Dire Work weeenle BUILDING FOUNDATION Piling 7 a} Steel we Insulation ** Re inforce~ -- ment Pour ** Boiler o* Supports | BUILDING ERECTION Frame - Siding ite | te Rose titi O/H Crane } = pene HOLLER ERECTION Installation ak ggg» RotpOiogIOtoIgOig: J tolotoiotoioeot Auxiliary | | we Boiler PROCESS EQUIPMENT Coal ok oni tinigioiOn foto Conveyor Gest | orien | tne Pulverizer Coal Silo/ sini Hopper Ash Con~ — veyor/llopper Stockpile oma Conveyor Piping and Pumps Heat j Sareates Exchangers Water = Treatment tek Loe ooo iE Jenico too: FINISH WORK Framing Plumbing | 33 Neating & na Vent Painting & Finish ELECTRICAL Plant oa a Lighting Plant Power aed Power Feed aa Proces, Controle Site — Lighting EXTERIOR Fence Cleanup DENOBE - Single shift kexee Double Shitt CONSTRUCTION SCHEDULE COAL FIRED LOW-PRESSURE DISTRICT HEATING SYSTEM (ALTERNATIVE "B") WEEK DISTRICT HEATING DISTRIBUTION SYSTEM 123 4|567 8 fFwnre w own Bl INSTALLATION Surveying Ditching Utility Conflicts Bedding & Compaction Laying Pipe Welding Backfilling Compacting HOUSE TIE-INS Connections 9 10 11 12 13 14 15 16 17 18 19 20|21 22 23 24 F-43 5. GEOTHERMAL (ALTERNATIVE "D')/TEST WELL PROGRAM PHASE I (TEST WELL NO. 1) 1. Land Ownership Status $ 30,000 2. Locating Primary Drill Site 25,000 3. Test Well Permitting 40,000 4. Program Refinement 20,000 5. Mobilization and Demobilization 200,000 (2 HERC Loads, includes load/unload) 6. Drill Site Construction 60,000 (2,000 c.y. Gravel) 7. Drilling, Casing, Cementing, Pumping 240 ,000 30 days @ $8,000/day (including subsistence) 7a. Miscellaneous Rentals 15,000 (including blow-out prevention) 7b. Casing 100,000 7c. Mud 20,000 7d. Cement (200 bags @ $30/bag) 6,000 7e. Miscellaneous Materials 12,000 (includes bits, fuel, lube) 7£. Material Shipment (by barge) 40 ,000 8. Logging (480 mhr @ $65/hr) 50,000 (includes equipment and subsistence) TOTAL PHASE I COST $858,000 F-44 GEOTHERMAL (ALTERNATIVE "D'')/TEST WELL PROGRAM PHASE II TEST WELL NO. 2 2. Locating Second Test Well Site $ 50,000 4. Program Refinement 20,000 6 Drill Site Construction 60,000 (2,000 c.y. Gravel) 7. Drilling, Casing, Cementing, Pumping 240,000 15 days @ $8,000/day (including subsistence) 7a. Miscellaneous Rentals 15,000 (including blow-out prevention) 7b. Casing 100,000 7c. Mud 20,000 7d. Cement (200 bags @ $30/bag) 6,000 7e. Miscellaneous Materials 12,000 (includes bits, fuel, lube) 7£. Material Shipment (by barge) 40,000 8. Logging (480 mhr @ $65/hr) 50,000 (includes equipment and subsistence) (OBSERVATION WELLS) 7. Drilling, Casing, Cementing, Pumping $560,000 70 days @ $8,000/day (includes subsistence) 7a. Miscellaneous Rentals 15,000 7b. Casing 140,000 7c. Mud 40,000 7d. Cement 12,000 7e. Miscellaneous Materials 12,000 7£. Material Shipment 60,000 8. Logging 140,000 Instrumentation 300,000 TOTAL PHASE II COST $1,892,000 TOTAL PROJECT COST (PHASE I AND II) $2,750,000 F-45 CEOTHERMAL (ALTERNATIVE "D"') Item Description Crew Size Man-hours Description Material Equipment Equipment Houre No. of Task Time Labor Kate, of Material Cost, Weight Kequirements Kate and Cost | Required and Cost i Al | MOBILIZATION OF EQUIP- Cost of material, Crew wize 66s mir @ | freight, and cquipment| dependent | $50.00, | standby, aa delineated! on casks $144,400 \ by the following item#) described will be incurred below. during mobilization Ee EE il. Bl | PRODUCTLON AND INJECTION WELL | DRILLING | 2 | Permitting and Oe we tee) a = Land Ownership | $60,000, +2. pare nf eerie OOO.| ms 7 3 | Surveying and @ men, 3 wke! 2,016 whe @ 7,500 yde. gravel $2.00/yd, (CAT, loader, | 252 houre each Dirt Work 946.78, $15,000 2 dumps, $94,300 water trailer . compactor 4 | Land Cost TS acres [$15,000 | (for inform. Fo IL only) _ 5 | Mobilization and $300, 000 Demobilization of | Drilling Rig and Crews shel J eck es 6 | Drilling, Inetailation 12 welts @ Casing, mud, cement, | 12 welle @ Included with of Casi $250,000/well| ete, $180,000/well| crew coute { and_Logg in: be ets | 9 O00 000 da | $2,160,000 | 7 7 Set-up and Moving TZ woves © Between Drilling Sites $10,000/move, Por 220,000 C1 | BUILDING SITE PREPARATION tl Hk 2 [Grubbing & Surveying | 2 men, t wk | 16d mir @ | $50.00, 7 | $8400 | a i 3] Dirt Work \"emen, 2 wks! 1,344 mhr @ | 6,000 ydw. gravel $2.00/yd. 946.78, (Ld acces) $12,000 $62,900 aa 4 | Land Cost 1 TY acres [ $11, 000 (for | tT Je ie _|_inform, only)| os D1 | BUILDING Fol Pe tS a eee 2 | Inecall Pil Tih $0. 35/1b. Mixer, auger,| 168 hours each 947.08, $56,700, backhoe, 363,300 162,000 Ib, | water trailer crane Slab Steel, Pans, and Beams Stab Insulation 840 ober & $48.08, $40,400 5 men, 2 wks! Cine in Icem D3) | 8,000 aa fe, Pan 800 Et. beam, 100 1b/ft. $3.00/8q. ft $24,000, 40,000 Ib, $0. 35/1b., $28,000, Crane, welder, torch 168 houre each Slab Reinforcement UO ft. VS Kebur ($0.40/ie., $12,000, _ [30,000 tb. | Slab Concrete Pour ; 500 ydw. gravel $?.00/yd., Mixer, crane,| 84 houre each $1,000; bucket, 993,100 2,500 wackea cement $0.00/sack, loader, water $15,000, trailer, dump 225,000 Lb. ‘Pump and Engine ~~) Cine tudes” 1,500 ft. beam, $0.35/1b., Supporte in leens 60 lb/ft. $31,500, b3 and ve) | 90,000 1b. Material ilandling Crew vize 672 whe @ (15%) dependent $44.25, on tasks $29,700 described in this section —__ J 7 i -—-L-. GEOTHERMAL (ALTERNATLVE "D") Item Description Crew Size Man-hours Description Material Equipment Equipment Hours No. of Task Time Labor Kate, of Material Cowt, Weight | Requirements | Rate and Cost Required and Cost a El Ed £1 | BUILDING ERECTION Zs 2 | Steel Frame 4 men, 1 wk | 336 mir © Steel frame “$45,400, Crane, 64 Noure (Walle Only) $47.13, 90,000 1b.; | welder $15,800 Siding & insulation | $36,300 (we. ol incl. above) 3 | Siding, Insulation, @ men, 2 wke| 672 mhr @ | Fastenere $1,000, Crane, 84 houre, and Overhead Doors $47.13, 500 1b.; man lift crane; $31,700; 252 hours, 4 men, 1 wk | 3360 mhr @ 2 Overhead doors $30,000 (we. man lift $47.88, inel. with $1,100 Item E2) 4 7 Roof (Including G men, 1 wk | 330 mir @ I Fastenece [~$800, Crane 8a hours Purlins & Insulation) $47.13, 500 Ib. $15,800 5 | Overhead Crane 3 men, 2 wke| 504 mhr @ Crane | $200, 000, (Installed in $48.08, 20,000 1b. Building) $24,200 __ Ss 6 | Material Handling Crew size 168 mhr @ [— Air compres- | 168 houre each (7%) dependent $44.25, sors, on taske $7,400 2 pneumatic described guns in thie section Fl | FUEL STORAGE TANKS Ale 2 | Slab Annulus ZTwen, 4 wke| 672 whr @ . OS rebar Torch, i $48.08, Crane (1 wk) 32 300 3 | Stab Annulu “$04 mir © 150 yde. gravel $2. 007yd. Mixer, crane,| 84 hours each Concrete Pour $46.16, $300; bucket, $23,300 750 sacks cement $6,00/ sack, lou » water $4,500, trailer, dump enya | ert oe eae eet Lett 418 00 0 tsi af oe peste lettres xb eo 4 7 Ofl Sand Base TO men, | wk; 440 mir @ ‘350 yda, wand $2.00]. londer, 64 hourw each Inside Annulus | $45.65, $700; dump, CAT, 934,300 400 gallons oil $000, compactor a entree fn tell ets | ete ates |g UO 5 Hatta —— 5 | Tank Erection 8 men, 6 wks! 4,032 mie @ 5 = L million gallon | $650,000, 504 hours each $48.08, tanks 1,000,000 1b.| 2 man lifts | jieenteptentoebestil | (93 90D smelt: | etic _cetistel|batsieabeaiotek = — 6 | Tank Painting “Tmen, 3 wks} 504 mhe @ | 250 gallons paint $5,0U0, Man lift, 252 hours each $50.55, 2,100 Ib. air compres- | $25 :500 2 apes Seema sor 7 | Material Handling Crew size YoU mir @ | (15%) dependent $44.25, | on taske $42,500 described in this | ction | E G1 | DIESEL ENGINES FOR PUMPS . Lae filed 4 ail 2 | Installation @ men, 4 wke| 2,688 wir @ | 4 - 1,300 hp diesels | $800,000, Crane, | wk | 84 houre $47.13, 70,000 tb. ; $126,700 1 = 1,000 hp diesel | $150,000, 15,000 tb. ; 2 - 340 hp diesels $130,000, 2 teat _____(inel. pumps) | 20,000 tb. | ian 3 | Jacket Water Heat 6 men, 2 wks) 1,008 mhr @ 7 heat exchangers $105,000, Welder, 168 houre Exchangers $44.08, 45,000 Ib, torch |_ $48,500 | aie 4 TAir-to-Glycol Heat "émen, 2 wke| 2,016 mhe @ | Ducting, fanw $100,000, Welder, 336 houre Exchangece | $40.08, 60,000 Ib, tourch 1 5 | Exhaust Heat G men, 4 wke “Vient recovery $175,000, Welder, | 168 hours Exchangers silencers 35,000 Ib, | torch Ce een ae Uda L a tae 6 | Exha $s & men, 4 wks| 1,344 whe @ $30,000, der, 336 Nourse $44.08, 20,000 1b, torch $64,600 _ 7 Material Handling 072 ¢ (uz) dependent $44.29, | on tasks | $29,700 | described | in this j section | Crew wi GHOTHERMAL (ALTERNATIVE "D"') Item Description Crew Size Man-hours Description Material Equipment Equipment Hours No. of Tusk Time Labor Kate, of Material Cost, Weight Requirements Rate and Cost Required and Cout oy ee H1 | PROCESS EQUIPMENT Hi E | 2 ) Geothermal /Diebribu- 6 men, 4 wke! 3,026 whe $450,000, tion Syetem ieat $47.88, a 90,000 Ib, Exchanger $145,000 304 stainless steel 3 [Auxiliary Boi Ws 000 a/ir | $115,000, | boiler 30,000 Ib. 4 | Pumpa = = ita | Toe ioure, 1 = Geothermal Pump | 16 wke $47.88, 6,400 gpa pump $60,000, crane; $144,000 10,000 1b.; 1,344 hours, 8 - Well Pumps Submersible pumps $120,000, welder | 20,000 1b.; 4 - Injection Pumps 1,600 gpm pumpe $160,000, | 40,000 1b. ; 2 - Disbribution ; (Included in [tem 62) pumps 8 - Screens and | Screens and hydro- $160,000, lydrocyclonee [cyclones __ 40,000 1b. 5 | Geothermal Water 24 men, 40,320 mhr @ | Alloy Piping $1,400,000, |G welders, €,720 houre Piping from Production! 20 wks $47.88, 260,000 1b, torch Welle co Injection $1,930,500 a es il a | 6 | Distribution System TS wen, 3,780 whe @ | Piping $109,200, 3 welders, 756 Piping in Plant 3 wke $47.88, 21,000 1b, torch aL ae _|_$181, 000 pee 7? | Expansion Tank 4 men, | wk | 336 houre @ Tank $30,000, Crane 84 hours each (Distribution System) $48.55, 30,000 Ib, welder, i _ i 316,20 ey torch 8 | Engine Clycol Piping 7,056 wher @ | Piping $208,800, 2 welders, 1,176 houre 31,400 Lb, torch 9 T Pampa Cingine Coolant) Pumpe $12,000, 6,400 Ib, 10] Engine Lubrication Piping, pumps, and | $108,000, 2 welders, 1,008 hours (Piping, Pumps, and filter prene 12,000 Ib. torch Filter Press) ecies ess Spee }—__ 11] Engine Fuel Syetem Paupe, piping, $64, 300, Welder, 336 Nourse (Including Pumpe, day tanks 10,000 Ib, torch | Piping) i nea) ae 12] Fuel Storage Area Gwen, 6 whe] 4,556 mie € | Supply piping, €iIT "$150,000, 2 welders, 1,008 hours Supply Piping $47.88, piping, pumps 25,000 1b. torch a __|_ $217,200 le El eel 13] Water and Glycol @ men, 1 wk | 504 whe @ Equipment $75,000, Treatment and Mixing $48.35, 50,000 1b.; $24,400 95,000 gallons glycol| $4.00/gal., | $380,000, = Ps ele |_788,500 Ib. 14] Heating and 2 men, 640 wher Ducts, fane, and 940,000, Man lift 420 houre T Ventilating System $52.45, coils 42,000 Lb. -|_244,000 a 1S] Material Handling | Crew size 360 mhe @ | 30 bottles oxygen $2,000, (5%) | dependent $44.25, | 7,500 Lb. | on tasks $148,700 15 bottles acetylene described in thie section mae) Tl CARPENTRY, PLUMBING, INTERIOR FINISH WORK a oe leet eek - fee 2 | Fraaing, Doors, ‘J men,3 wke | 756 mhr @ Lumber & plywood $2,000, ‘Air 252 hours Sheet Kock $49.35 15,000 Ih.; compressor $37, 300 Doors & windows $3,500, 1,200 1b. Sheet rock $1,000, loo Ib, _| GEOTHERMAL (ALTERNATIVE ("D") Item Description Crew Size Man-hours Description Material Equipment Equipment Hours No. of Task Time Labor Rate, of Material Cost, Weight | Requirements | Rate and Cost Required and Cost 13 | Plumbing (Bathroom, 3 men,3 wks 756 mhr @ Pipe and fittings $4,000, Backhoe 84 hours Drains, and Utility $49.72 2,000 1b.; (1 week) Connections) $37,600 Fixtures $1,000, 100 1b. 4 ] Heating & Ventilation: Office 3 men,2 wks 504 mhr @ Heater, ducts, fans $7,500, $52.45 2,000 1b.; $26,400 ducts, auxiliary $100,000, Plant 3 men,3 wks | 756 mhr @ heaters 10,000 1b. $52.45 $39,700 5 Painting & Finish Work; 4 men,2 wks 672 mhr @ Paint $3,000, $50.55 1,500 1b. $34,000 6 | Material Handling Crew size 200 mhr @ (7%) dependent $44.25 on tasks $8,900 described in this section Ji ELECTRICAL WORK 2 Lighting 2 men, wk 168 mhr @ Lights, wire, $6,300, Man Lift 84 hours $53.65, conduit 800 1b. $9,000 5 Power 1 man, wk | 84 mir @ Fixtures, wire, $1,300, 359).65;, conduit 300 1b. $4,500 4 Site Lighting 2 men, wks| 336 mhr @ Lights, wire, $3,800, Man lift 168 hours $53.65, conduit 300 1b. $18,000 5 | Process Electrical 3 men, 5 wks| 1,206 mhr @ Starters, wire, $25,000, $53.65, conduit, panels 20,000 1b. $67,600 6 Motor Control 2 men, wks| 504 nhr @ Starters, controls, $35,500, 953)..65:,, wire, conduit, 4,000 1b. $27,000 panels Z ] Material Handling Crew size 80 mhr @ (5%) dependent $44.25, on taska $3,600 described in this section Kl EXTERIOR FINISHING 2 Fence Erection 2 men, 1 wk 168 mhr @ Chain link fence $5,000, Backhoe 84 hours $45.31, 5,000 lb. $7,600 8) Miscellaneous and 2 men, 2 wks! 336 mhr @ Loader, 84 hours each Cleanup $45.31, dump $15,200 4 7 Material Handling Crew size 50 mhr @ (10%) dependent $44.25, on tasks $2,200 deacribed in this section M1 DEMOBILIZATION Crew size 2,016 mhr @ varies $50.00, $100 , 800 TOTAL $9,470,100 $8,671,400 $8,934,900 <less Mobe/Demobe> 3,649,000 1b. GEOTHERMAL (ALTERNATIVE "D") DISTRICT HEATING DISTRIBUTION SYSTEM Item Description Crew Size Man-hours Description Material Equipment Equipment Hours No. of Task Time Labor Rate, of Material Cost, Weight Requirements | Rate and Cost Required and Cost | Al MOBILIZATION OF EQUIP- MENT AND WORKFORCE TO THE SITE Cost of material, Crew size 7,016 whe @ — freight, and equipment) dependent $50.00, standby, as delineated| on tasks $100,800 by the following items} described will be incurred during mobilization Bl INSTALLATION 2 Surveying 6 men, 5 wks! 2,520 mhr @ $50.00 $126 ,000 3 | Ditching 2 men, 5 wks| 840 mhr @ 2 Backhoes 420 hours $48.50, (Large) $40,700 _¥ 4 | Utility Conflicts Crew size 1,008 mhr @ varies $48.50, $48,900 5 T Bedding & Compacting 5 men, 3 wks| 1,260 mhr @ 10,200 yds. $2.00/yd., Dump, loader,| 252 hours, $43.41, $20,400 2 compactors dump and $54,700 compactors; loader included with plant 6 | Laying Pipe 7 men, 8 wks| 4,704 mhr @ 2-1/2 in., 4,100 fe. | $21,000, Flatbed, 672 hours, $43.79, 20,500 1b.; 1 backhoe, flatbed and $206,000 3 in., 14,000 ft. $166,600, 2 welders backhoe; 210,000 1b.; 1,848 hours, 8 men,11 wks| 7,392 mhr @ 4 in., 2,000 fe. $33,800, welders $47.88, 30,000 1b.; $353,900 6 in., 8,100 ft. $204,200, 202,500 1b.; 8 in,, 2,900 ft. $98,300, 101,500 1b.; 10 in., 13,700 fe. $613,800, 753,500 Lb.; ; 12 in., 3,500 ft. $210,800, 227,500 1b.; 14 in., 900 fe. $70,200, 72,000 1b.; 16 in., 300 ft. $35,100, 36,000 1b, — 7 Back filling 2 men, 5 wks| 840 mhr @ 1 CAT 420 houre $48.50, $40, 700 8 | Compacting 5 men, 3 wks| 1,260 mhr @ 2 compactors | 252 hours 944.18, $55, 700 9 | Material Handling Crew size 1,092 mhr @ | (5%) dependent $44.25, on tasks | $48,300 described in this section — —t cl INDIVIDUAL HOUSE TIE-IN 2 Estimate for 1,400 16 men, 13,440 mhr @ | Heat Exchangers $840,000, Individual Connections| 10 wks $50.00, 100,800 1b.; $672,000 Valves & Fittings $100,800, | 25,200 1b. Di DEMOBILIZATION Crew size 1,512 mhr @ varies $50.00, $75,600 | TOTAL $1,823,300 $2,415,000 $1,646,900 <less Mobe/Demobe> E=-50 1,779,500 1b. PROJECT EQUIPMENT COST SUMMARY GEOTHERMAL (ALTERNATIVE " ) DISTRICT HEATING DISTRIBUTION SYSTEM Monthly Project Rental Operation Maintenance Replacement Fuel & Lube Item Weight Rate Length Cost Hours Cost Parts Cost Backhoe (large) 40,000 1b. s*800 6 months 94° 600 840 hrs. = 3,400 3,000 gal, 4,000 Backhoe (small) 20,000 1b. 3,200 : 19,200 672 hrs. 3,200 1,400 400 gal, 600 Compactor (one 21,000 1b. 4,700 ” 28,200 504 hrs. 5,800 2,000 2,400 gal, 3,200 large, one small) CAT (large) 115,000 1b, 9,900 " 59,400 840 hrs. 9,400 3,600 5,600 gal, 7,600 Dump Truck 200,000 1b. 9,900 . 59,400 252 hrs. 12,900 5,100 3,300 gal, 4,500 (large) Flatbed 15,000 1b. 1,500 " 9,000 672 hra. 900 900 5,200 gal, 7,000 Welder 2,000 1b.x2 600x2 . 7,200 3,696 hrs. 3,200 400 7,000 gal, 9,600 TOTALS 225 tone $217,200 $48,000 $16,800 $36,500 TOTAL COST $318,500 PROJECT EQUIPMENT COST SUMMARY GEOTHERMAL (ALTERNATIVE "D"') Monthly Project Rental Operation Maintenance Replacement Fuel & Lube Item Weight Rate Length Cost Hours Cost Parts Cost Air Compressor 2,000 1b. (300 13 months ie t00 504 hrs. oe ees 400 gal, - Auger 30,000 1b. 6,800 " 88,400 168 hrs. 4,000 1,600 2,400 gal, 3,400 Backhoe 20,000 1b. 3,200 as 41,600 336 hrs. 1,600 700 200 gal, 300 Compactor (one 21,000 1b. 4,700 " 61,100 336 hrs. 3,900 1,300 1,600 gal, 2,100 large, one small) CAT 31,000 1b. 5,700 M 74,100 336 hres. 3,700 1,500 2,300 gal, 3,100 Crane 200,000 1b. 9,900 » 128,700 1,932 hrs. 97,900 39,300 25,500 gal, 34,300 Dump Truck x 2 30,000 1b.x2 4,400x2 a 114,400 756 hrs. 4,300 3,100 4,100 gal, 5,500 Loader 45,000 1b. 5,600 “ 72,800 588 hre. 8,900 6,100 4,300 gal, 5,800 Man Lift 5,000 1b. 2,100 ” 27,300 1,932 hres. 10,700 1,800 3,300 gal, 4,300 Mixer & Water 6,000 1b. 1,400 " 18,200 336 hrs. 500 300 400 gal, 500 Trailer Heater 1,000 1b. 1,200 in 15,600 840 hre. 200 100 2,900 gal, 4,000 Welder 2,000 1b.x4 600x4 a 31,200 14,196 hrs. 12,600 1,600 26,700 gal, 36,000 TOTALS 215 tons $690,300 $149,000 $57,600 $99,800 TOTAL COST $996,700 APPENDIX G OPERATION AND MAINTENANCE APPENDIX G OPERATION AND MAINTENANCE TABLE OF CONTENTS L.1 Generale ccccccccccvesccccccecccccccccccvescceseseseses Gr 1.2 Personnel Requirements For Operation ANd Maintenance... eseeeeercecceceeeceeeesescsssseseses eG 1.3 Estimate of Present Worth per Employee. ..seeeeeeeeeees eG-6 1.4 Present Worth of Operations and Maintenance for the Various CaSeS..cecccccccccccccvcccccscssccssses sary LIST OF TABLES Table G.l Operation and Maintenance Personnel REQUITEMENES. cece eer eerccvccrcersceeeeeseses sro Table G.2 Present Value of Operation and MAiNtENance. cece ccececvccvecccveveseceseses vary APPENDIX G OPERATION AND MAINTENANCE 1.1 GENERAL As some of the alternatives dealt with in this report are rather labor intensive, it is necessary to make an analysis of the work forces required to operate them. For all alternatives an estimate has been made concerning the requirements for operative and maintenance personnel. It is anticipated that one clerk and one superintendent will be needed for each alternative and that one skilled person will be needed for mechanical repairs on each alternative. The cost of major overhauls has not been included in these estimates since the costs of such overhauls are estimated to be of limited significance compared to the costs of normal operation and maintenance, and since part of the work in connection with overhauls is done by the maintenance workers and is thus covered by expenses for normal maintenance. 1.2 PERSONNEL REQUIREMENTS FOR OPERATION AND MAINTENANCE CASE 1 Diesel Generation and Oil Stoves for Heating Based on data from Kotzebue and other cities with diesel generation systems it has been anticipated that 5 operators will be needed to keep the power plant manned at all times. In addition, on week days a maintenance team consisting of one electrician, one mechanic and one laborer will be present. Total work force: 10 persons. CASE 2 Coal-fired Cogeneration In addition to the work force needed in a diesel power plant it is anticipated that 2 workers will be needed for coal handling. This brings the total work force up to 12 persons. CASE 3 Hydropower with Oil Stoves for Heating In addition to the work force needed in a diesel plant this plan requires a line crew to inspect and repair the 90-—mile transmission line linking Kotzebue to the Buckland site. This crew would consist of two electricians and one laborer. This brings the work force for this case to 13 persons. CASE 4 Diesel Generation with Waste Heat Recapture and Oil-Fired Boilers for Supplement , It is anticipated that no extra maintenance crew will be needed to maintain the district heating system. Thus total work force will be 10 persons. CASE 5 Oil-Fired Cogeneration It is anticipated that operation and maintenance of an oil-fired cogeneration plant will require basically the same personnel as is the case with the diesel power plant with waste heat recapture. Total work force: 10 persons. CASE 6 Diesel Generation with Waste Heat Recapture and Coal-Fired Boilers for Supplement The work force required for this case will be the same as the work force required for Case 2, i.e. 12 persons. CASE 7 Coal-Fired Steam Generation and Oil Stoves The work force required for this case will be the same as the work force required for Case 2, i.e. 12 persons. CASE 8 Hydropower and Coal-Fired Boilers for District Heating This case is quite labor intensive as two plants have to be manned at all times. Also, crews are required for coal handling and transmission line maintenance. Total work force estimated: 21 persons. CASE 9 Diesel Generation with Waste Heat Recapture and Geothermal Base Load for District Heating Geothermal installations are not anticipated to require any extra maintenance crews and thus labor demand for this case will be equal to that of Case 1. Total work force: 10 persons. CASE 10 Hydropower with Geothermal District Heating It is anticipated that one maintenance man would be assigned to maintenance work on the district heating system, as the remaining maintenance crews will be located away from town. Total work force estimated: 14 persons. CASE 11 Hydropower with Resistance Heating The work force required for this case will be 13 persons as is the case with Case 3. In Table G.1 estimated work forces are shown for each case. Table G.1l Operation and Maintenance Personnel Requirements Elec. Mech. Gen. Case Operators Maint. Maint. Maint. Office Manage. Total 1) Diesel Generation Oil/stoves 5 1 1 1 L 1 10 2) Coal-Fired Cogeneration 5 1 1 3 1 1 12 3) Hydropower* and Oil Stoves 5 3° 1 2 1 1: 13 4) Diesel Generation/ Oil District heat 5 1 1 ll! 1 1 10 5) Oil-Fired Cogeneration 5 1 1 1 1 1 10 6) Diesel Generation/ Coal District 5 1 1 3 i 1 12 7) Coal-Fired Steam Generation and Oil Stoves 5 I il 3 1 1 12 8) Hydropower/ Coal District 10 a* il 4 1 1 21 9) Diesel Generation/ Geothermal District 5 i 1 1 1 1 10 10) Hydropower/ Geothermal District 5 3% 1 3 1 1 14 11) Hydropower/ Resistance Heat 5 3* 1 2 1 1 13 * Includes transmission line maintenance. 1.3 ESTIMATE OF PRESENT WORTH PER EMPLOYEE Basic assumptions: Average expense per employee: 75,000 $/yr. Inflation rate on wages 0 Real interest 3.0% Thus, present value per employee over 20 respectively will be $1,116,000 and $2,008,000. and 55 years Maintenance of residential installations has not been included. 1.4 PRESENT WORTH OF OPERATIONS AND MAINTENANCE FOR VARIOUS CASES Table G.2 Present Value of Operation and Maintenance Case Present Worth $ xX 1000 1. Diesel Generation and Oil Stoves 27,600 2. Coal-fired Cogeneration 37,600 3. Hydropower and Oil Stoves 28,800 4, Diesel Generation with Waste Heat Recapture and Oil-fired Boiler for District Heating 24,100 5. Oil-fired Cogeneration 25,400 6. Diesel Generation with Waste Heat Recapture and Coal-fired Boilers for District Heating 29,500 7. Coal-fired Steam Generation and Oil Stoves 37,400 8. Hydropower and Coal-fired District Heating 47,500 9. Diesel Generation with Waste Heat Recapture and Geothermal Heat for District Heating 24,800 10. Hydropower and Geothermal Heat for District Heating 32,600 11. Hydropower and Electrical Resistance Heating 28,800 APPENDIX H FUEL DEMAND APPENDIX H FUEL DEMAND TABLE OF CONTENTS GENELAl cece ceevesereeveeeseresesssessessvere 2.0 Present worth of Fuel Demand for the VariouS CaS€S....ceccccccccccccccccece Methods of CalculationS....ceccccceccccccsvece 4.0 Fuel Demands and Annuities for Fuel Costs..... LIST OF FIGURES Figure H.1 Oil Demand for Various Cases...... e+e. Figure H.2 Oil Demand for Various Cases...... sees Figure H.3 Oil Demand for Coal and Oil Burning CASES cocccccccvccccccccccccce Figure H.4 Coal Demand for Various Alternatives... LIST OF TABLES Table H.1 Fuel Costs for Heating and Blectricity..ccccccccccsccccscveccccce Table H.2 Annual Fuel Demands Oil-Based SySteM..cecesececceccecsees Table H.3 Annual Fuel Demands Various Oil-Fired Systems......eeeeee -H-10 eH-11 - H-2 osH=§ » H-7 APPENDIX H FUEL DEMAND 1.0 GENERAL Based on the projected demands for electricity and space heating for the next 20 years as described in Section 4, fuel costs have been established. Seasonal load variations have been taken into account as these have considerable impact on the economy of co- generation and waste heat recapture. Fuel costs for existing systems have been included for the time during which the alternative systems are being built. Fuel costs are presented as the present worth of total fuel demand for the next 55 years thus making direct comparison with hydropower alternatives possible, as outlined in standard A.P.A. evaluation procedures. Calculations are based on following assumptions: Heating demand: aa 109 Btu/year in year 2002 including line losses in a district heating system. Electrical demands: 47.22 x 103 MWh/year in year 2002 including line losses. Coal price: 168 $/ton (S$6.00/Mbtu) (Cape Beaufort coal 14,000 btu per pound). Oil prices $1.46 /gallon for fuel for individual space heating. $1.28 /gallon for fuel for power generation and district heating purposes. Inflation rates: Oil 2.6% Coal 2.0% Interest rate: 3.0% In Table H.1 total fuel cost figures are presented for various combinations of generation and heating systems based on a 55 year time span. 2.0 PRESENT WORTH OF FUEL DEMANDS FOR THE VARIOUS CASES Table H.1 Fuel Costs for Heating and Electricity 1) Diesel generation and oil stoves $341,800,000 2) Coal-fired steam co-generation 179,300,000 3) Hydropower and oil stoves 220,300,000 4) Diesel generation and oil supplemented district heating 217,600,000 5) Oil fired co-generation 285,400,000 6) Diesel generation and coal supplemented district heating 183,200,000 7) Coal-fired steam generation and oil stoves 301,000,000 8) Hydropower and coal-fired district heating 95,700,000 9) Diesel generation and geothermal district heating 172,400,000 10) Hydropower and geothermal district heating 25,000,000 11) Hydropower, oil supplemented 41,400,000 az 3.0 METHODS OF CALCULATION In order to make a close estimate of the fuel demands for the next 20 years, the following procedure was performed for each month in the next 20 years: a) b) C) d) e) £)) Based on statistics from Kotzebue concerning seasonal variations in electricity demands and on projections for future electricity demands, monthly electricity demand was calculated. Based on monthly demand, the conversion efficiency was derived using specifications for various systems. With monthly demand and conversion efficiency as known parameters, monthly fuel demand was calculated together with the amount of waste heat available for district heating. Based on seasonal variations in the number of heating degree days per month and on the forecasts for total heat demand, the monthly heat demand was calculated. Knowing the monthly heat demand and the amount of waste heat available, the need for supplemental heat from other sources could now be determined. With known boiler characteristics this was converted to a fuel demand, which, when added to the fuel demand from c) above, gave the total fuel demand for this specific month. H-3 Total fuel cost for a system over the next 20 years was calculated using the following procedures. a) For each year total fuel demand was calculated by adding together demands for each month of a year. b) For each year the annuity of the fuel cost was calculated on a 1982 basis using an interest rate of 3% and inflation rates for oil and coal of 2.6 and 2.0% respectively. c) Present worth of the fuel costs was calculated by adding up the annuities of the 20 years. d) As outlined in APA standard evaluation procedures, fuel consumption per year for years 21-55 has been set equal to projected fuel consumption for year 20 counting from the present (1982). Present worths of these consumptions have been added to the figures calculated in c) above, 4.0 FUEL DEMANDS AND ANNUITIES FOR FUEL COSTS In Table H.2 annual fuel demands are shown for various oil-based systems over the next 55 years. In Table H.3 annual fuel demands are shown for various coal-fired systems and for the mixed systems over the next 55 years. These demand numbers are illustrated graphically in figures H.l, H.2, H.3 and H.4. Table H.2 Annual Fuel Demands Oil-Based Systems Case 1 Case 3 Case 4 Case 5 Diesel Gene- Oil Stoves Diesel Gene- Oil-Fired ration and and Hydro ration and Cogeneration Oil Stoves Oil Supp. Year x 106 gallon x 106 gallon x 10” gallon x 106 gallon 83 3.08 3.08 3.08 3.08 84 3.26 3.26 3.26 3.26 85 3.58 3.58 2.60 3.29 86 3.75 Sie) 2.70 3.39 87 3.98 3.98 2.30 3.50 88 4.10 2.47 2.91 3.63 89 4.28 2.53 3.01 2.75 90 4.46 265i Se13 3.87 91 4.67 2.67 3.25 4.01 92 4.88 2615 3.37 4.16 93 5.09 2.83 3.50 4.31 94 5.30 2.89 3.64 4.47 95 5.54 2.98 3.78 4.64 96 Ser 3.04 3.92 4.81 97 6.01 Sell 4.05 5.01 98 6.26 3.17 4.23 S22. 99 6.54 3.26 4.42 5.47 2000 6.84 3.35 4.61 Cro) 01 7.17 3.45 4.83 6.19 02 7.63 3.70 5.08 6.95 Year x 10° gallon 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 2000 01 02 Case 9 Diesel and geothermal 3.08 3.26 aospe 1.41 1.52 1.63 Ven 1.89 2.00 Ziel) 2.26 2.41 2.56 Ziel 2.90 3.09 3.28 3.49 3.72 3.93 Table H.2 (Cont'd) Annual Fuel Demands Oil Based Systems Case 10 Hydro and Geothermal x 10° gallon x 10 gallon 3.08 3.26 U3) 1.41 a WALS73 joo ooo oO oO OOOO Co Case ll Oil Supp. for Hydropower 3.08 3.26 3.58 Sto 3.98 oooeoso 0.04 0.08 0.12 0.17 0.22 0.277 0.33 0.39 0.47 0.55 Table H.3 Annual Fuel Demands Various Coal Fired Systems Case 2 Case 8 Coal-Fired Coal-Fired Co-gene- District ration Heating & Hydropower Year tons tons g3(1) 3,080,000 gallons 3,080,000 gallons g4(1) 3,260,000 gallons 3,260,000 gallons 85 17,028 10,446 86 17,538 10,446 87 18,155 10,950 88 18,788 P1200 89 19,403 11,450 90 20,021 11,696 91 20,758 11,950 92 21,538 12,250 93 22,321 12,500 94 23,157 12,800 95 24,024 13,080 96 24,935 13,450 97 25,929 13,800 98 27,027 14,175 99 28,328 14,550 2000 29,840 14,999 Ol 32,051 15,350 02 35,949 15,714 (1) 83 ana 84 oil use to continue until coal system operational. H-7 (2) Year 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 2000 01 02 Table H.3 (Cont'D) Annual Fuel Demands Various Coal Fired Systems Case 6 Diesel Generation and Coal-Fired District Heating x 106 gallon 3.08 3.26 1.31 1.41 1.52 1.63 167 1.87 2.00 2.13 2.26 2.41 2.56 2013 2.90 3.09 3.28 3.49 3.72 3.93 tons (1) 5,698 5,594 5,542 5,787 5,231 5,180 4,973 4,817 4,662 4,610 4,403 4,299 4,196 4,062 4,040 3,937 3,729 3,004 Case 7 Coal-Fired Steam Generation and Oil Stoves tons (1) 11,658 12,074 12,501 12,929 13,303 13,378 14,264 14,799 15,386 16,027 16.655 17,417 18,218 19,126 20,088 21,076 22,118 23,149 x 106 gallon 3.08 3.26 2.27 2.34 2.46 2.47 2.53 2.57 2.67 2.75 2.83 2.89 2.98 3.04 3.11 3.17 3.26 3.35 3.45 3.70 83 and 84 oil use to continue until coal system operational, H-8 FIGURE H.1 OIL DEMAND FOR VARIOUS CASES case 1 case 5 case 4 oil/ 10° gallons case 3 year H-9 FIGURE H.2 OIL DEMAND FOR VARIOUS CASES 5 case 9 case 11 year FIGURE H.3 OIL DEMAND FOR COAL AND OIL BURNING CASES 6 case 6 case 7 year H-10 FIGURE H.4 COAL DEMAND FOR VARIOUS CASES case 2 case 7 a ¢ ° -— ‘o i > 3 ° case 6 APPENDIX | CALCULATION OF PRESENT WORTH OF CAPITAL COST APPENDIX I CALCULATION OF PRESENT WORTH OF CAPITAL COST TABLE OF CONTENTS ve General Grates cere eroretetete eretereterheteteteloleherataielerenetores clever erate eliclel ee ri 2. Calculation of Present Worth of Capital Costs (Including |Construction Interest). emsicleiieceisicis se cre eioleteior LIST OF TABLES Table’ i:.)1)| | Planté, COMPONENES 4) «jo: «1wjol's w.cilsis @ wicile w willie =) Sislis s SuaKe els «eL-3 Table I.2 Present Worth of Capital Cost for the Various Cases Considered............ rererelelsl a aiclere ete ~I-4 APPENDIX I - CALCULATION OF PRESENT WORTH OF CAPITAL COST al GENERAL The calculations of present worth of capital costs are based on capital costs in 1982 prices and interest accrued during construction (See Table I.1). For each component the capital cost is converted into equal annuities over the life expectancy of the component. These annuities are applied from the year of inauguration until the year 2037, on the basis of which the present worth in 1982 of all annuities are summarized. The following Tables I.1 and I.2 are a tabulated summary of the various capital costs (including breakdown of components therein) and present worth of the systems analyzed respectively. The components capital cost and present worth calculations follow the summary tables. The component breakdowns for the different alternatives show: a the year of inauguration and the capital cost of different components - for the same components life expectancy annual cost (annuity) time span of operation o0oo°0 0 55-year present worth The annual cost is the annuity that will fund the capital cost over the life of the component. Using this annual cost t-1 throughout the operation life span therefore covers the cost of renewing the entire component after the expiry of its life expectancy. Where existing components require replacing during the life expectancy span, a sinking fund is provided (see Table 10.5). I-2 000000 0 O10 10 Io Fo FO TABLE I.1 Plant Components (Includes Construction Interest) Diesel plant extension, complete Waste heat recovery system for diesel plant extension Improvements to waste heat equipment for existing plant Coal-fired low pressure plant Oil-fired low pressure plant Coal-fired cogeneration Oil-fired cogeneration Coal-fired power plant District heating distribution system District heating distribution system for geothermal District heating transmission line Hydro plant Transmission line 8.86 MW gas turbine 2 x 8.86 gas turbine Geothermal system, including wells and test well program Oil stoves and furnaces, including addition for large boilers, etc. 1) 1982 Capital Cost $ x 10? 12,749 67,395 523) 20,064 31736 29,681 23,644 277, 10) 6,605 8,444 8,244 136,689 51,623 4,500 8,281 39,064 Varies TABLE I.2 Present Worth of Capital Cost for the Various Cases Considered 1982 Present Worth x 10° Case Type Facility 1. Diesel Generation and Oil Stoves 27.3 2. Coal-fired Cogeneration 60.1 ae Hydropower and Oil Stoves 199.6 4, Diesel Generation with Waste Heat Recapture and Oil-fired Boiler 33.5 5. Oil-fired Cogeneration 40.6 6. Diesel Generation with Waste Heat Recapture and Coal-fired Boilers for District Heating 68.3 Ts Coal-fired Steam Generation and Oil Stoves 35.0 8. Hydropower and Coal-fired District Heating 244.3 9. Diesel Generation with Waste Heat Recapture and Geothermal Heat for District Heating 142.6 10. Hydropower and Geothermal Heat for District Heating 309.2 il. Hydropower and Electrical Resistance Heating 202.2 I-4 2. CALCULATION OF PRESENT WORTH OF CAPITAL COSTS (Including Construction Interest) CASE: 1 MAIN FEATURES: recovery, oil stoves CAPITAL COSTS IN 1982 PRICES: YEAR OF COMPONENTS INAUGURATION 1. Diesel plant extension, complete 88 2. Oil stoves, etc. 1983-2037 PRESENT WORTH CALCULATED TO YEAR 2037 LIFE ANNUAL cgst OPERATION COMPONENT EXPECTANCY $ xX 10 TIME SPAN YEARS YEARS 1. Diesel plant extension 20 Varies 50 3. Oil stoves, etc. 10 Varies 55 TOTAL I-6 Base Case, diesel generation with additional heat CAPITAL,COST $ xX 10 12,749 1,729 55 YEARS PRESENT WORTH $ X 10 17,394 786 18,180 CASE: 2 MAIN FEATURES: Coal-fired Cogeneration COMPONENTS Plant Complete CAPITAL COSTS IN 1982 PRICES: YEAR OF INAUGURATION 85 85 85 83-84 PRESENT WORTH CAILCULATED TO YEAR 2037 2. District heating transmission system 3. District heating distribution system 4. Oil stoves, etc. LIFE COMPONENT EXPECTANCY YEARS 1. Plant complete 30 2. District heating transmission system 20 3. District heating distribution system 20 4. Oil stoves, etc. 10 TOTAL ANNUAL CQST OPERATION $ x 10 TIME SPAN YEARS 1,551 53 554 53 461 53 varies 2 CAPITAL,COST $ xX 10 30,404 8,244 6,852 36 55 YEARS PRESENT WQRTH $ X 10 37,436 13,372 11,127 34 61,969 CASE: 3 MAIN FEATURES: Hydropower, oil stoves CAPITAL COSTS IN 1982 PRICES: COMPONENTS 1. Hydro plant 2. Transmission line 3. Back-up gas turbine 4. Oil stoves, etc. YEAR OF INAUGURATION 88 88 88 1983-2037 PRESENT WORTH CALCULATED TO YEAR 2037 LIFE COMPONENT EXPECTANCY YEARS 1. Hydro plant 50 2. Transmission line 20 3. Gas turbine 50 4. Oil stoves, etc. 10 TOTAL ANNUAL cst OPERATION $ X 10 TIME SPAN YEARS 5, O12 50 3,470 50 175 50 Varies 55 I-8 CAPITAL gost $ X 10 136,689 51,623 4,500 1,729 55 YEARS PRESENT WQRTH $ X 10 117,909 77,016 3,884 786 19977595) CASE: 4 MAIN FEATURES: Diesel generation with waste heat recapture, district heating, oil-fired low-pressure boilers. CAPITAL COSTS IN 1982 PRICES: YEAR OF CAPITAL,COST COMPONENTS INAUGURATION $ x 10 1. Diesel plant extension, complete 88 12,749 2. Improvements to existing waste heat equipment 84 523 3. Oil-fired supplementary low-pressure boilers 84 3,136 4. District heat distribution system 84 6,605 PRESENT WORTH CALCULATED TO YEAR 2037 LIFE ANNUAL cQst OPERATION 55 YEARS COMPONENT EXPECTANCY $ x 10 TIME SPAN PRESENT WORTH YEARS YEARS $ X 10 1. Diesel plant extension, complete 20 Varies 50 17,394 2. Improvements to existing equipment 10 61 53 LeSid 3. Oil-fired Boiler plant 30 160 53 3,978 4. District heat distribution system 20 444 53 10,615 TOTAL 33,504 r=9 CASE: 5 MAIN FEATURES: Oil-fired Cogeneration CAPITAL COSTS IN 1982 PRICES: YEAR OF COMPONENTS INAUGURATION 1. Oil-fired steam plant 85 2. District heating distribution system 85 3. Oil stoves, etc. 83-84 PRESENT WORTH CALCULATED TO YEAR 2037 LIFE ANNUAL cgst OPERATION COMPONENT EXPECTANCY $ X 10 TIME SPAN YEARS YEARS 1. Oil-fired steam plant 30 1,206 53 2. District heating distribution system 20 444 53 3. Oil stoves, etc. 10 2 TOTAL CAPITAL COST $ X 10 23,644 6,605 36 55 YEARS PRESENT WQRTH $ xX 10 29,990 10,615 34 40,639 CASE: 6 MAIN FEATURES: Diesel generation with waste heat recapture, Coal- fired low-pressure district heating CAPITAL COSTS IN 1982 PRICES: YEAR OF COMPONENTS INAUGURATION 1. Diesel plant extension, complete 88 2. Improvements to existing waste heat equipment 84 3. Coal-fired low-pressure boilers 85 4. District heating transmission system 85 5. District heating transmission systems 85 6. Oil stoves, etc. 83-84 PRESENT WORTH CALCULATED TO YEAR 2037 LIFE ANNUAL cQst COMPONENT EXPECTANCY $ x 10 YEARS 1. Diesel plant extension, complete 20 Varies 2. Improvements to existing waste heat equipment 10 61 3. Coal-fired boilers 30 1,024 4. District heat transmission line 20 554 5. District heat distribution system 20 444 6. Oil stoves, etc. 10 TOTAL I-11 OPERATION TIME SPAN YEARS 50 54 53 53 CAPITAL gost $ X 10 12,749 523 20,064 8,244 6,605 36 55 YEARS PRESENT WQRTH $ X 10 17,394 1,517 25,458 13,251 10,615 34 68,269 CASE: 7 MAIN FEATURES: Coal-fired steam generation, Oil stoves for space heating CAPITAL COSTS IN 1982 PRICES: YEAR OF CAPITAL gost COMPONENTS INAUGURATION $ xX 10 1. Coal-fired steam generator plant 85 27.7015 2. Oil stoves, etc. 1983-2037 1,729 PRESENT WORTH CALCULATED TO YEAR 2037 LIFE ANNUAL gost OPERATION 55 YEARS COMPONENT EXPECTANCY $ x 10 TIME SPAN PRESENT WQRTH YEARS YEARS $ xX 10 1. Coal-fired steam plant 30 1,378 53 34,258 2. Oil stoves, etc. 10 Varies 55 786 TOTAL 35,044 I-12 CASE: 8 MAIN FEATURES: Hydropower generation, Coal-fired low-pressure district heating. CAPITAL COSTS IN 1982 PRICES: YEAR OF COMPONENTS INAUGURATION 1. Hydro plant 88 2. Power transmission line 88 3. Back-up gas turbine 88 4. Coal-fired low pressure boiler plant 85 5. District heating transmission system 85 6.. District heating distribtion system 85 7. Oil stoves, etc. 83-84 PRESENT WORTH CALCULATED TO YEAR 2037 LIFE ANNUAL cgst OPERATION COMPONENT EXPECTANCY $ x 10 TIME SPAN YEARS YEARS 1. Hydro plant 50 5,312 50 2. Power transmission line 20 3,470 50 3. Back-up gas turbines 50 L775 50 4. Coal-fired boiler plant 30 1,024 53 5. District heating transmission system 20 554 53) 6. District heating distribution system 20 444 53 7. Oil stoves, etc. 10 2 TOTAL I=13) CAPITAL gost $ x 10 136,689 51,623 4,500 20,064 8,244 6,605 36 55 YEARS PRESENT WORTH $ X 10 119,909 77,016 3,884 25,458 13,251 10,615 34 250,167 CASE: 9 MAIN FEATURES: Diesel generation, Geothermal district heating CAPITAL COSTS IN 1982 PRICES: YEAR OF CAPITAL gost COMPONENTS INAUGURATION $ xX 10 1. Diesel plant extension complete with additional capacity for geothermal pumps 85 17,625 2. Improvements to waste heat equipment for existing plant 84 523 3. District heating distribution system 85 8,444 4. Geothermal installation including wells and test well program 85 39,064 5. District heating transmission line 85 8,263 6. Oil stoves, etc. 83-85 54 PRESENT WORTH CALCULATED TO YEAR 2037 LIFE ANNUAL cgst OPERATION 55 YEARS COMPONENT EXPECTANCY $ x 10 TIME SPAN PRESENT WORTH YEARS YEARS $ xX 10 1. Diesel plant extension, complete with additional capacity for geo- thermal pumps 20 285 53 31,728 2. Waste heat equipment for existing plant 10 61 54 Loe 3. District heat distribution system 20 568 53 14,121 4. Geothermal instal- lation including wells and test well program 15 3,272 53 81,345 5. District heating transmission line 20 wal) 53 13,797 6. Oil stoves, etc. 10 3 50 TOTAL 142,615 I-14 CASE: 10 MAIN FEATURES: Hydropower generation, Geothermal district heating CAPITAL COSTS IN 1982 PRICES: COMPONENTS 1. Hydropower plant 2. Power transmission line 3. Backup gas turbine 4. District heating distribtion system uo systems (3 miles) 7. Oil stoves, etc. PRESENT WORTH CALCULATED TO YEAR 2037 LIFE COMPONENT EXPECTANCY YEARS 1. Hydropower plant 50 2. Power transmission line 20 3. Backup gas turbine 50 4. District heating distribution system 20 5. Geothermal instal- lation including wells and test well program 15 6. District heating transmission system 20 7. Oil stoves, etc. 10 TOTAL Geothermal installation including wells and test well program 6. District heating transmission $ x 10 TIME SPAN YEARS 5,312 50 3,470 50 186 50 568 53 37272 53 555 53 2 YEAR OF INAUGURATION 88 88 88 85 85 85 83-84 ANNUAL cgst OPERATION CAPITAL gost $ x 10 136,689 51,623 4,781 8,444 39,064 8,263 36 55 YEARS PRESENT WQRTH $ X 10 117,909 77,016 4,980 14,121 81,345 13,797 34 309,202 CASE?) 27 MAIN FEATURES: Hydropower for all purposes including electrical space heating COMPONENTS 1. Hydropower plant 2. Power transmission line 3. Backup gas turbine 4. Oil stoves, etc. CAPITAL COSTS IN 1982 PRICES: YEAR OF 83-87 INAUGURATION PRESENT WORTH CALCULATED TO YEAR 2037 COMPONENT 1. Hydropower plant 2. Power transmission line 3. Backup gas turbine 4. Oil stoves, etc. TOTAL LIFE EXPECTANCY YEARS 50 20 50 10 ANNUAL cst $ X 10 5, 3, reb6 312 470 322 OPERATION TIME SPAN YEARS 50 50 50 5 CAPITAL gost $ x 10 136,689 51,623 8,281 94 55 YEARS PRESENT WORTH $ x 10 117,909 77,016 7,143 85 202,153 APPENDIX J COAL TRANSPORTATION ANALYSIS APPENDIX J COAL TRANSPORTATION ANALYSIS TABLE OF CONTENTS 1. INTRODUCTION... .cccecccccccccccccccscscccscsecsesssesvvess Jnl 2 COAL RESOURCES... ccccscccscccccvcccccccscssccrescsscesseees JIn2 3. COST OF COAL DELIVERED TO KOTZEBUE....cscccesccvccveseeese Jn-6 4. COST COMPARISON OF COAL SUPPLIED TO KOTZEBUE....seeeeeeeee J-34 5. REFERENCES... .cccccvcrcvccscveee ver versceenne sc veveee cooe JH35 LIST OF TABLES J.1 ANALYSIS OF SELECTED ALASKAN COALS....c.eccccesecescsceee J-36 J.2 COST OF COAL DELIVERED TO KOTZEBUE (Based on a Constant 80,000 tons/year).......eeeeeeeeeees I-37 J.3 COST OF COAL DELIVERED TO KOTZEBUE (Based on a Constant 975 Billion Btu/year)........eee002+ J-38 APPENDIX J - COAL TRANSPORTATION ANALYSIS 1. INTRODUCTION The overall program determined the best method of supplying heat and electrical energy to the City of Kotzebue with the assumption that coal will be supplied. This study will determine the cost of coal delivered to Kotzebue from the following sources: o Nenana (Usibelli) field o Chicago Creek Area o Kobuk River Area (outside Federal jurisdiction) o Cape Beaufort Area These costs will include: mining, manpower, equipment, terminals, roads, docks, transportation, etc. Kotzebue is a city of 2,600 people located at the northwest end of the Baldwin Peninsula. There are no roads into the area and all transportation of goods is done by air or sea. The water is shallow (A’6 feet in depth) at the loading facility. Dredging of the area to allow access by deep draft vessels is impractical due to the silting action of the Kobuk River. Kotzebue is "iced-in" for approximately eight months of the year. This situation allows only a four month period to barge in fuel and supplies for the rest of the year. This "iced-in" situation also prohibits the building of any over water pile supported docks or piers. This study will describe: (1) the coal regions of Nenana, Chicago Creek, Kobuk River, and Cape Beaufort, along with the proximate analysis of the coals from these regions; (2) the cost of coal delivered to Kotzebue based on a constant quantity and a constant energy of the coal delivered under the following conditions: (a) road building as a direct coal development cost, (b) without road building, (c) using existing docking facilities at Kotzebue, (d) the dock is provided at Kotzebue, and (e) marine terminal to Cape Blossom and a road to the mine; and (3) a comparison of the costs of the coals delivered to Kotzebue under the various conditions. Each of these are described in detail in the various sections of the report. 2. COAL RESOURCES The coal resources used are described in the following paragraphs. A summary of the coal proximate analysis is presented in Table l. Nenana Coal Field(1) The Nenana coal field, one of the two producing coal fields of Alaska, extends for about 80 miles along the north flank of the Alaska Range, between the headwaters of the Wood River on the east and the Kantishna River on the west. Tertiary coal-bearing rocks outcrop in a discontinuous belt generally ranging from 1 to 30 miles in width. The rocks have been folded and faulted into a series of basins, between which they are either eroded away or covered by younger Tertiary or Quaternary deposits. The coal-bearing formations include a large number of subbituminous coal béds, ranging from a few inches to 60 feet in thickness. Analysis of mine and outcrop samples from the Nenana field are given in Table 1. Total source figures based on a detailed survey indicate approximately 6,940 million tons. The structure of most of the individual basins is simple; the beds are broken by a few faults and compressed into open folds with moderate to low dips. At the east end of the Healy Creek basin nearly vertical to slightly overturned beds were measured near the axis of a faulted syncline. The Nenana coal field is served by The Alaska Railroad, which follows the Nenana River across the center of the field. Principal development and coal production to date has been on Healy Creek and from an underground mine at Suntrana and two strip mines farther upstream. A strip mine was operated for a few years during and after World War II on the western extension of the same beds about 4 miles southwest of Healy and a strip mine was opened in 1955 on Lignite Creek. All other parts of the field are remote from present transportation and are undeveloped. Chicago Creek Area(1) Significant coal deposits (late Cretaceous age) are known on the Kugruk River, about 15 miles west of Candle, where coal beds have been opened on the river about 4 miles south of Chicago Creek, and on Chicago Creek about a mile above its mouth. The bed on the river is reported to contain 18 feet of lignitic coal in three benches separated by several inches of clay. This bed dips nearly 70° and has been opened by a slope from which a few thousand tons of coal had been mined. The bed on Chicago Creek also has been opened by a slope, from which 60,000-100,000 tons of lignite was mined between 1908 and 1911. This bed, which dips 53° and has only a few thin parting 4% is reported to be at least 85 feet thick where measured along a crosscut. The coal is frozen solid down to the bottom of the slope, 200 feet vertically below the surface. The only information on the extent of the bed was obtained by drilling in 1908, which showed that the coal is present about 70 feet below the surface half a mile northwest of the mine. Analysis of the coal are given in Table J.1l. Kobuk River Area(!) Coal-bearing rocks that are probably Late Cretaceous occur at several widely scattered localities in a belt that extends along the Kobuk River and eastward to the headwaters of the Koyukuk River. The westernmost locality is on the north side of the Kobuk between Trinity Creek and the Kallarichuk River, where several thin coal beds, only a few of which are as much as 2 feet thick, are exposed in the river bluffs. Some of this coal was mined for use in the nearby placer gold fields. An analysis of a coal sample from this locality indicates that it is on the borderline between subbituminous and bituminous (Table J.1). Other reported coal localities in the Kobuk basin are on the Hunt, lower Ambler, and Kogoluktuk Rivers, and in the Lockwood Hills near the Pah River. A coal bed containing 9-10 feet of nearly pure coal lies within an eastward extension of the coal-bearing rocks of the Kobuk basin, about 35 miles above Bettles. An analysis of this coal indicates that it probably is bituminous in rank (Table J.1). As far as is known, this coal has not been developed; its extent is unknown. The presence of coal on the John River, north of Bettles, is indicated by abundant coal float in the river gravels, but no coal has been found in place. Cape Beaufort Area(1) Coal-bearing Cretaceous rocks are known or inferred to underlie this area. These rocks, consisting mainly of alternating layers of sandstone and shale, have been folded into eastward-trending anticlines and synclines. Because of differences in resistance of the rocks to J-4 erosion, the folds are expressed topographically by the general east-west alignment of the ridges and valleys. Near, the mountains the folding and faulting has been more intense and in places the strata stand nearly vertical, but in the northern foothills, which include the southernmost coal-bearing rocks, deformation has been only moderate, and farther north under the Coastal Plain the beds are nearly horizontal. Far to the west, along the coast south of Cape Lisburne, bituminous coal is exposed in several places in strongly folded and faulted Mississippian rocks. In the Cape Beaufort region, at least 20 beds of bituminous coal ranging from 2 1/2 to 9 feet in thickness, as well as many thinner beds, are exposed in beach bluffs from the vicinity of Corwin Bluff, about 30 miles east of Cape Lisburne, to Cape Beaufort. These beds dip moderately to steeply southwestward from the eastward trending coast, and one inland outcrop shows that the coal-bearing rocks extend at least 10 miles along the strike. Down the Kukpowruk River, coal-bearing rocks are exposed at intervals along the lower 25 miles of the river, where they lie in a series of eastward-trending folds which dip 12°-55°. Forty coal beds 1 1/2-13 feet thick were measured along the river; some of the beds may be repeated by folding. Coal-bearing rocks also underlie a small area 70 miles above the mouth of the river and include at least one 3-foot bed of coal. Analyses show all this coal to be bituminous in rank and is presented in Table J.1). Because these beds are exposed only in the river valley, their lateral extent is unknown, but geologic evidence suggests that large areas on both sides of the river may be underlain by coal beds of minable thickness. 3 COST OF COAL DELIVERED TO KOTZEBUE The cost of coal delivered to Kotzebue from Nenana, Chicago Creek, Kobuk River, and Cape Beaufort was determined for the quantity of coal required in the year 2002. The cost of the coal that was moved from each area was evaluated in terms of: (1) road building as a direct coal development cost, (2) excluding road building as a direct coal development cost, (3) using the existing docking condition at Kotzebue---no dock, (4) a dock is provided at Kotzebue but not part of the coal cost, and (5) a marine terminal is provided at Cape Blossom and/or such a terminal with a road to Chicago Creek. Further, the transportation costs also included the sizes of tugs and barges, the number of trips, seasonal constraints on shipping and loading/off-loading of the coal. Nenana In the evaluation of coal from Nenana field two possible approaches were taken. The first approach was to assume that coal would be delivered by the Alaska Railroad to a river barge loading facility to be constructed near Nenana. The coal would be barged down the Tanana and Yukon rivers to a trans-loading facility near the mouth of the Yukon. The coal would then be trans-loaded to the 400 x 76 foot 9200 DWI barges and hauled to the Kotzebue Sound area where lightering barges would be used to transfer it to Kotzebue Sound where it would then be hauled to the power plant by truck and stockpiled. J-6 This supply plan becomes very expensive and impractical because: (a) the large number (84) of small capacity 200 DWT shallow draft river barges required; (b) the two week round trip; and (c) the short (75) day season. Also required would be two 9200 DWI and three 1000 DWI barges and one 9000 HP ocean tug and three 650 HP lightering tugs. The second approach was to assume that the coal would be delivered to a coal handling facility in Seward via the Alaska Railroad. The coal would be off-loaded from the railcars and loaded onto two 400 x 76 foot 9,200 DWI barges and hauled to Kotzebue Sound area where lightering barges would be used to transfer it to Kotzebue for transfer to the power plant. The barges would leave the Seward terminal and travel through the Unimak Pass in the Aleutian chain and then through the Bering Sea up to Kotzebue. The barges would then be lightered to transfer the coal to Kotzebue and then to the power plant. Chicago Creek In the evaluation of using coal from the Chicago Creek area it was assumed the mine would be reopened and a twenty mile road constructed (either as part of the project, or by the State) and an ocean barge loading facility.constructed at tidewater. Coal would be loaded on 9200 DWT barges and taken to Kotzebue sound area where lightering barges would be used to transfer the coal to Kotzebue sound where it would then be trucked to the power plant and stockpiled. Two 9200 DWI and three 1000 DWI barges and one 9000 HP and three 650 HP tugs would be required for barging operation. In the evaluation of coal from the Kobuk River area it was assumed that a mine would be opened and a haul road and access roads constructed (approximately 3 miles). Further, it was assumed that a river barge loading facility would be constructed on the Kobuk River near the mine area, a trans-loading facility constructed at the mouth of the Kobuk River. The mined coal would be hauled to the river barge loading facility and loaded aboard 120' x 30' 250 DWI self-propelled tunnel drive 2.5 foot draft river barges which would carry the load to the trans-loading facility at the mouth of the river. The coal would then be transferred to 160' x 48' "lightering" type barges which would be towed to the unloading facility on Kotzebue Sound by two 650 HP lightering tugs. The coal is then off-loaded and hauled approximately 5 miles and stockpiled at the power plant. The river barge round trip will take two days (one day loading and traveling down river and one day unloading and returning up river). Larger quantities of coal can be hauled per trip early in the season when the water is high; however, the barge will hve to be loaded with smaller quantities of coal to reduce the draft during low water conditions. The average load per barge over the season was assumed to be 178 tons. Eight to twelve barges will be required, depending on the selected scenarios, to move the coal during the operating season which was assumed to. be 75 days. Three 1000 DWT 160' x 48' barges will be used to transfer the coal at Kotzebue (one loading, one unloading and one in transit). Cape Beaufort In the evaluation of using coal from the Cape Beaufort area it was assumed the mine would be reopened, a five mile road constructed and an ocean barge loading facility constructed at tidewater. Coal would be loaded on 9200 DWI barges and taken to the Kotzebue sound area where lightering barges would be used to transfer the coal to Kotzebue sound where it would then be trucked to the power plant and stockpiled. Two 9200 DWI and three 1000 DWI barges and one 9000 HP and three 650 HP tugs will be required for barging operation. In Case 1, the cost for the construction of the haul road and access roads are included in the overall cost. Further, Case 1 assumes that there is no dock at Kotzebue and that the existing conditions will be utilized in the off-loading of the coal. In Case 2, the road construction costs are not included in the overall costs. Further, it was assumed that the existing unloading conditions at Kotzebue are used as in Case l. In Cases 3 and 4 it was assumed that a dock was built at Kotzebue, however, the costs associated with this docking facility are not included in the overall cost of coal. In Case 3 it was assumed that a haul road and access roads are included in the overall costs, whereas, in Case 4 the road construction costs were eliminated from the overall cost of coal. J-9 In Cases 5 and 6 it was assumed that a marine terminal would be provided at no cost to the project at Cape Blossom, along with a road to Kotzebue. In Case 5 road construction costs were included, whereas, in Case 6 road construction costs were eliminated from the overall coal costs. In Cases 3, 4, 5 and 6 it was assumed that the off-loading equipment is included in the overall cost of the coal. The mining costs included materials, equipment, and personnel required to perform the mining and/or open a new mine. Surface mining was only considered because of the logistical problems associated with underground mines, and the difficulty in obtaining skilled underground miners. In the evaluation of the cost of coal delivered to Kotzebue, two different scenarios were considered. In the first scenario, a constant quantity of coal (80,000 tons/year) is delivered to Kotzebue under each of the five cases, whereas, in the second scenario, a constant amount of energy (975 billion Btu/year) is delivered to Kotzebue in the form of coal. In the development of the costs, the equipment was amortized over a ten year period. The interest rate for money was assumed at 15 percent and simple interest analysis was used. J-10 3.1 COST OF COAL -- CONSTANT QUANTITY DELIVERED TO KOTZEBUE The cost of coal delivered to Kotzebue is based on 80,000 tons per year. This coal will come either from the Nenana Field, Chicago Creek, Kobuk River, or Cape Beaufort from which the costs will be evaluated under five different situations and are presented in the following paragraphs. Nenana Field The cost to obtain coal from the Nenana field for use in Kotzebue is based on the following assumptions: (a) the coal has an average gravimetric heat of combustion of 8,000 Btu/lb., (b) 80,000 short tons are required, and (c) four months are available to mine, ship, and store the coal in Kotzebue prior to the onset of the winter season. Summary of coal Costs (Case 1 - Includes Road Building As a Direct Coal Development Cost With Existing Facilities At Kotzebue NOT APPLICABLE Summary of Coal costs (Case 2 - Does Not Include Road Building As A Direct Coal Development Cost with Existing Facilities at Kotzebue Via Via Rail To Yukon Seward River S/Ton_ — _$/Ton Mine Development and Camp Facilities N/A N/A Road Construction at Mine N/A N/A Construction of Trans Loading and/or Quay N/A N/A Mining, Hauling & Loading — 425 22) 34.63 oe Barge Transportation 76.59 182.64 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 12.09 12.09 Royalty =O =05 Total Unit Cost ($/Ton) $ 130.90 $229.36 Total Unit Energy Cost ($/Million Btu) 8.18 14.34 Summary of Coal Costs (Case 3 - Includes Road Building As a Direct Coal Development Cost With Docking Facilities At Kotzebue) NOT APPLICABLE Summary of Coal costs (Case 4 - Does Not Include Road Building As a Direct Coal Development Cost with Docking Facilities at Kotzebue) Via Via Rail To Yukon Seward River _$/Ton __$/Ton Mine Development and Camp Facilities N/A N/A Road Construction at Mine N/A N/A Construction of Trans Loading and/or Quay N/A N/A Mining, Hauling & Loading 42.22 34.63 Barge Transportation 65.25 173.10 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 12.09 12.09 Royalty -0- -0- Total Unit Cost ($/Ton) $119.56 $219.82 Total Unit Energy Cost ($/Million Btu) $ 7.47 §$ 13.74 J-12 Summary of Coal Costs (Case 5 - Includes Road Building As a Direct Coal Development Cost With a Marine Terminal At Cape Blossom NOT APPLICABLE Summary of Coal costs (Case 6 ~ Does Not Include Road Building As a Direct Coal Development Cost With a Marine Terminal At Cape Blossom) Via Rail To Seward $/Ton Mine Development and Camp Facilities N/A Road Construction at Mine N/A Construction of Trans Loading and/or Quay N/A Mining, Hauling & Loading 42.22 Barge Transportation 65.25 Coal Off-Loading, Hauling & Stockpiling at Kotzebue. 13.84 Royalty aa Total Unit Cost ($/Ton) $121.31 Total Unit Energy Cost ($/Million Btu) $ 7.58 Chicago Creek Area Via Yukon River $/Ton N/A N/A N/A 34.63 170.29 13.84 -0- $218.76 $13.67 The cost to bring coal from the Chicago Creek area to Kotzebue is based on: (a) the average gravimetric heat of combustion is 6,500 Btu/lb., (b) 80,000 short tons of coal, (c) four months are available to mine, ship, and store the coal at Kotzebue. w—13 Summary of Coal Costs (Case 1 - Includes Road Building As a Direct Coal Development Cost with Existing Facilities at Kotzebue) $/Ton Mine Development and Camp Facilities $ 11.87 Road Construction at Mine 19.50 Construction of Trans Loading and/or Quay 2.10 Mining, Hauling & Loading 37.15 Barge Transportation 19.34 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 12.09 Royalty 1.00 Total Unit Cost $103.05/Ton Total Unit Energy Cost $7.93/million Btu Summary of Coal Costs (Case 2 - Does Not Include Road Building As a Direct Coal Development Cost - With Existing Facilities at Kotzebue) $/Ton Mine Development and Camp Facilities $ 11.87 Road Construction at Mine N/A Construction of Trans Loading and/or Quay 2.10 Mining, Hauling & Loading 37.15 Barge Transportation 19.34 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 12.09 Royalty 1.00 Total Unit Cost J-14 $ 83.55/Ton Total Unit Energy Cost $6.43/million Btu Summary of Coal Costs (Case 3 - Includes Road Building As a Direct Coal Development Cost With Docking Facilities at Kotzebue) $/Ton Mine Development and Camp Facilities $ 11.87 Road Construction at Mine 19.50 Construction of Trans Loading and/or Quay 2a10 Mining, Hauling & Loading 37.15 Barge Transportation 19.34 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 12.09 Royalty 1.00 Total Unit Cost $ 103.05/Ton Total Unit Energy Cost $7.93/million Btu Summary of Coal Costs (Case 4 - Does Not Include Road Building As a $/Ton Mine Development and Camp Facilities $ 11.87 Road Construction at Mine N/A Construction of Trans Loading and/or Quay 2.10 Mining, Hauling & Loading 37.15 Barge Transportation 19.34 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 12.09 Royalty 1.00 Total Unit Cost $ 83.55 Total Unit Energy Cost $6.43/million Btu J-15 Summary of Coal Costs (Case 5 - Includes Road Building As a Direct Coal Development Cost With a Marine Terminal at Cape Blossom) $/Ton Mine Development and Camp Facilities $ 11.87 Road Construction at Mine 19.50 Construction of Trans Loading and/or Quay 2.10 Mining, Hauling & Loading 37.15 Barge Transportation 17.24 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 13.84 Royalty 1.00 Total Unit Cost $102.70 Total Unit Energy Cost $7.90/million Btu Summary of Coal Costs (Case 6 - Does Not Include Road Building As a Direct Coal Development Cost With a Marine Terminal at Cape Blossom) $/Ton Mine Development and Camp Facilities $ 11.87 Road Construction at Mine N/A Construction of Trans Loading and/or Quay 25:10 Mining, Hauling & Loading 37.15 Barge Transportation 17.24 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 13.84 Royalty 1.00 Total Unit Cost $ 83.20/Ton Total Unit Energy Cost $6.40/million Btu J-16 Kobuk River Area The cost to bring the coal from the Kobuk River area to Kotzebue is based on: (a) the average heat of combustion of the coal of 10,000 Btu/lb., (b) 80,000 tons/year coal, (c) four months are available to mine, ship and store the coal at Kotzebue. Summary of Coal Costs (Case 1 ~ Includes Road Building As a Direct Coal Development Cost With Existing Facilities at Kotzebue) $/Ton Mine Development and Camp Facilities $ 14.21 Road Construction at Mine 3.18 Construction of Trans Loading and/or Quay 2. 25 Mining, Hauling & Loading 27.22 Barge Transportation 35.49 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 12.09 Royalty 1.00 Total Unit Cost $ 95.44 Total Unit Energy Cost °$4.77/million Btu Direct Coal Development Cost - With Existing Facilities at Kotzebue) $/Ton Mine Development and Camp Facilities S 14.521 Road Construction at Mine N/A Construction of Trans Loading and/or Quay 2.25 Mining, Hauling & Loading 27322 Barge Transportation 35.49 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 12.09 Royalty 1.00 A hd! Total Unit Cost $ 92.26/Ton Total Unit Energy Cost $4.61/million Btu Summary of Coal Costs (Case 3 - Includes Road Building As a Direct Coal Development Cost With Docking Facilities at Kotzebue) $/Ton Mine Development and Camp Facilities $ 14.21 Road Construction at Mine N/A Construction of Trans Loading and/or Quay 2.25 Mining, Hauling & Loading 271622 Barge Transportation 35.49 Coal Off-Loading, Hauling & Stockpiling at Kotzebue = | 12509 Royalty 1.00 Total Unit Cost $ 95.44 Total Unit Energy Cost $4.77/million Btu Summary of Coal Costs (Case 4 - Does Not Include Road Building As a Direct Coal Development Cost - With Docking Facilities at Kotzebue) $/Ton Mine Development and Camp Facilities $ 14.21 Road Construction at Mine N/A Construction of Trans Loading and/or Quay 2325 Mining, Hauling & Loading 27.22 Barge Transportation 35.49 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 12.09 Royalty 1.00 Total Unit Cost $ 92.26/Ton Total Unit Energy Cost $4.61/million Btu J-18 Summary of Coal Costs (Case 5 - Includes Road Building As a Direct Coal Development Cost With a Marine Terminal at Cape Blossom) $/Ton Mine Development and Camp Facilities N/A Road Construction at Mine N/A Construction of Trans Loading and/or Quay N/A Mining, Hauling & Loading N/A Barge Transportation N/A Coal Off-Loading, Hauling & Stockpiling at Kotzebue N/A Royalty N/A Total Unit Cost Total Unit Energy Cost Summary of Coal Costs (Case 6 - Does Not Include Road Building As a Direct Cost With a Marine Terminal at Cape Blossom) $/Ton Mine Development and Camp Facilities N/A Road Construction at Mine . N/A Construction of Trans Loading and/or Quay N/A Mining, Hauling & Loading N/A Barge Transportation N/A Coal Off-Loading, Hauling & Stockpiling at Kotzebue N/A Royalty N/A CAPE BEAUFORT AREA The cost to bring coal from the Cape Beaufort area to Kotzebue is based on: (a) the average gravimetric heat of combustion of 14,000 Btu/lb., (b) 80,000 tons/year coal, (c) four months are available to mine, ship, and store the coal at Kotzebue. J—Lo Summary of Coal Costs (Case 1 - Includes Road Building As a Direct Coal Development Cost with Existing Facilities at Kotzebue) $/Ton Mine Development and Camp Facilities $ 11.87 Road Construction at Mine 7.87 Construction of Trans Loading and/or Quay 2.10 Mining, Hauling & Loading 27 a27 Barge Transportation 61.21 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 12.09 Royalty 1.00 Total Unit Cost $123.41/Ton Total Unit Energy Cost $4.41/million Btu Summary of Coal Costs (Case 2 - Does Not Include Road Building As a Direct Coal Development Cost with Existing Facilities at Kotzebue) $/Ton Mine Development and Camp Facilities . $ 11.87 Road Construction at Mine N/A Construction of Trans Loading and/or Quay 2.10 Mining, Hauling & Loading a1 27 Barge Transportation 61.21 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 12.09 Royalty 1.00 Total Unit Cost $115.54/Ton Total Unit Energy Cost $4.13/million Btu Summary of Coal Costs (Case 3 - Includes Road Building As a Direct Coal Development Cost With Docking Facilities at Kotzebue) J-20 $/Ton Mine Development and Camp Facilities $ 11.87 Road Construction at Mine 7.87 Construction of Trans Loading and/or Quay 2.10 Mining, Hauling & Loading 27 «27 Barge Transportation 51.67 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 12.09 Royalty 1.00 Total Unit- Cost $113.87/Ton Total Unit Energy Cost $4.07/million Btu Summary of Coal Costs (Case 4 - Does Not Include Road Building As a Direct Coal Development Cost With Docking Facilities at Kotzebue) $/Ton Mine Development and Camp Facilities $ 11.87 Road Construction at Mine N/A Construction of Trans Loading and/or Quay 2510) Mining, Hauling & Loading c Dees Barge Transportation 51.67 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 12.09 Royalty __ 1.00 Total Unit Cost $106.00/Ton Total Unit Energy Cost $3.79/million Btu Summary of Coal Costs (Case 5 - Inlcudes Road Building As a Direct Coal Development Cost With a Marine Terminal at Cape Blossom) $/Ton Mine Development and Camp Facilities $ 11.87 Road Construction at Mine ov J-21 Construction of Trans Loading and/or Quay Zald Mining, Hauling & Loading Bald Barge Transportation 51.67 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 13.84 Royalty 1.00 Total Unit Cost $115.62/Ton Total Unit Energy Cost $4.13/million Btu Summary of Coal Costs (Case 6 - Includes Road Building As a Direct Coal Development Cost With a Marine Terminal at Cape Blossom) $/Ton Mine Development and Camp Facilities $ 11.87 Road Construction at Mine N/A Construction of Trans Loading and/or Quay 2.10 Mining, Hauling & Loading 27.27 Barge Transportation 51.67 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 13.84 Royalty i 1.00 Total Unit Cost $107.25 Total Unit Energy Cost $3.83/million Btu 3.2 COST OF COAL CONSTANT ENERGY DELIVERED TO KOTZEBUE The cost of coal delivered to Kotzebue is based on a constant energy of 975 billion Btu/year. The coal under the evaluation will come from either the Nenana Field, Chicago Creek, Kobuk River, or Cape Beaufort areas. The costs of delivering either of these coals to Kotzebue under five different situations was evaluated and is presented in the following paragraphs. J-22 Nenana Field The cost to obtain coal from the Nenana Field for use in Kotzebue is based on the following assumptions: (a) the coal has a heat of combustion of 8000 Btu/lb., (b) 61,000 short tons/year are required, and (c) four months are available to mine, ship, and store the coal in Kotzebue. Summary of Coal Costs (Case 1 - Includes Road Building As a Direct Coal Development Cost With Existing Facilities at Kotzebue) NOT APPLICABLE Summary of Coal Costs (Case 2 - Does Not Include Road Building As a Direct Coal Development Cost - With Existing Facilities at Kotzebue) Via Via Rail To Yukon Seward River $/Ton __$/Ton Mine Development and Camp Facilities N/A N/A Road Construction at Mine N/A N/A Construction of Trans Loading and/pr Quay N/A N/A Mining, Hauling & Loading 42.80 B5 ie 21. Barge Transportation 84.93 185.83 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 13-562, 13.62 Royalty ~ Or -0- J=23 Total Unit Cost ($/Ton) $141.44 Total Unit Energy Cost ($/Million Btu) $ 8.84 $234.66 $ 14.67 Summary of Coal Costs (Case 3 - Includes Road Building As a Direct Coal Development Cost With Docking Facilities at Kotzebue) NOT APPLICABLE Summary of Coal Costs (Case 4 - Does Not Include Road Building As a Direct Coal Development Cost With Docking Facilities at Kotzebue) Via Rail To Seward $/Ton Mine Development and Camp Facilities N/A Road Construct on at Mine N/A Construction of Trans Loading and/or Quay i N/A Mining, Hauling & Loading 42.80 Barge Transportation 70.81 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 13.62 Royalty -0- Total Unit Cost ($/Ton) $127.23 Total Unit Energy Cost ($/Million Btu) S795) Via Yukon River $/Ton N/A N/A N/A 35.21 174.07 13.62 ote $222.90 $ 13.93 Summary of Coal Costs (Case 5 ~ Includes Road Building As a Direct Coal Development Cost With a Marine Terminal at Cape Blossom) J-24 NOT APPLICABLE Summary of Coal Costs (Case 6 - Does Not Include Road Building As a Direct Coal Development _ Cost With a Marine Terminal At Cape Blossom) Via Via Rail To Yukon Seward River $/Ton $/Ton Mine Development and Camp Facilities N/A N/A Road Construction at Mine N/A N/A Construction of Trans Loading and/or Quay N/A N/A Mining, Hauling & Loading 42.80 35.21 Barge Transportation 70.81 170.29 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 15.44 15.44 Royalty -0- -0- Total Unit Cost ($/Ton) $129.05 $221.91 Total Unit Energy Cost ($/Million Btu) « § @.07 § 13.87 Chicago Creek Area The cost of coal delivered to Kotzebue from the Chicago Creek area is based on: (a) the average gravimetric heat of combustion is 6,500 Btu/lb., (b) 75,000 short tons of coal, and (c) four months are available to mine, ship, and store the coal at Kotzebue. Summary of Coal Costs (Case 1 - Includes Road Building As a Direct Coal Development Cost With Existing Facilities at Kotzebue) $/Ton Mine Development and Camp Facilities $ 12.66 J-25 Road Construction at Mine 20.80 Construction of Trans Loadingand/or Quay 2.24 Mining, Hauling & Loading 37.15 Barge Transportation 19.88 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 12.42 Royalty 1.00 Total Unit Cost $106.15/Ton Total Unit Energy Cost $8.17/million Btu Summary of Coal Costs (Case 2 - Does Not Include Road Building As a Direct Coal Development Cost With Existing Facilities At Kotzebue) $/Ton Mine Development and Camp Facilities 12.66 Road Construction at Mine N/A Construction of Trans Loading and/or Quay 2.24 Mining, Hauling & Loading 37.515 Barge Transportation 19.17 Coal Off-Loading, Hauling & Stockpiling at Kotzebue - 12.42 Royalty 1.00 Total Unit Cost $ 85.35 Total Unit Energy Cost $6.57/million Btu Summary of Coal Costs (Case 3 - Includes Road Building As a Direct Coal Development Cost With Docking Facilities at Kotzebue) $/Ton Mine Development and Camp Facilities $ 12.66 Road Construction at MIne 20.80 Construction of Trans Loading and/or Quay 2.24 J-26 Mining, Hauling & Loading 37.15 Barge Transportation 19.88 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 12.42 Royalty 1.00 Total Unit Cost $106.15 Total Unit Energy Cost $8.17/million Btu Summary of Coal Costs (Case 4 - Does Not Include Road Building As a Direct Coal Development Cost With Docking Facilities At Kotzebue) $/Ton Mine Development and Camp Facilities $ 12.66 Road Construction at Mine N/A Construction of Trans Loading and/or Quay 2.24 Mining, Hauling & Loading 37.15 Barge Transportation 19.17 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 12.42 Royalty . 1.00 Total Unit Cost $ 85.35 Total Unit Energy Cost $6.57/million Btu Summary of Coal Costs (Case 5 - Includes Road Building As a Direct Coal Development Cost With a Marine Terminal at Cape Blossom) $/Ton Mine Development and Camp Facilities $ 12.66 Road Construction at Mine 20.80 Construction of Trans Loading and/or Quay 2.24 Mining, Hauling & Loading 37.15 Barge Transportation , 17.78 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 14.19 Royalty 1.00 Total Unit Cost $105.82/Ton Total Unit Energy Cost $8.14/million Btu Summary of Coal Costs (Case 6 - Does Not Include Road Building As a Direct Coal Development Cost With a Marine Terminal at Cape Blossom) $/Ton Mine Development and Camp Facilities 12.66Road Construction at Mine N/A Construction of Trans Loading and/or Quay 2.24 Mining, Hauling & Loading 37.15 Barge Transportation 17.78 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 14.19 Royalty 1.00 Total Unit Cost . $ 85.02 Total Unit Energy Cost $6.54/million Btu Kobuk River Area The cost to bring the coal from the Kobuk River area to Kotzebue is based on: (a) the average heat of combustion of the coal of 10,000 Btu/1b., (b) 52,000 tons/year coal, and (c) four months are available to mine, ship and store the coal at Kotzebue. Summary of Coal Costs (Case 1 - Includes Road Building As a Direct Coal Development Cost With Existing Facilities at Kotzebue) J-28 $/Ton Mine Development and Camp Facilities $ 23.19 Road Construction at Mine 5.20 Construction of Trans Loading and/or Quay 3.26 Mining, Hauling & Loading 24.75 Barge Transportation 42.99 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 15.19 Royalty 1.00 Total Unit Cost $115.58/Ton Total Unit Energy Cost $5.78/million Btu Summary of Coal Costs (Case 2 - Does Not Include Road Building As a Direct Coal Development Cost With Existing Facilities at Kotzebue) $/Ton Mine Development and Camp Facilities $ 23.19 Road Construction at Mine N/A Construction of Trans Loading and/or Quay 3.26 Mining, Hauling & Loading : 24.75 Barge Transportation 42.99 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 15.19 Royalty 1.00 Total Unit Cost $110.38/Ton Total Unit Energy Cost $5.52/million Btu Summary of Coal Costs (Case 3 - Includes Road Building As a Direct Coal Development Cost With Docking Facilities at Kotzebue) $/Ton Mine Development and Camp Facilities $ 23.19 Road Construction at Mine ~— 5.20 J-29 Construction of Trans Loading and/or Quay 3.26 Mining, Hauling & Loading 24.75 Barge Transportation 42.99 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 15-19) Royalty 1.00 Total Unit Cost $115 .58/Ton Total Unit Energy Cost $5.78/million Btu Summary of Coal Costs (Case 4 - Does Not Include Road Building As a Direct Coal Development Cost With “Docking Facilities at Kotzebue) $/Ton Mine Development and Camp Facilities 23.19 Road Construction at Mine N/A Construction of Trans Loading and/or Quay 3.26 Mining ,Hauling & Loading 24.75 Barge Transportation 42.99 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 15.19 Royalty - 1.00 Total Unit Cost $110.38/Ton Total Unit Energy Cost $5.52/million Btu Summary of Coal Costs (Case 5 - Includes Road Building As a Direct Coal Development Cost With a Marine Terminal at Cape Blossom) $/Ton Mine Development and Camp Facilities N/A Road Construction at Mine N/A Construction of Trans Loading and/or Quay N/A Mining, Hauling & Loading N/A Barge Transportation : N/A J-30 Coal Off-Loading Hauling & Stockpiling at Kotzebue N/A Royalty N/A Total Unit Cost Total Unit Energy Cost Summary of Coal Costs (Case 6 - Does Not Include Road Building As a Direct Coal Development Cost With a Marine Terminal at Cape Blossom) $/Ton Mine Development and Camp Facilities N/A |Road Construction at Mine N/A Construction of Trans Loading and/or Quay N/A Mining, Hauling & Loading N/A Barge Transportation N/A Coal Off-Loading, Hauling & Stockpiling at Kotzebue N/A Royalty N/A Total Unit Cost Total Unit Energy Cost Cape Beaufort The cost to obtain coal from the Cape Beaufort Area for use in Kotzebue is based on the following assumptions: (a) the heat of combustion is 14,000 Btu/lb., (b) 35,000 tons/year of coal are required, and (c) four months are available to mine, ship, and store the coal at Kotzebue. Summary of Coal costs (Case 1 ~- Includes Road Building As a Direct Coal Development Cost with Existing Facilities at Kotzebue) $/Ton Mine Development and Camp Facilities $ 27.15 Road Construction at Mine 18.00 Construction of Trans Loading and/or Quay 4.79 Mining, Hauling & Loading 27.27 Barge Transportation 88.71 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 18.38 Royalty 1.00 Total Unit Cost $185.30/Ton Total Unit Energy Cost $6.62/million Btu Summary of Coal Costs (Case 2 - Does Not Include Rod Building As a Direct Coal Development Cost With Existing Facilities at Kotzebue) $/Ton Mine Development and Camp Facilities $ 27.15 Road Construction at Mine N/A Construction of Trans Loading and/or Quay 4.79 Mining, Hauling & Loading 27.27 Barge Transportation 88.71 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 18.38 Royalty 1.00 Total Unit Cost $167.30/Ton Total Unit Energy Cost $5.98/million Btu Summary of Coal Costs (Case 3 - Includes Road Building As a Direct Coal Development Cost With Docking Facilities at Kotzebue) $/Ton Mine Development and Camp Facilities $ 27.15 Road Construction at Mine i 18.00 J-32 Construction of Trans Loading and/or Quay 4.79 Mining, Hauling & Loading a7 a7 Barge Transportation 69.99 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 18.38 Royalty 1.00 Total Unit Cost $166.58/Ton Total Unit Energy Cost $5.95/million Btu Summary of Coal Costs (Case 4 -Includes Road Building As a Direct Coal Development Cost With Docking Facilities at Kotzebue) $/Ton Mine Development and Camp Facilities $ 27.15 Road Construction at Mine N/A Construction of Trans Loading and/or Quay 4.79 Mining, Hauling & Loading Qe2t Barge Transportation 69.99 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 18.38 Royalty 1.00 Total Unit Cost $148.58/Ton Total Unit Energy Cost $5.31/million Btu Summary of Coal Costs (Case 5 ~- Includes Road Building As a Direct Coal Development Cost With a Marine Terminal at Cape Blossom) $/Ton Mine Development and Camp Facilities $ 27.15 Road Construction at Mine 18.00 Construction of TransLoading and/or Quay 4.79 Mining, Hauling & Loading ~ 27.27 Barge Transportation 69.99 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 20.53 Royalty 1.00 Total Unit Cost $168.73/Ton Total Unit Energy Cost $6.03/million Btu Development Cost With a Marine Terminal at Cape Blossom) $/Ton Mine Development and Camp Facilities $ 27.15 Road Construction at Mine N/A Construction of Trans Loading and/or Quay 4.79 Mining, Hauling & Loading 27-27) Barge Transportation 69.99 Coal Off-Loading, Hauling & Stockpiling at Kotzebue 20.53 Royalty 1.00 Total Unit Cost $150.73/Ton Total Unit Energy Cost $5.38/million Btu 4. COST COMPARISON OF COAL SUPPLIED TO KOTZEBUE The cost of coal supplied to Kotzebue was based on supplying 80,000 tons per year from the Nenana field, Chicago Creek Area, Kobuk River Area, and the Cape Beaufort Area. Further, the cost was determined assuming a constant 975 billion Btu being supplied. This is equivalent to 61,000 tons per year from Nenana; 75,000 tons per year from Chicago Creek; 52,000 tons per year from Kobuk River, and 35,000 tons per year from the Cape Beaufort Area. The results of these evaluations are summarized in Tables J.2 and J.3. I-34 An examination of Table J.2 (based on a constant 80,000 tons per year quantity)indicates that the most economical coal to be used at Kotzebue is from the Cape Beaufort Area for each of the six cases. An examination of Table J.3 (based on a constant 975 billion Btu per year) indicates that the most economical coal to be used at Kotzebue will be supplied from the Kobuk River area. In the case of the Cape Beaufort coal, the high heat content along with low transportation costs and ease of access to the potential mine site are some of the reasons why the Cape Beaufort coal area is the most economical approach to supplying coal to the City of Kotzebue if a quantity of 80,000 tons per year are required; however, the Kobuk River coal at approximately 10,000 Btu per pound and the use of 52,000 tons make this source the most economical approach to supplying coal to Kotzebue. 5. REFERENCES 1. Coal Resources of Alaska, U.S.Geological Survey Bulletin 1242-B, U.S. Government Printing Office, Washington, D.C. (1967). 2. Assessment of the Feasibility of Utilization of Coal Resources of Northwestern Alaska for Space Heating and Electricity, Phase II. Dames and Moore (1981). 3. Personal communication Crowley Maritime Company. 4. Personal communication Arctic Literage Company. 5. Personal communication Yutana Barge Company. 6. Personal communication General Motors Corporation---GMC Truck Division. 7. Personal communication with Link Belt Company. 8. Personal communication with Usibelli Coal Mines. J-35 Area/Field Nenana Chicago Creek Kobuk River Cape Beaufort Cape Beaufort ANALYSIS OF SELECTED ALASKAN COALS TABLE J.1 Moisture Volatile Fixed Ash Sulfur Heating Constant Matter Carbon Content Copntent Value Rank (Percent ) (Percent ) (Percent (Percent ) (Percent ) (Percent ) Subbituminous 17.8-27.1 33.3-42.0 27 .1-35..3 3 9-132 0.1-0.3 7570-9430 Lignite 33.8 39.9 19.2 Vek 2 tec 6825 Bituminous 10.5 29.0 52.9 7.6 0.4 10,534 Bituminous 3.0-5.9 28.8-40.1 47.8-58.0 elel.6 === | s$sse== Bituminous 0.8-9.9 31.4-35 .6 52.6-56.1 2.5-15.0 0.2-0.3 11,910-14,000 J-36 Le-f CASE 1 - Includes Road Building As a Direct Coal Cost With Existing Facil- ities at Kotzebue CASE 2 - Does Not Include Road Building As a Direct Coal Cost with Existing Facilities at Kotzebue CASE 3 - Includes Road Building As a Direct Coal Cost with Docking Facil- ities at Kotzebue CASE 4 - Does Not Include Road Building As a Direct Coal Cost With Docking Facilities at Kotzebue CASE 5 - Includes Road Building As a Direct Coal NENANA FIELD‘1) (80,000 Tons/yr) N/A $130.90/Ton $ 8.18/Mil.Btu N/A $119.56/Ton TABLE J.2 COST OF COAL DELIVERED TO KOTZEBUE (Based On a Constant 80,000 Ton/Year) CHICAGO KOBUK CREEK RIVER (80,000 Tons/yr) (80,000 Tons/yr) $103.05/Ton $ 7.93/Mil.Btu § 4.77/Mil.Btu $ 83.55/Ton $ 92.26/Ton $ 6.43/Mil.Btu $ 4.61/Mil.Btu $103.05/Ton $ 7.93/Mil.Btu $4.77/Mil.Btu S$ 83.55/Ton $ 92.26/Ton $ 7.47/Mil.Btu N/A Cost With Docking Facilities at Kotzebue CASE 6 - Does Not Include Road Building As a Direct Coal Cost With a Marine Terminal at Cape Blossom $121.31/Ton $ 6.43/Mil.Btu $ 4.61/Mil.Btu $102.70/Ton N/A $ 7.90/Mil.Btu $ 83.20/Ton N/A $ 7.58/Mil.Btu (1) The cost of the coal via the Yukon River route was higher than that via rail transport; therefore, the data on the rail route is presented. $ 6.40/Mil.Btu CAPE BEAUFORT (80,000 Tons/yr) $123.41/Ton $ 4.41/Mil.Btu $115.54/Ton § 4.13/Mil.Btu $113.87/Ton $ 4.07/Mil.Btu $106.00/Ton $ 3.79/Mil.Btu $115.62/Ton $ 4.13/Mil/Btu $107.25/Ton $ 3.83/Mil.Btu CASE 1 - Includes Road Building As a Direct Coal Cost With Existing Facil- ities at Kotzebue CASE 2 - Does Not Include Road Building. As a Direct Coal Cost with Existing Facilities at Kotzebue CASE 3 - Includes Road Building As a Direct Coal Cost with Docking Facil- ities at Kotzebue CASE 4 - Does Not Include Road Building As a Direct Coal Cost With Docking Facilities at Kotzebue CASE 5 - Includes Road Building As a Direct Coal Cost With Docking Facilities at Kotzebue CASE 6 - Does Not Include Road Building As a Direct Coal Cost With a Marine Terminal at Cape Blossom NENANA FIELD(1) (61,000 Tons/yr) N/A $141.44/Ton $ 8.84/Mil.Btu N/A $127.23/Ton $ 13.99/Mil.Btu N/A $129.05/Ton $ 8.07/Mil.Btu (1) The cost of the coal via the Yukon River route was higher than that via rail transport; therefore, the data on the rail transport rate is presented. TABLE J.3 COST OF COAL DELIVERED TO KOTZEBUE CHICAGO CREEK (75,000 Tons/yr) $106.15/Ton $ 8.17/Mil.Btu $ 85.35/Ton $ 6.57/Mil.Btu $106.15/Ton $. 8.17/Mil.Btu $ 85.35/Ton $ 6.57/Mil.Btu $105 .82/Ton $ 8.14/Mil.Btu $ 85.02/Ton $ 6.54/Mil.Btu (Based On a Constant 975 Billion Btu/Yr) KOBUK RIVER (49,000 Tons/yr) $115.58/Ton $ 5.78/Mil.Btu $110.38/Ton $ 5.52/Mil.Btu $115.58/Ton $5.78/Mil.Btu $110.38/Ton $ 5.52/Mil.Btu N/A N/A CAPE BEAUFORT (35,000 Tons/yr) $185.30/Ton § 6.62/Mil.Btu $167.30/Ton $ 5.98/Mil.Btu $166.58/Ton $ 5.95/Mil.Btu $148.58/Ton $ 5.31/Mil.Btu $168.73/Ton $ 6.03/Mil/Btu $150.73/Ton $ 5.38/Mil.Btu J-38