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Feasibility Study and Preliminary Engineering For Chena Station 1983
BD AB Oy * ¥.COP’ ALASKA POWER AUTHORITY FAIRBANKS MUNICIPAL UTILITY SYSTEM FEASIBILITY STUDY AND PRELIMINARY ENGINEERING FOR CHENA STATION Phase One Report-February 1983 PROPERTY OF: Alaska Power Authority oe 334 W. 5th Ave. “Anchorage, Alaska 99501 0130c.022483 ONDOFPWPRYH oF 10. i We Appendix A Appendix C Appendix D Appendix E -000 .000 -000 -000 -000 -000 -000 -000 000 000 000 000 TABLE OF CONTENTS Introduction and Summary Existing Conditions Conceptual Design Scenario No. 1 Scenario No. 2 Scenario No. 3 Scenario No. 4 Environmental and Licensing Considerations Cost and Economic Analysis Financial Analysis Methodology Summary and Results of Analysis Special Studies -Plant Inspection Report -Outline Performance Specifications -Criteria and Assumptions -References LIST OF DRAWINGS Drawing Number Rev. Title 100-001 0 Conceptual Equipment Layout Scenario 2 100-002 0 Conceptual Equipment Layout Scenario 3 100-003 0 Conceptual Equipment Layout Scenario 4 100-004 0 Conceptual General Arrangement Scenario 2 100-005 0 Conceptual General Arrangement Scenario 2 100-006 0 Conceptual General Arrangement Scenario 3 100-007 0 Conceptual General Arrangement Scenario 3 100-008 0 Conceptual General Arrangement Scenario 3 610-001 0 Process Flow Diagram Scenario 2 610-002 0 Process Flow Diagram Scenario 3 610-003 0 Process Flow Diagram Scenario 4 711-001 0 Typical Switchgear Arrangement 711-002 0 4.16kV Substation-Existing Arrangement 711-003 0 4.16kV Substation-Alternate No. 1 711-004 0 4.16kV Substation-Alternate No. 2 711-005 0 4.16kV Substation-Alternate No. 3 711-006 0 4.16kV Substation-Alternate No. 4 711-007 0 69/12.5/4.16kV Substation 711-008 0 Single Line Diagram-Scenario 1 711-009 0 Single Line Diagram-Scenario 2 711-010 0 Single Line Diagram-Scenario 3 711-011 0 69/12.5kV Substation-Scenarios 1, 2 & 3 0130c .022483 0130c .022483 Table @ ©o CO co © COC co oe} coco oo © Number a ue Ww rm om “0 ee ele els 14 Lo 10 LIST OF TABLES Title Summary of Existing Power Plant Equipment Licensing and Regulatory Framework Summary Comparison of Existing and Predicted Emission Rates, Units 1, 2, and 3 Summary List of Licensing Requirements Generic Licensing Schedule Selected Physical and Chemical Characteristics of the Chena River Characterization of Land Use in Fairbanks Fairbanks Boom-Bust Cycles Preliminary List of Environmental Review Criteria U.S. EPA and Alaska Air Quality Standards Physical Stack Parameters and Emission Rates Average 24-Hour Meteorological Scenario Maximum Pollutant Concentrations Predicted for the Average 24-Hour Meteorological Condition "Worst Case" 24-Hour Meteorological Scenario Maximum Pollutant Concentrations for the "Worst Case" 24-Hour Meteorological Conditions Wastewater Effluent Limitations Applicable to the Chena Feasibility Study Summary of Air Quality Compliance Strategies for Individual Units Summary Capital Cost Estimate - Scenario 1 Summary Capital Cost Estimate - Scenario 2 Summary Capital Cost Estimate - Scenario 3 Scenario 1 Income and Cash Flow Statement Scenario 2 Income and Cash Flow Statement 0130c .022483 LIST OF TABLES, Continued Table Number 9.6 9.7 9.8 9.9 TEI Title Scenario 3 Income and Cash Flow Statement Scenario 1 Income and Cash Flow Statement - No Sales of Excess Capacity Scenario 2 Income and Cash Flow Statement - No Sales of Excess Capacity Scenario 3 Income and Cash Flow Statement - No Sales of Excess Capacity Heat Rejection and Utilization Cost Summary LIST OF FIGURES Figure Number Title Process Flow Diagram, Scenario 1 Bunker Modifications Site Plan for Increased Capacity Bunker Elevation RDF Process Flow Diagram, Scenario 4 Dust Loading with Chain Grate Stoker NOR RL PRRwWwrH 0130c.022483 Rev: 0 Rev. Date: 2/18/83 1.000 INTRODUCTION & SUMMARY This feasibility study has been conducted to determine the correct growth increment that must be pursued by the Fairbanks Municipal Utilities System to provide for the needs of the community of Fairbanks, Alaska. In addition the modernization of parts of the utility were investigated with the aim of providing continued dependability and efficiency. This study began in September, 1982 with an on-site investigation of the existing Chena facilities and an indepth review of the environmental considerations for the station growth. Four approaches to providing future electric power and municipal heating were followed. Scenario 1 Refurbish boilers 1, 2 and 3 to provide for 20 years of additional life. Perform all useful maintenance on the associated systems of these boilers to improve their reliability to near-new condition. Cost for this Scenario has been estimated at $8,712,000. 0123c.021483 oe) Rev: 0 Rev. Date: 2/18/83 Scenario 2 Replace boilers 1, 2 and 3 with one 150,000 1b/hr 850 psig/950°F boiler and topping turbine-generator and use the existing electrical generating facilities associated with the 1, 2 and 3 boilers. Upgrade existing systems to near-new conditions. Cost for this system has been estimated at $24,530.00. Scenario 3 Retire boilers 1, 2 and 3 and associated electrical generation facilities and replace them with a new 30 MW coal-fired power plant at the present site adjacent to the existing power plant. Cost for this new system has been estimated at $41,800.000. Scenario 4 Replace boiler 1, 2 & 3 with either a 150,000 lb/hr coal fired and refuse burning boiler or a new 150,000 1b/hr boiler and a 40,000 lb/hr refuse burning boiler. Operational experience at plants which burn municipal waste for electric utility steam is poor and utility type reliability can not be assured. Therefore, this design has not been pursued nor has a cost estimate been developed. Using the available data of previous studies and the forecasting of the Alaska Power Authority, the economics of the Scenarios 1, 2 and 3 were predicted. In this development of the economics the impact of 0123c.021483 lac Rev: 0 Rev. Date: 2/18/83 the Susitna Hydroelectric Project and its 1020 MW contribution to the Railbelt Utilities in 1994 was considered. The analysis showed that there would be no dollar impact on the coal Scenarios as the new power would only displace high cost oil and gas generation. If the price of oi] and gas in relation to coal stay somewhat constant, there will be an economic need for about an additional 300 MW coal-fired power plant capacity in the next ten years , according to the Alaska Systems Coordinating Council Forecast. The economic. analysis over the next 30 years yielded the following results: Benefit Net Estimated Cost Present Cost Ratio Value Scenario 1 $ 8,712,000 1.3 $ 77,410,000 Scenario 2 $24,530,000 1nd $ 46,990,000 Scenario 3 $41,800,000 1.7 $161,118,000 Solutions to present and potential future environmental problems have been reviewed and successful mitigating procedures and plans have been developed. For example, it has been learned that pulverized _ coal-firing the boiler in Scenario 3 will make it possible to bring Chena 5 into compliance with air quality regulations. This is true because then a properly screened and sized feed can be burned in 0123c.021483 1-3 Rev: 0 Rev. Date: 2/18/83 Chena 5 while all the extra fines can be burned in the new pulverized coal system. Required environmental licensing of the three Scenarios has been reviewed and procedures and strategies have been developed for each case. This Feasibility Study has resulted in the recommendation of Scenario 3 as the wisest course of action for the growth of the Chena Station. The new Railbelt Electric Tie Line makes this Scenario 3 with its early years of saleable extra capacity the optimum choice of this study. The relatively inexpensive coal produced kilowatts will be able to compete successfully throughout the predominantly oil and gas powered Railbelt Electric System producing early dividends to the City of Fairbanks. The level of cooperation of all parties to this study must be commended. Communications have been very effective and data retrieval very rapid. Continuance of these helpful attitudes will assure a first rate Chena Station addition with effective modernization where it is needed. 0123c.021483 oC 2.000 2.100 Rev: 0 Rev. Date: 02/18/83 EXISTING CONDITIONS Plant Description The Chena Station facility is located between the Chena River to the north and First Avenue to the south in Fairbanks, Alaska. The City of Fairbanks Municipal Utilities System (FMUS) owns, operates, and maintains the plant and an associated district steam heating system. The facility consists of three chain grate stoker-fed lignite coal-fired boilers, three associated single controlled extraction, condensing turbine generators, designated Units 1, 2 and 3, and auxiliary equipment. These units are housed together in the original building and are about thirty years old. In addition, a spreader stoker-fed lignite coal-fired boiler, an associated automatic extraction, condensing turbine generator, designated Unit 5, and auxiliary equipment are adjacent to the Units 1, 2 and 3 building and housed in a newer building about ten years old. Along with these coal-fired units, there are Unit 4, an oil-fired gas turbine generator with waste heat boiler located in the original building with Units 1, 2 and 3; Unit 6, an oil-fired gas turbing generator located to the west of Units 1, 2, 3, 4 and 5, and three diesel | generators located south of Unit 6. 0120c .021883 2-1 Rev: 0 Rev. Date: _ 02/18/83 The steam and electricity generating units share the site with the city water treatment plant, a vehicle garage and office building, and various storage sheds and warehouses. The power plant substation is located on the site, also. The City of Fairbanks currently operates a district heating system wherein steam is extracted from number 1, 2 and 3 turbines and distributed to about 140 customers. There is also a demonstration hot water district heating system under construction to supply heat to the Lathrop-Ryan School which is about 4,000 feet south of the Chena Station. A summary of the power plant equipment follows: 0120c.021883 2-2 Rev: 0 Rev. Date: 2/18 Table 2.1 SUMMARY _OF EXISTING POWER PLANT EQUIPMENT NAME OF DATE OF STEAM TYPE CAPACITY DEMONSTRATED OUTPUT UNIT CONSTR- PRESS TEMP BOILER GENERATOR BOILER GENERATOR CAPACITY VOLTAGE (PSIG) (OF) (LB/HR) (KILOWATTS) (KILOWATTS) (KV) Chena 1 1954 610 720 Stoker (B&W) Steam Turbine (Elliott) 50,000 5,000 5,500 4.16 Chena 2 1952 610 720 Stoker (B&W) Steam Turbine (Westinghouse) 50,000 2,000 2,000 4.16 Chena 3 1952 610 720 Stoker (B&W) Steam Turbine (Westinghouse) 50,000 1,500 1,800 4.16 Chena 4 1963 610 720 Waste Heat Gas Turbine (Gen. Electric) 40,000 5,350 7,500 12.47 Chena 5 1970 850 900 tRitey'S Koei Steam Turbine (Gen. Electric) 200,000 20,000 22,000 12.47 Chena 6 1976 oor oor --- Gas Turbine (John Brown) --- 23,100 29,500 12.47 Diesel 1 1967 oe oe <= Diesel —— 2,750 3,000 12.47 Diesel 2 1968 ae == —a Diesel --- 2,750 3,000 12.47 Diesel 3 1969 <= --- --- Diesel --- 2,750 3,000 12.47 0120c.021883 2-3 2.200 Rev: 0 Rev. Date: 02/18/83 Summary of Plant Inspection This summary presents the results of the inspection of Chena Units 1, 2 and 3 located in Fairbanks, Alaska and operated by the Fairbanks Municipal Utilities System. The inspection was performed to determine the condition of existing plant equipment for the Chena Feasibility Study scenario #1, a study of the conceptual design and economic feasibility of plant renovation. The Babcock and Wilcox Co. performed the detailed boiler inspection, which included the boiler, F.D. and I.D. fans, multiclone fly ash collectors, and air preheaters. Morrison-Knudsen personnel conducted the balance of the inspection. The inspection included the building housing Units 1, 2 and 3, mechanical, electrical, ash collection equipment, and coal handling equipment within the building. Coal handling equipment outside the plant building wall is not a part of this study and was not inspected. The inspection was performed on September 29 and 30, and October 1, 1982 and included extensive interviews with the plant staff. In general, buildings and equipment are in good condition considering the age of the plant. It is well maintained and the senior staff has been at the plant since the early days of operation. 0120c .021483 2-4 Rev: 0 Rev. Date: 02/18/83 The boilers were designed to operate on coal having an as received heating value of 8900 Btu/lb. Approximately two years after the units were placed in service, the heating value began to decline and it presently averages 7850 Btu/lb. Plant operators expect the value may deteriorate to 7500 Btu/lb in the future. The output of each boiler is presently limited to 40,000 lb/hr due to environmental restrictions set by agreement with the Alaska Department of Environmental Conservation. Coincidentally, the decline of coal quality and the age and condition of the boilers also limits output to approximately 40,000 lb/hr. Coal is supplied by the Usibelli Coal Company from mines located near Healey, Alaska. Coal is delivered by train and unloaded in a track hopper located north of the Chena River. It is conveyed to the plant over a bridge crossing the river to bucket elevators which then feed the trippers for Units 1, 2 and 3 and for Unit 5. This section is a brief summary of the inspection; details are presented in the Attachment A. ° Substructures and foundations are in good condition. . 0120c.021483 Zao 0120c .021483 Rev: 0 Rev. Date: 02/18/83 Structural steel frame and bridge crane are in good condition. Buildings are in fair condition. There is no heating or ventilating system and F.D. fan air makeup from inside the building causes high negative pressure in the building. One circulating water well shows reduced capacity. Circulating water pumps and piping have been rebuilt and reconditioned within the last three years and are in good condition. The coal handling tripper is in only serviceable condition. Coal bunkers are in good condition but their design causes operating problems. The turbine-generator units are in good to excellent condition considering their age. The three boilers are each limited to 40,000 lb/hr due to air quality limitations and lower coal quality. They have been well maintained and are in fair condition considering their age. The controls are obsolete. Mechanical dust collectors are in good condition. 0120c.021483 Rev: 0 Rev. Date: 02/18/83 The pump ends of the boiler feed pumps are in good condition; however, turbine-end controls are inoperable. Two BFP turbines are being replaced with electric motors. No. 2 and 3 condensate pumps are experiencing cavitation and may need replacement soon. Main condensers No. 2 and 3 were retubed within the last year and are in excellent condition: No. 1 has never been retubed. The air ejectors are in good condition. The feedwater heaters and the deaerator are in good condition. Condensate make-up surface condensers are in good condition. Two evaporators are in good condition, two are out of commission. The chemical feed equipment is in good condition. Service air compressor is in fair condition. The ash handling system works well but does experience fires due to carbon carryover during hard boiler firing. There is a problem with excessive dust at the dustless unloader. Zel, 0120c.021483 Rev: 0 Rev. Date: 02/18/83 Both high pressure and low pressure steam piping have flanged connections, with resultant high maintenance. Steam piping insulation is in poor condition with the exception of the extraction steam piping which has an aluminum jacket and is in good condition. Feedwater piping has flanged connections; insulation and lagging are in good condition. Bearing cooling water piping is in good condition. Boiler and boiler feed pump controls are obsolete and inadequate. The voltage and governor controls for Units 1, 2 and 3 in the Unit 5 control room are in excellent condition. The 4160-480 volt transformers are operating satisfactorily. The 4.16 kV switchgear is operating satisfactorily. A single fault could result in the loss of all circuits. The motor control centers are basically in good condition. Spare parts are not available. The 480 volt load centers are suitable for integration into renovation plans. 2-8 2.300 Rev: 0 Rev. Date: 02/18/83 0 Renovation plans should include new wiring. 0 Lighting is substandard in all areas and renovation should include a complete new lighting system. 0 Motors must be evaluated on a case basis. If a pump is replaced, the motor must also be replaced. ° The existing battery is suitable for continued usage. Basic Area Criteria The elevation of the facility is 443 feet above sea level. Average annual precipitation is seven inches. For construction purposes, the site is in a seismic zone three (3). The frost penetrates to an average depth of eight feet. Permafrost is discontinuous, existing on the north of some buildings and on the north slope of hills and embankments. The river water averages 33°F in winter and 59° in summer. The well water temperature averages 38°F in winter and 42°F in summer. The normal daily winter low temperature is -22°F. The normal daily summer high temperature is 73°F. The population of Fairbanks is approximately 26,000 within the city limits and is approximately 60,000 for the greater metropolitan area. 0120c.021483 ano Rev: 0 Rev. Date: 02/18/83 3.000 CONCEPTUAL DESIGN 3.100 Over view of Scenarios The scenarios considered in this study represent a range of logical approaches to upgrading the Chena site. Upgrading options run from simp] e refurbishment of the existing boiler with no increase in plant capacity, to a new, larger capacity boiler and turbine-generator. The scenarios are: ° 0108c .020383 Scenario 1: Rehabilitation of Existing Boilers Units 1, 2 and 3 boilers and their auxiliaries will be rehabilitated with no increase in design capacity (150,000 1b/hr) or more extraction to the district steam heating system (DSHS). See Section 4.000. Scenario 2: New Boiler Facility A new 150,000 1b/hr boiler and auxiliaries will be built and Units 1, 2 and 3 boilers will be retired from service. The existing turbine-generators will not be replaced and will be operated with steam from the new boiler via a topping turbine. As in Scenario 1, extraction steam to the district heating system remains constant at the 1982 level. 0108c .020383 Rev: 0 Rev. Date: 02/18/83 Plant operation will be improved, but output will be essentially the same. See Section 5.000. Scenario 3: New Boiler and Turbine-Generator A new 286,000 lb/hr boiler and 30 MW steam turbine-generator will be constructed, and Units 1, 2 and 3 will be retired. Plant electrical output and steam to DSHS will be increased. Refer to Section 6.000. Scenario 4: Coal and MSW Burning Facility The replacement of Units 1, 2 and 3 boilers with either 1) a 150,000 1b/hr boiler burning both coal and refuse-derived fuel or 2) a 150,000 1b/hr coal-fired boiler and a separate 40,000 lb/hr municipal-solid-waste (MSW) boiler was studied, based on plant electrical output and steam to DSHS, remaining constant. See Section 7.000. Refuse-derived fuel burned in a coal-fired boiler is inadvisable due to the lack of positive industry-wide experience. The operating and maintenance costs for the process equipment required to convert the MSW to RDF are extremely high as is down-time. The problems related to co-firing RDF with coal, such as boiler tube deterioration and lowered efficiency, are legion and intractable. Rev: 0 Rev. Date: 02/18/83 Mass burning of MSW at the Chena Station is inadvisable due to the requirement of a full-sized (150,000 1b/hr) boiler firing coal in addition to the MSW fired boiler, in order to attain acceptable reliability. In addition to the resulting high capital cost, the site plan of equipment arrangement indicates an unmanageable traffic pattern, see Drawing 100-003. Due to ash system pluggage and high wear on traveling grates and drag conveyors, maintenance costs are high. For these reasons, an economic and financial analysis were not performed in Scenario Four. 3.200 Common Assumptions Assumptions which effect all Scenarios are summarized as follows. In arriving at common assumptions, effort was made to make assumptions which lead to consistency. See Appendix D for detailed criteria and assumptions. See Section 9.100 for cost and economic assumptions. 1. Coal composition and ash composition are based on the Poker Flats Average Coal Analysis, November 1981. an The coal quality and composition will remain constant over the life of the plant. 0108c . 020383 S=0= 0108c .020383 Rev: 0 Rev. Date: — 02/18/83 The coal unloading and handling system will be capable of delivering up to one hundred-fifty (150) tons-per-hour of coal to the plant by 1985. There are no significant underground ducts, pipes, or other yard fixtures in the area directly to the west of Unit 5. The Anchorage-Fairbanks Electrical Inter-tie is in operation by January, 1985. The primary regulatory agencies for licensing and permitting are: Alaska Department of Natural Resources, Alaska Department of Environmental Quality, The United States Environmental Protection Agency, and the City of Fairbanks. No increase in heat to the Chena River is allowed over that currently being transferred. 3-4- 4.000 4.100 4.110 Rev: 0 Rev. Date: 02/18/83 SCENARIO NO. 1 REHABILITATION OF EXISTING BOILERS General Refurbish boilers 1, 2, and 3 to near new condition to extend their useable life by 20 years. Specific Assumptions This scenario evaluates the technical feasibility and economics of rehabilitating the existing Units 1, 2 and 3 boilers and their auxiliaries with no increase in design capacity or extension of the district steam heating system. Existing conditions are discussed in Section 2.000. The planned life of the facility will be 20 years. There are two approaches being considered for rehabilitation of Chena Units 1, 2, and 3. The first approach, discussed in Section 4.200, is rehabilitating the units to a point where they more efficiently and reliably supply a maximum of 40,000 lb/hr of steam each. The second, discussed in Section 4.300, is to modify the boilers and add flue gas cleanup equipment to achieve 50,000 lb/hr. The recommendations presented in this scenario are based largely ona plant inspection conducted by Morrison-Knudsen and Babcock & Wilcox 0055c.012483 Cel 4.120 4.130 4.140 Rev: 0 Rev. Date: 02/18/83 personnel on September 29, 30, and October 1, 1982. A report of this plant inspection is presented in Appendix A. Process Flow Description Refer to Figure 4.1. Heat Balance Boilers 1, 2 and 3 each are designed to consume about 4.7 tons of coal per hour when producing 50,000 lbs/hr of steam at 700°F and 600 psig. Turbine-Generator No. 1 is an Elliott condensing unit with one controlled extraction and is capable of 5,500 kw maximum output and 60,000 Ibs/hr of steam maximum extraction flow. Turbine-Generator No. 2 is a Westinghouse condensing unit with one controlled extraction and is capable of 2,500 kw maximum output and 40,000 lbs/hr of steam maximum extraction flow. Turbine-Generator No. 3 is a Westinghouse condensing unit with one controlled extraction and is capable of 1,875 kw maximum output and 35,000 Ibs/hr of steam maximum extraction flow. Efficiency The boilers are no longer capable of nominal output. They are equipped with mechanical dust collectors and, at high load, 0055c.012483 4-2 4.150 Rev: 0 Rev. Date: _ 02/18/83 particulate emissions are unacceptable. Agreement has been reached with Alaska Department of Environmental Conservation to limit the flowrate of each boiler to 40,000 lb/hr. The efficiency used for all aspects of this study for Units 1, 2 and 3 boilers is 66%. A decline in coal quality, from an original of 8,900 Btu/1lb to approximately 7,800 Btu/1b also limits boiler output. Electrical System Overview The existing electrical system serving Turbine-Generators 1, 2 and 3 and Boilers 1, 2 and 3 no longer meets many of the constraints normally considered as minimum for a central station generating facility. This is not the result of poor maintenance or design, but instead results from revised needs and normal degradation and obsolescence of equipment. For this reason, the implementation of Scenario 1 necessitates that certain equipment and systems be replaced in their entirety, irrespective of whether the boilers are rerated to 40,000 lb/hr of steam or upgraded to 50,000 lbs/hr of steam. The modifications recommended for the electrical system will result in an arrangement that is substantially identical to the existing system; however, it will meet present day standards and will have an increased service life. The major exception to this is with respect to the 4.16 kV switchgear installation, where it is recommended that the switchgear bus be sectionalized and a second step-up transformer 0055c.012483 Aaoe3 4.200 4.201 q-2011 4.201.2 4.202 4.202.1 Rev: 0 Rev. Date: 02/18/83 to 12.5 kV be added. Single Line Diagrams, Drawings 711-008 and 711-011, portray the revised system. Structures and Equipment Description Site Development Roads, Walks, and Fences No major changes are anticipated to the roads, walks, or fences for the facility. Removals and Demolition No major buildings or earth work removal or demolition is anticipated as part of the refurbishment of Units 1, 2, and 3. Substructures and Foundations Building Foundations The foundation and building walls appear to be in good condition with no significant cracking or breaking. Therefore, no rehabilitation is anticipated. 0055c.012483 4-4 Rev: 0 Rey. Date: 02/18/83 4.202.2 Yard Foundations 4.203 4.203.1 4.203.2 4.204 There are no significant yard foundations required. Structural Features Building Steel Although the structural frame appears to be in good condition and has not been allowed to rust or deteriorate, it is recommended that the structure be cleaned and painted for appearance purposes and for extended corrosion protection. Minor modifications, such as removal of siding and walkway grating, are anticipated for construction access and for installation of new equipment. Cranes and Hoists No changes to the 20-ton bridge crane or auxiliary hoists are expected. Buildings 0055c.012483 A==5 4.204.1 4.204.2 4.204.3 4.205 Rev: 0 Rev. Date: 02/18/83 Station Building The built up roof should be replaced. The single pane casement type windows will be replaced with thermopane type which will alleviate condensation and icing problems inside the building. Heating & Ventilating Building heating and ventilation will be improved indirectly by the F.D. fan intake improvements discussed in section 4.209.5, "F.D. Fans". The negative-pressure problem will be eliminated, and removing heated air from the boiler building upper levels will improve operator comfort in the summer months. Yard/Miscellaneous Buildings No new service, warehouse or shop buildings are contemplated. Circulating Water System The existing Unit 1, 2, and 3 circulating water storage tanks, pumps, piping, and other equipment have recently been refurbished and are in good condition. No new piping or equipment is contemplated. During the 20-year life of the refurbished Units 1, 2, and 3, it is expected that all of the circulating water pumps and equipment will be again refurbished. 0055c.012483 4-6 4.206 4.206.1 4.206.2 Rev: 0 Rev. Date: 02/18/83 Coal Handling Equipment Bunker Because of the problems associated with the existing catenary-shaped bunker bottom, it will be modified internally. One-quarter inch thick mild steel plates will be welded into the bunker bottom. One plate will be installed longitudinal to the bunker axis for the full length of the bunker on the west side of the bunker bottom (the drag conveyor and openings to it are offset to the east). Other plates will be welded transverse to the bunker axis to eliminate areas of no flow between openings. A polymer liner will be included to facilitate coal flow. See Figure 4.2. This modification will not change the working capacity, 200 tons, of the bunker. Trippers The existing 60 tons/hr traveling tripper belt conveyor will be rebuilt to a 150 tons/hr capacity to coordinate with the anticipated capacity of the new yard coal handling and deliver system. Rebuilding will include: 0 Replacing the belt and head pulleys with new, more durable ones. 0055c.012483 ald Rev: 0 Rev. Date: 02/18/83 0 Replacing the chain drive, motor, and speed reducer with a belt drive and larger motor and reducer. oO Replacing the 20° carrying idlers with 35° idlers. 0 Redesigning the discharge chute to withstand the higher impact and abrasion from the coal as it leaves the belt. oO Replacing the rubber seals around the discharge chute. 0 Replacing the bunker cover plates which run the length of the bunker between the bunker inlet openings. Two bin vents with about 150 square feet of area each will be added to control dust as air is displaced from the bunker during filling. Each vent will consist of a cloth filter element receiver, an exhauster fan with spark-proof wheel and explosion-proof motor, and housing. About two cfm of dry, filtered compressed air at 100 psi will be used intermittently to blow down the filter into the bunker. 4.206.3 Coal Feeding Equipment The operation and condition of the drag-chain conveyor, weigh feeders, and Stock nonsegregating splitters are covered in Section 6.0 of the Plant Inspection Report (Appendix A). 0055c.012483 Gs=28) Rev: 0 Rev. Date: _ 02/18/83 No changes to this equipment are required. However, overhaul of the drag-chain conveyor and of the mechanical parts of the Unit 3 weigh feeder are included in the cost estimate. 4.208 Steam Generator The Units 1, 2, and 3 steam generators are Babcock & Wilcox F-type boilers with a chain grate stoker. These were originally designed for a flow condition of 50,000 Ib/hr at 750°F and 675 psig. Feedwater inlet temperature to the economizer is approximately 335°F. The furnace is balanced draft. In order to provide for reliable operation of these boilers at 40,000 lb/hr for another 20 years, the following refurbishing is required. This is based on the Babcock and Wilcox Boiler Inspection Report Reference No. F-1747-F-2334 and B & W Proposal P25-734. 4.208.1 Furnace The brick work and refractory will be replaced throughout the boilers and furnace settings, including on the suspended arch. One IK retractable sootblower will be installed in the screen cavity of each boiler. 0055c.012483 ag) 4.208.2 4.208.3 4.208.4 4.208.5 Rev: 0 Rev. Date: 02/18/83 Superheater All broken superheater ties will be replaced. The existing G9B sootblowers will be replaced with IK retractable sootblowers. Stoker and Ash Handling The under-grate air compartments, stoker seals, and ash dumping valves will be replaced. Economizer for Unit 3 Due to damage to Unit 3 economizer caused by freezing of the feed water, the economizer pressure parts including headers, tubes, spacers, ties, and attachments will be replaced. F.D. Fans New F.D. fan inlet air vents will be installed in the building roof. These will include a gravity actuated damper which will open when the static head is lowered by the F.D. fan. The vents will be sized to minimize the difference between atmospheric pressure and building _ internal pressure. Inlet air will be drawn from the top of the boiler room in an uninsulated duct to the F.D. fan inlets. 0055c.012483 4 - 10 4.209 Rev: 0 Rev. Date: 02/18/83 Therefore, in the wintertime, the waste heat from the boilers will help preheat combustion air which will be a mixture of outside air and inside heated air rising from the boilers. This will also alleviate the negative pressure problem created in the winter by the current practice of drawing forced draft air from the boiler building without adequate venting. Removing this overheated air from the upper levels of the building will improve the comfort of the operators in the summer months. A new glycol air preheater will be installed directly downstream of the F.D. fan. Implementation of these improvements this will require approximately fifty feet of 3 ft. x 3 ft. square duct for each unit, along with a louvered vent opening in the roof. The existing F.D. fan inlet duct would be extended from its existing location directly up to the ceiling. See Section 4.215.1 for a discussion of fan requirements if the boiler capacity is increased. Turbine-Generators Other than the planned modernization and maintenance procedures described in the Plant Inspection Report (Appendix A) under turbine-generators, very little needs to be done to the turbine 0055c .012483 4-11 4.210 4.210.1 4.210.2 Rev: 0 Rev. Date: — 02/18/83 generators for an expected life of an additional 20 years. One additional refurbishment will probably be required in the 20-year life. The cost of this refurbishment is included in operating cost estimate. Air Correction Equipment Existing Dust Collector As pointed out in the Babcock & Wilcox inspection report, the dust collectors for Units 1, 2, and 3 are in good condition. No major work, other than continued maintenance, is required, assuming the coal quality does not deteriorate. Stack The existing stacks were replaced in 1972 with thicker, more corrosion resistant materials. They appear to be in good condition and no additional work is anticipated. 0055c.012483 anol 2 4.211 Aelia anellee. Rev: 0 Rev. Date: 02/18/83 Mechanical Equipment Major Pumps Plant operations personnel report that the Ingersoll-Rand boiler feed pumps are in good condition; although the pump drives are a problem. FMUS will replace two of the boiler feed pump turbine drives with motors. Plant personnel report that the pump thrust bearings are an occasional repair problem. These are inspected and replaced as needed. With maintenance and repair continued at the level and quality of the past, the boiler feed pumps are expected to last an additional 20 years. Miscellaneous Pumps Miscellaneous pumps, such as cooling water pumps, sump pumps, condensate pumps, raw water pumps, evaporator coil drain pumps, and distilled water pumps, are periodically inspected. When problems develop, the entire pump is replaced with a new or rebuilt one. This program will be continued into the future. For cost estimating purposes, it is assumed that all pumps will be replaced over the 20-year life of the plant. 0055c.012483 4 - 13 Rev: 0 Rev. Date: 02/18/83 4.211.3 Condensers and Auxiliaries Main condensers nos. 2 and 3 have been retubed within the last year and are in excellent condition. No. 1 condenser has several plugged tubes and should be retubed soon. Plant personnel report that the main condenser tubes must be cleaned every three or four weeks due to fouling inside the tubes. It is assumed that this fouling is due to dissolved solids in the cooling water. Since the cleaning of the condenser tubes is required periodically, it is recommended that an on-line mechanical cleaning system be added to the condenser cooling water upstream of the condenser. Such a system is made by Amertap of West Germany. The basic principle of the Amertap system is to circulate oversize rubber balls through the condenser tubes with the cooling water. These balls, after the original charge, are injected into the inlet pipe, collected at the discharge piping in a basket arrangement and then repumped continually to the inlet. These sponge balls are effective in removing soft chemical precipitates or bacterial slimes before they become adherent. The balls can also be furnished with an abrasive band, to be used only where older deposition needs to be removed by the scouring action of the abrasive. 0055c.012483 4 - 14 Rev: 0 Rev. Date: 02/18/83 The steam jet air ejectors are in excellent condition and the only maintenance that is performed is periodically cleaning the nozzles. No refurbishment is needed. Nos. 2 and 3 main condensate pumps should be replaced as the operators report significant cavitation and vibration occurring in these pumps. 4.211.4 Feedwater Heaters It is our judgement that the feedwater heaters and deaerator will continue to function properly for 20 more years. Cleaning and retubing will be required within that time and the cost for this is included. 4.211.5 Water Treatment Equipment One of the three wells supplying cooling water to the Units 1, 2, and 3 main condensers is losing performance. It is suspected that this is due to pluggage of intake screens in the bottom of the well. Acid cleaning or a new well may be needed. The two evaporators located in the east end of the Unit 1, 2, and 3 building are functioning well and appear to be in excellent condition. The two older evaporators located in the west end of the building are out of commission because water came directly to them 0055c.012483 4-15 4.211.6 amc Rev: 0 Rev. Date: _ 02/18/83 from the water treatment plant for a period of time without going through the Unit 5 zeolite softener. These two evaporators will need to be disassembled, cleaned, and repaired before they can be put back into service. Compressed Air Equipment Instrument air for Units 1, 2 and 3 is supplied by the Unit 5 instrument air equipment. The 100-cfm service air compressor will be overhauled during the 20-year life. Ash Handling System The existing pneumatic ash handling system is ten years old. Ash is pulled from the bottom, fly ash, dust collection, and carryover hoppers sequentially with the Unit 5 mechanical exhausters, and is collected in a common ash silo. Normal maintenance such as elbow wearback replacement and pipe rotation will continue. One problem experienced is overheating of the ash conveying lines due to burning carbon particles and coal clinkers carried over into the ash system when the boilers are fired hard or receive poor coal. Jt is expected that the repairs to the boilers and reduction of amount of coal fines being delivered to the boiler may alleviate this problem somewhat. 0055c.012483 4 - 16 4.211.8 4.211.9 Rev: 0 Rev. Date: 02/18/83 To reduce dust production when unloading the silo into trucks, the scraper bars and spray nozzles need to be replaced, and this is included in the cost estimate. The pressure of the spray water will be adjusted to conform to manufacturer's specifications. Segregation of fine ash from more coarse ash in the silo results in inadequate wetting during unloading. Modifications should be made to the silo interior to blend the various ash sizes. A vertical pipe with slots or holes over the length of the pipe will be installed to accomplish this blending. Tanks Raw water tanks, condensate storage tanks, flash tanks, distilled water tanks, chemical feed tanks, and lube oi] tanks all appear to be in good condition. Fire Protection System It is not expected that there will be any additions or changes required in the fire protection system for the refurbishment of Units 1, 2, and 3. 0055c.012483 Geely, Rev: 0 Rev. Date: 02/18/83 4.211.10 Miscellaneous Mechanical Equipment 4.212 Ameer The bearing cooling water is taken from the treated city water system. Bearing cooling water pumps are no longer used. Condensate make-up is accomplished by condensing low pressure evaporator steam in surface condensers. These have been retubed recently and are in good condition. No modification or addition is recommended at this time. No modification or addition to chemical feed equipment is recommended. Piping Systems Power Piping All high pressure and low pressure steam and feedwater piping will be reinsulated with calcium silicate or fiberglass insulation and new lagging added. The sootblower piping shall be insulated and lagged also. All flanged-type steam and feedwater valves will be replaced with new weld-end valves to reduce maintenance. 0055c.012483 Charzea fs} Rev: 0 Rev. Date: 02/18/83 4.212.2 Auxiliary Piping Auxiliary steam piping and auxiliary water piping supplying building heating steam, steam for glycol heat exchangers, miscellaneous drips and drains, potable water, station instrument air, heater vents, and cooling water all are in good condition. It is recommended that all hot auxiliary piping be insulated and lagged. 4.212.3 Yard Piping It is assumed that no changes to yard piping will be required. 4.213 Instrumentation and Controls The existing instrumentation and control systems for boilers 1, 2 and 3 are obsolete and inadequate. The boiler and turbine instrumentation and controls for Units 1, 2 and 3 will be modernized with a centralized pneumatic control system to be compatible with Chena 5. The control system will consist of a central control panel, monitoring and annunciation equipment, new process sensing elements and pneumatic control tubing. It is proposed that the boiler and turbine controls for Units 1, 2 and 3 be assembled in a single control panel. This control panel will be located to the southeast of Boiler No. 5, on the firing 0055c.012483 4-19 4.214 Rev: 0 Rev. Date: 02/18/83 aisle, so that all four units can be controlled from one location. Boiler controls such as drum level, furnace draft, and feedwater flow will be situated on the lower panel with compact indicators and strip chart recorders above. The plant annunciators can be located at the top of the panel. Operators will be able to monitor Units 1, 2 and 3 from the central control panel by means of compact indicators and strip chart recorders. Draft pressure indicators will be direct connected types while level and flow indicators will receive signals from pneumatic transmitters. Strip chart recorders will be used to provide hard copy records of specific plant process parameters. Recorders designed for direct thermocouple input will be employed to monitor applicable process and equipment temperatures. Multiple window annunciators will provide audible and visual warnings of plant upsets and excursions such as Hi/Low furnace draft, Hi/Low drum level, etc. To insure efficient boiler operation, operators will be able to monitor the boilers and correct any process excursion from the central control panel. Electrical Systems and Equipment 0055c .012483 4 - 20 Rev: 0 Rev. Date: 02/18/83 4.214.1 Auxiliary and Miscellaneous Transformers The existing 4160 - 480 volt load center transformers 1A, 1B and 1C are capable of continuing to serve the loads associated with boilers 1, 2 and 3 and turbine-generators 1, 2 and 3 under this scenario as long as the existing fans and flue gas cleaning devices are not replaced. This is the situation if the boiler output is maintained at 40,000 1b/hour of steam each, through rehabilitation. These transformers are therefore being retained. Due to the age of the transformers, however, and to the fact that it is not possible to perform any tests that will accurately indicate the remaining life of the units, it should be recognized that is it possible that one or more of them may have to be replaced in the next 20 years. This could occur even if they were replaced now. Existing 480-120/240 volt transformers will generally be replaced. The cost estimate includes all such transformers, however, a final detailed design could conceivably retain some existing units where convenient. The existing 12.5-4.16 kV transformers interconnecting the 4.16 kV switchgear with the outdoor 69-12.5 kV substation will be retained and a second 7500 kVa, essentially duplicate unit, will be added to obtain increased reliability. This transformer, to be located in the outdoor substation area, will require a new 14.4 kV circuit breaker, 0055c.012483 e221 4.214.2 areas Rev: 0 Rev. Date: 02/18/83 with isolating switches, in its primary circuit, and will be interconnected with the switchgear by underground cable. Switchgear and Accessories The 4160 volt switchgear will be modified in accordance with the "Recommendations for Rehabilitation and Renovation of the Old Plant Substation" (see Section 12.100). These modifications will provide increased electrical system security by sectionalizing the 4160 volt bus into two portions and adding the second tie to the 69-12.5 kV outdoor substation previously mentioned. With the ultimate arrangement, the 4160 volt switchgear will no longer serve distribution feeders eminating from the plant to feed the downtown area. This will result in increased reliability also since exposure to faults will be reduced. Motor Control Centers and Load Centers Motor control centers Al, A2, Bl, B2, C1 and C2 will be replaced in their entirety with new motor control centers containing combination circuit breaker-starter elements. This replacement is required due to the total lack of spare parts for the existing units. The existing 480 volt load centers A, B and C are suitable for continued use. The bus structure in these load centers should be subjected to hypot testing to verify insulation integrity and any 0055c.012483 dan 22 4.214.4 4.214.5 Rev: 0 Rev. Date: 02/18/83 necessary repairs performed. Circuit breakers should be serviced and tested and the trip elements calibrated. The ultimate load center loads should be of the same general magnitude as the present loads since a number of present loads are increased and others are decreased. The revised coal handling system being contemplated will reduce loads since the new system will probably be fed from 12.5 kV feeders across the river. The Stock coal feeders will be removed; however, lighting loads will increase. If this scenario is adopted, a final load check should be made at time of detailed design. Wiring Systems All new wiring will be provided. Existing conduit systems will be utilized to the greatest extent possible, with cable tray employed to extend individual circuits from the vicinity of the existing motor control centers to the new motor control centers. Control and low energy circuits will be isolated from power circuits in the cable tray. Lighting A complete new lighting system will be installed. Lighting levels. will be in accordance with I.E.S. Standards. General area lighting will be of the high pressure sodium vapor type. Fluorescent lighting will be utilized in areas with low ceilings and in areas requiring supplementary lighting such as the firing aisle. Incandescent 0055c .012483 ai— 123 4.214.6 4.214.7 4.300 Rev: 0 Rev. Date: 02/18/83 lighting will be utilized only in small areas and in any unheated areas. New lighting panelboards will be provided to serve this lighting. Motors Motor replacement will be required only for those cases where the driven device is replaced. This is considered feasible since considerable maintenance and rebuilding of existing motors has taken place over the last few years. Batteries and Emergency Power Systems The existing storage battery with its associated charger will be retained. This battery adequately supplies all critical services at present and should continue to do so. Increased Capacity of Boilers Currently, Chena Units 1, 2, and 3 are each limited to about 40,000 lb/hr of steam output. This is due in part to the degraded fuel energy content and to the more stringent environmental air quality, standards of today. In order for these boilers to produce substantially more than the 40,000 lb/hr on a sustained basis, the following items will have to be studied in greater detail. 0055c .012483 4 - 24 Rev: 0 Rev. Date: 02/18/83 4.300.1 Forced Draft and Induced Draft Fans It is possible that the forced draft and induced draft fans which were designed and installed in the original boilers are inadequate to provide enough air for burning the degraded coal of today. If additional flue gas cleanup equipment is installed, more power may be needed to push the flue gas through this cleanup equipment. 4.300.2 Dust Collector The existing Western Precipitator cyclone type mechanical dust collector is incapable of adequate clean-up above 40,000 lb/hr of steam production. One electrostatic precipitator and stack are proposed to serve Units 1, 2 and 3. All three manufacturers contacted manufacture both baghouses and precipitators. After examination of the coal and ash analyses, they all indicate that a precipitator will function, and reduce the stack gas outlet dust loading to acceptable levels. A precipitator common to all three units was chosen because it will require lower operating costs and less space than either a baghouse or three individual precipitators. The precipitator will weigh about 210 tons. From the available R.W. Beck drawings, it is apparent that the Units 1, 2 and 3 existing roof steel and building cannot support this precipitator and stack without 0055c.012483 4 - 25 4.300.3 4.300.4 Rev: 0 Rev. Date: _ 02/18/83 extensive modifications. The recommended location for the precipitator is to the south of the building between the building and First Avenue. The precipitator will be elevated on four columns to allow the inlet ducting to enter horizontally from the roof of the building. There will be room under the precipitator for vehicles to pass between the columns. The stack is to be supported on three columns forming a triangle in plan around the southeast corner of the Units 1, 2 and 3 building. The top of the stack will be about 150 ft. above grade. See Figure 4.3. Grate The existing chain grate size and speed will have to be evaluated to determine if it is adequate to supply enough coal for producing more than 40,000 lb/hr of steam, without excessive carbon carryover in bottom ash. Furnace The existing design of the gas passages of the boiler will have to be evaluated for possible pluggage problems. Should there be more pluggage problems with the added flue gas dust loading, additional. sootblowers may have to be installed. 0055c.012483 4 - 26 STACK GAS 14,400 dscm | 600 PSIG O.lgr/dscf | 720°F fre 374 ppm SOz |50,000 Ib./hr, 375ppm NO, BOILER NO. | Ss FD. FAN 25 hp. ( COAL 4.7 tph 0.42 tph ASH BOILER NO. 2 “\ Gr (.5))Hga (\5")HgA RETURN FROM DSHS DEAERATOR F.D. FAN 25 hp. Cp COAL 4.7 tph 0.42 tph ASH BOILER NO. 3 w\ FD. FAN 25hp. Cp COAL 4.7 tph 0.42 tph ASH BOILER FEED PUMPS !70h.p. EACH FIGURE 4.1 PROCESS FLOW DIAGRAM SCENARIO 14 MORRISON 2-4 fr 50° MIN. 7- 4%" 4. NOTE: 48'-O0" BUNKER (EXISTING) Ln to TEFLON a MILD STEEL 4spcs.o_7'- 1/2" = 28-6" LOOKING EAST USE THIS FOR MATERIAL TAKE-OFF ONLY, NOT FOR FINAL DESIGN ! FIGURE 4.2 BUNKER MODIFICATIONS — 1 r-4%p" fest DAA 20-6" SECTION LOOKING NORTH APPROX 000 FT? \'ms. 1,000 FT® J" TEFLON @ wees POWER PLANT WAREHOUSE WATER TREATMENT PLANT CONVEYOR TRIPPER PROPOSED PRECIPITATOR STACK FIRST AVE. ’ = FIGURE 4.3 SITE PLAN FOR INCREASED CAPACITY MA worse 4.10 AV LOAO [CENTER C CONTINUED ON PRAWING 711-11 4.16 KV- qB0V XEMR 7500 AVA 12.5 - 4.1GKV KFEMA #2 BUS * 1 e250 AVA TURBINE GENERATOR ke T50O KVA 12.5 - 4.16 KV XKEFMAR #) & 4.16 AV Bus #2 ES ed tT ] a 2500 1875 AVA nVA TURBINE. GENERATOR TURBINE. GENERATOR CENTER A : Cc . CHENA- FEASIBILITY STUDY NOTE: ALL EQUIPMENT 15 EXISTING EXCEPT TRANSFORMER *2 SPARE SPARE 4. 1@ KV- 4.1@KV- 480V XFMA B LOAO | CENTER & SINGLE LINE DIAGRAM~ SCENAR) | DRAWING NO. 7\I- 008 5.000 5.100 5e110 Rev: 0 Rev. Date: 02/18/83 SCENARIO NO. 2 NEW BOILER FACILITY General Specific Assumptions In Scenario 2, Chena Units 1, 2 and 3 boilers will be retired from service. A new 150,000 lb/hr boiler and its associated auxiliaries will be built to supply steam to existing Units 1, 2 and 3 turbine-generators and the District Heating System. The new boiler facility, designated Chena 7-2, will be added to the Chena Unit 5 building as shown on Drawing 100-001. The old boilers will not be removed. Major new equipment which will be added as a part of the new facility are: boiler, stack, FD and ID fans, combustion air preheaters, topping turbine, electrostatic precipitator, deaerator, high pressure feedwater heater, evaporator, condensate storage tank, chemical feed system, station air compressor, two boiler feed pumps, fire protection system, two station auxiliary transformers, 4.16 kV switchgear modifications, and two motor control centers. 011783 .0025c Sra Rev: 0 Rev. Date: 02/18/83 Existing equipment which will not be replaced includes the Units 1, 2 and 3 turbine-generators, condensers, and condensate and circulating water systems. The new boiler facility equipment arrangement (see Drawings 100-004 and 100-005) will be as similar as possible to the Unit 5 arrangement: i.e., equipment in Unit 7-2 will be at the same elevation and general location as similar equipment in Unit 5. This will simplify plant operation. Steam and feedwater will be cross-connected to Unit 5 for flexibility of maintenance and operation. 5.120 Process Flow Description The process flow diagram, Drawing 610-001, shows the critical flow paths, temperatures, pressures, energy consumption and energy output. 5.150 Electrical System Overview The electrical requirements for boiler 7-2 will be supplied from the existing 4.16 kV switchgear, through a new 4160-480 volt, double-ended load center. The load center bus will be sectionalized, with one of the two boiler feed pumps connected to each of the ca bus sections. This will prevent the loss of both pumps due to a single electrical system failure. The complete electrical system 011783 .0025c Dec 5.201 Se2Oded Rev: 0 Rev. Date: 02/18/83 will be designed in accordance with accepted central station design techniques. Since existing turbine generators 1, 2 and 3 will remain in service under this scenario, electrical modifications will be required in the systems serving these machines also. This will include replacement of motor control centers, a complete new lighting system for the turbine generator area and new wiring for turbine generator auxiliaries and controls. It is recommended that the 4.16 kV switchgear be sectionalized and a second stepup transformer to 12.5 kV be added, all in accordance with Section 12.100 "Recommendations for the Rehabilitation and Renovation of the Old Plant Substation." Single line diagrams, Drawings 711-009 and 711-011, portray the complete system. As may be observed on these drawings, the topping turbine-generator is connected to the 4.16 kV switchgear also. Site Development Refer to Drawing 100-001. Roads, Walks and Fences Existing hut type storage buildings and shops will be relocated to make room for new construction. The entry-way structure on the west side of Unit 5 will be relocated. The unloading dock on the north 011783 .0025c BS) BecOilee Rev: 0 Rev. Date: 02/18/83 side of the Unit 1, 2, 3 turbine hall will be relocated. A new parking area will be provided west of the new unit. No new fences or security facilities are required. Removals and Demolition Although the three 50,000 1b/hour boilers will be retired when the Unit 7-2 boiler is placed in service, there will be no removal of the old equipment. It is the Owner's option to sell or otherwise dispose of these units. When Unit 5 was constructed, the addition of another boiler was contemplated. The basement foundation wall of Unit 5 has been constructed with knockout sections for access to the new unit. These will be removed. The west wall of the Unit 5 building will be removed to the extent that the Unit 7-2 boiler building matches the Unit 5 profile. The Unit 7-2 boiler area is essentially free of underground piping, thus no significant relocation is required. The 69 kV line running east-west along the north edge of the site will be relocated. Special excavation procedures will be followed to insure the integrity of the electrical duct bank running north-south along the west side of the new Unit 7-2 building and of the large water piping between the water treatment plant and the Units 1, 2 and 3 building. 011783 .0025c 5 - 4 Rev: 0 Rev. Date: 02/18/83 5.202 Substructures and Foundation 5.202.1 Building Foundations Unit 7-2 will be constructed on a reinforced concrete mat. The basement mat will be at the same grade as the present Unit 5 basement mat. The basement walls will be of the same type as used for Unit 5 and will extend above the flood plain to an elevation matching Unit 5. The precipitator will be supported from reinforced concrete foundations bearing below the frost line to the north of the Unit 7-2 building. 5.202.2 Yard Foundations There are no significant yard foundations required. 5.203 Structural Features 5.203.1 Structural Steel A braced structural steel frame will be used to support equipment and enclose Unit 7-2. This building will be about 60 feet wide, 115 feet long and 77 feet high. 5.203.2 Cranes and Hoists 011783 .0025c Sean: Rev: 0 Rev. Date: 02/18/83 Miscellaneous monorails and hoists will be provided to service equipment. The rails of the Units 1, 2 and 3 turbine-generator crane will be extended to enable it to service the topping turbine, which will be located just to the north of the Units 1, 2 and 3 turbine-generators at the same level. (See Drawing 100-004.) 5.204 Buildings 5.204.1 Station Building The Unit 7-2 boilerhouse will be enclosed with insulated sandwich panel siding. The ground floor will be a concrete slab constructed on the structural steel frame. Other floors will be grating and these will match the Unit 5 elevations to the extent practical. The control room and superintendents office will be expanded into a common facility serving Units No. 5 and 7-2. Space for a new maintenance workshop will be provided for in the new building. Windows in the new structure will be thermopane type. A complete new lighting system will be provided for Unit 7-2 and the turbine room and auxiliaries portions of Units 1, 2 and 3. The Unit 5 elevator will be used for access to the various above grade floors in Unit 7-2. 011783 .0025c SSO) 5.204.2 5.204.3 5.205 Rev: 0 Rev. Date: 02/18/83 HVAC Steam unit heaters will be provided to heat the Unit 7-2 building. Heating steam will be supplied from the auxiliary steam system, which is supplied from a pressure reducing station off the common Units 1, 2, 3 extraction header. The Unit 7-2 auxiliary steam system will be cross-connected with the Unit 5 auxiliary steam header. Building ventilation make-up air will be preheated by glycol coil heaters. Yard/Miscellaneous Buildings It is assumed that the existing warehouse facilities will be adequate for the Chena Power plant after Unit 7-2 is added and boilers 1, 2 and 3 are retired. No new service warehouse or shop buildings are contemplated. Circulating Water System The existing circulating water system, including circulating water. pumps and piping, will be utilized. 011783 .0025c SEoey, Be ZO5myL 5.20522 5.206 D206) 1 Rev: 0 Rev. Date: 02/18/83 Structures or Wells Two of the three wells presently serving Units 1, 2 and 3 are in good condition. A new well will be drilled to replace the third well which is presently losing capacity because of screen plugging. Piping and Equipment The existing Unit 1, 2 and 3 circulating water storage tanks, pumps, piping and equipment have recently been refurbished and are in good condition. No new piping or equipment is contemplated. During the thirty year life of Unit No. 7-2 it is contemplated that all of the circulating water pumps and equipment will be refurbished once and cost estimates will include this expense. Coal Handling Equipment Bunkers A 350 ton (24 hour) capacity bunker will be provided above the boiler firing isle and stoker feed equipment and in line with the Unit 5 . bunker. The bunker will have two conical hoppers and slide gate outlet valves. The hoppers will have a polymer liner to facilitate coal flow and minimize freezing of coal to inner hopper surfaces. The Unit 7-2 bunker will be about forty feet long. Tripper and 011783 .0025c 58 5220652 S2206R3 Rev: 0 Rev. Date: 02/18/83 discharge elevations, as well as overall height and width of the bunker, will match those of Unit 5. The west end of the Unit 5 bunker will be reworked to allow the passage of the tripper. The east end of Unit 7-2 bunker will have a similar passage. See Figure bile Trippers The Unit 5 100-ton/hr tripper will be extended about fifty-five feet to feed the Unit 7-2 bunker. This will require a new conveyor belt, idlers, and head pulley. The capacity of the tripper will be increased to 150 tons/hr by adding a new drive. Fugitive dust suppression equipment will consist of two bin vents with exhauster fans, filters, and housings. Coal Feeding Equipment Coal will be fed, by gravity, from the bunker hoppers through a gravimetric weigh belt feeder to nonsegregating splitters to the boiler stokers. The weigh belt feeder will be designed such that coal can be fed when it is out of commission. 011783 .0025c Sia) 5.208 5.208.1 5.209 5.209.1 Rev: 0 Rev. Date: 02/18/83 Steam Generator Boiler and Auxiliaries The new steam generator will be capable of producing 150,000 Ibs of steam per hour at 900 psig and 950°F. It will be a coal fired, pulverizer or spreader stoker feed, balanced draft, natural circulation unit with no steam reheat. FD, overfire air and ID fans and associated duct work, a steam-to-glycol heat exchanger, and a glycol coil combustion air preheater will be included. Combustion air will be heated in a tubular or Lungstrom air heater located in the combustion gas stream between the economizer and dust collector. The boiler will be designed for ease of conversion to oi] or natural gas at a later date. Turbine-Generator TG Units and Auxiliaries The Unit 1, 2, and 3 turbine-generators and their auxiliaries have all been refurbished or will be in the near future. These will be. used without further modification. The units operate with steam inlet conditions of 600 psig and 720°F. The new boiler will be 011783 .0025c SPL) Rev: 0O Rev. Date: 02/18/83 designed to operate at 900 psig and 950°F to provide standby for operating the Unit No. 5 TG Unit in the event the Unit 5 boiler is out of service. To reduce this pressure and temperature to a level compatible with the existing turbine inlet conditions, a topping turbine operating with 850 psig inlet pressure and 600 psig exhaust pressure will be provided. A spray attemperator to cool the steam to about 720°F before it reaches the inlets of the existing turbine will also be included. The topping turbine is a noncondensing unit with no extractions. It will produce about 1300 kw at full throttle flow of 150,000 1b/hr. 5.210 Air Correction Equipment 5.210.1 Precipitator/Baghouse Air correction equipment for particulate control will be required to reduce particulate emissions below 0.1 gr/dscf. Two methods of particulate removal were considered for the new boiler: baghouses and electrostatic precipitators. A precipitator is included in the conceptual design due to its more favorable physical size, lower operating costs and overall dependability. Equipment sizing and cost estimates were obtained from manufacturers for both types of air correction equipment. The total installed costs of baghouses and precipitators are almost equal. 011783 .0025c Sill Rev: 0 Rev. Date: 02/18/83 Baghouses, or fabric filters, will work well on a wide range of coal quality and type. Filter type collection equipment is sized based on flue gas volume. Collection efficiencies are high, usually better than 97%. However, operating costs for a baghouse will be higher than for a precipitator because of the higher pressure drop through the baghouse filter and correspondingly higher fan power requirements. A precipitator for this application will be substantially smaller than a baghouse. This is a significant factor in light of the limited space available at the Chena site. The effectiveness of a precipitator, however, is dependent on the ash characteristics, specifically resistivity. Although low sulfur content in the coal can put the resistivity into an unfavorable collection range, other ash constituents such as iron and soda and high fuel moisture content help condition the ash thereby making collection by a precipitator effective. Given the Poker Flats ash analysis, precipitator manufacturers indicate that a precipitator would be the correct gas cleaning method for the Chena Plant. In the detailed design phase, an ash analysis may be required by the equipment manufacturers to confirm precipitator performance. Mechanical dust collectors were considered, but the maximum suspended solids removal efficiency is not sufficient to consistently satisfy the state emission limit of 0.1 grain/dry standard cubic foot. 011783 .0025c Seem e 5.210.2 Breil Breda) Beale Rev: 0 Rev. Date: 02/18/83 Stack A steel stack will be provided to handle the exhaust gases from the precipitator. Mechanical Equipment Major Pumps Two new 100-percent motor driven boiler feed pumps will be provided to supply feed water to the boiler. The ASME Power Boiler Code, Section 1, Part PG61.1, requires a back-up turbine driven boiler feed pump. The use of only motor driven pumps in this design is based on the Owner's current practice on Unit 5. Essential power during total power outage will be provided by a backup diesel-electric generator. This exception to the ASME Code should be further investigated in the detailed design stage. Miscellaneous Pumps The following miscellaneous pumps will be required: sump pumps, - glycol pumps, glycol heater condensate pumps, and fire pumps. 011783 .0025c Sams) Seelles Sclilin4: Biedo Rev: 0 Rev. Date: 02/18/83 Condensers and Auxiliaries The Unit 2 and 3 condensers have been reconditioned and retubed. The Unit 1 condenser will be reconditioned and retubed. The existing steam jet air ejectors are in good condition and will be used in Chena 7-2. The existing condensate pumps will be utilized. Feedwater Heaters The feed water will be heated to about 227°F in a new deaerator which will use 5-psig extraction steam. The feedwater will then be heated to about 301°F in a new shell-and-tube feedwater heater using extraction steam at 50 psig and 350°F. Valves and piping will be provided to bypass the heater. Water Treatment Equipment The existing makeup water treatment system for Units, 1, 2, 3 and 5 utilizes potable water, which has been chlorinated and softened, from the city water treatment plant. The potable water is fed to an existing zeolite softener, located in Unit 5, for the removal of calcium, magnesium, and iron ions which would create scale in the evaporators. The stream is split to the existing Unit 5 evaporator and to new evaporators to be located in the Unit 7-2 building. 011783 .0025c 5 - 14 521156 Sede Rev: 0 Rev. Date: 02/18/83 Evaporator output then goes to deaerators serving Units 5 and 1, 2 and 3. The new evaporators will provide make-up to the new 150,000 lb/hr boiler. New Unit 7-2 boilerwater chemical feed equipment will feed chelate for boiler water conditioning and hydrazine for oxygen scavenging and pH control. The new boiler water chelate feed equipment will consist of a solution tank with mixer and two 100 percent capacity pumps. The hydrazine feed equipment will consist of a solution tank with mixer and two 100-percent capacity pumps. A new Unit 7-2 sample rack will be provided to monitor water quality. Compressed Air Equipment A new station air compressor and receiver will be provided for Unit 7-2. Air will be taken off the new station air header, dried, and filtered for use as instrument air. Ash Handling System Furnace bottom ash, after passing through clinker grinders, will be pulled sequentially with fly ash from the economizer and precipitator hoppers into new vacuum-pneumatic ash piping. The Unit 5 Nash vacuum pumps will be utilized. The new ash piping supplied with Unit 7-2 011783 .0025c See) 5.211.8 Sele Rev: 0 Rev. Date: 02/18/83 will transport the ash to the existing ash silo. Along with the new ash piping, valves, actuators, replaceable wear-back elbows, wyes, and other fittings will be provided. The existing ash silo unloader will be reconditioned and made dependable by incorporating year around operable unloading system. Tanks New condensate storage tanks of 25,000 gallon capacity each will be provided. A boiler blow-down tank will be provided. Fire Protection System The coal conveyors will be protected with a dry pipe water deluge system to be actuated by automatic thermal detectors. The signal from the detectors will stop the conveyor, as well as actuate the pre-action valve. The coal bunker will be protected with a CO, flooding system. Predischarge and discharge alarms will be provided to warn personnel of the possible buildup to CO, in spaces adjacent to equipment being flooded. 011783 .0025c 5 - 16 Rev: 0 Rev. Date: 02/18/83 Buildings will be protected by a zone type sprinkler system. In addition, hose stations, portable fire extinguishers and breathing apparatus will be provided throughout the plant as required by National Fire Code and OSHA. 5.211.10 Miscellaneous Mechanical Equipment 5.292 5.212.1 Unit 7-2 vacuum cleaning system will be an extension of the existing Unit 5 system upgraded as necessary to handle the additional load. The combustion air preheating system includes steam to glycol heat exchangers, glycol pumps, and head tank. Piping System Power Piping Power piping includes: ° Main steam piping - from the boiler superheater outlet to the topping turbine throttle valve header and from the topping turbine exhaust to the Units 1, 2 and 3 throttle valve header. 011783 .0025c 5i|= 7 Rev: 0 Rev. Date: 02/18/83 ° Condensate piping - from Units 1, 2 and 3 condenser hotwells to new deaerator and from new deaerator to new boiler feed pump suction. ° Feedwater piping - from boiler feed pump discharge through new high pressure feedwater heater to economizer inlet. ° Extraction steam piping - from Units 1, 2 and 3 extraction points to the evaporator, new deaerator, new high pressure feedwater heater, and district heating system. All piping is to be new carbon steel or chromium-molybdenum material with welded joints. Valves will be weld-end cast steel construction. Piping material will be specified and piping engineered in accordance with ANSI B31.1 Power Piping Code, latest edition and addenda. Insulation will be calcium silicate or fiberglass. 5.212.2 Auxiliary Piping Auxiliary piping systems include: auxiliary steam piping to the . building heating system and the glycol heat exchangers, miscellaneous heater drips and drains, potable water, station and instrument air, heater vents, and cooling water. This piping will be new carbon steel material with welded joints. 011783 .0025c S18 Rev: 0 Rev. Date: 02/18/83 5.212.3 Yard Piping 5a213 No yard piping is required for Chena 7-2. Instrumentation and Controls The instrumentation and control system will consist of pneumatic analog controllers, indicators, recorders and an annunciator system. Instrumentation for Unit 7-2 will be selected and the control panel arranged similar to that for Unit 5 to facilitate operation. The control room of Unit No. 5 will be extended to provide space for the Unit No. 7-2 control area. The control philosophy employed on Unit No. 5 will be adhered to as much as possible in the design of Unit No. 7-2 controls. A central control panel located adjacent to Unit No. 5's panel will house indicators, recorders, controllers and annunciators to monitor the boiler, turbines and their auxiliaries. The operator will be able to control steam pressures, feed water flow, combustion air flow, etc., from the central control panel. 011783 .0025c Sarg Rev: 0 Rev. Date: 02/18/83 5.214 Electrical Systems and Equipment 5.214.1 Auxiliary and Miscellaneous Transformers Normal auxiliary power for Boiler 7-2 will be provided by a double-ended, 4160-480 volt load center. The two transformers will be 750 kVa each, with one of them connected to 4.16 kV switchgear bus 1 and the other to 4.16 kV switchgear bus 2. Each of these transformers is capable of serving the total boiler auxiliary load, including building facilities for the addition constructed to house it. The transformers will be of the nonflammable, liquid insulated type as defined by NEC Article 450-24. With the shutdown of boilers 1, 2 and 3, sufficient loads should be removed from 480 volt load centers A, B and C, to permit any one of them to serve as backup for another during an emergency, thus eliminating any need for connections to the Boiler 7-2 transformers. The auxiliary power transformers will have a solidly grounded, wye connected secondary winding so as to provide 277 volt service for most lighting in the building addition. 120/240 volt, single phase loads will be supplied from conveniently located dry type 480 - 120/240 volt transformers. 011783 .0025c DeeECO Rev: 0 Rev. Date: 02/18/83 The existing 12.5-4.16 kV transformer interconnecting the 4.16 kV switchgear with the outdoor 69-12.5 kV substation will be retained and a second 7500 kVa, essentially duplicate unit will be added to obtain increased reliability. This transformer will be located in the outdoor substation area and will require a new 14.4 kV circuit breaker with isolating switches in its primary circuit and will be interconnected with the switchgear by underground cable. 5.214.2 Switchgear and Accessories The electrical requirements for this scenario also require that the 4160 volt switchgear be modified in accordance with Section 12.100, "Recommendations for Rehabilitation and Renovation of the Old Plant Substation" so as to provide increased reliability. The increased reliability is obtained by sectionalizing the 4160 volt bus into two portions and adding the second tie to the 69-12.5 kV outdoor substation referenced hereinbefore. When the recommended modifications are completed, two circuit breakers will become available on 4.16 kV bus 2. These are then available for one of the feeds to the double-ended, 4160-480 volt . load center and for connection to the topping turbine-generator. It will be necessary however to add one circuit breaker to 4.16 kV bus 1 for the second feed to the load center. 011783 .0025c peel Rev: 0 Rev. Date: 02/18/83 5.214.3 Motor Control Centers and Load Centers Two new motor control centers will be provided to serve all motors except the boiler feed pumps, which will be fed directly from the 480 volt load center. In addition, power distribution panels will be located in the motor control centers for ease and convenience in serving miscellaneous loads other than motors. One of the motor control centers will be located on the mezzanine floor level and the other on the main operating floor. The motor control centers will utilize combination circuit breaker-motor starter type elements. The existing motor control centers, serving building and turbine generator auxiliaries, will be replaced with new units containing the same combination starter units. This is required due to the obsolescense of the existing units. The load center will be of the double-ended type with air circuit breakers and solid state type tripping elements. The bus will be split into two sections with a bus tie circuit breaker in between them. This will provide dual sources of power for the two boiler feed pumps, one from each bus section. The remaining loads will be balanced between the two sections. The bus tie circuit breaker will be arranged to close automatically upon failure of either feeder feeding the load center. 011783 .0025c 5) sed 5.214.4 Sedan Rev: 0 Rev. Date: 02/18/83 Existing load centers A, B and C will be retained to serve turbine generator auxiliaries and facilities for the existing building. Wiring Systems Cable tray will be utilized to the greatest possible extent with intermediate metal conduit used between the cable tray and equipment or enclosures. The exception to this is the lighting system, where electrical metallic tubing (EMT) with compression fittings, will be utilized throughout. Separate cable trays, or trays with metallic barriers will be used to isolate power from control and low energy circuits. Existing wiring that will remain in service after installation of the new boiler will be replaced. This is required due to the deterioration of the existing wiring. Lighting The lighting system for the new facility will provide light levels.in accordance with I.E.S. Standards. General area lighting will be of the high pressure sodium vapor type. Fluorescent lighting will be utilized in areas with low ceilings and in areas requiring 011783 .0025c Siac on21426 Sela, Rev: 0 Rev. Date: 02/18/83 supplementary lighting such as the firing aisle. Incandescent lighting will be utilized only in small areas and in unheated areas. General area lighting will be switched from conveniently located lighting panelboards. New lighting, designed in accordance with the same criteria, will be provided for the basement and operating floor of the Units 1, 2 and 3 turbine generator portion of the existing building also. Motors All motors will be peecltatl as an integral part of their respective fan, pump, etc. Motors will be drip-proof, class B insulated type with standard starting torque, unless the specific requirements necessitate otherwise. All motors 1/2 horsepower and larger will be rated 460 volt, 3-phase. Motors smaller than 1/2 horsepower will be 230 volt, single phase. Batteries and Emergency Power Systems The existing storage battery with its associated charger will be retained. This battery adequately supplies all critical services for turbine-generators 1, 2 and 3 at present and should continue to do so. 011783 .0025c 5 - 24 60'-0" 50'-0" (40'-0" SCENARIO 2) € EXIST. jj 74'-6" NEW CONV. COL. 7 EL.505'-0" N ro —+—_—_ ( eee BERBERS) NS ae is Leek T T TTT TTT | | | I | 540 TON BUNKER | 450 TON BUNKER (PROPOSED) \ (Exist) 350 TON (SCENARIO 2) \ N N N \ ‘0 \ | 40 \ ‘ \ \ i N 1 N \ h 7\\ EL. 46I'-3" i ihe | - 46I'- / t fal 4'-6" 1o'-o" Ale 14'-6" AD 25'-0" | € NEW BUNKER teal 69'-9" CTRS. a > 59'- 9" (SCENARIO 2) NOTE: ALL DIMENSIONS + NEW BUNKER FOR SCENARIO 2 TO HAVE 2 OUTLETS FIGURE 5.1 BUNKER ELEVATION OT ee Laeenist CONV. W/ TRIPPER MY taxnptnceant ,” TUTTI 1 | | I | | / A / / / / / / i / / y © EXisT. BUNKER @ wes CONTINUEO ON DRAWING 711-O}1 7500 KAVA 12.5-41@KV XFMA #2 TURBINE GENERATOR CENTER C 0 CENTER A LOAO | CENTERS 450 | | | | | =| ISSUED FOR PHASE | REPORT iva] =| Joare] REVISION DESCRIPTION PWN PY | toe |b CONTRACT NO. CHENA FEASIBILITY STUDY rae DRAWING NO. = | SINGLE LINE DIAGRAM- SCENARIO. 2 711-009 ih BS Lie BEETIaG deat eevee ae OUTFALL STRUCTURE D e sus-station ce Coal Costeres water veut F waren WELL soe ic : soren he ‘ise sue Sire cere een ere ereresar eres are are eee 7 iH ' SaL aoe _ Coat converon aecuain t Terres rover Plant Al i suor ' { iy | J GENERATOR #3 satanic yee 1 | = WARENOUSE & GaRACE t sz FUTURE Expansion OF 1 == r—_ WATER TREATRERT PLANT 1 == i 3 oe Tr: mea sorter #3 1 GENERATOR 42 1 J ' r-4 — -< - 4 ' ‘ / ~ ¢ ' h < . ' Ni a { | | 3 AVE. CHENA FEASIBILITY STUDY CONCEPTUAL EQUIPMENT LAYOUT SCENARIO 2 BETWEEN EL.427°-10° & 455°-0 i PLAN VIEW EL. 427° AND ABOVE K : Tore Stittesnts: 2765-8" l 4 ITEMS AT ELEW. 427° SHOWN ‘ WITH SOLID LIMES. ITEMS ABOVE ELEW. 427° SHOWN DOTTED. CONCEPTUAL GENERAL ARG'T ; “f= SCEMARIO £2 ies a BASEMENT FLOOR AND MEZZANINE x aT : . 5 I ¢ ~ ! ' | D | | stone tunes | I 7 O | aie an 1 nd SUPERISTEROCST “A fitine at! . wi ' u “4 : 5! 4———_ 1+ | | aod 2 ‘| 4 # 1 J F.D. Fan ar , ITEMS AT ELEY. 455° SHOWN PLAN VIEW EL. 455" AND ABOVE iin SOLID LIMES. / SCALE = 1° = §-0" ITENS ABOVE ELEW. 455° ; A SHOWN DOTTED. L ‘ S 2 . CHENWA FEASIBILITY STUDY Yas es aa : . : , . .* , . CONCEPTUAL CEWERAL ARG°T 2 1 : ie j oa nia pd SCENARIO #2 . : . Ks OPERATING FLOOR AND ABOVE feenlsy ed] 4038 | 100-005 | TOPPING TURBINE 150,000 Ib/hr 850 psig AIR 44,810 scfm 100 hp COAL 14.4 tph 1.4 tph ASH = STEAM CENERATOR 301°F (BOILER) #7-2 00208 PRECIPITATOR 250 hp WF. W. HEATER /— FEEDWATER 0.1 gr/dscf tsp DESUPERHEATER 374 ppm S09 373 ppm NOy 137 ppm CO | 600 psig» 700°F PRY DESUPER HEATER | | CONDENSERS | | | ' | | MAKE-UP RETURN FROM DSHS TO DSHS 0.0 psig 350° F, CHENA FEASIBILITY STUDY | SCENARIO 2 TO ATTEMPERATING . PROCESS FLOW DIAGRAM | DESUPERHEATER BOILER FEED PUMPS 300 Hp each IFPRC) PROS. CONTRACT NO. 40356 DRAWING NO- MORRISON KNUDSEN | 610-001 6.000 6.100 6.110 6.120 Rev: 0 Rev. Date: 02/18/83 SCENARIO NO. 3 NEW BOILER AND TURBINE-GENERATOR General Specific Assumptions A 30 megawatt coal-fired steam electric powerplant consisting of a 286,000 lb/hr boiler and a 30 MW steam turbine-generator unit will be constructed. When it is placed in service it will permit MUS to retire the Chena 1, 2, and 3 powerplants in their entirety and to increase the electricity and district heat output. The new unit will be referred to in this report as Chena 7-3. Although the turbine generator unit capacity is 30 MW, use of extraction steam for district heating will lower generator output during the winter. The net annual average power generation will be below 25 MW. Process Flow Description Process flow diagram 610-002 shows the critical flow paths, temperatures, pressures, energy consumption, and energy output. The conceptual equipment general arrangement drawings focusing on the 0029c .012083 6-1 6.130 Rev: 0 Rev. Date: 02/18/83 basement level and the operating level of the boiler building, are governed by the need to be compatible with Unit 5. The conceptual layout drawings represent the space occupied by new buildings and equipment relative to the existing buildings and equipment. The electrostatic precipitator and stack are located on the roof of the turbine-generator building to best utilize available space and allow for access to the air cooled condenser. Up to 215,000 lb/hr of steam will be available to the district heating system, through the extraction steam system of the turbine. Heat Balance Approximately 40 x 10° Btu/hour of heat in the turbine exhaust steam will be available for utilization in low grade heating applications or disposal when 165,000 pounds of steam per hour is being extracted from the turbine for district heating during winter operation and when electrical power from the generator is maximum for this amount of district heat load. Approximately 152 x 10° Btu/hour of heat in the turbine exhaust steam will be available for utilization or disposal when 30,000 pounds of steam per hour is being extracted from the turbine for district heating during the summer months and when electrical power from the generator is maximum for this amount of district heat load. 0029c.012083 6-2 6.140 Rev: 0 Rev. Date: 02/18/83 Low grade heat utilization and rejection is discussed in Section -4.400 of this report. Electrical System Overview The electrical requirements for Unit 7-3 will be supplied from a new, and largely independent, 4160/480 volt system. This system, interconnected with the outdoor 69-12.5 kV substation through new 12.5 kV metalclad switchgear, will also interconnect at the 4.16 kV level with the "old" plant substation so as to provide a backup source to that substation and conversely, in an emergency, receive power from it to serve Unit 7-3 auxiliaries. The 12.5 kV switchgear will contain a generator main circuit breaker so that normal startup can be achieved through the switchgear and unit auxiliary transformer without having to have a separate startup transformer. Single Line Diagrams, Drawings 711-010 and 711-011, depict the planned arrangement. As may be noted on the single line diagrams, it is anticipated that large motors will be fed directly from the 4.16 kV unit auxiliary bus. This bus will be sectionalized to provide electrically independent service to each of the two boiler feed pumps under emergency conditions. Normally, however, the circuit breaker interconnecting the unit auxiliary bus with the old plant substation will be open and the bus/tie circuit breaker will be closed. 0029c.012083 6-3 6.200 6.201 6.201.1 Rev: 0 Rev. Date: _ 02/18/83 Since it is anticipated that Units 1, 2 and 3 will be shut down upon the completion of Unit 7-3, it is anticipated that the electrical systems associated with them will not need any substantial repair and/or replacement. Any building services provided from these units will be reconnected to the Unit 7-3 system. Alternatively, since load centers A, B and C are in relatively good condition, it is perhaps possible to retain the old motor control centers partially in service to supply these loads by salvaging starters and circuit breakers from disconnected loads and retaining them as spares for remaining loads. The existing 4.16 kV switchgear will be retained "as is" since it will serve only load centers A, B and C and provide standby service only for Unit 7-3. Structures and Equipment Description Site Development Refer to Drawing 100-002. Roads, Walks and Fences Existing hut type storage buildings and shops will be relocated to make room for new construction. The entryway structure on the west 0029c .012083 6-4 6.201.2 Rev: 0 Rev. Date: 02/18/83 side of Unit 5 will be relocated. The unloading dock on the north side of the Unit 1, 2, 3 turbine hall will be relocated. A parking area will be provided west of the new unit. No new fences or security facilities are required. Removals and Demolition Although Units 1, 2 and 3 will be retired when the new boiler is placed in service, there will be no removal of the old equipment. When Unit 5 was constructed, the addition of another boiler was contemplated. The basement foundation wall of Unit 5 has been constructed with knockout sections for access to the new unit. These will be removed. The west wall of the Unit 5 building will be removed to the extent that the new building matches the Unit 5 profile. The Unit 7-3 area is essentially free of underground piping, thus no significant relocation is required, assuming that the new Unit 7-3 building does not extend to the west beyond the west end of the Units 1, 2 and 3 building. Should the Unit 7-3 building extend beyond that point, an electrical duct bank running north-south between the Unit 7-3 building and the Water Treatment Plant will be relocated, as well as several large water lines which run between the Water Treatment Plant and the Unit 1, 2 and 3 building. In any event, special excavation procedures will be necessary because the electrical duct bank and water lines are within the excavation area of the new Unit 7-3. 0029c .012083 6=5 6.202 620271 6.202.2 6.203 6e2OSel Rev: 0O Rev. Date: 02/18/83 The power plant warehouse, located to the northwest of the Unit 7-3, will be removed. Substructure and Foundation Building Foundations Unit 7-3 will be constructed on a reinforced concrete mat. The basement mat will be at the same grade as the present Unit 5 basement mat. The basement walls will be of the same type as used for Unit 5 and will extend above the flood plain to an elevation matching Unit 5. The air cooled condenser will be supported from four foot diameter drilled piers to the north of the Unit 7-3 building. The ash silo will be supported on drilled piers to the west, at the north end, of the Unit 7-3 building. Yard Foundations There are no significant yard foundations required. Structural Features Structural Steel 0029c .012083 6-6 6.203.2 6.204 6.204.1 Rev: 0 Rev. Date: 02/18/83 A braced structural steel frame will be used to support equipment and enclose the new powerplant, including the boiler, turbine-generator and all auxiliaries. The turbine area steel will be designed to support the precipitator and stack. See Drawing 100-008. The new building will be about 70 ft. wide, 150 ft. long and 77 ft. high. Cranes and Hoists The existing Unit 5 twenty-ton capacity turbine bay crane will be extended into the Unit 7-3 building to handle turbine generator erection and maintenance. The heaviest turbine part will be limited to the crane capacity. In addition, miscellaneous monorails and hoists will be provided to service equipment. Buildings Station Building The new unit will be enclosed with insulated sandwich panel siding. The ground floor will be a concrete slab constructed on the structural steel frame. Other floors will be grating and these will match the Unit 5 elevations to the extent practical. If new equipment dimensions allow, Unit 7-3 will be arranged so that the operating floor, boiler firing isle and turbine deck are at the same elevations as those in the existing Unit 5. However, the new 0029c.012083 6-7, 6.204.2 Rev: 0 Rev. Date: 02/18/83 structure will be approximately 20 feet higher and the top floors of the boiler structure will not match Unit 5. The control room and superintendents office will be expanded into a common facility for Units 5 and 7-3. There will be thermopane type windows in the new structure. A complete new lighting system will be provided for Unit 7-3 and the Unit 5 elevator will be rebuilt (raised approximately 20 feet) to provide access to the various above grade floors in Unit 7-3. Space for a new maintenance workshop will be provided for in the new building. The water laboratory in Unit No. 5 will be utilized for testing samples from Unit 7-3. HVAC Steam unit heaters will be provided to heat the Unit 7-3 building. Heating steam will be supplied from the auxiliary steam system which is supplied from a pressure reducing station off the low pressure _ extraction steam. The Unit 7-3 auxiliary steam system will be cross connected to the Unit 5 auxiliary steam header. Building ventilation make-up air will be preheated by glycol coil heaters. 0029c.012083 6-8 Rev: 0 Rev. Date: 02/18/83 6.204.3 Yard/Miscellaneous Buildings 6.205 No new warehouse or shop buildings are contemplated. Circulating Water System In the winter, it is essential that there is no increase in waste heat delivered to the river or to any device which will result in an increase in water vapor, and ultimately ice fog. With this in mind, the heat rejection system developed for the conceptual design consists of a conventional water cooled surface condenser operating in parallel with an air cooled condenser. Cooling water for the surface condenser will be well water at 38°F. The condenser will serve as a heater for well water make-up for the city water treatment plant. An average of 3156 gpm will be pumped from the existing well system through the condenser, which heats it to about 60°F, and from there to the water treatment plant. Approximately 300 gpm of well water will be circulated through the closed cooling water heat exchanger which in turn supplies treated cooling water to various plant equipment. 7 0029c.012083 6-9 6.206 6.206.1 6.206.2 Rev: 0 Rev. Date: 02/18/83 A more detailed discussion of the circulating water system can be found in Section 12.200, Waste Heat Rejection and Utilization. The air cooled condenser is discussed in Paragraph 6.211.3. Coal Handling Equipment Bunkers A 540 ton (24 hour) capacity bunker will be provided above the boiler firing isle and stoker feed equipment, in line with the Unit 5 bunker. The Unit 7-3 bunker will be about 60 ft. long. The height and width, top and discharge elevations will match those of Unit 5. The west end of the Unit 5 bunker will be reworked to allow the passage of the tripper. The east end of the Unit 7-3 tripper will have a similar passage. The bunker will have three conical hoppers and slide gate outlet valves. The hoppers will have a polymer liner to facilitate coal flow and minimize freezing of coal to inner hopper surfaces. See Figure 5.1. Trippers P The Unit 5 100-ton/hr tripper will be extended about seventy five feet to feed the Unit 7-3 bunker. This will require a new conveyor 0029c.012083 6-10 6.206.3 6.208 6.208.1 Rev: 0 Rev. Date: 02/18/83 belt, idlers, and head pulley. The capacity of the tripper will be increased to 150 tons/hr by adding a new drive. Fugitive dust suppression equipment will be provided, consisting of the two bin vents with exhauster fans, filters, and housings. Coal Feeding Equipment Coal will be fed by gravity from the bunker hoppers through a gravimetric weigh-belt feeder to nonsegregating splitters to the boiler stokers or to pulverizers. The weigh-belt feeder will be designed such that coal can be fed when it is out of commission. Steam Generator Boiler and Auxiliaries One pressurized steam generating unit of the natural circulation type with 286,000 lbs/hr continuous capacity will be furnished. It will be designed to deliver steam at 900 psig and 950°F at the superheater outlet when supplied with feedwater at 453°F. The unit will be spreader stoker or pulverizer fed and designed to operate on coal with an expected Btu rating of 7850 Btu/lb. Forced draft, overfire air and induced draft fans and associated duct work will be - included. A steam-to-glycol heat exchanger and a glycol coil combustion air preheater will be included. In addition, overfire 0029c.012083 6-11 6.209 6.209.1 Rev: 0 Rev. Date: 02/18/83 air will be preheated. Primary combustion air will be heated in a tubular or Lungstrom air heater located in the flue gas stream between the economizer and the dust collector. The boiler will be designed for ease of conversion to oil or natural gas at a later date. Turbine-Generator Turbine-Generator Unit and Auxiliaries One indoor type condensing turbine will be provided designed for operating throttle conditions of 850 psig and 950°F at a throttle flow rate of 286,000 Ilbs/hr. The turbine-generator will be rated at 30,000 MW, 2.5 inches of mercury absolute back pressure. One automatic and three uncontrolled extraction points will be provided for feedwater heating. The automatic extraction point will also provide up to approximately 215,000 lbs/hr of steam to the district heating system at 25 psig in an emergency with the two high pressure extraction valves shut. Condensate from the existing district steam heating system and the new district heating hot water heat exchangers will be returned to the feedwater system at the deaerator. 0029c .012083 6-12 6.210 6.210.1 Rev: 0 Rev. Date: 02/18/83 When extraction is at 165,000 Ibs/hr to the district heating system, which is the maximum for normal operation, the maximum output of the turbine-generator is expected to be 22,500 kilowatts. When there is flow of 30,000 Ilbs/hr to the district heating system in the summer months, the expected output of the turbine-generator will be about 26,700 kilowatts. The turbine-generator unit will be provided complete with exciter and all accessories customarily required, such as supervisory instruments, oi] reservoir, oi] coolers, main and auxiliary oil pumps, gland steam condenser, hydrogen coolers, and hydrogen and carbon dioxide systems. Air Correction Equipment Precipitators/Baghouse Air correction equipment for particulate control will be required. Two regulations are applicable: 1) Federal Standards of Performance for Fossil-Fuel-Fired Steam Generators (40 CFR 60, Subpart D) limits particulate output to 0.10 1b/million Btu and 2) State of Alaska, Department of Conservation limits output to below 0.05 gr/dscf. Both regulations require maximum 20 percent opacity. The air correction equipment design will allow compliance with the strictest regulations. (Refer to Section 8.000.) 0029c.012083 6-13 Rev: 0 Rev. Date: _ 02/18/83 As in Scenario 2, a precipitator is included in the conceptual design rather than a baghouse because of its smaller size and lower operating costs. (See Section 5.210.1.) Two locations were considered for the precipitator in this Scenario: 1) adjacent to the west wall of the new boiler building and 2) on the roof of the new turbine building. The large, air cooled condenser included in this scenario is located north of the new building; therefore, that space cannot be used for the precipitator, as it is in Scenario 2. Although the precipitator, forced draft fan and stack will fit to the west of the building this would severely limit the vehicle access between the new building and the existing water treatment building. To save space the roof top location was chosen for the conceptual design. Due to increased structural requirements this choice will increase the plant cost, but it is believed to be the best option in terms of the overall plant arrangement. 6.210.2 Stack A steel stack with top elevation 180 feet from grade, will be provided to handle the exhaust gases from the precipitator. It will be located on the turbine building roof near the precipitator and_ TADAEane 0029c.012083 6-14 65211 6211 Grell Ge2dta3 Rev: 0 Rev. Date: 02/18/83 Mechanical Equipment Major Pumps Two 100-percent motor driven boiler feed pumps will be provided to supply feedwater to the steam generator. Pump discharge pressure will be approximately 1060 psia. The ASME Power Boiler Code, Part PG61.1 requires a backup turbine driven boiler feed pumps when no black start backup is available. This exception to the ASME Code should be further investigated in detailed design. The use of motor driven rather than steam driven pumps is based on Unit No. 5 design and the Owner's indication that essential power during a total power outage will be provided by a back-up diesel-electric generator. Miscellaneous Pumps The following miscellaneous pumps will be required: closed cooling water pumps, sump pumps, glycol pumps, glycol heater condensate pumps, and fire pumps. Condensers and Auxiliaries An air cooled condenser and a conventional water cooled surface condenser will operate in parallel. The turbine exhaust design pressure is 6 inches of mercury absolute at 60°F ambient dry bulb temperature. 0029c.012083 6=15 6x cdla4 Rev: 0 Rev. Date: 02/18/83 The surface condenser, which will be a conventional shell and tube condenser will reject about 20% of the exhaust heat to well water which is then pumped to the city water treatment plant. An A-frame forced draft air cooled condenser will reject the remaining 80% of the exhaust heat. Four 50-hp variable pitch fans will be required. The condensate temperature will be controlled by varying the pitch of the fan blades and by recirculating air. This allows conservation of fan power when operating at lower condenser loads. The two condensers operate as separate systems, each with two 100-percent capacity Condensate pumps. Steam jet ejector systems are also included for each condenser. For more information see Section 12.200, Waste Heat Rejection and Utilization. Feedwater Heaters One stage of L.P. feedwater heating will raise the condensate to about 206°F. A deaerator operating at 50 psig and two stages of high pressure feedwater heating will be provided. The final feedwater temperature will be about 453°F. Valves and piping will be provided to bypass each feedwater heater, individually. The closed heaters 0029c .012083 6-16 652105 Rev: 0 Rev. Date: 02/18/83 are conventional shell and tube heat exchangers with desuperheat, condensing and subcooling zones. The deaerator has a 5-minute capacity storage tank. Water Treatment Equipment The Unit 7-3 makeup water treatment system will utilize potable water, which has been chlorinated and softened, from the city water treatment plant. The potable water will be fed to two new 100-percent capacity zeolite softeners for removal of scale forming calcium, magnesium and iron prior to feeding the new 100-percent capacity evaporator. (The new Unit 7-3 zeolite softeners will be in parallel with and supplementary to the existing zeolite softener in Unit 5.) Evaporator output then goes to the Unit 7-3 deaerator. The unit 7-3 evaporator chemical feed equipment will feed water conditioner to condition the evaporator water and sodium sulfite for oxygen scavenging. Water conditioning equipment will consist of a solution tank with mixer and two 100-percent capacity piston diaphragm metering pumps. Sodium sulfite feed equipment will also consist of a solution tank with mixer and two 100-percent capacity metering pumps. 0029c.012083 6-17 6.211.6 aC Rev: 0 Rev. Date: 02/18/83 New Unit 7-3 boiler water chemical feed equipment will feed chelate for boiler water conditioning and hydrazine for oxygen scavenging/pH control. The boiler water chelate feed equipment will consist of a solution tank with mixer and two 100-percent capacity pumps. The hydrazine feed equipment will consist of a solution tank with mixer and two 100-percent capacity pumps. A new Unit 7-3 sample rack will be provide to monitor water quality. Compressed Air Equipment A new compressed air system will be provided for Unit 7-3. The system will include two 100-percent capacity nonlubricated, reciprocating compressors, aftercoolers and air receivers. Air will be taken off the new station air header, dried, and filtered for use as instrument air. This is a cost effective arrangement which allows sufficient redundancy to permit maintenance of any single component without interrupting the functioning of the system. A tie to the Unit 5 instrument and service air headers will provide backup for these systems. Ash Handling System Furnace bottom ash, after passing through clinker grinders, will be pulled sequentially with fly ash from the economizer and precipitator 0029c.012083 6-18 Ges Rev: 0 Rev. Date: 02/18/83 hoppers. A new 100 horsepower vacuum pump operating in parallel with the two existing Unit 5 vacuum pumps, will provide the vacuum. The ash will be transported from the ash hoppers, via new vacuum Pneumatic ash piping, to a new silo. The silo will be sized for a five day storage capacity and will measure twenty-four feet in diameter with a thirty foot cylinder height. The overall height, including about ten feet on top for air/material cyclone separators, twenty feet beneath the cylindrical section for a conical bin and unloader, and ten feet beneath the unloader for haul truck clearance, is seventy (70) feet. The silo will be of welded steel construction. The piping will be Ashcolite material or equivalent. Valves, actuators, replaceable wear-back elbows, wyes, and other fittings will be provided. Tanks Two condensate storage tanks of 25,000 gallon capacity each will be provided. A boiler blowdown tank and lube oil storage tank will also be provided. 0029c.012083 6-19 Ca 2dT 9) 6.211.10 Rev: 0 Rev. Date: 02/18/83 Fire Protection System The coal conveyors will be protected with a dry pipe water deluge system actuated by automatic thermal detectors. The signal from the detectors will stop the conveyor, as well as actuate the pre-action valve. The coal bunker will be protected with a CO, flooding system. Predischarge and discharge alarms will be provided to warn personnel of possible build-up of CO, in spaces adjacent to equipment being flooded with CO,. Buildings will be protected by a zone type sprinkler system. In addition, hose stations, portable fire extinguishers and breathing apparatus will be provided throughout the plant as required by National Fire Code and OSHA. Miscellaneous Mechanical Equipment Unit 7-3 vacuum cleaning system will be an extension of the existing Unit 5 system. A closed equipment cooling water system will be provided for cooling the generator hydrogen, lube oil, boiler feed pump lube oi] and bearings, air compressors, I.D. fan and F.D. fan bearings, spreader 0029c .012083 6-20 6.2 yl 67212 C2121 Rev: 0 Rev. Date: 02/18/83 feeders, and ash doors. The system will include two 100-percent heat exchangers, two 100-percent circulating water pumps, a system head tank and water piping. The combustion air preheating system will include steam-to-glycol heat exchangers, glycol pumps, head tank, and a glycol-to-air heat exchanger. District Heating System Heat Exchanger Unit 7-3 will supply steam to DSHS heat exchanger(s) which will heat water for the expanded district heating system. Condensate from this exchanger will be returned to the Unit 7-3 feedwater cycle, making this a closed cycle. Although the DSHS exchangers were not sized or evaluated as a part of this study, performance assumptions were made to determine the return condensate conditions. Piping System Power Piping Power piping includes: 0 Main steam piping - from the boiler superheater outlet to the Unit 7-3 turbine throttle valve header. 0029c.012083 6=21 6421252 Rev: 0 Rev. Date: 02/18/83 0 Condensate piping - from condenser hotwell to the L.P. feedwater heater, to the deaerator, to the boiler feed pump suction. 0 Feedwater piping - from boiler feedwater pump discharge to H.P. feedwater heaters, to boiler economizer inlet. ° Extraction steam piping - from turbine extraction points to the L.P. feedwater heater, evaporator, deaerator, and H.P. feedwater heaters. One of the turbine extraction points will be sized to provide steam at 25 psig to the district heating system heat exchanger(s). All piping is to be new carbon steel or chromium-molybdenum alloy material with welded joints. Valves will be weld-end cast steel construction. Piping materials will be specified and piping will be engineered in accordance with ANSI B31.1 Power Piping Code, latest edition and addenda. Insulation will be calcium silicate or fiberglass. Auxiliary Piping Auxiliary piping systems include: auxiliary steam piping to supply the building heating system and the glycol heat exchangers, miscellaneous heater drips and drains, potable water, station and 0029c.012083 6E22) Oral Zms Grci3 Rev: 0 Rev. Date: 02/18/83 instrument air, heater vents, and cooling water. This piping will be carbon steel with welded joints. Yard Piping Piping outside the Unit 7-3 walls will be ash conveying piping to the silo, water piping from the surface condenser to the potable water treatment plant, and wastewater piping. Instrumentation and Controls The instrumentation and control system will consist of pneumatic analog controllers, indicators, recorders and an annunciator system. Instrumentation for Unit 7-3 will be selected and the control panel arranged similar to that for Unit 5 to facilitate operation. The control room of Unit No. 5 will be extended to provide space for Unit No. 7-3 control area. The control philosophy employed on Unit No. 5 will be adhered to as much as possible in the design of Unit No. 7-3 controls. A central control panel located adjacent to Unit No. 5's panel will house compact indicators, recorders, controllers and annunciators to monitor the boiler, turbines and their auxiliaries. The operator will be able to control steam pressures, feed water flow, combustion air flow, etc., from the central control panel. 0029c.012083 6-23) 6.214 6.214.1 Rev: 0 Rev. Date: _ 02/18/83 Controls for the new turbine-generator will be housed in the control panel along with those of the new boiler. This includes synchronizing devices for the generator, such as voltage and governor control, and complete control for the unit auxiliary 12.5kV, 4.16kV and 480volt switchgear. Electrical Systems and Equipment Auxiliary and Miscellaneous Transformers Normal auxiliary power for Unit 7-3 will be provided by a 5000/6250 kVa outdoor type unit auxiliary transformer connected to the unit 12.5 kV metalclad switchgear. This transformer will feed a 4.16 kV unit auxiliary bus, which in turn feeds 4 kV motors such as the boiler feed pumps and the 480 volt transformers. Standby power, for use in the event of a transformer failure, will be supplied from the existing 4.16 kV "old substation". 480 volt auxiliary power for Unit 7-3 will be obtained from a double-ended, 4160-480 volt load center. The two transformers will be 1500 kVa each. The high voltage side of both transformers will be supplied from the 4.16 kV unit auxiliary bus, with one transformer connected to each of the two bus sections. Each of these transformers is capable of serving the total auxiliary 480 volt load 0029c.012083 6-24 Rev: 0 Rev. Date: 02/18/83 for the unit, including building facilities for the addition constructed to house it. The transformers will be of the nonflammable, liquid insulated type, as defined by NEC Article 450-24. With the shutdown of boilers and turbine-generators 1, 2 and 3, sufficient loads will have been removed from 480 volt load centers 1, 2 and 3, to permit any one of them to serve as a backup for another during an emergency, thus eliminating any need for interconnections with Unit 7-3, 480 volt system. The 480 volt auxiliary power transformers will have a solidly grounded, wye connected secondary winding to provide 277 volt service for most lighting in the building addition. 120/240 volt single phase loads will be supplied from conveniently located dry type, 480-120/240 volt transformers. The existing 7500 kVa, 12.5-4.16 kV transformer interconnecting the "old substation" with the outdoor 69-12.5 kV substation will be retained as the normal feed to this substation. If this transformer were to fail, service to all parts of the building may be maintained by backfeeding the "old substation" from the 4.16 kV Unit 7-3 switchgear. The unit auxiliary transformer is sized to accommodate this possibility. 0029c.012083 6-25 6.214.2 Rev: 0 Rev. Date: 02/18/83 Grounding resistors will be installed in the 4.16 kV transformer neutral ground connections for both the new Unit 7-3 auxiliary transformer and the existing 7500 kVa, 12.5-4.16 kV transformers to reduce fault levels due to ground faults on the system. This will minimize damage to the 4.16 kV motors when such a fault occurs in them. Switchgear and Accessories Under this scenario, the existing 4160 volt switchgear installation will be retained as is. This is considered feasible since turbine-generators 1, 2 and 3 and boilers 1, 2 and 3 will be out of service when Unit 7-3 is added. The switchgear, however, can be retained in service to feed 480 volt load centers A, B and C and, in addition, to provide a standby source of 4.16 kV power for Unit 7-3. While not subject to modifications under this plan, this switchgear should be subjected to complete dielectric testing and an overall inspection and calibration of protective devices. An assembly of 12.5 kV metalclad indoor switchgear will be required for generator 7-3. This switchgear will include the generator main circuit breaker, the unit auxiliary transformer high voltage circuit breaker, surge protection devices and potential transformers for the generator and terminations for the cable connection to the outdoor 69-12.5 kV substation. The circuit breakers should have an 0029c.012083 6-26 6.214.3 Rev: 0 Rev. Date: _ 02/18/83 interrupting capacity of 1000 MVA at rated voltage. This is somewhat in excess of the actual requirement for the generator breaker; however, since it is required for the auxiliary transformer circuit, it appears desirable to have both breakers identical for sparing purposes. A 4.16 kV switchgear assembly is required to serve Unit 7-3 auxiliaries. This switchgear, also of the metalclad, indoor type, will utilize 350 MVA circuit breakers. The assembly will include circuit breakers for two incoming feeders, two 480 volt load center transformers, two boiler feed pumps, one induced draft fan and for bus sectionalizing. Motor Control Centers and Load Centers Two or more motor control centers will be provided to serve all motors other than the boiler feed pumps and the induced draft fan, which will be fed directly from the 4.16 kV metalclad switchgear. Power distribution panels will be located in the motor control centers also, to provide ease and convenience in serving miscellaneous loads other than motors. One of the motor control centers will be located on the mezzanine floor level and the other. on the operating floor. If specific requirements of the ultimate detailed design indicate that it is desirable to divide the loads among more than two motor control centers, this may be accomplished 0029c.012083 6527) Rev: 0 Rev. Date: _ 02/18/83 with little or no cost increases, since the savings accrued by reducing the length of motor circuits should offset the costs associated with an additional motor control center. All motor control centers will utilize combination circuit breaker-motor starter type elements. The load center will be of the double ended type with air circuit breakers and solid state type tripping elements. The bus will not be sectionalized since redundant service to critical equipment is not considered necessary. The two main circuit breakers will be arranged so that a failure of one transformer will initiate an automatic transfer of the loads to the other one. 6.214.4 Wiring Systems Cable tray will be utilized to the greatest possible extent with intermediate metal conduit used between the cable tray and equipment or enclosures. The exception to this is the lighting system, where electrical metallic tubing (EMT) with compression fittings will be utilized throughout. Separate cable trays, or trays with metallic barriers will be used to isolate power from control and low energy circuits. 0029c .012083 6-28 6.214.5 6.214.6 Rev: 0 Rev. Date: 02/18/83 Lighting The lighting system for the new facility will provide light levels in accordance with I.E.S. Standards. General area lighting will be of the high pressure sodium vapor type. Fluorescent lighting will be utilized in areas with low ceilings and in areas requiring supplementary lighting such as the firing aisle. Incandescent lighting will be utilized only in small areas and in unheated areas. General area lighting will be switched from conveniently located lighting panelboards. Motors All motors will be procured as an integral part of their respective fan, pump, etc. Motors will be drip-proof, class B insulated type with standard starting torque, unless the specific requirements necessitate otherwise. Rated motor voltages will be as follows: 200 horsepower and above - 4000 volt, 3-phase 1/2 to 150 horsepower - 460 volt, 3-phase Less than 1/2 horsepower - 230 volt, l-phase 0029c .012083 6-29 Rev: 0 Rev. Date: 02/18/83 6.214.7 Batteries and Emergency Power Systems A new storage battery with its associated battery charger will be provided to serve Unit 7-3. This equipment will be sized to assure a safe shutdown of the turbine-generator upon loss of normal ac power, the control and indication for all associated circuit breakers and other critical functions. The need for an uninterruptible power supply is not foreseen at this time due to the utilization of a complete pneumatic instrumentation system, however, this is subject to review at time of detailed design when the exact requirements are known. 0029c.012083 6-30 CONTINUED ON DRAWING 711-Oll ee PLA WS SOR Sein le eel eee ec I2.5.AY UNIT: ?-3 “SuiIGR 4.1@ KV UNIT a-s SUNTOCHGEAF. EXISTING 4.1G AV SWITCHGEAR = > fe & be Ee LJ { LJ Ld B es Bw eC) Gy C2) Cr) ) BDAY - or gd oO QO 1OCOD KVA : IVTVN 1000) Kb x a So ye 2 >e 41GO-4qeov AIGO - 4BOV Z 4 Of ae oe az a a mu Oe a Qu 0 0 7X o™* 0 +x CENTEF. ISSUED FOR PHASE | REPORT a TO MCC'E ANO OTHER, 480. LOADS CHENA FEASIBILITY STUDY an Se ee ~ “ a“ OUTFALL STRUCTURE AIR COOLED COmDERSER far Sua-station C1 COL comvErOR WATER WELL : ® WATER WELL saree | ic : sorven a7 es >. J} -----------------------------------—----- 4 iH ' { WATER TREATRERT PLAT (ais Geeusiaa waerae i ee POWER Plant 7 1 1 1 @ { pagar ' on 1 fut sense ee WAREHOUSE & GARAGE : “ purune 1 t —————— TuReitt sorter porter #3 T SenERATOR #2 P t -4 =< a oy, —l ' ewe NA ' a 1 ee i 4 : J , AVE. _—— ao F = oo S \ / wae rik aa ad iN CHENA FEASIBILITY STUDY CONCEPTUAL EQUIPMENT LAYOUT SCENARIO 3 . BETWEEN EL.427°-10° & 455'-0* HORRISON KNUDSER PLAN VIEW EL. 427" AMD ABOV Ste Tt © 1-8 £ WATER TREATMENT BUILDING ITEMS AT EL. 427° SHOVE WITH SOLID LIMES. ITEMS ABOVE EL. 427° SHOWN DOTTED. CONCEPTUAL CEMERAL ARG'T SCEMARIO #3 BASEMENT FLOOR AND ABOVE 4 ~@- . ; | i Gl ieee | art | ‘ 8 — + + ——— | pop OD 7 | —— eres 2 . tif q ' i ’ i] _——— ' ' 1 7 L _ i E FERCE ' coupessite | ' ' STORacE Taans t TwRBIAE wins F . ¢ r ‘ ' ' t i. ' tt { + Hote 1 lf = ale coolee { | ! = CORDENSER th Mes fa | 3 ! I t lL iC 1 ' ' ! u SL TCOL i an ‘WEATER. f = t : ITEMS AT EL. 455° SHOVE . WITH SOLID LIMES. ITEMS ABOVE EL. 455° o a =, = = SHOWN DOTTED. PLAN VIEW EL. 455° AND ABOVE SCALE + It» wae ‘ ; : . ; eae ik " coacertoaL GENERAL ARG “bs hae : set Brie ee to Be SCEMARIO #3. : eros ; Soe : . OPERATING FLOOR AND ABO sms ser*-s0" veipece e Econonizen ae . a1 MeATER AIR COOLED ConpeasER aare-e* PRY > 1—___ 286,000 Ib/hr 850 psig 950°F 73,700 scf 150 Hp COAL PRECIPITATOR STACK GAS 72,600 dscn +05 gr/dscf tsp S74 ppm S09 373 ppm NOy 137 ppm CO oF: teh 1D 1p ei: ater 405.5 peas 196 psia MAKE - UP 2-2 tph ASH— RETURN FROM STEAM GENERATOR (BOILER) #7-3 Rie JH»P. FEEDWATER DSHS H.P. FEEDWATER HTR-NO.2 HTR-NO.3 28 MW SUMMER 22.5 MW WINTER DESUPERHEATER | 30,000 Ib/hr summelr L-P. FEEDWATER HTR-NO-1 DEAERATOR 78 psia | BOILER FEED PUMPS 350 Hp each CHENA FEASIBILITY STUDY SCENARIO 3 PROCESS FLOW DIAGRAN 00210 7.000 7.100 Rev: 0 Rev. Date: 02/18/83 SCENARIO NO. 4 COAL AND MSW BURNING FACILITY General In Scenario 4, existing Units 1, 2 and 3 boilers would be retired and replaced by one of two options: 1) a new 150,000 1b/hr boiler capable of suspension firing of coal and refuse derived fuel (RDF), or 2) a new 150,000 lb/hr coal-fired boiler and a separate 40,000 lb/hr stoker-fired boiler to burn unprocessed municipal solid waste. The district steam heating system will not be expanded under either option. In the first option, the MSW must first be upgraded to improve its quality as boiler fuel. This upgraded fuel is then suspension fired in a pulverized coal (PC) boiler. This option is discussed further in Section 7.120, but experience to date with both the RDF processing facilities and co-firing the two fuels in one boiler has been poor. The alternative to producing RDF and co-firing it with coal in the same boiler is to fire unprocessed MSW in a dedicated boiler (sometimes termed a mass burn process). The experience with this type of system has been much better than co-firing rdf and coal; however, reliability of steam generation is lower than coal firing. The reasons for this are detailed in Section 7.120. 0054c.012683 ak Teal 7.120 Rev: 0 Rev. Date: 02/18/83 Specific Assumptions The assumptions for the study, listed in Appendix D, are based on municipal solid waste facilities in the lower 48 states. The efficiency of the MSW dedicated boiler is 65%, the density of MSW is 18.5 Ib/cu. ft., and the heating value is 4500 Btu/lb (as received). The design flow rate of 182 tons of MSW per day is based on information received in a telephone conversation with personnel at Fairbanks North Star Borough. Steam flow from the MSW boiler is 40,000 1b/hr, based on the above MSW flow rate, heating value, boiler efficiency, and a steam temperature of 700°F and pressure of 600 psig, and feedwater temperature of 300°F. Process Flow Descriptions RDF Systems The only units known to M-K which co-fire RDF and coal do so in pulverized coal (PC) boilers. To accomplish this, two systems are required, one to produce the RDF and the other to combust it. Some vendors will state that RDF has been co-fired with coal in P spreader-stoker units, but closer examination has determined that the RDF was produced from materials with relatively Constant properties, such as wood wastes, and not from MSW. 0054c .012683 Vane Rev: 0 Rev. Date: 02/18/83 RDF is produced by first shredding the raw MSW, then magnetically removing ferrous material, and finally air classifying the shredded refuse. The air classification separates lighter from heavier particles. The heavy stream can be used as feedstock for additional materials recovery or landfilled. The light portion is shredded further to produce small (minus 2 inch) particles, or fluff RDF. A simple process flow diagram that is a typical RDF unit is shown in Figure 7.1. The fluff RDF is fired in suspension, where it begins to combust. The burning refuse particles fall onto a grate where combustion is completed prior to ash discharge. The grate is a necessary modification for the pulverized coal boiler to be capable of providing sufficient residence time for good burnout of the RDF. The boiler feed equipment consists of a fluffer and pneumatic conveyor system (see Figure 7.1). The fluffer is a mechanical device to decompact the RDF after transport and storage. Boiler problems and considerations have included such things as superheater tube metal wastage and lowered efficiency while burning RDF. Boiler slagging and clinker bridging which prevents removal have also been problems. Since the MSW from which the RDF is derived consists of many different materials, which have vastly differing heating values, the heat release rate varies with time making it difficult to 0054c.012683 1e3 Rev: 0 Rev. Date: 02/18/83 control. Compounding control difficulties are the hot spots created in the furnace by high heat content materials such as plastic and rubber. One significant advantage of fluff RDF systems is that the processing facility can be located at any convenient location. For example, it might be located at the site of Fairbanks North Star Borough MSW compaction plant. However, it would have to be trucked to the RDF plant and back to the power plant. A significant disadvantage is that due to the widely varying nature of the MSW, production and firing of fluff RDF is an expensive, energy intensive, complex process. Reliability is important in any system so this aspect of RDF was explored. A survey of 13 RDF units in the United States found that seven, or 54%, were operational and six were shutdown due to extreme technical or financial problems. A literature review and personal communication with plant operators has indicated that only two or three of the seven RDF plants which are operational could be considered even moderately successful. Problems commonly encountered in the process of producing RDF from MSW are: 0054c.012683 7-4 Rev: 0 Rev. Date: 02/18/83 0 Explosive material detonation in primary shredder destroys the equipment and endangers personnel. ° Wire becomes wrapped around shredder and screw conveyor rotating parts, stopping equipment. ° The power required by the shredders, classifiers, and conveyors is very significant. oO Lightweight noncombustibles such as aluminum foil and fine wire are not removed by the air classifier. Nonmagnetic metals are not removed by the magnetic separation equipment. These items tend to foul the ash conveying system. 0 The market for scrap metal removed is highly volatile and may even be nonexistent. The majority of the problems with these systems were related to material handling (a widely varying stream has to go through many discrete operations to produce RDF). Capital cost of RDF facilities was also surveyed. The average capital cost for just the RDF processing facility for the units surveyed was $39,000 per ton/day of installed capacity. There were too few installations where the boilers had been modified and were 0054c.012683 7=5 Rev: 0 Rev. Date: 02/18/83 actually firing RDF to provide a good average cost for this portion of the system. However, to provide a feel for the magnitude of this cost, the Madison Gas and Electric unit at Madison, Wisconsin, which is burning RDF, was examined. At an existing power plant in Madison, two Babcock and Wilcox pulverized coal boilers were modified and RDF receiving and feed equipment added at a cost of about $4,000 per ton/day of RDF capacity. The boilers, installed in 1957 and 1961, each have a capacity of 425,000 lb/hr of steam at 1250 psig and 950°F. Modifications to the boilers to burn RDF are the addition of drop grates just above the ash pits, addition of two fans per boiler to supply underfire and overfire air to the grates, and installation of two air cooled RDF mozzles on each boiler. The RDF processing plant has a nominal capacity of 50 tons per day and follows a process flow as shown in Figure 7.1. The total costs are summarized as follows: RDF Processing Facility $39 ,000/TPD Boiler Modification and Addition of RDF Feed Equipment 4 ,000/TPD TOTAL $43 ,000/TPD As can be seen, most of the expense is in the RDF facility. 0054c.012683 7-6 Rev: 0 Rev. Date: 02/18/83 Mass Burn Systems The alternate way to fire MSW is in a mass burn system. Drawing 610-003 shows the process flow, and Drawing 100-003 the equipment layout for this method. MSW is typically fired in a dedicated waterwall incinerator. Waterwall incinerators use either a pit and crane charging arrangement or a tipping floor with a front end loader and conveyor. Other than removal of very large objects such as car bodies, no front end processing is employed and "as received" refuse is fed directly into the charging hopper leading to the combustion chamber. An automatic feeder introduces refuse from the hopper onto the grates. Automatic stoking provides fairly uniform combustion and a high degree of burnout in the combustion chamber. The boiler is a convection pass water wall unit similar to that used in coal-fired steam generation systems and may include a superheater. After leaving the economizer the flue gases pass through a cleaning device (usually an electrostatic precipitator), and discharge to the atmosphere. Residue from the system is water quenched and collected for disposal. Some systems propose ferrous and nonferrous metal recovery from the residue or use of it as roadbed material. However, to date, the markets for this material have been limited and site-specific. Provisions for landfilling these materials are normally provided. The system control may be 0054c.012683 ex Rev: 0 Rev. Date: 02/18/83 somewhat uneven but since the separate coal-fired boiler is steady, the net effect of this option should be better than the uneven control in a boiler co-firing RDF and coal. A survey similar to that done for the RDF units found that of 30 mass burn units, 27, or 90%, were operational and only three were shut down due to extreme technical or financial problems. However, mass burn units still do not have as good an operating history as coal-fired utility boilers. Reliability is adversely affected by the pluggage of the ash handling and conveying equipment. Wire, large metal objects, and molten glass inevitably foul the drag conveyors. Wear on the traveling grate and ash drag conveyors is quite high relative to coal-fired units. The average capital cost of the mass burn units, which includes the fuel handling equipment, boilers, and peripherals, is $35,000 per ton/day of capacity. Summary The mass burn units have shown much better reliability than the RDF units with 90% as opposed to 54% operational. The mass burn units also have lower capital costs, $35,000 as opposed to $43,000 per ton/day of capacity. For these reasons, a 150,000 lb/hr coal fired boiler and a 40,000 1b/hr MSW fired boiler are studied as potential replacements for existing Chena 1, 2, and 3 boilers. The Structures and Equipment Description is not as detailed as for Scenarios 1, 2 0054c.012683 7-8 Rev: 0 Rev. Date: 02/18/83 and 3 because the low reliability, high maintenance costs, and problems associated with garbage truck traffic into and out of the plant preclude consideration of Scenario 4 prior to the cost and economic analysis stage. At the majority of MSW mass burn type plants, a tipping fee is charged the hauler by the utility to help amortize the debt. The full capacity coal-fired boiler is proposed due to the seasonal variation of the MSW supply and the fact that even with a mass burn system, its reliability is less than the coal fired boiler. As the 150,000 lb/hr coal-fired boiler is the same as that in Scenario 2, only features of the conceptual design which are unique to the MSW boiler are discussed in the Scenario 4, Structures and Equipment Description section, which follows. This unit will be referred to as Unit 7-4. A pulverized coal burning boiler with refuse derived fuel injection is not considered for more detailed study for the following reasons: 0 Higher operating and maintenance costs associated with the RDF processing equipment. 0 Pulverized coal boilers are usually larger than 150,000 lb/hr. 0054c .012683 7-9 7.200 7.201 TseO lt fecolg Rev: 0 Rev. Date: 02/18/83 0 Pulverized coal with refuse derived fuel combustion is still in a developmental stage and does not offer dependability required by public utilities. Structures and Equipment Description Site Development Road, Walks, and Fences (See Drawing 100-003) Access for MSW delivery trucks would be from First Avenue between the Units 1, 2 and 3 building and the water treatment plant. To access the MSW plant from the west would require a torturous routing of the MSW trucks due to the water treatment plant expansion, Unit 6 gas turbine generator and the substation. The clearance required for the trucks eliminates parking between the water treatment plant, the MSW unit, and the coal-fired units. Removals and Demolitions The well house for the abandoned well will be removed. Major relocation of four electrical ductbanks between the existing plant and the substation will be required. Piping relocations are also necessary. 0054c .012683 7-10 7.202 PeeWee Te er2 7.203 7203/1 Rev: 0 Rev. Date: 02/18/83 Substructures and Foundations Building Foundations The MSW-fired boiler will be in a separate building and thus require its own foundation. Yard Foundations A truck scale foundation for the MSW truck scales will be required. A reinforced concrete receiving pit and tipping floor will be required. The pit will be designed to withstand the impact of the feed crane bucket and the tipping floor will be designed to handle tractor-trailer rigs. Structural Features Structural Steel A braced structural steel frame will be used to support equipment and enclose Unit 7-4 coal-fired boiler, the MSW fired boiler, and associated auxiliaries. 0054c.012683 i 7-11 TpcAlKier4 7.204 7.204.1 7.204.2 7205 Rev: 0O Rev. Date: 02/18/83 Cranes and Hoists Two traveling cranes will be installed as part of the MSW boiler feed system to feed MSW from the receiving pit into the furnace. Buildings Station Building The MSW boilerhouse will be a separate building located north of the water treatment building. The ground floor will be a suspended slab constructed on the structural steel frame. Other floors will be grating. HVAC Combustion air is taken from inside the building above the receiving pit and tipping floor to control odors from the garbage. Circulating Water Systems The existing circulating water system would be utilized as in Scenario 2. The comments in Scenario 2, Section 5.205, regarding the wells, piping and equipment apply. 0054c.012683 TN, 7.206 7.207 7.207.1 Weevrec Rev: 0 Rev. Date: 02/18/83 Coal Handling Equipment The comments in Scenario 2, Section 5.206, regarding the bunkers, tripper, and coal feed equipment apply. Refuse Handling Equipment MSW Receiving Pit A 550 ton (3-day) capacity receiving pit will be located at the south end of Unit 7-4. The pit will be fed by MSW trucks which will back onto the tipping floor from the west, proceed to the edge of the pit, discharge their load, and exit over the route they entered. MSW Feeding Equipment The MSW will be fed from the pit to the feed hopper by an overhead traveling crane. A hydraulic ram will feed the MSW from the hopper to the stoker. Combustion air will be taken from the pit area in order to minimize odor and dust. 0054c .012683 als 7.208 7.208.1 7.209 7.209.1 Rev: 0 Rev. Date: 02/18/83 Steam/Generator Boiler and Auxiliaries The new coal steam generator will be capable of producing 150,000 lbs of steam per hour at 915 psig and 905°F. It will feed Units 1, 2, and 3 via the topping turbine and will be cross-connected to Unit 5 for redundancy. Normally, it will produce about 110,000 lb/hr when the MSW steam generator is in production. The MSW steam generator will feed 40,000 lb/hr of 600 psig, 700°F steam directly to Units 1, 2, and 3 and will not be cross-connected to Unit 5. It will be an MSW-fired, inclined reciprocating grate, balanced draft, natural circulation unit with no reheat. It will have its own ID and FD fans and combustion air heaters. Turbine/Generator TG Units and Auxiliaries The MSW boiler will operate at a nominal temperature and pressure of 600 psig and 700°F and will feed directly to Units 1, 2, and 3. The possibility of partially desuperheating the topping turbine exhaust by combining it with saturated or only slightly superheated steam from the MSW boiler is also being considered. 0054c .012683 7-14 7.210 Hee Ole 7e2u) Lorelei Usha Rev: 0 Rev. Date: 02/18/83 Air Correction Equipment Precipitator Air correction equipment will be required as particulate loading must be reduced to below 0.1 gr/dscf corrected to 12% CO This will be 2: accomplished with a dedicated electrostatic precipitator which will be located to the east of the MSW boiler. Mechanical Equipment Major Pumps The MSW boiler will receive BFW from the two new 100 percent motor driven boiler feed pumps Ash Handling System Bottom ash from the MSW furnace will be quenched in a water bath, dewatered indoors, and transported to the east end of the MSW building by drag chain conveyor. From there it will be trucked to a landfill for disposal. The MSW fly ash will be combined with either the coal ash or the MSW bottom ash. During extremely cold periods, transport and unloading of damp ash will be complicated by freezing. 0054c.012683 glo Rev: 0 Rev. Date: 02/18/83 7.211.3 Fire Protection System Tele Hers The MSW building will be protected by a zone type sprinkler system. In addition, fire water monitors will be provided in the MSW pit area. Piping System The comments in Scenario 2, Section 5.212, regarding power and auxiliary power apply. Utilities, BFW, and steam piping will be required between the MSW-fired boiler building and the coal-fired boiler building. Instrumentation and Controls Control systems for the boiler and auxiliary systems will be the latest type of electro-pneumatic controls. With the proposed system, the MSW-fired boiler would be flow controlled and the coal-fired boiler would be pressure controlled. This control scheme will provide good overall system stability. 0054c .012683 7-16 PRIMARY SCREEN & SHREDDER MSW CLASSIFIER 182 TPD 102.3 TPD FERROUS METALS RDF MAGNETICALLY NONCOMBUSTIBLES UNIT REMOVED (DIRT, GLASS, ETC. ) 9.1 TED 70.6 TPD SECONDARY CLASSIFIER SHREDDER HEAVY'S TO LANDFILL 4 TPD ee ee eee _| STEAM | 150,000 PPH 850 PSIG C) 950° F RDF FLUFFER & PNEUMATIC BOILER CONVEYER ROF STORAGE COAL 11.6 TPH | | BFW | POWER PLANT | FIGURE 7.1 RDF PROCESS FLOW DIAGRAM SCENARIO 4 KNUDSEN 1 CLieat peviee OUTFALL STRUCTURE Tirrias Flees Coal converoe WATER WELL water WELL Gas TURBINE WHIT 66 [| ase sue rover Plant WAREWOUSE & Canuce FUTURE EXPANSION OF WATER TREATNEST PART SUITCHCEAR CHENA FEASIBILITY STUDY CONCEPTUAL EQUIPMENT LAYOUT SCENARIO 4 BETWEEN EL.427'-10° & 455°-0* 975 K.-W. 110,000 Ib/hr 600 psig» 700°F 850 psig 950° F BFW ATTEMPERATING j a DESUPERHEATER ,-— STACK GAS: 84,200 sefa PARTICULATE: «1 gr/dsef 279 ppm S09 377 ppm NOy COAL-FIRED BOILER #7-4 AIR 32,861 FD FAN sefn 80 Hp COAL 10.6 tph 0.6 tph ASH 40,000 Ib/hr 301° F DEAERATOR 600 ee. rao’r H.P. HEATER Sipats FD FAN AIR 25,873 scfm 60 Hp PRECIPITATOR BOILER FEED PUMP PIT I TO ATTEN DESUPE 1.9 tph ASH PRY BOILER FEED MSW-FIRED BOILER #7-4 PUMP 300 Hp each URN FROM $ TO DSHS 30 psig 350°F CHENA FEASIBILITY STUDY SCENARIO 4 PROCESS FLOW DIAGRAM DRAWING NO- 610-003 00209 8.000 8.100 8.110 8.111 Rev: 0 Rev. Date: 02/18/83 ENVIRONMENTAL AND LICENSING CONSIDERATIONS Licensing and Regulatory Framework Licensing modifications to the Chena Generating Station involve a broad range of federal, state, and local requirements. The primary objective of the Phase 1 regulatory review is to prepare a summary of those licensing requirements that may impact the project. In Phase 2, the specific licenses, permits and approvals required for the chosen scenario will be identified along with a schedule and methodology for obtaining agency approvals. A summary list of potential licensing requirements and the associated implementing agencies is included in Table 8.1. Summary of Requirements/Constraints Federal Requirements Federal regulatory requirements impacting this project range from air quality, water quality, and solid waste limitations to navigable water construction and aviation guidelines. Air Qualit. 0103c.022483 Saoel Rev: 0 Rev. Date: 02/18/83 One of the most important considerations for the Chena Feasibility Study is the Clean Air Act (42 USC 7401 et seq.). This statute requires each state to adopt and submit a State Implementation Plan (SIP) to the U.S. EPA Administrator which provides for implemen- tation, maintenance, and enforcement of national primary and secondary ambient air quality standards. In Part 50 of Title 40, Code of Federal Regulations (CFR), the EPA establishes National Ambient Air Quality Standards (NAAQS) for a number of air pollutants. Those parts of the country where ambient air quality monitoring data exceeds these standards are designated as nonattainment areas for the specific pollutant. The remaining areas are designated as attainment or unclassifiable depending on the availability of monitoring data. One of the key objectives of the SIP is to improve air quality conditions in nonattainment areas while maintaining the clean air status of attainment areas through the control of existing and new air pollution sources. An important portion of the SIP process deals with siting new stationary air pollution sources and the Prevention of Significant Deterioration (PSD) of ambient air quality. Until a state's review program is approved by EPA, the PSD review process is conducted by the regional EPA office. Alaska has received approval of its review program for certain types of new sources. However, new major stationary sources and major modifications of fossil-fuel boilers and steam electric power plants were not included in the 0103c .022483 Ss 2 Rev: 0 Rev. Date: 02/18/83 approved review program and will, therefore, be subjected to a PSD review by the regional EPA office in Seattle, Washington. As defined by the Clean Air Act (CAA), a major source is (1) any source type belonging to a list of 28 source categories which emits or has the potential to emit 100 tons per year (tpy) or more of any pollutant regulated under the CAA, or (2) any other source type which emits or has potential to emit such pollutants in amounts equal to or greater than 250 tpy. Since fossil fuel-fired steam electric plants of more than 250 million Btu/hr heat input are included in the list of 28 source categories, they become subject to PSD regulation when potential emissions of any regulated pollutant equal or exceed 100 tpy. Certain major modifications of stationary sources are also subject to PSD review. These modifications are defined as -any physical change or change in the method of operation of a major stationary source that would result in a significant net emissions increase of any pollutant subject to regulation under the Act. ae Significant net emission rates have been developed individually for each regulated pollutant. The significant quantities for pollutants that are of interest to this project include: 0103c.022483 Sees Rev: 0 Rev. Date: 02/18/83 Carbon Monoxide 100 ton/yr Nitrogen Oxides 40 ton/yr Sulfur Dioxide 40 ton/yr Particulate Matter 25 ton/yr Any power plant modification that causes emission increases greater than these significant quantities will be subject to PSD review for that pollutant. Predicted emission rates for the three refurbishing/ replacement Scenarios are listed in Table 8.2 along with an estimate of current emission from Units 1,2 and 3. Maximum predicted emission rates for the three Scenarios are based on full load operation 100% of the year while average rates are based on historical operating conditions of 57% of the year. This method establishes the maximum as well as the normal potential to emit. Current emission rates for Units 1, 2 and 3 are based on facility operation at 80% of design capacity for less than 57% of the year as evidenced by plant operating records during the previous two years. When current emission rates are compared to the average predicted rates, Scenario 3 is the only option subject to PSD review since the average net emissions change exceeds the "significant emission rate" established in 40 CFR 52.21(b)(23). However, the maximum net emissions change resulting from full year operation makes all three Scenarios subject to PSD review. 0103c.022483 8-4 Rev: 0 Rev. Date: _ 02/18/83 As part of the PSD process, the applicant must prepare several analyses addressing each pollutant that is subject to PSD review. First, a Best Available Control Technology (BACT) analysis must be completed to determine the control strategy required for the source undergoing PSD review. Second, an air quality analysis is required to demonstrate that neither a NAAQS nor an allowable PSD increment (i.e., allowable pollutant increase) will be violated as a result of emissions from the proposed major modification. Third, an additional-impacts analysis is required to determine the air pollution impacts on soils, vegetation and visibility caused by emissions from the modification. Results from this analysis will assist in BACT decision making and informing the general public of potential air quality-related impacts. If available baseline air quality data is not adequate, the applicant may be required to monitor air quality in the project area for a full year before the air quality analysis can be contemplated. This additional requirement may extend the PSD review process to as much as 18 or 24 months. If predicted air quality impacts are below certain significance thresholds, EPA may grant an air quality monitoring exemption pursuant to 40 CFR 52.21 (i)(8). An air quality analysis of emissions from the three refurbishing/replacement scenarios indicates that the air quality impacts will be below the designated thresholds. Based on this analysis and associated modeling results, EPA granted an air quality monitoring exemption for the Chena Project on January 20, 1983. 0103c.022483 Seno) Rev: 0 Rev. Date: 02/18/83 Violation of the NAAQS for CO resulted in the EPA designation of a nonattainment areas for the city of Fairbanks. Mobile sources of CO are the major contributors in the CO nonattainment area. The location of a new major stationary source or major modification in an area which is designated nonattainment for one or more pollutants presents special problems for an applicant and requires completion of a "new source review". To ensure that the new source does not exacerbate the degraded air quality conditions in a nonattainment area, several stringent conditions set forth in 40 CFR 51, Appendix S, must be met. These conditions are designed to ensure that the new source's emissions will be controlled to the greatest degree possible (Lowest Achievable Emission Rate or LAER); that more than equivalent offsetting emission reductions (emission offsets) will be obtained from existing sources; and that there will be progress toward achievement of the NAAQS. The actual emission rate allowed for any new source is affected by a number of regulatory processes and requirements. Fossil fuel-fired steam electric plants of more than 250 million Btu/hr heat input must comply with applicable New Source Performance Standards (NSPS) found in 40 CFR 60. EPA has not promulgated NSPS for fossil fuel-fired boilers of less than 250 million Btu/hr heat input. The specific emission limitations that are applicable to each of the Scenarios is discussed in Section 8.310. 0103c.022483 8 - 6 Rev: 0 Rev. Date: _ 02/18/83 The PSD review process may further restrict the allowable emissions through the application of available PSD increments. Depending on the modeling results submitted with the PSD permit application, a portion of these increments may be consumed by new sources. However, the allowable emissions could be restricted to levels less than NSPS if the existing PSD increment is too small or already allocated to previous new sources. Emission levels become increasingly stringent if the proposed site is classified as nonattainment for any pollutants. The resulting emission levels allowed from any new source are a product of the PSD and new source review processes as well as applicable NSPS. Water Quality Water quality considerations in the Clean Water Act (33 USC 1241 et seq.) also provide a major element in the statutory and regulatory framework. The Clean Water Act (CWA) was enacted to restore and maintain the integrity of the nation's waters. As part of this effort, the Clean Water Act authorizes the development and enforcement of water quality related effluent limitations, water quality standards, toxic and pre-treatment effluent standards, and the National Pollutant Discharge Elimination System (NPDES) permit program. Wastewater discharges to surface waters are regulated under Section 402 of the CWA by means of NPDES permits. Since authority for implementing this program has not been delegated to the state of 0103c .022483 8-7 Rev: 0 Rev. Date: 02/18/83 Alaska, the regulation of industrial wastewater discharges is conducted by the regional EPA office in Seattle, Washington. Specific effluent limitations for steam-electric power plants were revised on November 19, 1982 at 40 CFR 423. This regulation restricts the concentration of selected pollutants in all wastewater discharged from steam-electric power plants. A summary of the effluent limitations that are applicable to the Chena Plant wastewater discharges is provided in Section 8.320. EPA uses these effluent guidelines as a major criteria in establishing the discharge restrictions for a NPDES permit. Several other sections of the CWA may also impact the Chena Feasibility Study. Section 401 requires any applicant for certain federal licenses or permits to obtain certification that any discharge into navigable waters will comply with appropriate effluent limitations and not violate applicable water quality standards. No federal license or permit (such as U.S. Army Corps of Engineers Permit discussed below) will be granted until the Section 401 certification has been issued by the state or waived following inaction by the state. Owners or operators of nontransportation-related onshore and offshore facilities engaged in activities such as storing and consuming oil and oil products which, due to their location, could reasonably be 0103c.022483 8-8 Rev: 0 Rev. Date: 02/18/83 expected to discharge oi] in harmful quantities into or upon the navigable waters of the U.S. must prepare a Spill Prevention Control and Countermeasure Plan (SPCC Plan) pursuant to Section 311. A copy of the Plan must be maintained at the facility if the facility is normally attended at least 8 hours per day or the nearest field office if the facility is not attended. This requirement does not apply to facilities where underground storage capacity is less than 42,000 gallons of oil or the storage capacity, which is not buried, is less than 3,200 gallons of oil, provided no single container has a capacity in excess of 660 gallons. The U.S. Army Corps of Engineers is responsible for implementing Section 404 of the CWA in the regulation of various types of activities in navigable waters such as dredge and fill projects. This authority has been broadly interpreted by the Corps so that regulated activities include removal of dredged material, placement of fill material and relocation of dredged material. Although certain types of dredge and fill projects are permitted by regulation, most of these activities require approval by the Corps and the issuance of a Corps Permit under Section 404. The current dredge and fill permit program is generally consolidated with individual requirements in the River and Harbor Act of 1899 (33 USC 401 et seq.). Section 10 of this statute empowers the Corps to require a permit for the construction of any structures placed in 0103c.022483 8-9 Rev: 0 Rev. Date: 02/18/83 navigable waters and for work in or affecting navigable waters such as power plant intake and discharge structures. Since the placement of any structure subject to the River and Harbor Act will generally involve some dredge and fill activities, both permit requirements are consolidated into a single Corps permit program. Unless the final conceptual design for the Chena Project involves a modification of the existing intake and discharge structures, a Corps permit will not be required. Solid Waste Federal regulation of solid waste management was enhanced through enactment of the Resource Conservation and Recovery Act of 1976 (42 USC 6901 et seq.). RCRA amended the Solid Waste Disposal Act to promote resource recovery and other resource conservation measures as waste management alternatives. To achieve these goals, RCRA encourages the development of comprehensive state and local solid waste programs through federal financial and technical assistance. Since RCRA is largely implemented at the state government level in Alaska, the applicability of solid waste management to the Chena Project is discussed further in State and Local Requirements (Section 8.112) Environmental Impacts 0103c.022483 8 - 10 Rev: 0 Rev. Date: 02/18/83 At the federal level, consideration of potential environmental impacts is established by the National Environmental Policy Act of 1969 (42 USC 4341 et seq.). This act declares a general policy to use all practicable means to conduct federal activities in a way that will promote the general welfare and that will be in harmony with the environment. One of the key provisions of Section 102 of this Act requires all agencies of the federal government to include an Environmental Impact Statement (EIS) in every recommendation or report on proposals for legislation and other major federal actions significantly affecting the quality of the human environment. Federal actions such as permit or license approvals frequently thrust a federal agency into the decision making process that evaluates the significance of their action relative to the quality of the environment. The key issue is whether the proposed agency action constitutes a major federal action that significantly affects the quality of the human environment. If the action is not significant, the agency may choose to issue a "Finding of No Significant Impact" in lieu of an EIS. Other options include endorsing an EIS prepared by another federal agency or a state agency on the same project. For the Chena Project, the federal actions that may require an EIS include the NPDES permit and the Corps permit, if required. Navigable Airspace 0103c.022483 Sle 8.112 Rev: 0 Rev. Date: 02/18/83 The Federal Aviation Administration (FAA) has established standards in 14 CFR 77 for determining obstructions in navigable airspace and has set forth requirements for notice to the FAA Administrator of certain proposed construction or alteration activities. These requirements were promulgated under the authority of the Federal Aviation Act (49 USC 1101 et seq.) and are brought into play when structures such as new buildings or chimneys exceed certain elevations above ground level. A notice of proposed construction or alteration is required for any structure more than 200 ft in height above the ground level and any structure of greater height than certain imaginary surfaces extending outward and upward from airports and heliports. Although a notice of construction is required by the FAA, there is no regulatory authority to prohibit such obstructions unless they exceed 2000 ft. For those structures that exceed the FAA standards, the FAA will recommend specific obstruction marking and lighting to minimize the potential for conflict with air trafic. The 180 ft. chimney proposed for Scenarios 2 and 3 will not penetrate the FAA imaginary surface. However, a notice of construction should be filed for Scenarios 2 and 3 as a courtesy to the FAA. State and Local Requirements 0103c.022483 BaoFl2 Rev: 0 Rev. Date: 02/18/83 The statutory and regulatory requirements for power plant construction in the State of Alaska involve numerous licenses, permits and approvals and make up the majority of items included in the licensing framework. These state regulations include several permits and approvals that are similar or parallel with federal requirements. Those areas that are most important to the Chena Project include air quality, water quality, solid waste and water rights. Local requirements are limited to building permits and zoning compliance for the city of Fairbanks and the Fairbanks North Star Borough. Air Qualit Air quality regulation is one of several responsibilities delegated to the Alaska Department of Environmental Conservation (ADEC) pursuant to Alaska Statutes (AS 46.03). This statute provides ADEC with the authority to establish air pollution control regulations that are necessary to prevent, abate or control air pollution in the state and to protect human health and welfare and natural resources of the state. In a fashion similar to the federal approach, ADEC has established ambient air quality standards and designated certain areas that fail to meet the standards as nonattainment areas. According to ADEC's Air Quality Control Regulations in the Alaska Administrative Code (18 AAC 50.201), the Fairbanks~area does not meet the air quality standard for carbon monoxide and therefore has been designated as a nonattainment area. 0103c.022483 8513 Rev: 0 Rev. Date: 02/18/83 One of ADEC's key enforcement tools is the Air Quality Control (AQC) Permit to Operate. This permit is required for the construction, modification, reconstruction or operation of most air pollution sources. The Air Quality Control Regulations were revised in November 1982 to include many of the same provisions contained in EPA's PSD permit regulations. As a result, the AQC Permit to Operate process is very similar to the PSD process discussed in the Federal Requirements Section above. Depending on the extent of modifications contemplated in Scenario 1, and AQC Permit to Operate may not be required. An AQC Permit to Operate will be required for Scenarios 2, 3 and 4 prior to construction. Water Quality ADEC is also responsible for setting water quality standards and implementing several permit or certification programs to maintain the quality of Alaska's surface waters. Water quality standards and designated use classifications have been established for all waters in the state (18 AAC 70). These standards set criteria which limit man-induced pollution to protect the designated water uses. In addition to planning functions, ADEC uses these standards for establishing effluent restrictions in wastewater discharge permits and for enforcement actions against operations adversely affecting water quality. The water quality standards are reviewed and revised at least once every three years to reflect new information on 0103c.022483 8 - 14 Rev: 0 Rev. Date: 02/18/83 criteria limitations and to accurately identify existing or potential water uses. Wastewater discharges to surface water and sanitary sewer systems require several approvals from ADEC. For those projects that require federal licenses or permits and will result in the discharge of wastewater into navigable waters, the applicant must certify that the proposed activity will comply with the requirements of Section 401 of the Clean Water Act for the protection of water quality during construction and operation of the project. Based on the applicants' satisfactory submittal, ADEC will issue a "Certificate of Reasonable Assurance" (Water Quality Certification) that also satisfies the requirements of Section 401 of the Clean Water Act. The discharge of wastewater into a publicly operated sewerage system or into waters of the State requires a wastewater disposal permit from ADEC. This permitting process is designed to prevent water pollution due to unsafe wastewater disposal systems and practices. The applicable water quality standards for the designated receiving water are the primary guides in setting effluent limitations in the permit. If the EPA issues an NPDES permit for a wastewater discharge to surface waters, however, the ADEC waives the procedural . requirements for issuing a state permit and adopts the NPDES permit as the State permit. The applicability of the ADEC wastewater disposal permit to the Chena Project is discussed in Section 8.320. 0103c.022483 SrealS Rev: 0 Rev. Date: 02/18/83 Prior to construction and operation of certain wastewater treatment works, a "Plan Review" of the system is required by ADEC to ensure compliance with Alaska's Water Quality Standards. This plan review requirement is also applicable to any construction, alteration or modification of industrial wastewater treatment systems at facilities such as power plants. To gain approval, the applicant must provide detailed engineering reports, plans and specifications that demonstrate the system's ability to ensure compliance with water quality standards. In most cases, NPDES permit and a Certificate of Reasonable Assurance as well as a Wastewater Disposal Permit will be required prior to beginning operation of the wastewater disposal facility. This Plan Review will only be required if wastewater from one of the Scenarios requires treatment prior to discharge. A Water Rights Permit is required to appropriate waters of the state. This program is administered by the Alaska Department of Natural Resources (ADNR) to reserve the waters of Alaska for beneficial uses which comply with standards for the protection of public health and safety and preservation of anadromous fish. Applications for a water right must include information on the location of the water source, the means of appropriation, the quantity to be appropriated and the place the water will be used. _A certificate of appropriation which secures the holder's rights to the water will be issued when the applicant notifies the ADNR that withdrawal and use of water have begun. Since additional surface 0103c.022483 8 - 16 Rev: 0 Rev. Date: 02/18/83 water withdrawals are not anticipated for any of the Scenarios, a water rights permit will only be required for the new well contemplated in Scenarios 1, 2 and 3. Solid Waste Municipal solid waste incinerators and other solid waste disposal facilities are required to obtain a Solid Waste Disposal Permit prior to establishing, modifying or operating the facility. This permit program is administered by ADEC and requires the submittal of detailed plans and specifications for the proposed facility, certification of compliance with local ordinances and zoning requirements and a report detailing the proposed method of operation. In the case of processing facilities such as incinerators, the application must also describe the use and distribution of processed materials and the method of residue disposal. Solid Waste Disposal Permits are issued by ADEC for a period not to exceed 5 years. Since a portion of the fuel supplied to Scenario 4 includes municipal solid waste, a solid waste disposal permit would be required to implement this alternative. Local Local requirements are centered around building permits and compliance with zoning restrictions. In Fairbanks, Individual 0103c.022483 Shey, 8.120 Rev: 0 Rev. Date: 02/18/83 permits are required for mechanical, electrical, plumbing and building aspects of a project. Upon presentation and review of acceptable plans, the Fairbanks Building Department will issue the required permits. New construction within Fairbanks must also comply with the comprehensive master plan and applicable zoning restrictions. A conditional use permit from the Fairbanks North Star Borough will be required prior to any plant expansion on the existing property. These local requirements apply uniformly to all Scenarios. Permitting Coordination One of the key elements in the state regulatory framework is the Environmental Coordination Procedures Act (AS 46.35). This statute creates an optional licensing procedure for applicants who must obtain one or more federal, state or local permits licenses and approvals. With this optional process, permit applicants receive a greater certainty on permit requirements and members of the public receive a better opportunity to present their views on proposed uses of the State natural resources and related environmental concerns. The process also increases the coordination between federal, state and local agencies in their administration of programs affecting the state's air, land and water resources. . Based on this statute, ADEC has established the Alaska Permit Information Center to aid in coordinating the permitting process. Some of the services provided by this information center include: 0103c.022483 Bro 18 Rev: 0 Rev. Date: 02/18/83 oO Permit Information O Permit Lists 0 Master Application Process 0 Pre-application Conferences For those applicants that have questions regarding a specific project, the Permit Center can identify those regulatory agencies that have jurisdiction over the proposed project. A list of potential licenses, permits and approvals can also be prepared by the Permit Center. One of the Center's most important functions involves implementing the Master Application Process. This program begins with the preparation and submittal of the Master Application Form to the appropriate regional office of the Alaska Permit Information Center. This approach provides for a simultaneous review of a project by all state agencies and the applicable local government. Any requirements for public notices and hearings are also consolidated, thus eliminating duplicate and inconsistent requirements for public participation. Upon request, the Permit Center also arranges for pre-application _ conferences between the applicant and appropriate federal, state and local regulatory agencies. This meeting provides a forum for the potential applicant to present a proposed project to applicable 0103c.022483 8719 8.130 Rev: 0 Rev. Date: 02/18/83 regulatory agencies prior to filling out any applications. At the same time, the agencies can describe the requirements necessary to gain agency approval for the project. Since the pre-application conference is not a judgemental meeting, the applicant can become familiar with each regulatory agency and discuss potential problems at an early stage without making any major commitments or decisions regarding ultimate project direction. In Phase 2 of this study, M-K will submit a preliminary list of permits and approvals to the Fairbanks office of the Permit Information Center for their review. This process will verify the preliminary permit list and ensure that al] state and local requirements are identified for the best refurbishing/replacement scenario. The results of the center's analysis will be combined with a final permit list and schedule to characterize the licensing requirements of the scenario chosen for conceptual design in Phase 2. Permit List/Licensing Schedule The range of licenses, permits and approvals that are important to the Chena Feasibility Study are summarized in Table 8.1. This table also identifies the applicable regulatory authority, statutory L authority and licensing constraints associated with each item. Since the construction activities contemplated in each scenario are 0103c.022483 Siac Rev: 0 Rev. Date: 02/18/83 slightly different, not all of the permits identified in the regulatory framework are applicable to all scenarios. Table 8.3 provides a preliminary assessment of the licensing requirements for each of the four scenarios. A generic schedule for obtaining the required permits and approvals is illustrated in Table 8.4. The relative timeframes will vary somewhat depending on the scenario selected for conceptual design. A detailed licensing schedule will be prepared for the chosen scenario in Phase 2. 0103c.022483 im ail 8.200 8.210 ENVIRONMENTAL OVERVIEW This section provides an overview of the Fairbanks area environmental features including topography, water and air resources, biological environment, land use, and socio-economics. Background information for the overview was obtained from a literature search, selected agency contacts and site visits to the Fairbanks area. A list of environmental criteria is used to identify important environmental issues for each scenario. Existing Environment The City of Fairbanks is located at the confluence of the Chena and Tanana Rivers, 100 miles south of the Arctic Circle. Over the years, Fairbanks has developed into the interior's economic and transportation center as well as its second largest city. 0103c.022483 Sree? Geology/Topography The City of Fairbanks lies in a hilly and mountainous region between the Yukon and Tanana Rivers known as the Yukon-Tanana upland. Mountains in this area are characterized by smooth topped ridges with gentle side slopes and occasional rugged peaks. All drainage from this upland area eventually reaches the Yukon River via the Tanana and various tributaries. The Fairbanks area is bounded on the north by the Tintuna Fault Zone and on the south by the Denali Fault System which parallels the Tanana River Valley. Recent vertical movements along the Denali Fault System are evidenced by offset topographic features and the presence of local cliffs. The lowland regions are underlain with areas of discontinuous permafrost. Permafrost or perennially frozen ground in North America is intimately related to it's glacial or post-glacial history. The amount of ice found in permafrost varies directly with the nature of the material in which it forms, the availability of moisture and the rate of freezing. Unsaturated permafrost is referred to as dry-permafrost and usually has less than 10% of it's total volume occupied by ice. Supersaturated permafrost or massive ice has an ice content by volume of greater than 15% while saturated permafrost occupies the range 0103c.022483 Bases between the two. The volume of ice in permafrost is especially crucial when considering problems of bearing strength and slope stability, particularly upon thawing. In the Fairbanks area saturated and supersaturated permafrost generally occurs in poorly drained areas of fine grained sediments or in areas where ground cover consists of material with a high organic content. Water Resources Within the Fairbanks area, water quality is characteristic of the Tanana Subarea (Balding G.O. 1976). This region includes the drainages of the Chisana River and the Nenana River as well as the Chena and Tanana Rivers. The Chena River is one of the major tributaries of the Tanana and is the surface water of primary interest to this study. The Chena River has an estimated drainage basin in excess of 2,000 square miles. The river's flood magnitude varies from an average maximum flow of 8,000 CFS to over 50,000 CFS for a fifty year event. Water quality in the Chena River is generally good with seasonal variations of certain parameters. The concentration ranges shown in Table 8.5 are attributed to winter low flow periods that contrast with substantial dilution during summer peak flows. These values do not exceed the levels set by the Environmental Protection Agency (EPA) for industrial water use. (Personal Contact with Joyce Beelman ADEC). 0103c.022483 8 - 24 In the 1960's, substantial amounts of partially treated and untreated sanitary sewage were discharged in the Chena River from several sewage treatment plants and private residences. The high levels of oxygen demanding material caused a decrease in dissolved oxygen (D.0.) concentrations and resulted in violations of the Alaska water quality standard for D.O0. Fecal coliform counts in the river also exceeded water quality standards. With completion of the regional sewage treatment plant in 1976, most of the sewage discharges to the Chena River were eliminated resulting in a significant increase in D.O. levels and reductions in fecal coliform concentrations. Most groundwater sources within the Fairbanks area require some form of water treatment to make the water potable (Balding G.0O., 1976). Water from these wells contain higher concentrations of iron and manganese then those levels recommended for drinking water in EPA's Interim Primary Drinking Water Standards. Methane and hydrogen sulfides have been noted in some wells indicating an anaerobic environment in which oxygen has been consumed by decomposing organic matter. The most desirable groundwater for drinking purposes is found in sand and gravel deposits that have small amounts of detritus and are close to a source of recharge by oxygenated surface water (Balding G.O. 1976). The availability of groundwater varies widely across the region. In some areas, wells produce less than 50 gallons per minute while other wells exceed 1000 gallons per minute. Groundwater is used 0103c 022483 8 - 25 predominately for agricultural or industrial purposes. Air Quality Except during unique wintertime meterological events, air quality in the Fairbanks area is generally good. Data collected since 1969 and summarized in the Fairbanks North Star Borough Air Quality Attainment Plan (Environmental Services Department, 1979) indicates that carbon monoxide levels during the winter months continue to violate NAAQS. The principal sources of CO emissions include motor vehicle operations, aircraft operations, and business and residential heating fuel consumption (Environmental Services Division, 1982). These violations result from the unique climatology of the region coupled with the effect of the severe wintertime temperatures on automotive emissions. Meteorological data collected by the National Weather Service at Fairbanks International Airport documents a prevailing wind direction from the North with a secondary maximum from the southwest. During the winter months, temperature inversions are created in Fairbanks when cooler air is trapped near the ground level by warmer air overhead. Because the majority of inversions are surface based, there is no mixing layer available for vertical dispersion of pollutants. This condition tends to trap the pollutants at a certain level in the inversion layer leading to a build up of near ground level CO concentrations. Limited wind movement in the winter 0103c.022483 8 - 26 combines with the inversions to create a stagnated air mass. Recent data published by the Fairbanks North Star Borough indicates a steady decrease in the carbon monoxide concentrations recorded in Fairbanks since 1973 (Environmental Services Department, 1982). Another air quality problem in Fairbanks involves the formation of ice fog during periods of very low temperatures. As described in the Air Quality Attainment Plan, ice fog is formed by the release of supersaturated water vapor into the ambient air during periods of severe cold. This vapor is cooled by the atmosphere and transformed into ice crystal droplets. During ice fog episodes, visibility in the city is substantially reduced. Many combustion sources such as automobiles, powerplants, and home space heating equipment, emit both the water vapor and the condensation nuclei required for ice fog formation. As new combustion sources are installed or operated in the City, the potential for severe ice fog conditions are increased. The Fairbanks North Star Borough has measured visibility during ice fog conditions using a MRI Fog Visionmeter since the mid 1970's. Results from these studies indicate that visibility reduction from ice fog formation is becoming worse in the Fairbanks area. 0103c .022483 Sie27) Biological Environment Both the Chena and Tanana Rivers provide commercially and recreationally important fishery resources. Commercial harvesting of salmon is permitted down stream of the Tanana's confluence with the Chena River. Commercially valuable species found in the Tanana include king salmon, coho salmon and chum salmon. The king and coho salmon are important to Alaska's food processing industry while chum salmon are generally used for sled dog food. Harvesting of chum salmon has expanded with the increase in popularity of recreational sled dog teams and the steady improvement of subsistence roe sales (Anderson and Geigor 1978). The Chena River serves as the primary sport fishery waters in the Fairbanks area. In addition to the salmonids, the Chena contains a healthy population of arctic grayling and burbot and is the most accessible river near Fairbanks. (Corps of Engineers 1980). A major overwintering area for fish in the Tanana River is located at the confluence of the Chena River. Species commonly found there include arctic grayling, round whitefish, longnose suckers, humpback whitefish, burbot and northern pike. Wildlife near Fairbanks include beaver, coyote, wolf, red fox, mink, muskrat, porcupine, snowshoe hare, voles, lemmings shrews and mice. Big game animals such as moose and black bear are found throughout 0103c.022483 Bice28 the surrounding area. Generally, moose are found outside the city proper, but occasionally do enter town. Eighty-five species of birds use this area as a summer residence with an additional 25 species using it as a migratory stop off. Twenty-seven species remain throughout the year including the ruffed grouse, spruce grouse, chickadee, ptarmigan, gray jays and ravens. Vegetation in the Fairbanks area is composed primarily of forest types. White spruce, quaking aspen, paper birch and balsam populous are the dominate species. On imperfectly drained soils of the floodplain, scrubby white spruce, black spruce, paper birch and willow generally are found in dense stands. Poorly drained sites are dominated by sparce stands of black spruce in association with thick mats of moss. Land Use The evaluation of land use compatibility considers the general character of the area, adjacent recreational and cultural resources and the effects of distraction or disruption of current activities. The preservation of existing and projected land use is the primary concern. The general characteristics of land use within the Fairbanks North Star Borough are summarized in Table 8.6 Less than 20% of the total land area is currently developed. Public and 0103c.022483 Brae9 semi-public agricultural, highways and streets, and residential land uses are the primary components of developed land in Fairbanks. The Fairbanks Metropolitan Area Transportation Study provides a forecast for expected further development. That forecast predicts three main areas of growth: 1) transportation, communication and utilities, 2) residential use and 3) commercial use. These areas are expected to show 99.3%, 83.4% and 67.0% growth, respectfully, over the next 10 to 20 years. Socio-Economic The economic climate in Fairbanks has been based on a boom-bust philosophy for the last 80 years. The boom-bust cycles revolve around the rapid population fluctuations associated with large scale development such as short term mining and construction projects. Table 8.7 illustrates the major periods of rising and falling economic conditions. The current economic climate in Fairbanks is similar to the rest of the country in that very little growth is taking place. At the present time, Fairbanks is recovering from the pipeline construction and is trying to develop industrial expansion with steady and controlled growth. 0103c .022483 8 - 30 8.220 Evaluation Criteria The broad range of environmental criteria considered for the Chena Feasibility Study are listed in Table 8.8. Those criteria of greatest interest to this project include: 0 air quality 0 water quality 0 fish and wildlife resources 0 socio-economic 0 transportation 0 visual 0 historical/archaeological/cultural resources oO land use. The relative importance of these key criteria is discussed below for each scenario. 8.230 Relative Impact of Each Scenario Since the impacts on air and water quality are the most likely "major environmental issues" for the project, they are discussed in detail for each scenario in Sections 8.310 and 8.320. 0103c.022483 8 - 31 Scenario 1 Under this refurbishing scenario, all required construction would take place within the existing structures and no additional land resources would be required. All activities would be compatible with the existing and future land use designation of the site. The rehabilitation of the plant would offer employment of a number of people during construction while offering extended employment to the present work force. The size of the construction activities and resulting increased life of the plant would not adversely effect the socio-economic conditions within the Fairbanks area. No additional impacts to the fish and wildlife resources will be expected. There are no threatened or endangered plants or animals listed or proposed for listing by the Department of Interior under the Endangered Species Act of 1973 found in the Fairbanks area (USFWS Letter Report 1979). The project as proposed under this scenario would not affect traffic patterns or volume. The established mass transit systems, bus lines, airlines, and railroad systems would not be significantly affected by the project. 0103c .022483 Breese There are no known cultural resources in the area that would be affected by the proposed project. The probability of sites being found at this location is extremely low. Although a new chimney and air pollution control equipment would change the existing skyline of the site, the project would not significantly impact any visual resources within the Fairbanks area. If the minimal refurbishing option is selected, this additional chimney and equipment will not be installed. Scenario 2 Under this replacement scenario, the new boiler and building would be located on land designated for this type of construction. As such, the project would be compatible with the existing land use and any future land use designated for the adjacent area. Construction of a new boiler would increase employment at the plant during construction and, if the Chena 1, 2 and 3 boilers were not retired, keep a higher number of individuals employed over the life of the plant. Plant construction would tend to stimulate the local economy by adding a large scale construction project. The increased consumption of coal, while not increasing production at the mine, would tend to stabilize production level while showing a small growth in the use of coal. The expansion of the plant facilities would have 0103c.022483 Sioes3 a positive effect on the socio-economic conditions within the Fairbanks area. No additional impacts to the fish and wildlife resources within the Fairbanks area are expected from plant expansion. There are no threatened or endangered species of plants or animals listed or proposed for listing by the Department of Interior under the Endangered Species Act of 1973 found in the Fairbanks area (USFWS Letter Report 1979). The existing mass transit services such as bus lines, and airlines services would be unaffected by the project. Railroad services would see a modest gain as would the trucking service by increased shipment of material to Fairbanks. Overall the transportation services would not be adversely impacted by the project. There are no known cultural resources in the area that would be affected by the proposed project. The probability of sites being found as a result of the project is extremely low. The project would change the existing skyline of the plant by adding a new chimney and building that are slightly higher than the existing structures. However, these additions will not significantly affect the visual resources of the Fairbanks area. 0103c.022483 8 - 34 Scenario 3 Under this replacement scenario, electrical and district heating output will be increased. The new boiler would be constructed on land designated for this type of construction while expansion of the district hot water heating system would require the use of additional land within established utility corridors. As such, the project would be compatible with the existing and future land use designation for the area. Construction of a new boiler would temporarily increase employment at the plant. If Units 1, 2 and 3 are not retired, the number of individuals permanently employed at the plant would be increased. The expansion of the plant facilities coupled with expansion of the district heating system would tend to stimulate the local economy and have a positive effect on the socio-economic conditions in the Fairbanks area. No additional impacts to the fish and wildlife resources within the Fairbanks area will be expected. There are no threatened or endangered species of plants or animals listed or proposed for listing by the Department of Interior under the Endangered Species Act of 1973 found in the Fairbanks area (USFWS Letter Report 1979). 0103c.022483 Ey sk The existing mass transit services such as bus lines and airlines would not be affected by the project. Railroad and trucking services would see an increased demand for their services because of the increase in materials shipped to Fairbanks. Local traffic would be disrupted by the expansion of the district heating system. The disruption would be of a localized nature during the construction season. Overall the transportation services would not be adversely impacted by the project. There are no known cultural resources on the site. The probability of encountering a significant historical or archaeological site during the expansion of the district heating system is extremely low. The project would change the existing skyline of the plant by adding a new chimney and building that are slightly higher than existing structures. However, these additions will not significantly affect the visual resources of the Fairbanks area. Summary Based on the analysis of these evaluation criteria, all three scenarios provide several benefits for the Fairbanks area and present few if any detriments. Scenario 1 followed closely by Scenario 2 would have the least effect on Fairbanks, either short or long term. 0103c .022483 Sia SO The temporary inconvenience caused by construction at the site and along the district steam heating system in Scenario 3 are the principal detriments for the project. However, these short term deficits are offset by the stimulation to the local economy from a large scale construction project. Additionally, Scenario 3 could provide long term increased employment in the area and lower district heating costs. 0103c .022483 8 - 37 8.300 8.310 Rev: 0 Rev. Date: 02/18/83 MAJOR ENVIRONMENTAL ISSUES The major environmental issues affecting the Chena Project include air quality and water quality concerns. This section evaluates the air and water quality aspects of the project. Air Quality Existing Conditions Regardless of the refurbishing/replacement Scenario selected for implementation, the Chena power plant will continue to be a source of airborne sulfur dioxide, particulate, nitrogen oxides and carbon monoxide. The two pollutants for which extensive data exist are carbon monoxide and total suspended particulates. The Fairbanks North Star Borough has collected data for these two pollutants at various locations in the Fairbanks area since the early 1970's. Recorded concentrations of carbon monoxide and particulates exceed the national and state ambient air quality standards listed in Table 8.9. As a result, EPA and the State of Alaska have designated the Fairbanks area as non-attainment for CO. Since the major sources of particulates are agricultural and natural in origin rather than urban related, this area has not been designated as non-attainment for particulates. 0113c.022483 8 - 38 Rev: 0 Rev. Date: 02/18/83 A report prepared for Fairbanks North Star Borough (Sierra Research 1982) states that carbon monoxide has been monitored at various locations in the downtown area since 1972. Trend analyses for monitors at 2nd and Cushman and 4th and Lacey indicate that the frequency of concentrations greater than the ambient standard for CO has steadily decreased. For example, at 2nd and Cushman in 1972 the frequency of days with concentrations greater than the 8-hour average (10,000 ug/m?) was 70 percent compared to 41 percent in 1978. Likewise, at 4th and Lacey during the winter of 1977/1978, the frequency of CO concentrations greater than 10,000 ug/m> was 20 percent compared to 14 percent during the winter of 1981/1982. Fairbanks North Star Borough estimates that greater than 90 percent of the ambient CO in Fairbanks is due to automobile emissions (Joy, 1982). Also, the vast majority of occurrences of concentrations greater than the ambient standards are reported during the winter months, when cold engine starts increase CO emissions and light winds coupled with stable atmospheric conditions trap pollutants near the surface. The Fairbanks North Star Borough collects total suspended particulate (TSP) data at six locations in the Fairbanks area. Data for 1980 through August 1982 show 24-hour average concentrations greater than 0113c.022483 Beor39 Rev: 0 Rev. Date: 02/18/83 the primary and secondary TSP air quality standards. However, natural fugitive dust sources contribute heavily to TSP concentrations in Fairbanks. These periodic excursions of TSP concentrations are not considered to be a major problem. Continuous monitoring has not been conducted in the Fairbanks area for sulfur dioxide and nitrogen dioxide to define the ambient concentrations of these pollutants. Therefore, the attainment status of this area remains unclassified by EPA. For the purposes of this study, it is assumed that ambient concentrations of SO, and NO. are less than the applicable standards. Current Licensing Status The Chena Generating Plant operates under Air Quality Control Permit to Operate No. AQC-141C. This permit restricts the operation of Units 1,2 & 3 to 80% and Unit 5 to 90% of their respective design capacities. At the time of permit issuance in 1979, these derates were required to comply with the ADEC particulate limitation of 0.1 gr/dscf. Subsequent source testing at Unit 5 confirmed its compliance with the permit limitations. 0113c.022483 8 - 40 Rev: 0 Rev. Date: 02/18/83 Since 1979, declining coal quality at Chena Plant has limited the effectiveness of this compliance methodology. Late in 1981, the ADEC regional office in Fairbanks notified FMUS that emissions from Unit 5 were exceeding the Alaska particulates standard of 0.1 gr/dscf. The ADEC representative also indicated that emissions from Units 1,2, & 3 were only marginally in compliance at certain times. Excessive fines in the coal supply is suspected to be the primary factor causing these compliance difficulties. To alleviate this problem, FMUS intends to negotiate an action plan with ADEC that will bring the Chena Plant into compliance with Alaska standards. A critical element in this action plan is completion of the Chena Feasibility Study for Units 1,2 & 3. However, this feasibility study will not be completed before the current operating permit expires April 30, 1983. One of the key objectives of the action plan is to extend the current permit beyond the expiration date until the feasibility study is complete. In this manner, FMUS will have a sound basis to determine which compliance strategy is most appropriate for the Chena Plant. Applicable Emission Limitations The specific emission limitations that are applicable to the Chena Project vary depending on the Scenario. At the state level, fuel type and size of a stationary air pollution source are the most 0113c.022483 8 - 41 Rev: 0 Rev. Date: 02/18/83 important factors in determining applicable limitations. Since both Scenarios 1 and 2 involve coal-fired boilers of less than 250 million Btu/hr heat input, the appropriate emission limits, as defined in 18 AAC 50.050, are: PARAMETER LIMIT Opacity, % 208 Particulates, gr/dscf 0.1 Sulfur dioxide, ppm 500 Fugitive dust emissions Reasonable precautions @ For a total of more than three minutes in any one hour For Scenario 3, the emission limits are the same as above with the exception of particulate matter. Coal fired boilers rated greater than 250 million Btu/hr heat input are limited to 0.05 gr/dscf particulate matter. Federal emission limits are also based on the size and type of combustion source. EPA has promulgated New Source Performance Standards (NSPS) for a variety of stationary sources including fossil fuel-fired steam generators. Emission limitations for fossil 0113c.022483 8 - 42 Rev: 0 Rev. Date: 02/18/83 fuel-fired steam generators greater than 250 million Btu/hr heat input are published in 40 CFR 60, Subpart D. A summary of these NSPS that apply to Scenario 3 include: PARAMETER LIMIT Opacity, % 20° Particulates, 1b/million Btu 0.1° Sulfur dioxide, 1b/million Btu 1°25 Nitrogen oxides, 1b/million Btu 0.7 S Except 27% is allowed for 6 min/hr q Roughly equivalent to Alaska limit of 0.05 gr/dscf CG : i Does not include a % removal requirement Since EPA has not promulgated NSPS for fossil fuel-fired steam generators rated at less than 250 million Btu/hr, there are no NSPS that are applicable to Scenarios 1 and 2. The current emission levels of the Chena Generating Plant and the nature of the potential modifications qualify the plant modifications for regulation under the Alaska Air Quality Control Regulations (18 AAC 50) and the Clean Air Act as set forth in the Federal Code of Regulations (40 CFR Parts 51 and 52). These regulations stipulate 0113c.022483 Bs=n43) Rev: 0 Rev. Date: 02/18/83 that major new sources or modifications must apply Best Available Control Technology (BACT) and set forth pollutant - specific emission limitations. In a January 20, 1983 letter to M-K, EPA determined that Scenarios 1,2 and 3 are subject to PSD for review for S05, and NO. . Part of the PSD review process involves determining Best Available Control Technology for these pollutants. For Scenario 3, the NSPS published in 40 CFR 60, Subpart D define the minimum level of control necessary to meet BACT. Emission limits could be reduced further based on air quality modeling results and the availability of PSD increments. Since NSPS for Scenarios 1 and 2 do not exist, the baseline for judging BACT must come from a review of common practice in the industry. The State of Alaska Standards for this category of combustion equipment provide an acceptable guide in define BACT for Scenarios 1 and 2. in all cases, the final emission limitations will be determined by the PSD review process. Potential Air Quality Impacts The EPA screening models, PTMTP, and PTMAX were used to estimate potential air quality impacts for emission Scenarios 1, 2 and 3. The physical stack parameters and emission rates used in these analyses are summarized in Table 8.10. 0113c.022483 8 - 44 Rev: 0 Rev. Date: 02/18/83 Meteorological data from National Weather Service observations taken at Fairbanks International Airport were also used in the modeling. These data indicate that the prevailing wind direction is from the north, with a secondary maximum from the southwest. Northerly winds tend to occur most frequently during stable conditions, while neutral or unstable conditions tend to result in southwesterly flows. The classical diurnal stability cycle suggests that northerly winds and stable conditions would occur during late night and early morning hours. Neutral and unstable conditions generally occur during late morning and mid-afternoon hours. The Climatic Atlas of the United States (NOAA, 1979) reports that the prevailing wind direction is north for each month except June when the winds are from the southwest. This publication also reports an annual wind speed of 5 miles per hour. The PTMTP model was used in conjunction with artificially-constructed 24-hour meteorological scenarios to evaluate potential air quality impacts from modified Units 1, 2 and 3. The air quality analysis was designed to compare potential maximum concentrations with limits established by EPA to determine if the project may be exempted from EPA ambient monitoring requirements. The EPA monitoring significance 0113c.022483 8 - 45 Rev: 0 Rev. Date: 02/18/83 concentrations are all calculated for a 24-hour average. Therefore, all concentrations were calculated for an averaging time of 24-hours. Table 8.11 summarizes a typical meteorological scenario for the Fairbanks area. The wind speeds, directions and hourly stability variations were based on the Fairbanks airport data and assumed changes due to diurnal heating cycles. Results of the modeling activities are presented in Table 8.12. Maximum pollutant concentrations for all three Scenarios are well below ambient air quality standards and the concentrations considered significant by EPA to require ambient air quality monitoring. According to the PTMAX modeling results, hourly concentrations were maximized for "moderate" wind-speed, neutral or slightly stable conditions. Therefore, another 24-hour meteorological scenario was created to simulate "worst case" pollutant dispersion conditions. As shown in Table 8.13 this scenario assumes that the wind blows from one direction for every 16 of every 24 hours. The results of this analysis are illustrated in Table 8.14. Persistent wind direction and hourly dispersion assumptions designed to maximize surface concentrations were used to calculate the concentrations presented in Table 8.14. The possibility of the assumed meteorological conditions occurring is remote. Therefore, the chances of these maximum concentrations occurring are equally 0113c.022483 8 - 46 8.320 Rev: 0 Rev. Date: 02/18/83 remote. These calculated concentrations are also below the significance levels for the PSD monitoring exemption. Water Quality Existing Water Quality Conditions As noted in Section 8.210, water quality in the Chena River is generally good. With the exception of temperature, Alaska water quality standards are met at all times in the river. During summer flows, the river temperature upstream of the Chena Generating Plant approaches and occasionally exceeds the temperature standard of 15°C. Current Licensing Status At the present time, neither ADEC nor EPA have issued a wastewater discharge permit for the Chena Plant. In 1977, the Region 10 office of EPA prepared and public noticed a draft NPDES permit for the plant. The crucial effluent limitation in this draft permit required a 90% reduction of heat discharged in the plant circulating water system. Subsequent discussions with Region 10 Staff indicate that, the reduction in thermal discharge is required to maintain the water quality standard of 15°C in the Chena River. This approach is consistent with EPA's policy of using state water quality standards 0113c.022483 8 - 47 Rev: 0 Rev. Date: 02/18/83 as a primary basis for setting effluent limitations in wastewater discharge permits. Following public notice of the draft permits, FMUS notified EPA that a 316 (a) demonstration study would be completed to substantiate the acceptability of a less stringent thermal discharge limitation. Under Section 316 (a) of the Clean Water Act, an applicant may conduct a detailed study of the receiving water to demonstrate that an alternative effluent limitation will not hinder the normal propagation of indigenous species. However, FMUS has not yet completed the 316 (a) demonstration study. EPA has suspended further processing of the 1977 draft NPDES permit pending completion of the 316 (a) demonstration study. Specific Effluent Limitations Wastewater discharges from stream electric power plants must comply with the "Stream Electric Power Generating Point Source Category; Effluent Limitations Guidelines, Pretreatment Standards and New Source Performance Standards" published at 40 CFR 423. Table 8.15 summarizes those effluent limitations that are applicable to a new generating unit, such as Scenarios 2 and 3. Effluent limitations for existing units, such as Scenario 1 and Unit 5, vary slightly from the values listed in Table 8.15 in that chlorine discharge limitations 0113c.022483 8 - 48 Rev: 0 Rev. Date: 02/18/83 from once through cooling systems are more restrictive. Although there is no specific effluent limitation for thermal discharges in 40 CFR 423, EPA uses the applicable state water quality standards as a guideline in establishing discharge permit limitations. Wastewater discharge permits issued by ADEC are oriented toward maintenance of established state water quality standards. As such, there are no specific state effluent limitations for the Steam Electric Power Generating Point Source Category. Instead, ADEC adopts federal effluent limitations where appropriate and relies on a policy of water quality standard maintenance in establishing effluent limitations for state wastewater discharge permits. If an NPDES permit is issued for a wastewater discharger, ADEC generally endorses the federal permit as a fulfillment of the state's responsibilities for water pollution control under AS 46.03. Thermal Discharge - Ice Fog One of the air quality problems discussed in Section 8.210 has a partial basis in the discharge of cooling water from the Chena Plant. At temperatures below -30° to -40°C, open water areas in the Chena River below the Chena Plant may contribute to Fairbank's ice fog situation. Thermal discharges from the Chena Plant tend to maintain an open water area and encourage the transformation of 0113c.022483 8 - 49 Rev: 0 Rev. Date: — 02/18/83 river water into ice fog. Since the precise relationship between thermal discharges, open water and ice fog is not clearly understood, M-K is currently conducting a study of these three parameters in cooperation with the University of Alaska Institute of Water Resources and FMUS. The results of this study will be presented in the Phase 2 report. Anticipated Impact of Scenarios The overall water quality impact of each Scenario will be minimal. No changes in wastewater discharges to the Chena River are anticipated for Scenarios 1 and 2. Existing wastewater routing and cooling systems will be maintained without change in quality or quantity. If an optional method of discharging all wastewater, except once through cooling water, to the existing sanitary sewer is selected, the Chena Plant's current impact on the Chena River will actually be reduced. Increased powerplant wastewater flow would have a negligible effect on the sanitary wastewater treatment facility. Scenario 3 will reduce the thermal discharge to the Chena River through the use of a closed loop circulating water system. Up to. 6.1x107 Btu/hr of heat currently discharged to the river through operation of Units 1, 2 and 3 will be elimintated by the closed loop system in Scenario 3. This thermal discharge reduction will have a 0113c.022483 8 - 50 Rev: 0 Rev. Date: 02/18/83 positive impact on minimizing ice fog in the winter and maintaining water quality standards in the summer. If the wastewater discharge to the sanitary sewer option is selected for Scenario 3, water quality in the Chena River will actually be enhanced. As with Scenarios 1 and 2, increased powerplant wastewater flow is expected to have a negligible effect on the sanitary wastewater treatment facility. 0113c.022483 SiS 8.400 8.410 Rev: 0 Rev. Date: 02/18/83 ENVIRONMENTAL MANAGEMENT APPROACH A well balanced environmental management approach for this project involves air and water quality compliance considerations as well as the development of an overall licensing strategy. Since each of the replacement/refurbishing scenarios present slightly different licensing requirements, M-K has prepared an individual compliance strategy for all scenarios. These strategies are discussed below. Air Quality Compliance Strategy A summary of the air quality compliance strategies and their impact on the existing Chena Generating Station is provided in Table 8.16. Scenario 1 As discussed in Section 4.000, this scenario considers refurbishing the existing Units 1, 2 and 3 to reliably achieve either (1) the existing steam production of 40,000 lb/hr or (2) a maximum capacity approaching 50,000 lb/hr. In option 1, restoration and improvements of the furnace walls, undergrate air compartments, stoker seals, and dampers will minimize air losses and upgrade the efficiency of these 0115c.022483 CEGELYZ Rev: 0 Rev. Date: _ 02/18/83 units. Refurbishing the boilers in this manner will tend to improve combustion efficiency and reduce the fuel consumption rate. At the same time, a tighter windbox will reduce excess air requirements and also reduce the flue gas mass flow. The net result of these modifications will be improved boiler and mechanical collector efficiency and reduced particulate concentrations in the flue gas. Although the boiler improvements contemplated in Option 1 should reduce particulate emissions and ensure compliance with ADEC requirements, the constantly decreasing quality of the fuel supply will tend to increase particulate concentrations over time. Compliance with the ADEC emission limitation of 0.1 gr/dscf will be demonstrated with a source testing program following completion of the refurbishing tasks. An annual source testing program conducted by FMUS will be instituted to monitor the compliance status of Units 1, 2 and 3. If coal quality, equipment problems or operation and maintenance problems result in the inability to meet emission limitations, the units will be derated to a level that ensures compliance. In option 2, upgrading of the F.D. and I.D. fans and addition of an electrostatic precipitator (ESP) will be coupled with the m refurbishing activities included in option 1 to approach the maximum design capacity of 50,000 lb/hr. The flue gas will be routed through a single ESP to minimize particulate concentrations prior to 0115c .022483 8 - 53 Rev: 0 Rev. Date: 02/18/83 discharge through a single chimney. This common ESP will be designed to meet the existing ADEC particulate emission limitation. Option 1 minimizes environmental pollution control capital costs and allows FMUS maximum flexibility to comply with ADEC emission limitations without the acquisition of costly air correction equipment. However, the possibility of future derates will tend to reduce the benefits gained by refurbishing Units 1, 2 & 3. Although option 2 eliminates future compliance problems with the addition of an ESP, this approach involves substantial capital costs. Implementation of either option in the Scenario 1 compliance strategy will not affect the air quality problems experienced at Chena 5. Since additional air correction equipment is not contemplated in Option 1, there are no opportunities to improve particulate removal efficiency at Unit 5 through combined flue gas treatment. Installation of an ESP in option 2, however, provides an opportunity to treat a portion or all of the Unit 5 flue gas. Although there are facilities in the U.S. where two or more large boilers are served with a common ESP or baghouse, there are several problems involved with applying this concept to the Chena Plant. Partial treatment of Unit 5 flue gas in a Unit 1, 2, or 3 ESP presents several disadvantages. Further deterioration in the coal quality could render Unit 5 out of compliance earlier than if a separate ESP were installed on Unit 5. The deterioration of either 0115c .022483 8 - 54 Rev: 0 Rev. Date: 02/18/83 the existing particulate removal equipment or the new equipment could also cause a non-compliance situation. Future regulatory changes could make a marginally effective combined gas treatment system seem inadequate to maintain compliance. Since the capital and operating costs associated with an ESP designed for partial flue gas flow are not significantly less than those costs for equipment designed for full flow, the disadvantages of a combined flue gas treatment system at Unit 5 outweigh any economic advantage. The specific sources of noncompliance at Chena 5 must be studied further to establish the most appropriate corrective action. If Scenario 1 is selected for conceptual design in Phase 2, a parallel feasibility study should be initiated to explore independent methods of particulate compliance at Unit 5. Although the implementation of Scenario 1 will not impact Chena 5 compliance status, possible solutions range from derating Unit 5 below the current 90% performance level to installation of a separate ESP. Scenario 2 In Scenario 2, the existing Units 1, 2 and 3 boilers are replaced with a single 150,000 1b/hr boiler. Possible options for this new. boiler include stoker firing as well as pulverized coal firing. There are substantial differences between the air quality compliance strategies associated with each of these firing options. 0115c.022483 SSS Rev: 0 Rev. Date: 02/18/83 With the stoker fired furnace, an ESP will be installed to limit particulate emissions from the new unit. Compliance problems at Units 1, 2 and 3 will be eliminated with their retirement. Combined flue gas treatment at the new unit and Unit 5 is not feasible for the same reasons discussed under Scenario 1. Therefore, a special study is required to analyze the emission problem at Unit 5 and determine an independent correction methodology. Selection of the pulverized coal firing option for the new unit provides a unique approach to solving Unit 5's compliance problems. As discussed in Section 12.400, particulate emissions from Unit 5 can be substantially reduced by improving the fuel quality. By screening the coal supplied to Unit 5, the fines that cause excessive particulate emissions will be removed and burned in the pulverized coal unit. The improved fuel supply to Unit 5 will reduce particulate entrainment in the flue gas and allow the existing multiclone to comply with ADEC emission limitations. Particulate emissions from the new pulverized coal unit will be controlled by a new ESP. With the pulverized coal approach, compliance at both Unit 5 and the new unit can be assured regardless of coal quality degradation. Scenario 3 In Scenario 3, the existing Units 1, 2 and 3 boilers are replaced with a single 286,000 lb/hr boiler. As in Scenario 2, possible 0115c.022483 8 - 56 8.420 Rev: 0 Rev. Date: 02/18/83 options for this new boiler include stoker firing as well as pulverized coal firing. An ESP will be installed to limit particulate emissions on either the stoker or pulverized coal fired options. Compliance problems at Chena 1, 2 and 3 will be eliminated with their retirement. Combined flue gas treatment at the new unit and Unit 5 is not feasible for the same reasons discussed under Scenario 1. If the stoker fired option is selected, a special study will be required to analyze the emission problem at Chena 5 and determine an independent correction methodology. Selection of the pulverized coal option will provide the same approach to solving Unit 5's compliance problems that was described under Scenario 2. Screening the coal supplied to Unit 5 will minimize the combustion of fines that cause excessive particulate emissions. At the same time, particulate emissions from the pulverized coal unit will be controlled to ADEC emission limitations by a new ESP. With the pulverized coal option in Scenario 3, compliance at both Unit 5 and the new unit can be assured regardless of coal quality degradation. Water Quality Compliance Strategy The two major problems related to plant wastewater discharges involve ice fog formation in the winter and maintenance of the water quality standards in the summer. Thermal discharges from the Chena Plant 0115c.022483 8 - 57 Rev: 0 Rev. Date: 02/18/83 contribute to both of these problems. Although none of the Scenarios result in increased thermal discharges, Scenario 3 is the only option that reduces the amount of heat rejection to the Chena River. A broad range of thermal discharge minimization techniques were evaluated in the study. The most promising approach involves a thorough licensing review coupled with a variety of alternate heat rejection methodologies. Ice fog formation caused by thermal discharges can be minimized through application of dry condensers during critical winter months. If Scenario 1 or 2 is selected, a dry condenser, such as the one contemplated in Scenario 3, could be constructed to provide heat exchange capability for the entire Chena station. With the selection of Scenario 3, the dry condenser could be oversized to handle the cooling needs of both Scenario 3 and Unit 5. Elimination of thermal discharges to the Chena River during these critical winter months will minimize the formation of ice fog resulting from power plant operation. Compliance with thermal discharge limitations during summer months can be accomplished with alternative heat rejection techniques such as cooling towers and dry condensers or through variable effluent _ limitations (VEL). Before investing in the expensive cooling tower option, a series of licensing steps may be capable of obtaining an variable effluent limitation or VEL for thermal discharges. VELs 0115c.022483 8 - 58 Rev: 0 Rev. Date: 02/18/83 allow levels of treatment to vary, depending on the season and/or stream flow. Recent activities at the federal level have supported the concept of VELs to reduce cost of wastewater treatment while maintaining water quality. In a December 1, 1982 letter to EPA, the General Accounting Office indicated that VELs should be incorporated "to the extent possible” into new and revised NPDES permits issued under the Clean Water Act. EPA has indicated that VELs are a worthwhile concept that the agency is considering for possible use. Since the Alaska water quality standard for temperature is only violated during certain critical periods in the summer, thermal discharges from the Chena Plant do not contribute to a violation of the water quality standard during most of the year. The VEL concept may have direct applicability to the proposed Chena Plant NPDES permit. A 316(a) demonstration study could be designed to support the suitability of a VEL and establish the relative impact of thermal discharges on the Chena River. During those periods when the Chena River temperature approaches the water quality standard limit of 15°C, the circulating water system could be shifted to a standby closed loop system such as a dry condenser. Although the alternate cooling system may impose an efficiency penalty on the turbine, the units could operate at full power with once through cooling systems during most of the year. Preliminary analysis of thermal discharges indicates that combined 0115c.022483 8 - 59 8.430 Rev: 0 Rev. Date: 02/18/83 operation of Unit 5 and Scenario 3 (in a once through cooling system mode) would raise the river temperature by less than 0.5°C during the summer maximum flow period. Operation of Unit 5 alone will raise the river temperature by approximately half of this value. During low flow periods, combined operation of Unit 5 and Scenario 3 (in a once through cooling system mode) could raise the river temperature by approximately 1°C while operation of Unit 5 alone will raise the river temperature by approximately half of this value. A comprehensive analysis of thermal conditions, including a dispersion model, will be required to demonstrate the viability of a VEL. If this approach is selected as the water quality compliance strategy, the water quality modeling results would be coupled with a 316(a) demonstration study and a revised NPDES permit application requesting a VEL for thermal discharges. Licensing Strategy A specific licensing strategy will be developed for the Scenario selected in Phase 2. The final strategy will include the background elements discussed in Section 8.000 and specific recommendations from APA and FMUS. 0115c.022483 8 - 60 TABLE 8.1 LICENSING AND REGULATORY FRAMEWORK SUMMARY CHENA FEASIBILITY STUDY ntroduction This summary list identifies the licensing and regulatory requirements associated with refurbishing or replacing the Chena 1, 2 and 3 boilers at the Chena Generating Plant, Fairbanks, Alaska. Although every attempt has been made to develop a comprehensive summary, the enabling legislation and applicable regulations should be consulted for specific details. Abbreviation and Acronym List AAC = Alaska Administrative Code FAA = Federal Aviation Administration ADEC = Alaska Department of Environmental Conservation FNSB = Fairbanks North Star Borough ADNR = Alaska Department of Natural Resources NAAQS = National Ambient Air Quality Standard AS = Alaska Statutes NPDES = National Pollutant Discharge Elimination BACT = Best Available Control Technology System CAA = Clean Air Act NSPS = New Source Performance Standards CFR = Code of Federal Regulations PSD = Prevention of Significant Deterioration COF = City of Fairbanks, Alaska R&HA = River & Harbor Act COE = U.S. Army Corps. of Engineers sip = State Implementation Plan CWA = Clean Water Act SPCC = Spill Prevention Control & Countermeasure EPA = U.S. Environmental Protection Agency Plan usc = United States Code 0103c.022483 TABLE 8.1, Continued ITEM NO. PERMIT/APPROVAL AGENCY 1. PSD Permit EPA 2. NPDES Permit EPA 3. SPCC Plan EPA 4, COE Permit COE 5. Review of Tall FAA Structures 0103c.022483 AUTHORITY 42 USC 7401 4O CFR 51 33 USC 1251 4O CFR _? 33 USC 1251 4O CFR 112 33 USC 401-1241 33 CFR 320 & 322-329 49 USC. 1034 14 CFR 77 EGULATED ACTIVITY Major modification of an air containment source Wastewater discharge to surface water Accidental Discharge of Oil stored on or near navigable waters. Structures or dredge & fill in navigable water Construction of Tall Structures SUMMARY_OF CONSTRAINTS oO oO Must utilize BACT Must meet NSPS Must meet emission limita- tions under the State SIP Increased emissions limited to ambient air increments Must meet federal effluent limitations, standards of performance for new sources, effluent standards, effluent prohibitions, pre-treatment standards and any more stringent limitations necessary to meet water quality standards. Public hearing may be required. SPCC plan must be prepared by the operator and certified by a Registered Professional Engineer. The plan must be prepared in accordance with good engineering practices, See 33 CFR 220 & 322-329. The standards for determining obstructions to air navigation are established for various locations in 14 CFR 77. Notice of proposed construction and obstruction marking and lighting are required for certain structures. TABLE 8.1, Continued ITEM_NO, PERMIT/APPROVAL AGENCY 6 Master Appli- ADEC cation ile Permit to ADEC Operate 8. New Source ADEC Review 9. Certification ADEC of Reasonable Assurance 10. Wastewater ADEC Disposal Permit as Wastewater ADEC Treatment Works Plan Review 12. Solid Waste ADEC Disposal Permit 13. Water Rights ADNR Permit 14, Building Permits COF 15. Conditional Use FNSB Permit 0103c.022483 AUTHORITY AS 46.35 AS 46.03 18 AAC 50 AS 46.03 AS 46.03 CWA, Sec. 401 AS 46.03 AS 46.03 AS 46.03 AS 46.15.030-185 Local ordinance Local ordinance REGULATED ACTIVITY Major Project Construction or modification of an air containment source Air containment emissions ina nonattainment area Wastewater discharge into navigable water. Wastewater discharge to waters, lands or sewer system. Construction or alteration of wastewater treatment facilities Incineration of Solid Waste Appropriation and use of groundwater & surface water Construction of Structure Expansion of existing use SUMMARY _OF CONSTRAINTS °o None - voluntary program, pre-application conference is available. Compliance with applicable emission limitations (See PSD permit) Must utilize LAER for nonattainment pollutants. Offsets may be required. All sources owned by the applicant must be in compliance. Applicant must demonstrate compliance with Sections 301, 302, 303, 306 & 307 of the CWA. Compliance with water quality standards, Compliance with water quality standards. Meet plan review requirements. Must use approved method of operation, Water must be put to beneficial use. Compliance with applicable codes. Compliance with Master Plan Scenario Polutant Scenario 1 TSP so2 NOx co Scenario 2 TSP so2 NOx co Scenario 3 Tse so2 NOx co Maximum Predicted Emission Rate (ton/yr)(A) 163 338 338 124 166 345 345 126 136 566 567 207 TABLE 8.2 COMPARISON OF EXISTING AND PREDICTED EMISSION RATES FOR THE CHENA GENERATING STATION, Average Predicted Emission Rate (ton/yr)(B) 93 193 193 aa 95 ai, 197 72 78 323 323 118 Existing Chena 1,2,&3 Emissions (ton/yr)(C) 110 167 168 61 110 167 168 61 110 167 168 61 UNITS 1, 2 AND 3 Maximum Average Net Net Emission Emissions Change (ton/yr) Change (ton/yr) 53 171 170 63 56 178 VW77 65 26 399 399 146 (A) Based on facility operation at 100% of design capacity for 100% of the year (B) Based on facility operation at 100% of design capacity for 57% of the year. <17>(E) 26 25 8 <15> 30 29 11 <32> 156 155 Di, (C) Based on facility operation at 80% of design capacity for less than 57% of the year (D) Extracted from 4O CFR 52.21(b)(23) (E)<00> indicates emission reduction 0103c. 022483 Significant Emission Rate( ton/yr)(D) 25 40 40 100 25 40 4O 100 2D 40 100 TABLE 8.3 SUMMARY LIST OF LICENSING REQUIREMENTS FOR EACH OF THE REFURBISHING/REPLACEMENT SCENARIOS APPLICABILITY TO SCENARIOS AGENCY PERMIT/CONSTRAINT (1) (2) si) (4) FEDERAL EPA PSD Review A(a) A A A EPA NPDES Permit A A A A EPA SPCC Plan A A A A COE COE Permit FAA Review of Tall Structures A A STATE ADEC Master Application Process A A A A ADEC Permit to Operate A(a) A A A ADEC New Source Review A(a) A A A ADEC Certification of Reasonable Assurance A(a) A A A ADEC Wastewater Disposal Permit A A A A ADEC Wastewater Treatment Works Plan Review ADEC Solid Waste Disposal Permit A ADNR Water Rights Permit A A A LOCAL COF Building Permits A A A A COF Zoning Comp! iance A A A A LEGEND: A = Applicable ADEC = Alaska Department of Environmental Conservation ADNR = Alaska Department of National Resources COE = U.S. Army Corps. of Engineers COF = City of Fairbanks EPA = U.S. Environmental Protection Agency FAA = Federal Aviation Administration (a) 0103c.022483 Applicable to the increased power option only ~~ ACTIVITY/AGENCY TABLE 8.4 GENERIC LICENSING SCHEDULE TIMEFRAME (MONTHS) _ 1 2 3 4 5 6 7 8 9 10 11 #12 ~«130:«14~=«415 «16 «6«17:«:18«192=« 200-21 22 Master Application (ADEC) Air -PSD Permit (EPA) -Permit to Operate/NSR (ADEC) Dredge & Fill -Corps Permit (COE) -Cert. of Reas. Assurance (ADEC) Water -NPDES (EPA) -Wastewater Disposal -Plan Review (ADEC) -Water Rights (ADNR) (ADEC) Solid Waste -Disposal Permit (ADEC) Miscellaneous -Building Permits (COF) -Review of Tall Structures (FAA) -Zoning Compliance (FNSB) LEGEND: ---- Application preparation Agency review ADEC Alaska Department of Environmental ADNR Alaska Department of Natural COE U.S. Army Corps. of Engineers COF City of Fairbanks EPA U.S. Environmental Protection FNSB Fairbanks North Star Borough 0103c.021883 Conservation Resources Agency SELECTED PHYSICAL AND CHEMICAL CHARACTERISTICS THE Parameter Silica, mg/1 Calcium, mg/1 Magnesium, mg/1 Sodium, mg/1 Potassium, mg/] Bicarbonate, mg/1 Carbonate, mg/1 Sulfate, mg/1 Chloride, mg/1 Fluoride, mg/1 Nitrate, mg/1 Dissolved Solids, mg/1 Specific Conductance, umhos/cm Tron, ug/1 Manganese, ug/] pH, S.U. Characteristic Flow, cfs Characteristic Temperature, °C TABLE 8.5 CHENA RIVER® Value Winter 23.0 36.0 140.0 13.0 165.0 252.0 3,200 820 6.6 260 4adapted from Baldings Study, 1976. 0103c.022483 OF Summer 6.4 12.0 30.0 10.0 54.0 83.0 2,700 750 7.0 2,400 il 15 (Max.) Table 8.6 CHARACTERIZATION OF LAND USE IN FAIRBANKS, ALASKA Percent Percent of Land Use Category Acreage of Total Developed Total 94,086.85 100.00 Undeveloped 76,332.81 81.1 Developed 17,754.04 18.9 100.00 Residential 2,553.50 a7 14.4 Commercial 1,014.55 etd 5.7 Industrial 852.88 0.9 4.8 Public and Semi-Public 4,077.97 4.3 22.9 Water and Recreation 1,261.64 1.4 7.1 Highway and Streets 2,993.47 3.2 16.9 Transportation, Communica- tions and Utilities 1,772.80 1.9 10.0 Agriculture 3,227.23 — 3.4 18.2 Source: Field survey and measurement by Fairbanks Metropolitan Area Transportation Study. Basis for nonresidential land use provided by Fairbanks North Star Borough Planning Department. 0103c.022483 Year 1902 1920 1929 1950 1976 1980 TABLE 8.7 FAIRBANKS BOOM-BUST CYCLES Project Gold Discovery Exhausted Gold Supply Establishment of Alaska Agricultural College and Completion of Alaska Railroad Alcan completed, military expansion continues Peak Construction Tap Lin Trans-Alaska Pipeline completed, slow down in oi] exploration and production Maximum Population 10,541 2,182 10,000 plus 43,000 plus e 72,000 plus 53,000 plus® 8Personal communication with Craig Helmuth Fairbanks North Star Borough. 0103c .022483 TABLE 8.8 PRELIMINARY LIST OF ENVIRONMENTAL REVIEW CRITERIA FOR THE CHENA FEASIBILITY STUDY PHYSICAL ENVIRONMENT HUMAN ENVIRONMENT METEOROLOGY VISUAL RESOURCES o Climate HISTORICAL/ARCHAEOLOGICAL/CULTURAL o Air Quality RESOURCES o Noise LAND USES LAND FEATURES o Existing Use o Physiography/Topography o Land Cover o Geology and Soils o Zoning o Geological Hazards SOCIO-ECONOMIC HYDROLOGIC ENVIRONMENT Demographic Taxing Districts Utilities and Public Services Employment and Labor Force/ BIOLOGICAL ENVIRONMENT Primary and Secondary Property Ownership Positive and Negative Impacts o Surface Water o Groundwater oooo°o oo o Fauna o Flora o Threatened or Endangered Species TRANSPORTATION o Roadways o Railroads o Airports 0103c .022483 POLLUTANT Particulates Sulfur Dioxide Nitrogen Dioxide Carbon Monoxide 0113c.022483 U.S. EPA AND ALASKA AIR QUALITY STANDARDS AVERAGING TIME Annual 24-Hours Annual 24-Hours 3-Hours Annual 8-Hours 1-Hour TABLE 8.9 CONCENTRATION Micrograms/Meter> EPA 75 260 80 365 1,300 100 10,000 40,000 Alaska 60 150 80 365 1,300 100 10,000 40,000 Scenario 1 2 3 0113c.022483 Stack Height (ft) 180 180 180 TABLE 8-10 Physical Stack Parameters and Volumetric Flow Rate (ACFM) 77,700 76,300 125,500 Exit Temperature (°F) 360 330 330 Emission Rates Particulate 163 166 136 Emission (tons/year) so2 338 345 566 NOX 338 345 567 TABLE 8.11 Average 24-hour Meteorological Scenario Wind Wind Mixing Hour Stability Direction Speed (mps) Depth (m) 01 6 360 2.0 1000 02 6 360 Ze0 1000 03 6 360 2.0 1000 04 6 360 2.0 1000 05 6 345 2.0 1000 06 6 022 200 1000 07 5 360 350 1000 08 5 022 Sot!) 1000 09 4 360 3.0 1000 10 4 360 3.0 1000 11 4 022 4.0 1000 12 4 225 4.0 1000 13 4 225 4.0 1000 14 3 245 3.0 1000 LS 3 245 2.0 1000 16 3 225 Goll) 1000 17 4 225 S10 1000 18 4 345 3.0 1000 19 4 360 4.0 1000 20 5 360 Soll! 1000 ra 5 022 3.0 1000 22 6 360 250 1000 23 6 360 20 1000 24 6 360 a0) 1000 0113c.022483 TABLE 8.12 MAXIMUM POLLUTANT CONCENTRATIONS PREDICTED FOR THE AVERAGE 24-HOUR METEOROLOGICAL CONDITIONS EPA Monitoring Significance Parameter Concentrations Scenario 1 Scenario 2 Scenario 3 Particulates (ug/m ) 10.0 1.6 1.7 1.0 Sulfur dioxide (ug/m ) 13.0 3.4 3.6 G2 Nitrogen oxides (ug/m ) 14.0 3.4 3.6 4.2 Distance from source (km) 15 15 17 Direction from source South South South 0113c.022483 TABLE 8.13 "Worst Case" 24-Hour Meteorological Scenario Hour Stability Wind Speed (mps) Depth tm) 01 5 2.0 1000 02 5 220 1000 03 5 2.0 1000 04 5 2.0 1000 05 5 2.0 1000 06 5 2.0 1000 07 5 2.0 1000 08 5 2.0 1000 09 5 Ze0 1000 10 4 4.0 1000 15 4 4.0 1000 12 4 4.0 1000 13 4 4.0 1000 14 4 4.0 1000 15 4 4.0 1000 16 4 4.0 1000 0113c.022483 TABLE 8.14 MAXIMUM POLLUTANT CONCENTRATIONS PREDICTED FOR THE "WORST CASE" 24-HOUR METEOROLOGICAL CONDITIONS EPA Monitoring Significance Parameter Concentrations Scenario 1 Scenario 2 Scenario 3 Particulates (ug/m ) 10.0 1.6 1.7 1.0 Sulfur dioxide (ug/m’) 13.0 6.5 7.0 — 8.3 Nitrogen oxides (ug/m’) 14.0 6.5 7.0 8.3 Distance from source (km) 8.0 8.0 10.0 Direction from source South South South 0113c.022483 GENERAL: TABLE 8.15 WASTEWATER EFFLUENT LIMITATIONS THAT ARE APPLICABLE TO THE CHENA FEASIBILITY STUDY(a) o pH of all discharges except once through cooling water - 6.0 to 9.0 o Discharge of polychlorinated bipheny! compounds - None SPECIFIC: PARAMETER/LIMIT (mg/l) Free 126 Copper tron Avail Prior Chrom. Zinc TSS Oil & Grease (Total) (Total) Chlor. Poll. (Total) (Total) WASTEWATER CATEGORY MAX AVE MAX AVE MAX AVE MAX AVE MAX AVE MAX AVE MAX AVE MAX AVE Low Volume Wastewater 100 30 20 15 N/A N/A N/A N/A N/A N/A Chemical Metal Cleaning 100 30 20 15 1.0 1.0 1.0 1.0 N/A N/A N/A N/A Wastewater Bottom Ash Transport 100 30 20 15 N/A N/A N/A N/A N/A N/A Water Fly Ash Transport Water None None None None None None None None Cooling Tower Blowdown N/A N/A N/A N/A 0.5 0.2 NDA 0.2 0.2 1.0 1.0 Coal Pile Runnoff 50 N/A N/A N/A N/A N/A N/A N/A (a) Extracted from 4O CFR 423.15 N/A Not applicable NDA No detectable amount 0103c.022483 TABLE 8.16 SUMMARY OF AIR QUALITY COMPLIANCE STRATEGIES FOR INDIVIDUAL UNITS AT THE CHENA GENERATING STATION INDIVIDUAL COMPLIANCE MECHANISM REFURBI SHING/REPLACEMENT Chena Chena Chena Chena New OPTIONS 1 ra 3 5. Unit Scenario One Existing Power Level Derate Derate Derate Derate N/A Increased Power Level Ese Ese ESP Derate N/A Scenario Two Stoker Boiler Replace Replace Replace Derate ESP Pulverized Coal Boiler Replace Replace Replace Fuel imp. ESP Scenario Three Stoker Boiler Replace Replace Replace Derate ESP Pulverized Coal Boiler Replace Replace Replace Fuel Imp. ESP Scenario Four Coal/MSW Boiler Replace Replace Replace Derate Esp LEGEND: N/A = Not Applicable ESP = Electrostatic Precipitator Replace = Replace Unit With New Boiler Derate = Derate Existing Unit To Gain Compliance Fuel Imp. = Fuel Improvement (Screening) 0115c.022483 9.000 9.100 Rev: 0 Rev. Date: 02/18/83 COST/ECONOMIC ANALYSIS The economic analysis has two common goals. Firstly, it yields an optional scenario and a valid set of decision variables to be used for strategic planning and decision making purposes. Secondly, it yields these results within an acceptable framework of the APA to provide the information necessary to rank investment opportunities available to the City of Fairbanks. General Methodology The measurement tools which are used to rank the three scenarios are the Benefit/Cost (B/C) ratio and the Project Net Present Value (NPV). Both methods are consistent with APA economic analysis guidelines. In order to compute a Benefit/Cost ratio it is necessary to forecast the prices and demand for both electricity and steam. Also, by taking this approach all aspects of a "Plant" which produces electricity as well as heat are taken into account. However, no attempt is made to conduct a mode-split analysis in which costs associated with electricity and steam are split. This is because each scenario is to be evaluated in its entirety. 0124c.021883 eal 9.200 9.300 IO Rev: O Rev. Date: 02/18/83 Results of Analysis Presented below are the Net Present Values (NPV) and Benefit/Cost (B/C) Ratios for each Scenario. The NPV figures are in thousands of _1982 dollars. qu ye? sor Scenario 1 Scenario 2 Scenario 3 NET PRESENT VALUE $77,410 $46 ,990 $161,118 Benefit/Cost Ratio 153 Dee ey, Ranking (1=Highest) 2 3 1 Based on the income and cash flow analysis Scenario 3 results in the highest NPV and B/C Ratio, followed by Scenarios 1 and 2 respectively. The primary cause for this ranking sequence is the revenues and costs generated relative to the capital investment necessary for each Scenario. For a more in depth discussion of the results please refer to Section 9.800 "Summary" and Tables 9.4 thru 9.9. Sections 9.3 thru 9.7 present and discuss the assumptions that were used in this analysis. Construction and Operating Schedules The length of time to be covered by the analysis is 30 years. The economic life of Scenarios 2 and 3 is 30 years while Scenario 1 has an economic life of only 20 years. In keeping with APA guidelines 0124c.021883 Send 9.400 9.500 Rev: 0 Rev. Date: 02/18/83 which specify that projects must be evaluated on an equal life basis it is necessary to equate a 30 year economic life with Scenario 1. This is accomplished by assuming an investment in a new facility, identical in cost to Scenario 3, at the end of the 20 year life. Investment Schedule The capital investment for each of the three scenarios is outlined below. Capital costs are estimated in first-quarter 1983 dollars and assume no escalation. 1985 1986 2004 2005 Scenario 1 $8.712 M -0- $20.900 M $20.900 M Scenario 2 $12.265 M $12.265 M -0- -0- Scenario 3 $20.900 M $20.900 M -0- -0- Construction begins in 1985 for all three scenarios with operations starting in 1986 for Scenario 1 and in 1987 for Scenarios 2 and 3. Revenue The price for steam and electricity sold to FMUS customers are from the FMUS rate schedule of December 1, 1981, adjusted for estimated costs to operate, maintain, and administer the delivery of the steam and electricity and for line loses. 0124c.021883 Sao e3 Rev: 0 Rev. Date: 02/18/83 9.510 Electrical Sales Annual revenue from electricity sales consists of sales to FMUS to satisfy annual electrical demand, and sales of excess electrical capacity to the Grid. Electricity is sold to FMUS customers for 60 mils/kWH. Excess electrical capacity in Scenarios 1 and 2 is sold to the Grid for 30 mils/kWH. Since electrical capacity in Scenarios 1 and 2 is not influenced by the amount of steam produced and sold to the DSHS there will be no variance in the amount of electricity generated for resale. Excess electrical capacity is defined as "Net System Capacity less demand to the FMUS System". As FMUS demand increases the amount of electricity available to sell to the Grid decreases. In Scenario 3 electrical capacity decreases as steam produced for the DSHS increases.* Excess electrical capacity in Scenario 3 is sold for 40 mils/kWH. There is a 10 mil/kWH differential in the selling price of excess capacity for Scenario 3. This results from being able to sell excess capacity on a "firm" vs "non-firm" basis. Scenario 3 has a larger amount of excess capacity for resale. This excess capacity is thought to be more stable and predictable over the long term, both elements which are needed to sign a long term power sales agreement. * See Sec. 9.520 for the effect of an increase in steam production to the DSHS on electrical capacity. 0124c.021883 9-4 Rev: 0 Rev. Date: 02/18/83 Demand for electrical capacity in all three scenarios is 149,126,000 kWH's in 1985. This figure was derived by applying a growth factor to the actual demand of the FMUS system in 1982. The FMUS system demand was taken from the Plant Operating Statistics for 1982. Demand for 1985 was calculated as follows; 140,112,000 (demand in 1982) x 1.0213 (growth factor for 3 yrs) = 149,126,000. The table below presents the growth factors used in calculating electrical demand during the analysis period. Years Growth Factor 1982-1990 2.1% 1991-1995 4.1% 1996-1999 5.1% 2000-2016 2.1% The above yearly percentage growth rates were taken from the "Engineering Report: Electric Utility Five-Year System Analysis and Long Range Master Plan-Municipal Utilities System, City of Fairbanks, Alaska". This report was prepared by R.W. Beck and Associates, Inc. in March of 1982. (Section V-2). The forecast for growth rates prepared by R. W. Beck does not cover the entire time period for this analysis. Therefore, a 2.1% growth factor was assumed in years 2000-2016. This is felt to be a conservative assumption which is applied to all three scenarios equally. 0124c.021883 Oho 9.520 Rev: 0O Rev. Date: 02/18/83 The maximum net capacity for each scenario is presented below in kWH's per year. 1985-1986 1987-2005 2006-2016 Scenario 1 212,211,000 212,211,000 389,469,600 Scenario 2 212,211,000 223 , 380,000 223,380,000 Scenario 3 212,211,000 389,469,600 389 , 469,600 Net capacity (percent availability) was determined using the following factors: Scenario 1 85% Scenario 2 85% Scenario 3 90% Revenue from the sale of electricity is the sum of electricity sold to FMUS at 60 mils/kWH (Bus Bar price) and electricity sold to the Grid at 30 mils/kWH for Scenarios 1 and 2 and 40 mils/kWH in Scenario 3. This later rate is conservative but proper for this stage of the study. Steam Sales Annual revenue from steam sales results from the sale of steam to meet DSHS annual demand. The price per 1000 pounds of steam is $5.50, at the plant boundary ($.0055 per pound of steam). 0124c .021883 9-6 Rev: 0 Rev. Date: 02/18/83 System capacity for Scenarios 1 and 2 is 115,000 pounds per hour while peak demand is estimated at 36,000 pounds per hour. Steam sales are equal to the price per pound ($5.50 per 1000 pounds) x annual DSHS demand/1000 Ibs (170,235 in 1985). The annual DSHS demand figure was taken from the Plant Operating Statistics for 1982. The following table presents the demand for the DSHS for each Scenario (in thousands of pounds): 1985-1986 1987-2007 2007-2016 Scenario 1 170,235 170,235 170, 235x1.03" Scenario 2 170,235 170,235 170,235 Scenario 3 170,235 170, 235x1.03" 170,235x1.03" Peak system demand was estimated using data in the Plant Operating Statistics and was calculated as follows: 0124c.021883 9-7 Rev: 0 Rev. Date: 02/18/83 1) Highest monthly demand (January) = hours in one month = Average Hourly Demand 2) Average Hourly Demand x percentage increase to obtain peak demand = Peak Demand In Pounds Per Hour. or (22,652,500+730) = 31,031 x 1.15 = 36,000 Pounds Per Hour, (Rounded To Nearest 1000 Pounds) 0124c .021883 SE=t8 Rev: 0 Rev. Date: 02/18/83 The 36,000 pound per hour peak demand by the DSHS remains constant throughout the analysis period for Scenarios 1 and 2.** This parameter is felt to be consistent due to the fact that the excess steam capacity (115,000 pounds per hour-36,000 pounds per hour = 79,000 pounds per hour excess capacity) is not "Firm" capacity, i.e. the system does not contain the long-term reliability necessary for the sustained expansion of the DSHS. System capacity for Scenario 3 is 165,000 pounds per hour. Peak steam demand in 1985-1986 is 36,000 pounds. In 1987 peak DSHS demand begins to increase at 3% per year. The 3% per year growth factor was taken from the "City of Fairbanks Alaska: District Heating System Development, Final Engineering Report" prepared by Acres American Incorporated, July 1981 (Section 4-2). The forecast for growth in the Acres American Report is through the year 2000. For purposes of this analysis the 3% growth in the DSHS is assumed through the year 2016. ** Scenario 1 demand by the DSHS remains constant at 36,000 pounds per hour until the year 2007 at which time it begins to increase at 3% per year. This assumption is based on the investment in a new plant identical to the investment in Scenario 3 at the end of Z Scenario 1's 20 year life. Therefore, in 2007 a "Firm" capacity of 165,000 pounds per hour is introduced which enables growth in the DSHS system at 3% per year. 0124c.021883 ono) Rev: 0 Rev. Date: 02/18/83 Steam produced for the DSHS affects the total net kWH's available for resale as electricity. As steam to the DSHS increases the net kWH's available from the system decreases. This relationship is characterized as follows. y=29 ,400-.04182x Where y = maximum electrical output in kilowatts for Chena 7. and x = steam extraction in pounds per Hr. Therefore, when extraction for district heating is §,y = 29,400 kW. When extraction is 37,000 pounds per hour as in 1987 (first year of operation: Scenario 3) maximum output in kW's of electricity is 27,853 as derived by: y = 29,400-(.04182 x 37,000) y = 27,853 kW To find maximum net capacity for Chena 7 and Chena 5 at an extraction of 37,000 pounds per hour to the DSHS as expressed in kWH's the following would apply: 27,853 kW (Chena 7 at 37,000 pounds per hour extraction) + 20,000 kW (Chena 5) 47,853 kW (Total Gross kW's Available) 0124c.021883 9 = 10 Rev: 0 Rev. Date: 02/18/83 When Net kWH's kW x (Hours in a year x Percent availability) Net kWH's = 47,853 (8760 x .9) Net kWH's = 377,273,052 at 37,000 pounds per hour to the DSHS. Total revenue is the sum of revenue from electricity sales and revenue from steam sales. 0124c.021883 9-11 Rev: 0 Rev. Date: 02/18/83 9.600 Expenses 9.610 Operating and Maintenance Costs Operating costs were estimated based on a three shift day, seven day week, with four operators per shift in Scenarios 1 and 3, three in Scenario 2. The costs per man hour, including overhead and personal benefits, are: Operating Labor: $40.00 Superintendent: $50.00 Secretarial $25.00 Engineering: $40.00 Insurance costs were estimated at 0.1 percent of capital cost per year. 0124c.021883 Sieu2 Rev: 0 Rev. Date: 02/18/83 Maintenance costs were estimated directly from the Acres American Report of July 1981, pages 7-3, 7-4. Fuel costs and amounts used in 1982 were extracted from FMUS Power Plant Statistics dated 01/24/83. In addition, the amount of steam and electricity sold, and the amount of electricity purchased were extracted from the statistics. During construction O&M for Scenario 1 will be less than when it is in full operation beginning in 1986. This is mainly due to the fact that one boiler will be down at all times during the year long construction period. Scenario 2 will have higher O&M expenses during the two-year construction period, primarily due to having to operate and maintain three older boilers as opposed to a larger new boiler once construction is complete. Scenario 3 will have higher O&M costs after operation begins due to operating and maintaining a larger system relative to Scenarios 1 and 2 0124c.021883 9 - 13 9.620 9.630 Rev: 0 Rev. Date: 02/18/83 Fuel Costs Fuel costs were also determined using Plant Operating Data. For all Scenarios, fuel costs are slightly higher during construction and decline the first year of operation. In Scenarios 1 and 2, fuel costs remain constant once the facility is in operation. In Scenario 3, fuel costs increase as a function of steam demand, or $2.53 for every 1000 1b. increase in the DSHS demand for steam. The reason that fuel costs remain constant over the analysis period is because each Scenario will be producing at maximum capacity from the start of operations. This is based on the assumption that FMUS will be able to sell all of the excess electricity to the Grid because the tie-line will exist. Power Purchases The cost of purchased power was determined from the Plant Operating Statistics. Until FMUS demand exceeds the system capacity for each respective Scenario power purchases are limited to scheduled downtime. When FMUS demand exceeds system capacity it will be necessary to purchase power from an outside source. FMUS is currently purchasing power at 60 mils/kWH, which will be used throughout the analysis period. FMUS electrical demand reaches the system capacity for each respective Scenario in the following years. 0124c.021883 9 - 14 9.640 9.700 Rev: 0 Rev. Date: 02/18/83 Scenario 1 - 1995 Scenario 2 - 1996 Scenario 3 - 2014 Total Expenses Total expenses are equal to the sum of operation and maintenance expense, fuel costs and power purchases. Cash Flow Statement Net Operating Revenue is equal to Total Revenue less Total Expenses. Salvage Value: In order to make the analysis period for all three Scenarios equal to each other, it is necessary to extend the economic life of Scenario 1 to 30 years. This is accomplished by assuming an investment in a facility identical to Scenario 3 at the end of Scenario 1's 20 year life. At the end of the 30-year analysis period it is necessary to assign a salvage value to the investment in the new facility for Scenario 1. This new facility will operate for 11 years, therefore, a salvage _ value equal to 63% of the initial capital cost of the new plant would be appropriate. 0124c.021883 Sianls Rev: 0 Rev. Date: 02/18/83 _ Capital Expenditures: Capital expenditures are outlined in the Investment Schedule, Sec. 9.400. No other capital investments are assumed after the initial construction period with the exception of the investment in years 2004-2005 in Scenario 1. This investment is identical to Scenario 3. The following items were estimated by manufacturers for this study: The renovation of boilers No. 1,2 and 3, new boilers, turbine generators, air correction equipment, ash handling equipment, boiler feed pumps, feedwater heaters, water treatment equipment, and condensers The balance of the equipment, materials, shipping costs and erection were estimated by standard engineering/construction estimating methods. See Tables 9.1, 9.2 and 9.3. Net Cash Flow: Net cash flow is the sum of Net Operating Revenue plus Salvage Value (For Scenario 1 only) less Capital Expenditures. The Net Cash Flow reflects the actual cash inflows and outflows of each Scenario. Cumulative Net Present Value (NPV): The cumulative NPV is the sum of the annual discounted Net Cash Flows. For purposes of discounting 1985 is used as the base year. Each annual Net Cash Flow is discounted according to the following formula. 0124c.021883 9 - 16 9.800 9.810 Rev: 0 Rev. Date: 02/18/83 Annual Discounted Net Cash Flow = Annual Net Cash Flow x (1/(1+4)") Where i = discount rate of 3.5% and n = year following 1985 in which Net Cash Flow occurs (1985 = 0, 1986 = 1, 1987 = 2. etc.) The Cumulative Net Present Values are presented in Section 9.200 "Results of Analysis". Benefit Cost Ratio (B/C): The B/C ratio is derived by dividing the NPV of the Benefits by the NPV of the Costs. In Scenario 1 Benefits are defined as Total Revenue plus Salvage Value. Costs are defined as Total Expenses plus Capital Expenditures. Scenarios 2 and 3 do not have Salvage values, therefore, Benefits are Total Revenue and Costs are Total Expenses plus Capital Expenditures. The results of the B/C ratio are presented in Section 9.200 "Results of Analysis". Summary of Analysis Base Case using the foregoing assumptions, Scenario 3 is the optimal scenario as seen in the table below. . 0124c.021883 9-17 Rev: 0 Rev. Date: 02/18/83 Scenario 1 Scenario 2 Scenario 3 Net Present Value $77,410 $46,990 $161,118 Benefit/Cost Ratio 1.3 ee ee, Ranking (1=Highest) 2 3 1 The reason Scenario 3 ranks ahead of Scenario 1 is because of the larger Net Cash Flows associated with the Project. Although the Cumulative Net Present Value in Scenario 3 does not turn positive until 1991 (1990 for Scenario 1), the Net Cash Flows are substantially higher. This is due to a combination of factors: Revenues of both electricity and steam are greater in Scenario 3 due to a greater capacity of electrical output and sales as well as a "Firm" source of heat for the progressive expansion of the DSHS, which is not the case in Scenarios 1& 2. Finally, Capital Expenditures for Scenario 3 are lower than Scenarios 1 and 2 relative to each Scenario's Net Operating Revenue. All of the above factors are reflected in the Net Cash Flow which is the basis for calculating the NPV (Refer to Tables 9.4-9.6). Scenario 1 is more advantageous than Scenario 2 because Scenario 1 yields more Net Operating Revenue per dollar of investment. For example, Scenario 2 calls for roughly 3 times the investment of Scenario 1 but does not yield 3 times as much Net Operating Revenue. This is true even though Scenario 2 has larger revenues and smaller 0124c.021883 9 - 18 9.820 Rev: 0 Rev. Date: 02/18/83 expenses much of the time, i.e. revenues from electricity are larger due to a greater electrical capacity (223,380,000 net kWH's vs 212,211,000 kWH's) and expenses are smaller due to increased boiler efficiency. Case 1 (Varying the amount of excess capacity sold to the Grid) In the base case analysis it was assumed that all excess capacity was sold, however, if that assumption is changed so that no excess capacity is sold the ranking of the Scenarios remains the same, as illustrated below (Refer to tables 9.7-9.9 for backup) Scenario 1 Scenario 2 Scenario 3 Net Present Value $57,788 $32,207 $65,001 Benefit/Cost Ratio 1.2 1.1 1.3 Ranking (1=Highest) 2 3 1 Electricity sales for all three Scenarios are identical, as sales represent the FMUS service area only. However, sales of heat to the DSHS for Scenario 3 are larger than Scenarios 1 and 2 due to the larger capacity and the assumption that Scenario 3 represents a "Firm" source of heat while the other two do not. Scenarios 3 and 2 also have greater amounts of Net Operating Revenue per dollar of invested capital than Scenario 1. 0124c.021883 9 = 19 Rev: 0 Rev. Date: 02/18/83 There is only one case out of the various runs made that Scenario 3 does not yield the highest NPV & B/C Ratio. That is when a 1% growth rate in electrical and steam demand is assumed along with not being able to sell any excess capacity. In that particular case Scenario 1 ranks above Scenarios 2 and 3 respectively. However, it should be noted that since there was no change in the ranking of the scenarios when no excess capacity was sold, no further variations of this assumption were conducted. 9.830 Capital Sensitivity A sensitivity analysis was conducted to determine the impact on the NPV and the B/C Ratio by varying the Capital Expenditures by + 10%, 20%, and 30%. The table below presents the results. NPV*-B/C Ratio -30% -20% -10% 0 +10% +20% +30% Scenario 1 83 27—le4) 81R6=1 739 bal Se Wal Se (Oe Gal Suess een ou lel —1 53 Scenario 2 54 2=1 2 Sioa 9 4a 476 0-1neee 4456-122 642 -2=1°2 3958-101 Scenario 3 173.4-1.8 169.3-1.7 165.2-1.7 161.1-1.7 157.0-1.6 152.9-1.6 148.8-1.6 0124c.021883 CES Al 9.840 9.850 Rev: O Rev. Date: 02/18/83 The sensitivity analysis yielded the same results as the base case analysis with no change whatsoever. Rankings remained constant, Scenario 3, 1 and 2 in that order. Scenario 3 - Excess capacity is sold for 30 mils/kWH The base case analysis assumed a power sales contract could be negotiated at 40 mils/KWH for Scenario 3. However, the lowering of this figure to 30 mils/KWH for Scenario 3 does not change the ranking of the scenarios. The NPV for Scenario 3 in this case is 137.1* vs. the base case of 77.4* for Scenario 1. *NPV figures are stated in millions of dollars. Low Growth Case The Low Growth Case assumes a 1% annual increase in the demand for electricity within the FMUS service area. Steam demand is held constant for Scenarios 1 and 2 while allowing a 1% increase in the annual steam demand in Scenario 3. The order of rankings did not change, as illustrated below. NPV figures are in thousands of 1982 dollars. 0124c .021883 Oe au2 9.900 Rev: 0 Rev. Date: 02/18/83 Scenario 1 Scenario 2 Scenario 3 Net Present Value $54,000 $30,700 $133,400 Benefit/Cost Ratio 1.2 1.1 1.6 Ranking 2 3 1 The reason for Scenario 3 maintaining such a high margin over the other 2 scenarios is that the excess capacity is still saleable. There is only one case of the various runs made wherein Scenario 3 does not yield the highest NPV and B/C ratio. That is when a 1% growth rate in electrical and steam demand is assumed along with not being able to sell any excess capacity. In that particular case Scenario 1 ranks above Scenarios 2 and 3 respectively. However, it should be noted that in all three scenarios the Cumulative Net Present Value never turns positive. Conclusion to Economic Analysis In the base case as well as the other cases which varied Capital Expenditures, sales to the Grid, the price received for the sale of excess capacity and growth rates for electricity and steam, Scenario 3 proved to be the best investment out of the three choices presented in this analysis. 0124c.021883 9 - 22 Account No. PRR RR PWNHRFPOWONDOAHWNHEHE Re o TABLE 9.1 CHENA FEASIBILITY STUDY SUMMARY CAPITAL COST ESTIMATE Revision 0 SCENARIO NO. 1 Issued 1/25/83 Description Manhours Material Cost Installation Cost Total Cost Site Development N/A N/A N/A N/A Substructures & Foundations - 40,000 48,000 88 ,000 Structural Features 1,958 146 ,000 139,000 285,060 Buildings 2,387 42,000 202 ,000 244,000 Circulating Water System - 28,000 31,000 59,000 Coal Handling Equipment 1,888 64,000 153,000 217,000 Refuse Handling Equipment N/A N/A N/A N/A Steam Generator 8,331 713,000 583,000 1,296,000 Turbine/Generator N/A N/A N/A N/A Air Correction Equipment 10,054 839,000 613,000 1,452,000 Mechanical Equipment 6,733 289,000 448 ,000 737 ,000 Piping Systems 5,034 685 ,000 269,000 954,000 Instrumentation & Control 2,615 237 ,000 139,000 376,000 Electrical Systems & Equipment 7,789 184,000 417,900 601,000 (excl. Substation) Substation (Modification or Expansion) 4,265 342,000 236,000 578,000 Subtotal Direct Cost 51,054 3,609,000 3,278,000 6,887 ,000 Construction Management Cost 1,033,000 Total Direct Cost 7,920,000 Engineering 792,000 Total Construction Cost Based on 1/1/83 Prices 8,712,000 No allowance has been included for the cost of Contingency nor cost of Financing during construction. Account No. PRR RH PWNHMPRPOCOWONDANHWNHH he a Description Site Development Substructures & Foundations Structural Features Buildings Circulating Water System Coal Handling Equipment Refuse Handling Equipment Steam Generator Turbine/Generator 7 Air Correction Equipment Mechanical Equipment Piping Systems Instrumentation & Control Electrical Systems & Equipment (excl. Substation) TABLE 9.2 CHENA FEASIBILITY STUDY SUMMARY CAPITAL COST ESTIMATE Revision 0 SCENARIO NO. 2 Manhours 660 10,543 5,319 2,075 N/A 39,476 9,450 9,169 10,252 17,941 2,880 10,454 Substation (Modification or Expansion) 4,265 Subtotal Direct Cost Construction Management Cost Total Direct Cost Engineering 122,484 Total Construction Cost Based on 1/1/83 Prices Issued 1/25/83 Material Cost Installation Cost Total Cost 4,000 137 ,000 141,000 256 ,000 419,000 675,000 922 ,000 840,000 1,762,000 53,000 608 ,000 661,000 28,000 31,000 59,000 123,000 189,000 312 ,000 N/A N/A N/A 3,460,000 2,763,000 6,223,000 1,656,000 520,000 2,176,000 793,000 554,000 1,347 ,000 1,756,000 657,000 2,413,000 701,000 1,060,000 1,761,000 269,000 153,000 422,000 301,000 560,000 861,000 342 ,000 236,000 578,000 10,664,000 8,727,000 19,391,000 2,909,000 22,300,000 2,230,000 24,530,000 No allowance has been included for the cost of Contingency nor cost of Financing during construction. TABLE 9.3 CHENA FEASIBILITY STUDY SUMMARY CAPITAL COST ESTIMATE Revision 0 SCENARIO NO. 3 Issued 1/25/83 Account No. Description Manhours Material Cost Installation Cost Total Cost 1 Site Development 680 6,000 203 ,000 209 ,000 2 Substructures & Foundations = 484 ,000 793 ,000 1,277,000 3 Structural Features 17,100 1,496,000 1,363,000 2,859,000 4 Buildings 9,208 87 ,000 920,000 1,007 ,000 5 Circulating Water System 2,630 109,000 221,000 330,000 6 Coal Handling Equipment 2,302 131,000 210,000 341,000 7 Refuse Handling Equipment N/A N/A N/A N/A 8 Steam Generator 55,309 5,012,000 3,872,000 8,884,000 9 Turbine/Generator T5020) 5,056 ,000 831,000 5 ,887 ,000 10 Air Correction Equipment 14,676 1,087,000 884 ,000 1,971,000 11 Mechanical Equipment 20,000 5,264,000 1,169,000 6,433,000 12 Piping Systems 18,729 890,000 1,107,000 1,997 ,000 13 Instrumentation & Control 3,140 287 ,000 167 ,000 454,000 14 Electrical Systems & Equipment 8,700 1,224,000 462 ,000 1,686,000 (excl. Substation) 15 Substation (Modification or Expansion) 3424 133,000 188 ,000 321,000 Subtotal Direct Cost 171,018 21,266,000 12,390,000 33,656,000 Construction Management Cost 5,048,000 Total Direct Cost 38,704,000 Engineering 3,096 ,000 Total Construction Cost Based on 1/1/83 Prices 41,800,000 No allowance has been included for the cost of Contingency nor cost of Financing during construction. FEBRUARY 1983 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR TOTAL FMUS DEMAND - KWH REVENUE FROM SALES TO FMUS PRICE PER KWH TO GRID EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES STEAM PRICE PER POUND ANNUAL DSHS DEMAND 1000 LBS SYSTEM CAPACITY 1000 LB/HR PEAK DSHS DEMAND 1000 LB/HR REVENUE - STEAM SALES TOTAL REVENUE EXPENSES O & M EXPENSE FUEL COSTS POWER PURCHASES TOTAL EXPENSES NET OPERATING REVENUE CASH FLOW STATEMENT NET OPERATING REVENUE PLUS: SALVAGE VALUE LESS: CAPITAL EXPENDITURES NET CASH FLOW CUMULATIVE NET PRESENT VALUE BENEFIT / COST RATIO CHENA FEASIBILITY STUDY SCENARIO 1 INCOME AND CASH FLOW STATEMENT - $ 000 Table 9.4 1985 1986 1987 1988 1989 06 06 06 -06 06 149, 126 152,258 155,455 158,720 162,053 8,948 9,135 9,327 9,523 9,723 03 03 .03 .03 03 63,085 59,953 56,756 53,491 50,158 1,893 1,799 1,703 1,605 1,505 10,840 10,934 11,030 11,128 11,228 .0055 .0055 .0055 170,235 170,235 170,235 115 115 115 36 36 4,012 4,146 4,146 4,146 4,146 6,021 5,487 5,487 5,487 5,487 575 575 575 575 DID 10,608 10,208 10,208 10,208 10,208 1,168 1,662 1,758 1,856 1,956 8,712 (7,544) 1,758 (7,544) (5,937) (4,296) (2,622) (917) 6 8 9 9 120) 1990 - 06 165,456 9,927 -03 46,755 1,403 0055 115 PHASE 1 REPORT 1991 1992 -06 179,301 10,758 03 32,910 987 FEBRUARY 1983 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR TOTAL FMUS DEMAND - KWH REVENUE FROM SALES TO FMUS PRICE PER KWH TO GRID EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES STEAM PRICE PER POUND ANNUAL DSHS DEMAND 1000 LBS SYSTEM CAPACITY 1000 LB/HR PEAK DSHS DEMAND 1000 LB/HR REVENUE - STEAM SALES TOTAL REVENUE EXPENSES O & M EXPENSE FUEL COSTS POWER PURCHASES TOTAL EXPENSES NET OPERATING REVENUE CASH FLOW STATEMENT NET OPERATING REVENUE PLUS: SALVAGE VALUE LESS: CAPITAL EXPENDITURES NET CASH FLOW CUMULATIVE NET PRESENT VALUE BENEFIT / COST RATIO 1993 0055 m5) CHENA FEASIBILITY STUDY 1994 06 194,305 11,658 +03 17,906 537 SCENARIO 1 Table 9.4 1995 -06 202,272 12,136 -03 9,939 298 INCOME AND CASH FLOW STATEMENT - $ 000 1996 0055 170,235 115 1997 0055 115 1998 -06 234,825 14,089 PHASE 1 REPORT 1999 0055 115) 2000 06 259,388 15,563 FEBRUARY 1983 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR TOTAL FMUS DEMAND - KWH REVENUE FROM SALES TO FMUS PRICE PER KWH TO GRID EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES STEAM PRICE PER POUND ANNUAL DSHS DEMAND 1000 LBS SYSTEM CAPACITY 1000 LB/HR PEAK DSHS DEMAND 1000 LB/HR REVENUE - STEAM SALES TOTAL REVENUE EXPENSES O & M EXPENSE FUEL COSTS POWER PURCHASES TOTAL EXPENSES NET OPERATING REVENUE CASH FLOW STATEMENT NET OPERATING REVENUE PLUS: SALVAGE VALUE LESS: CAPITAL EXPENDITURES NET CASH FLOW CUMULATIVE NET PRESENT VALUE BENEFIT / COST RATIO CHENA FEASIBILITY STUDY SCENARIO 1 INCOME AND CASH FLOW STATEMENT - $ 000 Table 9.4 2001 2002 2003 06 06 06 272,616 278,341 284, 187 16,357 16,700 17,051 03 03 .03 16,357 16,700 17,051 4,146 4,146 4,146 5,487 5,487 5,487 4,199 4,543 4,894 13,832 14,176 14,527 3,461 3,461 3,461 3,461 3,461 24,107 26,036 27,899 12 1.2 tae 2004 -06 290,154 17,409 -0055 170,235 115 3,461 20,900 18,828 1.1 2005 .06 296,248 Ure} +03 0055 170,235 115 3,461 20,900 10,064 1.0 2006 06 302,469 18,148 04 74, 882 2,995 .0055 165 PHASE 1 REPORT 2007 2008 -06 - 06 308,821 315,306 18,529 18,918 -O4 -O4 68,167 61,307 2,727 2,452 21,256 21,371 0055 0055 180,602 186,020 165 165 38 39 993 1,023 22,249 22,394 4,771 4o7i 4,591 4,592 5Si> 575 9,937 9,938 12,312 12,456 12,312 12,456 12,312 12,456 21,756 27,402 FEBRUARY 1983 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR TOTAL FMUS DEMAND - KWH REVENUE FROM SALES TO FMUS PRICE PER KWH TO GRID EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE = ELECTRICITY SALES STEAM PRICE PER POUND ANNUAL DSHS DEMAND 1000 LBS SYSTEM CAPACITY 1000 LB/HR PEAK DSHS DEMAND 1000 LB/HR REVENUE - STEAM SALES TOTAL REVENUE EXPENSES O & M EXPENSE FUEL COSTS POWER PURCHASES TOTAL EXPENSES NET OPERATING REVENUE CASH FLOW STATEMENT NET OPERATING REVENUE PLUS: SALVAGE VALUE LESS: CAPITAL EXPENDITURES NET CASH FLOW CUMULATIVE NET PRESENT VALUE BENEFIT / COST RATIO CHENA FEASIBILITY STUDY 2012 .06 342,638 20,558 O04 32,362 1,294 2013 -06 349,833 20,990 -O4 24,732 989 SCENARIO 1 INCOME AND CASH FLOW STATEMENT - $ 000 Table 9.4 2009 2010 2011 06 06 .06 321,927 328,688 335,590 19,316 19,721 20,135 O04 -04 04 54, 300 47, 142 39,830 2,172 1,886 1,593 21,488 21,607 21,729 0055 .0055 .0055 191,601 197, 349 203,269 165 165 165 2014 06 357, 180 21,431 04 16,938 678 .0055 165 4,771 4,771 4,771 4,592 4,593 4,593 575 575 575 9,938 9,939 9,939 12,603 PHASE 1 REPORT 2015 2016 06 06 364, 680 372,339 21,881 22, 340 O04 Ou 8,977 Buy 359 34 22,240 22,374 4,771 4,771 4,595 4,595 575 575 9,941 9,941 13,557 13,729 13,557 13,729 26,473 13,557 40,202 63,572 77,410 13 1.3 FEBRUARY 1983 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR TOTAL FMUS DEMAND - KWH REVENUE FROM SALES TO FMUS PRICE PER KWH TO GRID EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES STEAM PRICE PER POUND ANNUAL DSHS DEMAND 1000 LBS SYSTEM CAPACITY 1000 LB/HR PEAK DSHS DEMAND 1000 LB/HR REVENUE - STEAM SALES TOTAL REVENUE EXPENSES O & M EXPENSE FUEL COSTS POWER PURCHASES TOTAL EXPENSES NET OPERATING REVENUE CASH FLOW STATEMENT NET OPERATING REVENUE LESS: CAPITAL EXPENDITURES NET CASH FLOW CUMULATIVE NET PRESENT VALUE BENEFIT / COST RATIO CHENA FEASIBILITY STUDY 1988 -06 158,720 0055 170,235 115 36 1989 -06 162,053 9,723 SCENARIO 2 INCOME AND CASH FLOW STATEMENT - $ 000 Table 9.5 1985 1986 1987 06 .06 06 149, 126 152,258 155,455 8,948 9,135 9,327 03 .03 03 63,085 59,953 67,925 1,893 1,799 2,038 10,840 10,934 11,365 .0055 -0055 .0055 170,235 170,235 170,235 115 115 115 36 36 36 936 936 936 11,776 11,870 12,301 12,265 12,265 (10,585) (20,829) (18,582) 5 ao 7 (16,324) at (14,054) 8 1990 (11,775) 9 PHASE 1 REPORT 1991 -06 172,240 10,334 -03 51,140 1,534 (9,408) 9 1992 (6,955) 9 FEBRUARY 1983 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR TOTAL FMUS DEMAND - KWH REVENUE FROM SALES TO FMUS PRICE PER KWH TO GRID EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES . STEAM PRICE PER POUND ANNUAL DSHS DEMAND 1000 LBS SYSTEM CAPACITY 1000 LB/HR PEAK DSHS DEMAND 1000 LB/HR REVENUE - STEAM SALES TOTAL REVENUE EXPENSES O & M EXPENSE FUEL COSTS POWER PURCHASES TOTAL EXPENSES NET OPERATING REVENUE CASH FLOW STATEMENT NET OPERATING REVENUE LESS: CAPITAL EXPENDITURES NET CASH FLOW CUMULATIVE NET PRESENT VALUE BENEFIT / COST RATIO CHENA FEASIBILITY STUDY SCENARIO 2 INCOME AND CASH FLOW STATEMENT - $ 000 1993 1994 -06 -06 186,653 194, 305 11,199 11,658 +03 +03 36,727 29,075 1,102 872 12,301 12,531 - 0055 .0055 170,235 170,235 115 115 3,970 3,970 5,350 5,350 575 575 9,895 9,895 Table 9.5 1995 06 202,272 12,136 03 21,108 633 1996 1997 06 06 212,588 223,430 12,755 13,406 03 .03 10,792 324 13,079 13, 406 0055 170,235 115 36 936 14, 342 3,970 3,970 5,350 5, 350 575 578 9,895 9,898 1998 PHASE 1 REPORT 1999 3,342 3,342 (4,416) (1,796) 1.0 1.0 4,120 444d 4,120 4, 444 3,728 6,669 10 ist 2000 -06 259, 388 15,563 FEBRUARY 1983 CHENA FEASIBILITY STUDY PHASE 1 REPORT SCENARIO 2 INCOME AND CASH FLOW STATEMENT - $ 000 Table 9.5 2001 2002 2003 2004 2005 2006 2007 2008 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR .06 06 06 06 06 06 06 .06 TOTAL FMUS DEMAND - KWH 272,616 278,341 284,187 290,154 296, 2u8 302,469 308,821 315, 306 REVENUE FROM SALES TO FMUS 16,357 16,700 17,051 17,409 17,775 18, 148 18,529 18,918 PRICE PER KWH TO GRID 03 -03 03 -03 03 .03 .03 03 EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES 16,357 16,700 17,051 17,409 7,775 18,148 18,529 18,918 STEAM PRICE PER POUND .0055 .0055 -0055 .0055 .0055 .0055 .0055 .0055 ANNUAL DSHS DEMAND 1000 LBS 170,235 170,235 170,235 170,235 170,235 170,235 170,235 170,235 SYSTEM CAPACITY 1000 LB/HR 115 115 115 115 115 115 115 115 PEAK DSHS DEMAND 1000 LB/HR 36 36 36 36 36 36 36 36 REVENUE - STEAM SALES 936 936 936 936 936 936 936 936 TOTAL REVENUE 17,293 17,637 17,987 18,346 18,711 19,084 19,466 19,855 EXPENSES O & M EXPENSE 3,970 FUEL COSTS 5,350 POWER PURCHASES 6,091 TOTAL EXPENSES 15,411 NET OPERATING REVENUE 4, 444 CASH FLOW STATEMENT NET OPERATING REVENUE 4, 444 4,444 4,444 4,444 4,444 4,444 4, 444 4, 4Uk LESS: CAPITAL EXPENDITURES NET CASH FLOW 4, 4b 4,444 4,444 4,444 4,444 4,444 4,444 4, 444 , CUMULATIVE NET PRESENT VALUE 17,472 19,948 22,341 24,652 26,886 29,044 31,128 33,143 BENEFIT / COST RATIO 1.1 1.1 1.1 1.1 1.1 ed 1.2 1.2 FEBRUARY 1983 CHENA FEASIBILITY STUDY PHASE 1 REPORT SCENARIO 2 INCOME AND CASH FLOW STATEMENT - $ 000 Table 9.5 2009 2010 2011 2012 2013 2014 2015 2016 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR .06 -06 .06 .06 -06 -06 06 -06 TOTAL FMUS DEMAND - KWH 321,927 328,688 335,590 342,638 349,833 357,180 364,680 372,339 REVENUE FROM SALES TO FMUS 19,316 19,721 20,135 20,558 20,990 21,431 21,881 22,340 PRICE PER KWH TO GRID -03 +03 +03 +03 +03 -03 03 -03 EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES 19,316 19,721 20,135 20,558 20,990 21,431 21,881 22,340 STEAM PRICE PER POUND 0055 0055 0055 -0055 0055 .0055 0055 0055 ANNUAL DSHS DEMAND 1000 LBS 170,235 170,235 170,235 170,235 170,235 170,235 170,235 170,235 SYSTEM CAPACITY 1000 LB/HR 115 ue 115 115 115 115 115 i: PEAK DSHS DEMAND 1000 LB/HR 36 36 36 36 36 36 36 36 REVENUE - STEAM SALES 936 936 936 936 936 936 936 936 TOTAL REVENUE 22,367 22,817 23,277 EXPENSES O & M EXPENSE 3,970 3,970 3,970 3,970 3,970 3,970 3,970 3,970 FUEL COSTS 5,350 5,350 5,350 5,350 5,350 5,350 5,350 5,350 POWER PURCHASES 6,488 6,893 7,308 7,730 8,162 8,603 9,053 9,513 TOTAL EXPENSES 15,808 16,213 16,628 17,050 17,482 17,923 18,373 18,833 NET OPERATING REVENUE CASH FLOW STATEMENT NET OPERATING REVENUE LESS: CAPITAL EXPENDITURES NET CASH FLOW CUMULATIVE NET PRESENT VALUE BENEFIT / COST RATIO FEBRUARY 1983 CHENA FEASIBILITY STUDY PHASE 1 REPORT SCENARIO 3 INCOME AND CASH FLOW STATEMENT - $ 000 Table 9.6 1985 1986 1987 1988 1989 1990 1991 1992 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR .06 06 06 06 06 06 .06 -06 TOTAL FMUS DEMAND - KWH 149,126 152,258 155,455 158,720 162,053 165,456 172,240 179,301 REVENUE FROM SALES TO FMUS 8,948 as oe 9,327 9,523 9,723 9,927 10,334 10,758 PRICE PER KWH TO GRID O04 04 -O4 -O4 O04 O04 -O4 .O4 EXCESS CAPACITY SOLD - KWH 51,319 48,188 221,896 218,268 214,560 210,771 203,590 196,119 REVENUE FROM SALES TO GRID 2,053 1,928 8,876 8,731 8,582 8,431 8,144 7,845 REVENUE - ELECTRICITY SALES 11,000 11,063 18,203 18,254 18,306 18,358 18,478 18,603 STEAM PRICE PER POUND 0055 0055 0055 0055 0055 0055 0055 -0055 ANNUAL DSHS DEMAND 1000 LBS NiO,es>. NTO;2oo 175, 342 180,602 186,020 191,601 197,349 203,269 SYSTEM CAPACITY 1000 LB/HR 165 165 165 165 165 165 165 165 PEAK DSHS DEMAND 1000 LB/HR 36 36 4 38 39 40 41 43 REVENUE - STEAM SALES 936 936 964 993 1,023 1,054 1,085 Ua k} TOTAL REVENUE UUACEIS 11,999 19,168 19,247 19, 329 19,412 19,563 19, f21 EXPENSES O & M EXPENSE 4,146 4,146 4,771 acer eu Le uean 4,771 es FUEL COSTS 5,387 SO 4,578 4,591 4,592 4,592 4,593 4,593 POWER PURCHASES 575 575 575 575 575 575 575 575 TOTAL EXPENSES 10,108 10,235 9,924 9,937 9,938 9,938 9,939 9,939 NET OPERATING REVENUE 1,829 1,764 9,244 9,310 9,391 9,474 9,625 9,782 CASH FLOW STATEMENT NET OPERATING REVENUE LESS: CAPITAL EXPENDITURES NET CASH FLOW CUMULATIVE NET PRESENT VALUE (19,071) (37,560) (28,931) (20,534) (12,350) (4,374) 3,456 Tite BENEFIT / COST RATIO 4 4 6 at 9 1.0 1.0 1.1 FEBRUARY 1983 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR TOTAL FMUS DEMAND - KWH REVENUE FROM SALES TO FMUS PRICE PER KWH TO GRID EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES STEAM PRICE PER POUND ANNUAL DSHS DEMAND 1000 LBS SYSTEM CAPACITY 1000 LB/HR PEAK DSHS DEMAND 1000 LB/HR REVENUE - STEAM SALES TOTAL REVENUE EXPENSES O & M EXPENSE FUEL COSTS POWER PURCHASES TOTAL EXPENSES NET OPERATING REVENUE CASH FLOW STATEMENT NET OPERATING REVENUE LESS: CAPITAL EXPENDITURES NET CASH FLOW CUMULATIVE NET PRESENT VALUE BENEFIT / COST RATIO CHENA FEASIBILITY STUDY 1996 06 212,588 12,755 04 161,070 6,443 1997 -06 223,430 13,406 -O4 149,753 5,990 SCENARIO 3 INCOME AND CASH FLOW STATEMENT - $ 000 Table 9.6 1993 1994 1995 06 06 06 186,653 194, 305 202,272 11,199 11,658 12,136 04 .04 O04 188,347 180,260 171, 846 7,534 7,210 6,874 18,733 18,869 19,010 0055 0055 .0055 209, 368 215,649 222,118 165 165 165 4,771 4,771 4,771 4,593 4,594 4,594 575 575 575 9,939 9,940 9,940 9,945 10,115 10,291 9,945 10,115 10,291 18,697 26,119 33,414 1.2 1.2 1.2 1998 -06 234,825 14,089 -O4 137,870 5,515 PHASE 1 REPORT 1999 2000 06 259, 388 15,563 O04 112,285 43491 0055 257,496 165 54 FEBRUARY 1983 CHENA FEASIBILITY STUDY PHASE 1 REPORT SCENARIO 3 INCOME AND CASH FLOW STATEMENT - $ 000 Table 9.6 2001 2002 2003 2004 2005 2006 2007 2008 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR 06 06 06 06 06 .06 06 06 TOTAL FMUS DEMAND - KWH 272,616 278,341 284, 187 290,154 296,248 302,469 308,821 315,306 REVENUE FROM SALES TO FMUS 16,357 16,700 17,051 17,409 17,775 18,148 18,529 18,918 PRICE PER KWH TO GRID -04 04 04 O04 04 .O4 -04 04 EXCESS CAPACITY SOLD - KWH 98,523 92,248 85,836 79,285 72,591 65,751 58,761 51,619 REVENUE FROM SALES TO GRID 3,941 3,690 3,433 3,171 2,904 2,630 2,350 2,065 REVENUE - ELECTRICITY SALES 20,298 20,390 20,485 20,581 20,678 20,778 20,880 20,983 STEAM PRICE PER POUND 0055 .0055 .0055 .0055 0055 .0055 .0055 .0055 ANNUAL DSHS DEMAND 1000 LBS 265,221 273,177 281,373 289,814 298,508 307,463 316,687 326, 188 SYSTEM CAPACITY 1000 LB/HR 165 165 165 165 165 165 165 165 PEAK DSHS DEMAND 1000 LB/HR 56 57 59 61 63 64 66 68 REVENUE - STEAM SALES 1,459 1,502 1,548 1,594 1,642 1,691 1,742 1,794 TOTAL REVENUE 21,757 21,893 22,032 22,175 22,320 22,469 22,621 22,777 EXPENSES O & M EXPENSE 4,771 4,771 4,771 4,771 4,771 4,771 4,771 4,771 FUEL COSTS 4,598 4,598 4,599 4,599 4,600 4,601 4,601 4, 602 POWER PURCHASES 575 575 575 575 575 575 575 575 TOTAL EXPENSES 9,944 9,944 9,945 9,945 9,946 9,947 9,947 9,948 NET OPERATING REVENUE 12,087 CASH FLOW STATEMENT NET OPERATING REVENUE 11,813 11,949 12,087 12,229 12,374 12,523 12,674 12,829 LESS: CAPITAL EXPENDITURES NET CASH FLOW 11,813 11,949 12,087 12,229 12,374 , et a CUMULATIVE NET PRESENT VALUE 75,411 82,069 88,576 94,937 101, 156 107,237 113, 183 118,998 BENEFIT / COST RATIO 1.4 1.5 1.5 1.5 Ts: 1.5 1.6 1.6 FEBRUARY 1983 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR TOTAL FMUS DEMAND - KWH REVENUE FROM SALES TO FMUS PRICE PER KWH TO GRID EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES STEAM PRICE PER POUND ANNUAL DSHS DEMAND 1000 LBS SYSTEM CAPACITY 1000 LB/HR PEAK DSHS DEMAND 1000 LB/HR REVENUE - STEAM SALES TOTAL REVENUE EXPENSES O & M EXPENSE FUEL COSTS POWER PURCHASES TOTAL EXPENSES NET OPERATING REVENUE CASH FLOW STATEMENT NET OPERATING REVENUE LESS: CAPITAL EXPENDITURES NET CASH FLOW CUMULATIVE NET PRESENT VALUE BENEFIT / COST RATIO CHENA FEASIBILITY STUDY 2012 -06 342,638 20,558 -O4 21,458 858 0055 367,127 2013 SCENARIO 3 INCOME AND CASH FLOW STATEMENT - $ 000 Table 9.6 2009 2010 2011 06 06 06 321,927 328,688 335,590 19,316 19,721 20,135 O04 04 O04 44, 322 36,865 29,245 1,773 1,475 1,170 21,089 21,196 215309 .0055 0055 0055 335,973 346,053 356,434 165 165 165 165 2014 PHASE 1 REPORT 2015 0055 165 2016 06 372,339 22,340 4,771 4,771 4,771 4,603 4,604 4,604 575 575 575 9,949 9,950 9,950 12,988 13,150 13,315 124, 686 130,250 1.6 135,694 1.6 1.6 141,021 1.6 146,233 1.6 151,335 1.7 156, 308 Ui. FEBRUARY 1983 CHENA FEASIBILITY STUDY PHASE 1 REPORT SCENARIO 1 INCOME AND CASH FLOW STATEMENT - $ 000 Table 9.7 1985 1986 1987 1988 1989 1990 1991 1992 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR 06 .06 06 06 .06 06 .06 06 TOTAL FMUS DEMAND - KWH 149,126 152,258 155,455 158,720 162,053 165,456 172,240 179,301 REVENUE FROM SALES TO FMUS 8,948 9,135 9,327 9,523 9,723 9,927 10,334 10,758 PRICE PER KWH TO GRID .03 03 03 03 03 03 03 -03 EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES 8,948 9,135 9,327 9,523 9,723 9,927 10,334 10,758 STEAM PRICE PER POUND .0055 .0055 .0055 .0055 .0055 .0055 ANNUAL DSHS DEMAND 1000 LBS 170,235 170,235 170,235 170,235 170,235 170,235 SYSTEM CAPACITY 1000 LB/HR 115 115 115 115 115 115 PEAK DSHS DEMAND 1000 LB/HR 36 REVENUE - STEAM SALES 936 TOTAL REVENUE EXPENSES O & M EXPENSE 4,012 4,146 4,146 4,146 4,146 4,146 4,146 4,146 FUEL COSTS 6,021 5,487 5,487 5,487 5,487 5,487 5,487 5,487 POWER PURCHASES DID) ot 575 OID Dip, Dil 575 575 TOTAL EXPENSES 10,608 10,208 10,208 10,208 10,208 10,208 10,208 10,208 NET OPERATING REVENUE (724) (136) 56 251 451 656 1,486 CASH FLOW STATEMENT NET OPERATING REVENUE (724) (136) 56 251 451 656 1,063 1,486 PLUS: SALVAGE VALUE LESS: CAPITAL EXPENDITURES NET CASH FLOW CUMULATIVE NET PRESENT VALUE (9,436) (9,568) (9,516) (9,289) (8,896) (8,344) (7,479) (6,311) BENEFIT / COST RATIO 5D aa 8 8 -8 9 ct) 9 FEBRUARY 1983 CHENA FEASIBILITY STUDY PHASE 1 REPORT SCENARIO 1 INCOME AND CASH FLOW STATEMENT - $ 000 Table 9.7 1993 1994 1995 1996 1997 1998 1999 2000 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR -06 -06 -06 -06 06 -06 -06 06 TOTAL FMUS DEMAND - KWH 186,653 194,305 202,272 212,588 223,430 234,825 246,801 259,388 REVENUE FROM SALES TO FMUS 11,199 11,658 12,136 12,755 13,406 14,089 14, 808 15,563 PRICE PER KWH TO GRID +03 +03 +03 -03 +03 -03 -03 03 EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES 11,199 11,658 12,136 2529) 13,406 14,089 14,808 15,563 STEAM PRICE PER POUND 0055 0055 0055 0055 0055 0055 0055 0055 ANNUAL DSHS DEMAND 1000 LBS 170,235 170,235 170,235 170,235 170,235 170,235 170,235 170,235 SYSTEM CAPACITY 1000 LB/HR 115 sh) 115. 115 wd 115 115 ui PEAK DSHS DEMAND 1000 LB/HR 36 36 36 36 36 36 36 36 REVENUE - STEAM SALES 936 936 936 936 936 936 936 936 TOTAL REVENUE 12,135 12,595 13,073 13,692 14,342 15,026 15,744 16,500 EXPENSES O & M EXPENSE FUEL COSTS POWER PURCHASES TOTAL EXPENSES NET OPERATING REVENUE CASH FLOW STATEMENT NET OPERATING REVENUE 1,927 2,387 2,865 3,461 3,461 3,461 3,461 3,461 PLUS: SALVAGE VALUE LESS: CAPITAL EXPENDITURES NET CASH FLOW 1,927 2,387 2,865 CUMULATIVE NET PRESENT VALUE (4,847) (3,096) (1,065) 1,305 3,596 5,809 7,947 10,013 BENEFIT / COST RATIO 9 1.0 1.0 1.0 1.0 1.0 ta 1.1 GOL 020‘98L SS00° O° 8L6‘8L 90¢e ‘GLE 90° 8002 GOL 209 ‘OSL SS00° O° 625‘8L L29 ‘soe 90° 4002 1uOd3Y Lt JSWHd GOL ene “SLL SS00° 9002 ort (s¢0‘2) 006 ‘02 Lone SLL Ge2‘OLL SS00° £0° GLL‘LL she ‘962 90° S002 006 ‘02 Lon‘e GLL Ge2‘OLL 4S00° 60 ‘LL £0° 60n ‘LL HGL ‘062 90° elerd 008‘61 LE6‘EL 60021 19n‘€ ions 19m‘ e Lon‘e Lon‘e Lon‘e 186‘LL 2eo‘ee £62‘ 9£6 9£6 9£6 ge ge 9¢ SLL GLL GLL Gee‘OLL Ge2‘OLL Ge2‘OLl SS00° SS00° S$S00° LGO‘LL 002 ‘9L LG€‘9L £0° £0° £0° LSO‘2L 002 ‘9L LG€‘9L L8L ‘nee Lhe ‘ez 919‘el2 90° 90° 90° £002 2002 L002 £6 eLgel 000 $ - INAW31V1S MO14 HSVO GNV 3WOONI Lt O1YVWNIOS AGNLS ALITI@ISva4 WN3IHO Ollvy 1809 / 1143N3d SNIWA LNAS3Yd LAN 3AILVINWND MO14 HSVO LIN S3YNLIGN3dX3 WWLidvVd :ss31 AMIVA JOVAIVS *SNid SANSARY ONILVY3SdO LIN IN3W31V1S MO14 HSVO SANSARY ONILVYadO LIN SASN3dX3 WLOL SASVHOUNd YIMOd $isoo 13N4 3SN3dXx3 W 20 SASNAdx3 SAN3A3Y TVLOL S31VS WV3LS - 3NNFARY YH/91 OOOL GNVW3G SHSQ YW3d YH/@1 OOOL ALIOVdVD WILSAS $a1 OOOL GNVW3G SHSG TWNNNV GNNOd Yad JO1Yd Wvals S31VS ALIOIYLO3T3 = 3NNSARY Ggiy9 OL S31WS WOYN4 ANNAARY HMA - G10S ALIOVdVO SS39X49 Giy9 OL HMM Yad JO1Yd SNW4 OL S3I1VS WON4 JNNIAAY HMM - GNVW3d0 SNW4 IWLOL uva SN@ LV HMM Yad FOINYd ALI91Y19373 SANN3AIY ANAW3LVLS AWOON! €86l Auvnugs4 FEBRUARY 1983 CHENA FEASIBILITY STUDY PHASE 1 REPORT SCENARIO 1 INCOME AND CASH FLOW STATEMENT ~ $ 000 Table 9.7 2009 2010 2011 2012 2013 2014 2015 2016 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR -06 -06 -06 .06 06 06 06 -06 TOTAL FMUS DEMAND - KWH 321,927 328,688 335,590 342,638 349,833 357,180 364,680 372,339 REVENUE FROM SALES TO FMUS 19,316 19,721 20,135 20,558 20,990 21,431 21,881 22,340 PRICE PER KWH TO GRID +04 -O4 -O4 04 -O4 o4 O04 o4 EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES 19,316 19,721 20, 135 20,558 20,990 21,431 21,881 22,340 STEAM PRICE PER POUND - 0055 -0055 0055 0055 0055 0055 0055 0055 ANNUAL DSHS DEMAND 1000 LBS 215,649 222,118 228,782 235,645 SYSTEM CAPACITY 1000 LB/HR 165 165 165 165 PEAK DSHS DEMAND 1000 LB/HR 45 47 48 49 REVENUE - STEAM SALES 1,186 1,222 1,258 1,296 TOTAL REVENUE 22,176 22,652 23,139 23,636 EXPENSES O & M EXPENSE 4,771 4,771 4,771 4,771 4,771 4,771 LA 4,771 FUEL COSTS 4,592 4,593 4,593 4,593 4,594 4,594 4,595 4,595 POWER PURCHASES 5715 575 575 575 575 DED DID 575 TOTAL EXPENSES 9,938 9,939 9,939 9,939 9,940 9,940 9,941 9,941 NET OPERATING REVENUE 12,236 12,712 13,198 13,695 CASH FLOW STATEMENT NET OPERATING REVENUE 10,431 10,868 11,314 11,770 12,236 25-112 13,198 13,695 PLUS: SALVAGE VALUE 26,473 LESS: CAPITAL EXPENDITURES NET CASH FLOW 10,431 10,868 11,314 CUMULATIVE NET PRESENT VALUE 16,027 20,625 25,251 29,901 34,571 39,258 43,960 57,788 BENEFIT / COST RATIO 1.1 1.1 1.4 17 usu 1.2 ime ee FEBRUARY 1983 CHENA FEASIBILITY STUDY PHASE 1 REPORT SCENARIO 2 INCOME AND CASH FLOW STATEMENT - $ 000 Table 9.8 1985 1986 1987 1988 1989 1990 1991 1992 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR 06 06 -06 06 -06 06 -06 -06 TOTAL FMUS DEMAND = KWH 149, 126 152,258 155,455 158,720 162,053 165,456 172, 240 179,301 REVENUE FROM SALES TO FMUS 8,948 9,135 9,327 9,523 9,723 9,927 10,334 10, 758 PRICE PER KWH TO GRID 03 03 03 03 03 -03 03 .03 EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES 8,948 9,135 9,327 9,523 9,723 9,927 10,334 10,758 STEAM PRICE PER POUND .0055 .0055 .0055 .0055 .0055 -0055 .0055 ANNUAL DSHS DEMAND 1000 LBS 170,235 W7O5259 IWO;e3> IADR IE) 1103235 n7O,es)) 170, 235 SYSTEM CAPACITY 1000 LB/HR 115 115 115 115 115 115 115 PEAK DSHS DEMAND 1000 LB/HR REVENUE - STEAM SALES TOTAL REVENUE EXPENSES O & M EXPENSE 4,146 4,146 3,970 3,970 3,970 3,970 3,970 3,970 FUEL COSTS 5,375 5,487 5,350 5,350 5,350 5,350 5,350 5,350 POWER PURCHASES 575 575 54D 575 575 575 575 515 TOTAL EXPENSES 10,096 10,208 9,895 9,895 9,895 9,895 9,895 9,895 NET OPERATING REVENUE CASH FLOW STATEMENT NET OPERATING REVENUE (212) (136) 369 564 764 969 1,376 1,799 LESS: CAPITAL EXPENDITURES 12,265 12,265 NET CASH FLOW (12,477) CUMULATIVE NET PRESENT VALUE (12,477) (24,459) (24,115) (23,606) (22,940) (22,124) (21,005) (19,591) BENEFIT / COST RATIO 4 4 eo) -6 7 7 8 8 FEBRUARY 1983 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR TOTAL FMUS DEMAND - KWH REVENUE FROM SALES TO FMUS PRICE PER KWH TO GRID EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES STEAM PRICE PER POUND ANNUAL DSHS DEMAND 1000 LBS SYSTEM CAPACITY 1000 LB/HR PEAK DSHS DEMAND 1000 LB/HR REVENUE - STEAM SALES TOTAL REVENUE EXPENSES O & M EXPENSE FUEL COSTS POWER PURCHASES TOTAL EXPENSES NET OPERATING REVENUE CASH FLOW STATEMENT NET OPERATING REVENUE LESS: CAPITAL EXPENDITURES NET CASH FLOW CUMULATIVE NET PRESENT VALUE BENEFIT / COST RATIO INCOME AND CASH FLOW STATEMENT - $ 000 1993 .0055 v5 CHENA FEASIBILITY STUDY 1994 -06 194,305 11,658 .0055 1D) (17,889) 8 (15,908) 9 SCENARIO 2 Table 9.8 1995 -06 202,272 12,136 (13,656) 9 1996 -06 212,588 12,755 -03 (11,055) 9 1997 - 06 223,430 13,406 .0055 115 (8,114) 9 1998 (5,273) 1.0 PHASE 1 REPORT 1999 06 246,801 14; 808 0055 115 (2,527) 1.0 2000 -06 259,388 15,563 FEBRUARY 1983 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR TOTAL FMUS DEMAND - KWH REVENUE FROM SALES TO FMUS PRICE PER KWH TO GRID EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES STEAM PRICE PER POUND ANNUAL DSHS DEMAND 1000 LBS SYSTEM CAPACITY 1000 LB/HR PEAK DSHS DEMAND 1000 LB/HR REVENUE - STEAM SALES TOTAL REVENUE EXPENSES O & M EXPENSE FUEL COSTS POWER PURCHASES TOTAL EXPENSES NET OPERATING REVENUE CASH FLOW STATEMENT NET OPERATING REVENUE LESS: CAPITAL EXPENDITURES NET CASH FLOW CUMULATIVE NET PRESENT VALUE BENEFIT / COST RATIO CHENA FEASIBILITY STUDY 2004 -06 290,154 17,409 0055 170,235 115 36 2005 -06 296,248 17,775 -03 SCENARIO 2 INCOME AND CASH FLOW STATEMENT - $ 000 Table 9.8 2001 2002 2003 06 06 06 272,616 278,341 284, 187 16,357 16, 700 17,051 03 03 .03 16,357 16,700 17,051 0055 0055 .0055 170,235 170,235 170,235 115 115 115 36 36 36 936 936 936 17,293 17,637 17,987 3,970 3,970 3,970 5,350 5,350 5,350 3,529 3,873 4,223 12,849 13,193 13,543 4,444 4, 4b 4,444 4, 44k 4,444 4, 444 2,688 5,165 7,557 1.0 1.0 1.0 2006 - 0055 115 PHASE 1 REPORT 2007 2008 .06 -06 308,821 315, 306 18,529 18,918 .03 .03 18,529 18,918 0055 0055 170,235 170,235 115 115 36 36 936 936 19,466 19,855 3,970 3,970 5, 350 5,350 5,701 6,091 15,021 15,411 4 44d, FEBRUARY 1983 CHENA FEASIBILITY STUDY PHASE 1 REPORT SCENARIO 2 INCOME AND CASH FLOW STATEMENT - $ 000 Table 9.8 2009 2010 2011 2012 2013 2014 2015 2016 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR 06 06 . 06 06 06 06 06 06 TOTAL FMUS DEMAND - KWH 321,927 328,688 335,590 342,638 349,833 357, 180 364, 680 372,339 REVENUE FROM SALES TO FMUS 19,316 19,721 20,135 20,558 20,990 21,431 21,881 22,340 PRICE PER KWH TO GRID 03 03 03 03 -03 03 03 03 EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES 19,316 19,721 20,135 20,558 20,990 21,431 21,881 22, 340 STEAM PRICE PER POUND .0055 0055 0055 .0055 .0055 0055 0055 .0055 ANNUAL DSHS DEMAND 1000 LBS 170,235 170,235 170,235 170,235 170,235 170,235 170,235 170,235 SYSTEM CAPACITY 1000 LB/HR 115 115 115 115 115 115 115 115 PEAK DSHS DEMAND 1000 LB/HR 36 36 36 36 36 36 36 36 REVENUE - STEAM SALES 936 936 936 936 936 936 936 936 TOTAL REVENUE 20,252 20,658 21,072 21,495 21,926 22,367 22,817 23,277 EXPENSES O & M EXPENSE 3,970 3,970 3,970 3,970 3,970 3,970 3,970 3,970 FUEL COSTS 5,350 5,350 5,350 5,350 5,350 5,350 5,350 5,350 POWER PURCHASES 6,488 6,893 7, 308 7,730 8,162 8,603 93053 9,513 TOTAL EXPENSES 15,808 16,213 16,628 17,050 17,482 17,923 18,373 18,833 NET OPERATING REVENUE 4,444 4, 444 4,444 4, 44u 4,444 444d 4,444 4444 CASH FLOW STATEMENT NET OPERATING REVENUE LESS: CAPITAL EXPENDITURES NET CASH FLOW CUMULATIVE NET PRESENT VALUE BENEFIT / COST RATIO FEBRUARY 1983 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR TOTAL FMUS DEMAND - KWH REVENUE FROM SALES TO FMUS PRICE PER KWH TO GRID EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES STEAM PRICE PER POUND ANNUAL DSHS DEMAND 1000 LBS SYSTEM CAPACITY 1000 LB/HR PEAK DSHS DEMAND 1000 LB/HR REVENUE - STEAM SALES TOTAL REVENUE EXPENSES O & M EXPENSE FUEL COSTS POWER PURCHASES TOTAL EXPENSES NET OPERATING REVENUE CASH FLOW STATEMENT NET OPERATING REVENUE LESS: CAPITAL EXPENDITURES NET CASH FLOW CUMULATIVE NET PRESENT VALUE BENEFIT / COST RATIO INCOME AND CASH FLOW STATEMENT - S$ 000 1985 0055 165 (21,124) aa) CHENA FEASIBILITY STUDY 1986 06 152,258 9,135 -O4 (41,475) 3 SCENARIO 3 Table 9.9 1987 -06 155,455 9,327 +04 .0055 165 (41,132) “4 1988 -06 158,720 9,523 -O4 (40,609) 5 1989 06 162,053 9,723 (39,905) 5 1990 - 06 165,456 9,927 (39,027) 6 PHASE 1 REPORT 1991 -06 172,240 10,334 (37,822) -6 1992 -06 179,301 10,758 -0055 203,269 165 43 (36,299) of FEBRUARY 1983 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR TOTAL FMUS DEMAND - KWH REVENUE FROM SALES TO FMUS PRICE PER KWH TO GRID EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES STEAM PRICE PER POUND ANNUAL DSHS DEMAND 1000 LBS SYSTEM CAPACITY 1000 LB/HR PEAK DSHS DEMAND 1000 LB/HR REVENUE - STEAM SALES TOTAL REVENUE EXPENSES O & M EXPENSE FUEL COSTS POWER PURCHASES TOTAL EXPENSES NET OPERATING REVENUE CASH FLOW STATEMENT NET OPERATING REVENUE LESS: CAPITAL EXPENDITURES NET CASH FLOW CUMULATIVE NET PRESENT VALUE BENEFIT / COST RATIO CHENA FEASIBILITY STUDY SCENARIO 3 INCOME AND CASH FLOW STATEMENT - $ 000 1993 .06 186,653 11,199 -O4 1994 -06 194, 305 11,658 Table 9.9 1995 06 202,272 12,136 -0055 165 1996 -06 212,588 V2eto> O04 +0055 165 1997 - 06 223,430 13,406 .0055 165 1998 -06 234,825 14,089 O04 PHASE 1 REPORT 1999 2000 -06 259,388 15,563 (34,468) lf (32, 337) onl (29,914) 8 (27,124) ug) (23,974) 8 (20,469) 9 (16,613) 9 (12,413) 9 FEBRUARY 1983 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR TOTAL FMUS DEMAND - KWH REVENUE FROM SALES TO FMUS PRICE PER KWH TO GRID EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES STEAM PRICE PER POUND ANNUAL DSHS DEMAND 1000 LBS SYSTEM CAPACITY 1000 LB/HR PEAK DSHS DEMAND 1000 LB/HR REVENUE - STEAM SALES TOTAL REVENUE EXPENSES O & M EXPENSE FUEL COSTS POWER PURCHASES TOTAL EXPENSES NET OPERATING REVENUE CASH FLOW STATEMENT NET OPERATING REVENUE LESS: CAPITAL EXPENDITURES NET CASH FLOW CUMULATIVE NET PRESENT VALUE BENEFIT / COST RATIO CHENA FEASIBILITY STUDY 2004 -06 290,154 17,409 .0055 165 2005 06 296,248 17,775 -O4 0055 298,508 165 63 SCENARIO 3 INCOME AND GASH FLOW STATEMENT - $ 000 Table 9.9 2001 2002 2003 06 06 06 272,616 278,341 284, 187 16,357 16, 700 17,051 O04 O04 04 16,357 16,700 17,051 0055 .0055 0055 265,221 ZT SEiE 281,373 165 165 165 56 57 59 1,459 1,502 1,548 2006 - 06 302,469 18,148 PHASE 1 REPORT 2007 -06 308,821 18,529 -O4 2008 -06 315,306 18,918 4,771 et 4,771 4,598 4,598 4,599 Bie) 575 575 9,944 9,944 9,945 Up ore 8,259 8,654 7,872 8,259 8,654 7,872 8,654 (7,873) (3,271) 1,388 1.0 1.0 1.0 FEBRUARY 1983 INCOME STATEMENT REVENUES ELECTRICITY PRICE PER KWH AT BUS BAR TOTAL FMUS DEMAND - KWH REVENUE FROM SALES TO FMUS PRICE PER KWH TO GRID EXCESS CAPACITY SOLD - KWH REVENUE FROM SALES TO GRID REVENUE - ELECTRICITY SALES STEAM PRICE PER POUND ANNUAL DSHS DEMAND 1000 LBS SYSTEM CAPACITY 1000 LB/HR PEAK DSHS DEMAND 1000 LB/HR REVENUE - STEAM SALES TOTAL REVENUE EXPENSES O & M EXPENSE FUEL COSTS POWER PURCHASES TOTAL EXPENSES NET OPERATING REVENUE CASH FLOW STATEMENT NET OPERATING REVENUE LESS; CAPITAL EXPENDITURES NET CASH FLOW CUMULATIVE NET PRESENT VALUE BENEFIT / COST RATIO CHENA FEASIBILITY STUDY SCENARIO 3 INCOME AND CASH FLOW STATEMENT - $ 000 Table 9.9 2009 2010 2011 2012 2013 06 06 .06 06 06 321,927 328,688 335,590 342,638 349, 833 19,316 19,721 20,135 20,558 20,990 04 O04 04 O04 O04 19,316 19,721 20,135 20,558 20,990 .0055 .0055 .0055 335,973 346,053 356,434 165 165 165 2014 06 357, 180 21,431 PHASE 1 REPORT 2015 2016 06 06 364,680 372,339 21,881 22, 340 04 Ol 21,881 22, 340 .0055 0055 401,170 413,205 165 165 84 87 2,273 24,613 4,771 4,771 4; 608 4, 608 751 1,261 10,130 10,640 13,957 13,973 13,957 13,973 60,192 65,001 1.3 1.3 10.000 Rev: 0 Rev. Date: 02/18/83 FINANCIAL ANALYSIS METHODOLOGY The financial analysis to be developed in Phase II of the study will incorporate the optimal scenario chosen in Phase I with various financing methods. This approach will yield the relative merits that one financing plan has over others. Inherent in the financial analysis is the assessment of costs associated with each method as well as a description and discussion of ownership assumptions and risks. The reason for developing the financial analysis based on Phase II costs is that they are more refined and reflect the amounts that will actually have to be borrowed if and when FMUS decides to proceed with this project. The pro forma income and cash flow statements developed in Phase II may also be used as a tool when seeking actual financing, determining debt service obligations, assessing the impact on FMUS operating procedures, policies and very importantly customers. The detailed financial analysis will also play a large part in determining decision criteria when viewing the City of Fairbank's alternative relative to the entire energy scene in Alaska. 0126c.021883 1O===1; Rev: 0 Rev. Date: 2/18/83 11.000 SUMMARY AND RESULTS OF ANALYSIS Benefit Net Estimated Cost Present Cost Ratio Value Scenario 1 $ 8,712,000 lees, $ 77,410,000 Scenario 2 $24,530,000 a2 $ 46,990,000 Scenario 3 $41,800,000 ey, $161,118,000 Based on both the Benefit Cost Ratio and net Present Value criteria, the ranking of the Scenarios is, from most favorable to least favorable: Scenario 3 Scenario 1 Scenario 2 0129c .021683 iB onal Rev: 0 Rev. Date: 2/18/83 12.000 SPECIAL STUDIES 12.100 RENOVATION OF THE OLD PLANT SUBSTATION 12.101 Introduction The old plant substation, consisting of an alignment of 4.16 kV metalclad switchgear cubicles, presently serves turbine generators 1, 2 and 3, the associated auxiliary and plant loads and in addition, three 4.16 kV radial feeders serving portions of the Fairbanks downtown area. The original switchgear was installed in 1951. The exact history of the installation from that date is not known, however, the majority of the circuit breakers were replaced in 1972-1973. The present installation includes at least one circuit breaker (Unit 1 main breaker) of 1951 vintage. The 4.16 kV feeder and other unit breakers were manufactured in 1972. The overall operating history of the switchgear seems generally good. The R.W. Beck report entitled "Electric Utility Five-Year System Analysis and Long Range Master Plan" dated March, 1982, indicates that one bus failure has been experienced. In addition, one circuit breaker has failed due to the entrance of water into the cubicle from the conduit. Perhaps these are interrelated in that the bus was removed from service due to the failure of the circuit breaker. The possibility of such a circumstance, however, points out 0030c.020183 12-1 Rev: 0 Rev. Date: 2/18/83 the overall vulnerability of the plant to the loss of all three turbine generators plus critical plant loads, due to a single fault. It is this vulnerability that is addressed in this report. Recommendations are developed, which when implemented, will eliminate the possibility of a total loss of the 4.16 kV plant system. 12.102 Recommendation It is recommended that, if generators 1, 2 and 3 are to remain in service for any substantial period of time, the 4.16 kV bus be sectionalized into two portions, as shown on Drawing 711-003, each section being interconnected with the 12.5 kV outdoor switchyard through its own 7500 kVA transformer. This will necessitate that two (2) 14.4 kV outdoor circuit breakers be added, together with appropriate protective relaying. Drawing 711-007 indicates this addition to the 12.5 kV system. The recommended modifications will: A. Provide a separate bus for Unit 1 (6250 kVA) and a common bus for Units 2 (2500 kVA) and 3 (1875 kVA). The common bus is found to be acceptable since Unit 3 is not normally required to run. 0030c .020183 enone 12.103 Rev: 0 Rev. Date: 2/18/83 B. Provide bus tie capabilities that will permit all units to be tied into the system through either of the two 7500 kVA transformers during an emergency. In order to assure the overall integrity of the switchgear, it will be necessary to completely checkout and test all components of the switchgear assembly at the time the modifications are performed. This includes conducting dielectric tests of the circuit breakers and 4.16 kV bus, cleaning, adjusting and mechanical testing of circuit breakers, testing and calibration of protective relays and a complete checkout and testing of all ancillary devices. Arrangements Considered The existing 4.16 kV switchgear is shown in single line form on Drawing 711-002. As can be seen, panels 1, 2 and 3 serve 4.16 kV radial distribution feeders while the balance are plant and unit related loads and services. Since it is the intent that all 4.16 kV feeders be converted to 12.5 kV as soon as possible, the schemes considered hereinafter have all been developed without concern for these feeders, i.e., it has been assumed that the feeders will have been converted to 12.5 kV prior to modifying the switchgear. When considering the subject of switchgear reliability, it is necessary to establish criteria, upon which to judge the possible arrangements. Drawing 711-001 has been prepared to illustrate a 0030c.020183 T2e==3 Rev: 0 Rev. Date: 2/18/83 scheme that is optimum for a system with switching at the generated voltage level. This scheme provides: 0 Redundant step-up transformer capacity to assure keeping all units in service at times when a step-up transformer is out of service. 0 Redundant 480 volt auxiliary power transformer capacity to assure keeping all units in service at times when an auxiliary power transformer is out of service. Oo Independent auxiliary buses at each voltage level for each unit, so that a bus fault will at worst, incapacitate a single unit. ° The capability to utilize automatic throwover schemes to minimize or eliminate time delays in restoring power upon a primary feeder loss or transformer loss. When developing recommendations for the rehabilitation and renovation of the old plant substation, it would obviously be desirable to adopt the above noted features as criteria and incorporate as many of them as is economically practical, into the final design. In addition, the need to minimize down time for the generators, dictates that the changes to existing switching equipment be relatively easy to perform. With these thoughts in mind, various schemes for obtaining 0030c.020183 12 - 4 Rev: 0 Rev. Date: 2/18/83 improved reliability have been considered. Drawings 711-003, 004, 005 and 006 depict four of the more feasible ones. The modifications required to achieve these schemes are outlined below. 12.103.1 Alternative I (Drawing 711-003) This scheme is perhaps the most ideal in that it meets all criteria previously established, other than the incorporation of redundant 480 volt service to back up each unit 4.16 kV - 480 volt load center transformer. This, however, can be accomplished readily at the time the boilers are refurbished or replaced. The scheme is accomplished with relative ease, since it requires only the following: 0 Relocation of unit 3 connections and exciter from panels 9 and 10 to panels 15 and 17. (The damaged circuit breaker with its accessories must be removed from panel 17). 0 Removal of a section of main bus in panels 6 and 13 or 14 so as to establish three separate buses. 0 Relocation of 480 volt load center C feed from panel 18 to panel 1. ° Addition of a new 4.16/12.5 kV transformer feed from panel 2. 0 Addition of bus tie connections from panels 3 and 18 to panel 2e 0030c .020183 ZS Rev: 0 Rev. Date: 2/18/83 12.103.2 Alternative II (Drawing 711-004) Alternative II is substantially equal to Alternative I in this particular installation, since unit 3 is seldom in service. With only the two larger units in service, it appears acceptable to have only two main bus sections. The modifications required are considerably simpler in that it is not necessary to relocate the unit 3 connections and exciter. The modifications that are required are: 0 Removal of a section of main bus in panel 6, to establish two independent bus sections. 0 Relocation of 480 volt load center C feed from panel 18 to panel 1. 0 Addition of a new 4.16/12.5 kV transformer feed from panel 2. oO Addition of a bus tie connection from panel 3 to panel 12. 12.103.3 Alternate III (Drawing 711-005) Alternate III provides for the addition of a synchronizing bus and the corresponding separation of the generator buses. Since syn bus tie 0030c.020183 12 - 6 Rev: 0 Rev. Date: 2/18/83 breakers are operated normally closed, it necessary that current limiting reactors be introduced into the syn bus tie circuits so as to limit the fault currents to acceptable levels when a second 4.16/12.5 kV transformer is added. These reactors can be installed external to the switchgear. Additional new metalclad switchgear is required to provide the quantity and arrangement of circuit breakers needed to accomplish the scheme. Overall, the new equipment and the modifications required to existing are: Oo The addition of a new 4.16 kV switchgear assembly with two circuit breakers. 0 Removal of a section of bus in panel 6 and panels 13 or 14 so as to establish three bus sections in the existing switchgear. oO Relocation of 480 volt load center C feed from panel 18 to panel 1. 0 Relocation of 480 volt load center B feed from panel 14 to new switchgear panel A. oO Relocation of unit 3 connections and exciter from panels 9 and 10 to new switchgear panels C and D. 0 Addition of new 4.16/12.5 kV transformer feed from panel 1. 0030c.020183 ee, Rev: 0 Rev. Date: 2/18/83 0 Addition of syn bus tie connections, new switchgear panel B to panel 15, panel 12 to panel 14 and panel 4 to panel 18. ° Addition of three current limiting reactors. 0 Relocation of existing 4.16/12.5 kV transformer feed from panel 19 to panel 10. A number of alternatives exist for the above items, however, a close analysis will indicate that irrespective of how the modifications are made, almost the same total number of changes are required. It should be noted that on those occasions when unit 3 is in service, there will be some power loss through the current limiting reactors. This seems acceptable, as opposed to adding a third 4.16/12.5 kV transformer, for those few occasions. 12.103.4 Alternate IV (Drawing 711-006) This scheme, a modification of isolation of any unit together conditions. It is anticipated and 15) would be normally open not exceed the circuit breaker either of the two 4.16/12.5 kV the traditional ring bus, provides for with its auxiliaries, under fault that two circuit breakers (panels 3 under day-to-day operations, so as to interrupting ratings. Upon failure of transformers or their high voltage supply, an automatic transformer system could be employed to 0030c.020183 LANs 12.104 0030c .020183 Rev: 0 Rev. Date: 2/18/83 disconnect the failed source and close these two circuit breakers, thus maintaining service to all bus sections. The modifications that are required are: Removal of a section of bus in panels 6 and 14 or 15. Relocation of 480 volt load center C feed from panel 18 to 1. Relocation of 480 volt load center B feed from panel 14 to panel 18. Relocation of unit 3 connections and exciter panels 9 and 10 to panels 17 and 19. (The damaged circuit breaker, with its accessories must be removed from panel 17.) Addition of new 4.16/12.5 kV transformer feed from panel 10. Addition of bus tie connections from panels 3, 4 and 14 to panels 11, 15 and 16 respectively. Discussion of Alternatives A review of the single line diagrams, Drawings 711-003 through 006 will indicate that reasonably comparable results-can be obtained with greatly different levels of modifications and additions; Alternative II Drawing 711-004 requiring the least changes and Alternative III TZ1e 9 Rev: 0 Rev. Date: 2/18/83 Drawing 711-005 requiring the most. It is also readily apparent that Alternative II requires the least "down" time and is the most economical since the changes are few. What then are the increased risks, if any, of adopting this plan? Assuming that unit 3 is seldom in service, the risk is minimal. If operating time for this unit increases, the possibility of having a single fault that incapacitates two machines (units 2 and 3) also increases. There are, however, only two fault conditions that could cause such an outage. They are: 0 A bus fault in the main bus. 0 A failure of a circuit breaker. Both of these conditions are generally avoidable in this type of equipment if the switchgear and the protective relays are in good operating condition. 0030c.020183 ZR WO 12105) Rev: 0 Rev. Date: 2/18/83 In consideration of the estimated cost and the improved reliability that can be achieved, it is recommended that Alternative II Drawing 711-004 be adopted. Serviceability of Equipment A review of the outage records for a 5-1/2 year period indicates that few faults occur on the 4.16 kV feeders presently served from the switchgear. Similarly, there is no indication that any of the other circuit breakers have been exposed to high magnitude, recurring fault currents. It is therefore reasonable to assume that the circuit breakers are presently in good condition. It is quite obvious that they should be inspected and serviced, with emphasis on the main contacts and arc chutes. In addition, the unit 1 main breaker is a model 50DH250D, a unit that was superseded in the early 1960's. Since the currently available model 50DH250E is electrically and mechanically interchangeable, it is recommended that this breaker be changed. This change will also result in all breakers being identical since the others have already been changed out. Westinghouse Electric Corporation, the manufacturer of the equipment has advised that complete circuit breaker assemblies will be . available through 1983 and all major parts through 1988. This will assure the parts supply through the renovation period. After 1988, parts will be available through the various service organizations 0030c.020183 1a 12.106 Rev: 0 Rev. Date: 2/18/83 that service and rebuild such devices. It is not felt that lack of parts will ever constitute a significant problem. The testing program that is to be included with the renovation/rehabilitation project, should include: 0 High potential testing (preferrably DC) of the switchgear main bus and circuit breakers. 0 Meggering of all low voltage wiring. oO Calibration and testing of all protective relays. 0 Testing of all interposing and lockout relays. Consideration can be given to the procurement of a complete spare circuit breaker assembly also since the capability to easily substitute any circuit breaker, enhances all future testing and maintenance programs. 4.16/12.5 kV Transformers Since all schemes considered employ a second step-up transformer to interconnect with the 12.5 kV system, it is necessary that two additional 14.4 kV circuit breakers be added in the outdoor substation for this purpose. The estimated costs contained in 0030c.020183 Nile Rev: 0 Rev. Date: 2/18/83 Paragraph IV, include the costs for these circuit breakers. Exhibit 7E depicts this connection in single line form. 12.107 480 Volt System None of the schemes considered have included provisions for a redundant source of power at 480 volt. This has been omitted from consideration herein since it can be readily accomplished as part of the plants future growth. For example, if it is decided that Boilers 1, 2 and 3 are to be retrofitted to increase their availability, the existing 460-480 volt transformers will be replaced. The new transformers can be selected with sufficient capacity to provide backup. Similarly, if a new boiler is added, redundancy can be provided as part of the new installation. The descriptions provided for the electrical system under each of the scenarios will address this subject specifically. 0030c.020183 2a=o13 Rev: 0 Rev. Date: 2/18/83 12.200 HEAT REJECTION AND UTILIZATION OPTIONS 12.201 Overview Scenarios 1, 2, and 4 utilize existing turbine generators and condensers. Scenario 3, however involves the addition of a new 30 megawatt turbine generator which will require the disposal of a large amount of heat to condense the exhaust steam, up to 152 million Btu/hour. Many methods have been used to reject waste heat from power plants. The method presently used at the MUS plant in Fairbanks is a once through cooling system. This is a common, efficient and well proven method used extensively for this purpose. Unfortunately, this method of heat rejection apparently contributes to ice fog problems in winter and may be limited by thermal discharge regulations in summer. For these reasons alternative heat rejection methods have been studied for Scenario 3 with the goal of eliminating once through cooling. Due to the high cost of energy, special consideration was taken in this study to identify methods for utilization of the low grade waste heat. 0030c.020183 Vie Rev: 0 Rev. Date: 2/18/83 12.202 Discussion of Options A mechanical draft evaporative cooling tower would typically be used for heat rejection if once through cooling water was unavailable. This is not a viable alternative in this case however, as a wet cooling tower would contribute to ice fog in winter and would be subject to severe freezing problems. Another possible method to reject waste heat is direct use wherein a hot glycol/water mix is piped to nearby users, the heat rejected via radiators and the cooled mix returned to the plant. There are significant problems with this alternative also. The temperature of the mixture is too low to economically heat offices or homes and thus is only suitable for areas such as garages or warehouses which do not require comfort level temperatures. The number of these potential direct use customers is probably limited. This means that another heat rejection system would be needed for the balance of the waste heat and to take care of low demand and load swings. The supply and return piping would be quite expensive and the capital investment probably couldn't be recovered by revenue generated from direct use sales (depending on sales, rate structure, etc.). For these reasons, direct use of waste heat outside the plant was not considered any further. Three options were chosen for further investigations. 0030c .020183 Zee Rev: 0 Rev. Date: 2/18/83 12.202.1 Option 1 In the first option, the one chosen for inclusion in Scenario 3, a dry condenser would receive the turbine exhaust steam and condense it by rejecting heat to the air and then return the condensate to the system. This option is a good choice as 1) its capital and operating costs compare favorably with the other options, 2) there is a similar system at the University of Alaska at Fairbanks which has given good service, and, 3) with year round dry operation, its environmental impact will be minimal. At full load conditions, some compromise of revenue would be suffered in the summer, due to higher condenser pressure which results in lower electrical power output. 12.202.2 Option 2 In the second option the heat from the surface condenser would be rejected to a glycol/water mix which would in turn reject heat in a cooling tower. The glycol/water mix would circulate in a closed loop finned tube system in the cooling tower. In the winter the tower would operate as a dry, air-cooled heat exchanger and in the summer there would be a water spray on the tubes to provide evaporative cooling. This option is considered the second choice due to its high operating cost, the plume from wet operation, the possibility of glycol contamination of the boiler feed water, and the lack of similar units in the Fairbanks area for comparison. In the summer, 0030c.020183 12 - 16 Rev: 0 Rev. Date: 2/18/83 at full load, there would be some compromise of revenue due to higher condenser pressure, as in the first option. 12.202.3 Option 3 In the third of these options water would be taken from the Chena River and pumped through a surface condenser, and then piped to the Tanana River where it would be discharged. There will be no loss of revenue, as the condenser pressure remains low throughout the year. Due to the high capital cost, potential for environmental and other institutional problems, and relatively high operating costs, this option was the third choice. Each of the options could have a dedicated surface condenser operating in parallel with the main heat rejection system to provide for heating the water supply for the city water treatment plant. Al] of the options use the Scenario 3 turbine (Unit 7-3) as the base case. All might be designed with some once through cooling in the summer using the Chena River. Thermal discharge regulations might preclude this activity but, if it could be permitted, it would have advantages from a system thermal efficiency, capital cost, and operating cost standpoint. This would especially be true for the dry condenser option as it would not then have to be sized for summer operation. 0030c .020183 2 a7 12.203 Rev: 0 Rev. Date: 2/18/83 A more detailed discussion of the three major options follows. Dry Condenser/Heat Rejection to City Water Plant With this option, there would be a dry condenser and a relatively small surface condenser operating in parallel serving Unit 7-3. The surface condenser would heat well water which would then be supplied to the city water treatment plant. River water could be used instead of well water if this is acceptable to the water treatment plant. However, then less heat could be rejected to the surface condenser in summer due to the higher river water temperature. The dry condenser would receive the balance of the turbine exhaust steam, condense it by rejecting heat to the air, and return the condensate to the system. The turbine exhaust design pressure was chosen to be 6" HgA at 60°F ambient dry bulb temperature. This is an unoptimized value. There is some point where the higher condenser costs are balanced by the higher system efficiency so further work needs to be done to determine the most economical backpressure. For instance, the maximum electrical power output when operating with a 6" HgA exhaust pressure, assuming 30,000 lb/hr of 25-psig extraction steam to district heating, is approximately 28,000 kw. The maximum output when operating with a 2 1/2" HgA exhaust pressure, with all other conditions being equal, is approximately 29,100 kW. Based on $.06/kWH, this means a gross loss of revenue of $1,584/day in the summer. This trade-off between capital cost and operating cost is 0030c.020183 12 - 18 Rev: 0 Rev. Date: 2/18/83 especially significant with dry condensers due to their high capital cost and the large swings in the ambient air temperature to which they reject heat (i.e., if the condenser is designed to maintain low backpressures during the relatively high ambient temperatures of summer, it will have more capacity than can be used in winter and will require about 45% more area in plan. Based on an average daily water demand of 4.54 million gallons per day in 1985 (Roen, et. al., May 1982) with well water as the source, about 20% of the Unit 7-3 heat will be rejected to the surface condenser and 80% to the dry condenser. With river water as the source of cooling water, the surface condenser will take about 11% of the heat load in summer and 26% in winter. The surface condenser will be sized to be capable of heating the maximum daily flow of the city water system while shorter term fluctuations will be damped by the city water storage system. Assuming 140-ft wells, two 100% capacity 250-hp pumps would supply the water treatment plant via the surface condenser. Normally one pump would be in service and the other in standby. In periods of high demand, both pumps would be in service. 0030c.020183 129 Rev: 0 Rev. Date: 2/18/83 The dry condenser will have four 50-hp fans which will consume 151 hp at design conditions. The condensate temperature will be controlled by varying the pitch of the fan blades and recirculating air. This allows the system fan horsepower requirements to be reduced at lower condenser loads or at ambient temperatures below the design, provides freeze protection, and prevents sub-cooling of the condensate. There is the possibility that some of the waste heat could be recovered by locating the combustion air intake in the flow path of the warm air exhausted from the condenser. For this to be worthwhile the plant layout would have to be such that the combustion air intake is relatively short or the pressure drop in the duct would be greater than the energy recovered. Also, the capital cost of any additional ducting would have to be balanced against the potential energy savings. The dry condenser will have its own controls and will control the condensate temperature. The surface condenser cooling water will have flow control based on the water requirements of the city water treatment plant. The condenser hotwell will be level controlled. The dry condenser will be located as close as possible to the turbine exhaust to minimize line pressure drop and to minimize the quantity of large diameter vacuum steam duct required. The dry condenser will be self-draining and it will have a closed loop glycol heater which provides additional freeze protection. 0030c .020183 220 Rev: 0 Rev. Date: 2/18/83 There are no permitting or institutional problems anticipated with this option. The fans on the dry condensers will be relatively noisy but as they are within the condenser housing and the system will be well within the confines of the plant the affect on the surrounding area should be minimal. The estimated budget cost of the dry condenser/surface condenser system is $2,200,000 installed. This cost includes the dry condenser, controls, fans, air recirculation system, non-condensible gas removal system, heating coil, condensate pumps, erection, and freight. The pumping cost from the wells, through the surface condenser, and to the waterplant boundary, assuming 140-ft well pumping level, 8760 hr/yr, and $.06 per kWh, is $89,400 per year. The fan power cost at the same cost for electricity is $59,400 if the fans operate at the design rate for the 8760 hours. The actual cost will be significantly less since in the colder months the fan horsepower requirements will be lower due to the pitch of fans being reduced (if air flow requirements are low enough some fans may even be shutdown). Condensate pumps power cost, using the same basis, is $21,600 per year. As noted previously, the system is not optimized and it is probable that the overall economics would not be significantly improved by balancing the efficiency in the summer (based on condenser pressure) against the capital cost of the dry condenser. 0030c .020183 epee Rev: 0 Rev. Date: 2/18/83 The price of the system is relatively high but compares favorably with the other options. This system does have the advantage of being proven in a similar service at the University of Alaska facility which is in the Fairbanks area. It is environmentally acceptable and will not contribute to ice fog problems. Part of the waste heat is recovered and supplied to the city water treatment plant. There is the possibility that the Unit 5 turbine exhaust could be piped to the dry condenser and in the winter the dry condenser (which, if sized for summer conditions, is oversized for winter) could take some or all of Unit 5's load and thus reduce the winter heat rejection to the Chena River. For these reasons, a fully optimized revision of this option is the first choice for heat rejection from Unit 7-3. 12.204 Wet/Dry Cooling Tower With a wet/dry cooling tower, there would be a closed loop glycol/water mix circulating system which will condense the turbine exhaust steam in a standard surface condenser and reject the heat in the cooling tower. The cooling tower will run as an air-cooled heat exchanger in periods of extreme cold when ice fogging might be anticipated but will have a water spray over the tubes in warmer weather. This system is sized for 4" HgA turbine exhaust pressure in the summer and 2.5" HgA in the winter. This option will also have a small surface condenser operating in parallel with the main condenser which would be used to heat well water and supply it to the city water treatment plant. The portion of the load taken by this 0030c.020183 12> 22 Rev: 0 Rev. Date: 2/18/83 condenser and the assumptions are the same as previously discussed in the section on the dry condenser option. The tower will consist of four cells each with a 125-hp fan. The circulating water pump will be 300 horsepower and the spray pumps 100-hp at 60°F ambient wet bulb. The spray pumps will be on line at design rates, at ambient dry bulb temperatures above 21°F. At design point, the wet cooling system will have 440 gpm evaporation and drift losses so this quantity of makeup would be required. With 140-ft wells, two 100% capacity 250-hp pumps will be required. With the condenser at 4" HgA in the summer, some cycle thermal efficiency would be sacrificed at full design rates. The maximum electrical power output when operating with a 4" HgA exhaust pressure, assuming 30,000 lb/hr of 25 psig extraction steam to district heating, is 28,400 kW. The maximum electrical power output when operating with a 2 1/2" HgA exhaust pressure, and all other conditions being equal, is 29,100 kW. Based on $0.06/kW this means a gross loss of revenue of $1,008 per day in the summer. If the system was run at less than design rates in the summer the adverse efficiency impact would be reduced. Further work will be required to fully optimize the system and determine the most economical turbine exhaust pressure. With this option a combustion air preheater could be incorporated into the design allowing the recovery of additional waste heat. 0030c .020183 2poecs Rev: 0 Rev. Date: 2/18/83 The glycol/water cooling tower will be self protected from freezing in the dry operating mode. The spray water system will have to be drained when going from wet to dry operation to prevent freezing. One advantage to this system is that it can be located in an area remote to the turbine. This is in contrast to the dry condenser which must be near the turbine to minimize the exhaust steam duct. In order to detect a tube leak in the surface condenser, a dedicated total carbon analyzer will continuously monitor the condensate. This will allow corrective action to be taken before glycol concentrations could buildup in the boiler feedwater system. The most serious problem with this unit from an environmental and institutional standpoint is the cooling tower drift and possibly a plume when operating in the wet mode. Although this system won't contribute to the ice fog problem as it will be operating dry during winter, residents in the area may be concerned with visible emissions from the plant. The location of the plant in the downtown area increases the plant exposure and likelihood of adverse reactions to any visible discharges to the atmosphere. The estimated budget cost of this wet/dry cooling tower system is $2,500,000 installed. This includes the tower, controls, pumps, fans, surface condensers, freight, and erection. The pumping cost from the wells, through the surface condenser, and to the plant boundary, assuming 140-ft well pumping level, 8760 hr/yr, and $.06 0030c.020183 amen cd Rev: 0 Rev. Date: 2/18/83 per KwH, is $89,400 per year. The fan power cost, with the same assumptions, is $195,600 per year and the circulating pumps power cost is $109,200 and the condensate pumps power cost is $21,600 per year. If the spray pumps are assumed to be in operation 120 days per year, then their energy cost $11,400 per year. The capital cost of this system is relatively high although it is comparable to the other options. The primary advantages of this system are the ease with which it could be modified to preheat combustion air, the fact it can be located remote from the turbine, and the fact that freeze protection is relatively simple. The disadvantages are the high operating cost, the plume, the possibility of glycol contamination of the boiler feed water and the fact that there aren't any similar units in operation in the Fairbanks area for comparison. Overall, it is felt that the disadvantages outweigh the advantages and this option is the second choice behind the dry condenser system. 12.205 Once Through Cooling With Discharge to the Tanana River With this option, cooling water will be pumped from the Chena River, through a standard surface condenser serving Unit 7-3, and discharged to the Tanana River. To accomplish this will require installation of a pumping station on the Chena River with two 100% capacity, 200-hp pumps. The river water will be pumped to the surface condenser through a 28-in NPS line. From the condenser, a 28-in underground 0030c .020183 N25 Rev: 0 Rev. Date: 2/18/83 line will follow the existing utility corridor for approximately 5 miles and will eventually discharge to the Tanana River. As in the other options, a small surface condenser, operating in parallel with the main surface condenser, will supply heated well water to the city water treatment plant. The overall plant efficiency will be maintained with this option as the condenser operating pressure could be held at the 2-1/2 inches HgA design pressure throughout the year. This option does have one special efficiency advantage in that it could, with some modifications, allow recovery of some portion of the waste heat. One way to do this would be to run two lines through the utility corridor. One line would receive the condenser discharge and would function as a supply line to users of low grade heat along the utility corridor. The other line would receive the spent low grade heating water from the users and discharge it to the Tanana River. Heat pumps would be used to remove the heat and upgrade it for space heating. Although a system of this type could recover large quantities of waste heat, there are technical, institutional, and financial obstacles which would have to be overcome to be able to do so. Technical problems are primarily associated with freeze-up and load swings. Continuous flow systems, probably similar to that used by the city water system, will have to be employed and will have to be 0030c.020183 Val > 26 Rev: 0 Rev. Date: 2/18/83 very carefully designed to accommodate load changes. The system could be designed with one header which is both supply and return, but as heat pumps only have high efficiencies over a relatively narrow design temperature range, the overall efficiency of the system would be adversely affected as their supply temperatures would change based on the load taken by the other heat pumps upstream. Institutional problems and considerations include permitting of the thermal discharge to the Tanana River, inter-basin transfer of water, ice fog on the Tanana, right-of-way acquisition, and public inconvenience. In addition, if heat recovery is attempted, customers will have to be solicited and mutually agreeable contracts developed. Possibly the worst of these problems will be associated with the thermal discharge to the Tanana River. The airport is in the vicinity and, as ice fog could be created by the discharge, interference with air traffic might occur. This option could be viewed as transferring any potential ice fog problems from the Chena River to the Tanana River. The estimated budget cost of a single 28 inch line from the plant to the Tanana River, without any heat recovery connections, will be a minimum of $4,000,000 installed and might be considerably higher when the actual route is established and detailed capitol cost estimates are prepared. The surface condenser for Unit 7-3 will be approximately $400,000. The total installed cost of the heat rejection system for Unit 7-3, with a pumping station, will be a 0030c.020183 12 - 27 Rev: 0 Rev. Date: 2/18/83 minimum of $4,500,000. The pumping cost, assuming 8760 hrs/yr per year and $.06 per kWh, is $58,800 per year. On the same basis, the condensate pumps' power cost is $21,600 and the well water pumps power cost is $89,400 per year. It should be noted that these are unoptimized costs and, depending on the demand curves, method of financing, actual power cost, probability of recovering costs through waste heat sales, etc., a smaller line with lower capital cost but higher operating cost or the inverse might be more economically attractive. With all factors considered, this option is not a good choice. This is due to its high capital cost, potential for environmental and other institutional problems, and relatively high operating costs. If a sufficient number of potential waste heat clients exist such that a reasonable return might be expected on waste heat sales, then this option would be much more attractive and further investigation of it would be warranted. TABLE 12-1 HEAT REJECTION AND UTILIZATION COST SUMMARY Capital Fan Energy Pump Energy Revenue Cost Cost Cost Loss Option 1 $2,200,000 $59,400/Yr. $111,000/Yr. $1,584/Day Dry Condenser In Summer Option 2 $2,500,000 $195,600/Yr. $231,600/Yr. $1,008/Day Wet/Dry Cooling In Summer Tower Option 3 $4,500,000 $ 0 $169,800/Yr. 0 Once Through Cooling To Tenana 0030c .020183 12 - 28 Rev: 0 Rev. Date: 2/18/83 12.300 RECOMMENDATIONS FOR CENTRALIZATION OF CONTROLS 12.301 Introduction At present, the controls and indicators for units 1, 2, 3 and 5 are not centrally located, but instead are installed in three different locations. Boilers 1, 2 and 3 are controlled and monitored locally from panels located in their common firing aisle. Turbines 1, 2 and 3 are monitored by devices located at the units while electrical controls for the governor and excitation system are located in Unit 5 control room. Unit 5 boiler and turbine generator are monitored and controlled from the Unit 5 central control room. In addition, an operator is stationed in the boiler 5 firing aisle for observation and to pull ashes. It is readily apparent that additional operating personnel are required under the present arrangement than would be needed if controls were more centralized. The feasibility of such a centralization has been evaluated and the results follow. 0030c .020183 12 - 29 12.302 12.303 Rev: 0 Rev. Date: 2/18/83 Recommendation It is recommended that the controls and instrumentation for boilers 1, 2, and 3 be replaced with new devices to be located on a central control panel positioned in the boiler 5 firing aisle. This panel will include indication for turbines 1, 2 and 3. The relocation of these devices will result in all controls for units 1, 2, 3 and 5 being in two places; the Unit 5 control room and the Unit 5 firing aisle. This will result in reduced manpower requirements for operating. This recommendation is obviously contingent upon the retention of boilers 1, 2 and 3 in service. Alternative plans for supplying steam and electricity, as discussed in the main body of this report, include specific recommendations pertinent to them. In all cases however, centralization of control is recommended. Discussion Centralization of controls reduces manpower requirements and improves efficiency by allowing an operator to monitor all units from a single location and respond quickly to any upsets and excursions. In addition, centralization helps insure the operation 0030c.020183 12 - 30 Rev: 0 Rev. Date: 2/18/83 of the plant equipment in a manner that will provide long equipment life with reasonable maintenance. The benefits are numerous. With respect to the Chena Plant however, practical limitations exist that prohibit complete centralization; the most important of which is lack of space in the central control room. In addition, since Unit 5 is a relatively new unit with reasonably modern controls, it is cost prohibitive to consider modifying it at this time. Emphasis is placed, upon improving the present situation without incurring undue costs. The controls and instrumentation for boilers 1, 2 and 3 are obsolete and inadequate. Replacement parts for these devices are unavailable commercially and thus must be specially made when required. It is quite apparent that these controls need to be replaced with modern equipment if boilers 1, 2 and 3 are to remain in service. With this realization, the problem becomes one of where to locate the new equipment so as to enhance the overall operational aspects of the plant. A review of potential locations for boilers 1, 2, and 3 instrumentation and control indicates that there is only one location that will offer some of the benefits of centralized control; the Unit 5 firing aisle. Locating these devices on new panels in the Unit 5 firing aisle will reduce the number of personnel required for operations. In addition, since the new panels will contain instrumentation that more adequately provides complete operating 0030c.020183 12 - 31 Rev: 0 Rev. Date: 2/18/83 data, increased efficiencies and longer equipment life can be obtained. The relocation of the control and instrumentation is easily accomplished by staging the installation of the new instruments on a boiler by boiler basis. The new panels can be installed in the boiler 5 firing aisle without disturbing the existing installation, with the control being cutover as the boiler re-instrumentation is completed. After complete changeover, the old panels can be removed. 0030c.020183 2ESSSc Rev: 0 Rev. Date: 2/18/83 12.400 Coal Screening The nature of the coal delivered to the Chena Station will be about constant for the next 20 years, according to the coal supplier. The high percentage of fines in the coal as received will continue to be the rule. For any stoker system there is a proper size range of coal feed which results in optimum burning efficiency and equipment protection. This proper coal feed size has the additional advantage of limiting flue dust emissions of ash and unburned coal. If the coal for Chena 5 could be screened from the incoming coal then crushed with the present equipment to give an ideal range of coal feed size, the stack emissions could be reduced and better fire control and carbon burn out could be gained. This would result in the reduction of emission from Chena 5 to the allowable level. In the Phase II of this study a feasible screening system will be designed around the present received coal size and the power plant crushing equipment. This system will greatly improve the feed size range to Chena 5. The attached graph from Babcock and Wilcox (Figure 12.1) shows the coal properties which will be controlled to reduce flue gas particulate emissions. 0030c.020183 USS Rev: 0 Rev. Date: 2/18/83 12.500 Alternative Plant Location As an alternative to the four Scenarios discussed above, M-K evaluated the possibility of siting a new coal-fired generating station at some location other than the existing Chena Generating Plant. Since the constraints and benefits of siting a new facility are similar for each Scenario (except Scenario 1), this evaluation is based on construction of a new 25 MWe facility such as Scenario 3. A summary of the evaluation results are included in this section. Two of the key objectives for alternative siting involve minimizing industrial intensity and reducing localized air quality impacts at the existing Chena Plant. Since construction of a Scenario 3 type generating station is predicated on expansion of the district hot water heating system (DHWS) the most valuable alternative plant location will be somewhere on the proposed DHWS loop. This requirement must also be balanced with the need for nearby rail facilities to support fuel deliveries. Based on these two primary constraints, an alternative site location is limited to an area north of the Chena River or near the southwestern perimeter of Fort Wainwright along the Alaska Railroad. If a new generating plant is constructed without expansion of the DHWS, the facility could be located at several locations along the Alaska Railroad including the coal mine in Healey, Alaska. 0030c .020183 1234, Rev: 0 Rev. Date: 2/18/83 Although locating a new unit somewhere on the DHWS will reduce the development intensity and environmental impact at the Chena Plant, this unit will result in new impacts at the alternative location. Most of the prime locations on the proposed DHWS loop are within previously developed areas in Fairbanks. The air quality benefits gained from relocating the Chena Station generating capacity will simply be translated into detriments in these new areas. Moving the new unit away from the main trunk lines of the DHWS could lessen the impacts on developed areas. However, distribution costs and capital costs increase abruptly as the distance between the hot water source and potential users is increased. Regardless of where the new unit is located, substantial costs will be incurred to duplicate the coal handle facilities and plant auxiliaries that already exist at the Chena Plant. Any new location will require coal unloading and handling equipment to fuel the plant. The necessary plant auxiliaries include items such as transformers, switchgear machine shop, water treatment, and others. In a 1978 report prepared for Alaska Power Authority, the consultant estimated that new electrical generating capacity in the Fairbanks area would have an installed cost of $2,100/kw (Stanley, 1978). Although this value does not reflect the economic benefits derived from a DHWS such as in Scenario 3, the installed cost of a cogeneration system would be very similar. Separate siting of a new unit also eliminates cross-over flexibility such as supplying steam to various turbine-generator sets during outages. 0030c.020183 12735 Rev: 0 Rev. Date: 2/18/83 Part of the relatively large cost per kw reported in the 1978 study can be attributed to the increased air pollution control equipment required to operate a large coal-fired boiler in Alaska. Those fossil fuel-fired boilers that sell more than 1/3 of their generating capacity as electricity to the grid and produce more than 25 MWe net annual average are subject to a 70-90% SO, removal requirement. Although the plant proposed in Scenario 3 will sell more than 1/3 of its generating capacity as electricity, it will produce less than 25 MWe on a net annual average basis. Therefore, Scenario 3 is not subject to the 70-90% SO, removal requirement. If the cogeneration aspect of Scenario 3 is eliminated, the new unit would exceed the 25 MWe criterion thus requiring 70-90% removal of potential SO, emissions. A Scenario 3 type boiler located at the coal mine in Healey, Alaska would require this SO, removal equipment since a DHWS is not available. Summary Locating a new coal fired generating station at an alternative site would provide several environmental benefits in the area of the existing Chena Plant. However, many of these benefits would be translated into detriments at most acceptable locations on the DHWS loop. The cost of distributing the hot water and installing a generating station away from the DHWS main trunk lines tends to increase with the relative distance between users and the source. Duplication of coal handling equipment and plant auxiliaries also 0030c.020183 124236 DUST LOAD LB/IOOO LB FLUE GAS DUST LOADING WITH CHAIN GRATE STOKER™ 0 10 20 30 40 50 60 70 80 90 100% PER CENT THRU |/4" SCREEN * DATA-BABCOCK & WILCOX STEAM (37 EDITION) MORRISON FIGURE 12.1 @ KNUDSEN PANEL NO, IN eee a” a @ i 7) ee 9 | 10 | Ul f(t te | | > | | Sas im | | Ga Se ee ae FUNCTION | FOR FOR | EDR, JUNIT |) UNIT I IFILLER| UNIT 2) UNIT 2.) UNIT 3) UNIT 3] 125 KV| BLANK |LOAD |LOAD | EDR (FILLER |OUT:OF| LOAD 125/440) IZSKV | BRIA, BRIA) BRIA EXCITER, BAKA PANEL IBICITER| BRAA EXCITER) BRA) FOR, | PANEL CENTERICENTEA BAIA, | PANEL | CENTER| KV | FOR alee a | | cS. |a | 8 | | cS. 1 Pe | Pray ty gt et ee ee ay 'olo!lg | | | | ca | | | | | | | | | WN Hy K' (2) gsg° (sy AVA ke > > = < Sow g § § 3 3 w ~ FF < 8.0 oS sy Se BF w< wu w : uw ,O 4 as 2c 2c = > =e = .¢€ Y¢ w sw wi 2& <3 3 S 2 2 a ¢ c eZ 2s S2 $ 2 $f st as &% 3 2% eo 2 ex er. 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CHENA FEASIBILITY STUDY 4036 DRAWING NO. REV 4.16 KV SUBSTATION-ALTERNATE *1 71-003. | O i 7\alolwoluteloslal selwl al wl al zl owt N Fi tela 1 @ tac) @ | | ! | | | | | | | | | | | | FUNCTION LOAD 1.5/4. Id Bus wT, UNIT |) FILLER, UNIT 2, UNIT2, UNIT3 unt 3!z5my | aus |Laao |Losp lepaee pasion cari-or Seine 25/Ao, 2. 5KV ICENTERIA TR TIE |EycITeR| BRKR [PANEL IECITER|BRKR |BCITER| BRKR [FOR | TIE |CENTER|CENTER|BRAR {PANEL |SeAvCE BRI |KV TA | FOR c |#2 | BARR bat ~ A | 8 t) 1cS 4.16 KV BuS* | Haig 1 4.1@KV 6US*2 | | | | cs | | ] | | | | | | | 4 | | (7.1 (94 634 | CJ | | ETI Per | Mia + tata || | Ey en | N.O. o° # REMOVE | BUS | SECTION { . (*1 e250 KvA 2500 Ey - 2 > KAVA KVA, Z z Sa 9h s S 5 8 4 3 0 G tre og dy ve er Us ee a 8 baer Zac ' oy > Wl Su ce Fa: w ‘of Sz 9§ So & oa Sz sz ; 2 o ae Eo ES Eo eR ak v 4 v r> eee tet te ISSUED. FOR PHASE | REPORT ive]. |. We ts REVISION . DESCRIPTION ON Oe | ow | EN ea @: ih [CONTRACT NO. CHENA FEASIBILITY STUDY 4036 DRAWING NO. 4.16 KV SUBSTATION - ALTERNATE * 2 711-004 a m < jo NEw METALCLAO SWITCH GEAR EXISTING METALCLAD SWITCHGEAR ee ee WNIT | Pee | | bad bd Loao! sew ! unit lunit || Loan | qe/i2s Seare leyciteal UNIT | ILLER) BLANK, UNIT. UNIT Alo asm Sun | Loaoluwit | unr FILLER Out- | UNIT |<PARE IZ SKV centes| tus | 3 | 3 ||CENTENKV TA /BRKA i PANEL! PANEL! 2 [2 |wvtR |FOR [ous center’ 2 | 3 |panecior |1 |cAKR (FOR s BAMA\EXCITERI#Y (cs. | THE | A | TIE | Tie SERVICE] THE cS. | | | | | | | T, | | | | Peo ee Ty Lt toh Porro) ot om REMOVE BUS | ~ SECTION Ss ore (2 PLACES) ) | @250 \ 2500 Kh Gia fA | 7@ ae 28 Oo Be we wt S At << PEACTORS “2 i> z< ig. 2a Z2< ‘Cc >ec Ob wl LS o% < 1e ow as ee < $2 a GE 32 L3 ce 82 Sé 2 é a PS gx TX OG Fo ES ok a> ra) Tol | ISSUED" FOR PHASE 1 REPORT [VB] | [Az | DRAWING NO, 4.16 KV SUBSTATION-ALTERNATE *3 711-005- CONTRACT NO. ; CHENA FEASIBILITY STUDY 4036 @ PANEL. NO. FUNCTION Pee ae ae 91°06) 0 aR 8 | ee ee a a @ LOAD 14.16/25! BUS {UNIT |) UNIT | FILLER) UNIT {UNIT | BLANK|4.16/125!BUS TIE’ BLANK! LOAD! BUS | BUS | BUS ‘UNIT | LOAD | UNIT 125K CENTERIKV TR | TIE |EXCITER! | PANEL|[2 12 | PANELI|KAV TRIG IZ5KV; PANEL/CENTER TIE | TIE | TIE.'3 ‘CENTEA;3 | FOR | c BRKR |éBUS TIE) BRKA BCITER: BARA | *2 |FOR | | A | BAKR| BRR. BICITER|® =| BRK | C.S. | ee | | \ | | ! | | | | Ch | Ti) | ek ce wee Ce NO. REMOVE BUS SECTION (2 PLACES): 1875 (3) ; ‘ j oe og S 8 “ +o #8 2U os wig we a 4 a x bs aot . - ike < s$ oy Gu < coe ow . $2 as Ss Ss 9 9 = 5 & GS sk mS ES we i vx FS ed ca Peete. ae |O| | ISSUED FOR PHASE! REPORT |VB/ = | (ZW | no |oare| REVISION DESCRIPTION “ DRAWN ey on ott fetal PERYae| re CONTRACT NO. CHENA FEASIBILITY STUDY @ n= : DRAWING NO, REV | 4.16 KV SUBSTATION-ALTERNATE #4 | 711-996 =| <0. ray 12.5 By EA. COWLES ST. FIRST AVE WEST GATE GAPROEN 12/1@/ 20 MVA AS%oZe |2C0A 1000 MVA& EA I2ZO0OA. il 25d0meM \2/1@/ 20 MWA 75 o0OZ 1200 A 1COO MVA NC 1200 A @ Kv BUS 12/16/20 MVA Te Z fw] 1200 A 1000 MVA 25,100 KVA CHENA FEASIBILITY STUDY 69/12.5/4.1GKV SUBSTATION GVEA ZEHNOER 4036 DRAWING NO. 711-007 Oo ; j z ° QVEe& ZENE oF KV BUE | ZOO w& | | oO. aq oy hileeta ul (ZOD A fwlt2oo aw | a: TT 100 MIVA | 12.5 Ky | COWLES = oo ST : : 1200 & x e FIRST AVE cone 1OCOMVA 25.100 KVA 71\1-CoSs, Zu 11 WESTG@ATE 711-COA CR TUN-O10 GAROEN ISLANO ar ! 1 LOu Ake 12/16/20 Mva 40 AS eZ i2. 5 KV” I2ZOOA oleae) HVA EA ISSUED FOR PHASE | REPORT ver fe Rt REVISION DESCRIPTION RS toe | on | Eh CONTRACT NO. CHENA FEASIBILITY STUDY 69/i2.5KV SUBSTATION - SCENARIOS 1,26 3200 hyo iy Rev: 0 Rev. Date: 02/18/83 CHENA FEASIBILITY STUDY W.O. NO. 4036 APPENDIX A PLANT INSPECTION REPORT Rev: 0 Issue Date: 12/15/82 CHENA FEASIBILITY STUDY PLANT INSPECTION REPORT This report presents the results of the inspection of Chena Units 1, 2 and 3 located in Fairbanks, Alaska and operated by the Fairbanks Municipal Utilities System. The inspection was performed to determine the condition of existing plant equipment for the Chena Feasibility Study scenario #1, a study of the conceptual design and economic feasibility of plant renovation. The Babcock and Wilcox Co. performed the detailed boiler inspection, which included the boiler, F.D. and I.D. fans, multiclone fly ash collectors, and air preheaters. Their report is included as Attachment A. Morrison-Knudsen personnel conducted the balance of the inspection. The inspection included the building housing Units 1, 2 and 3, mechanical, electrical, ash collection equipment, and coal handling equipment within the building. Coal handling equipment outside the plant building wall is not a part of this study and was not inspected. The inspection was performed on September 29 and 30, and October 1, 1982 and included extensive interviews with the plant staff. Summary In general, buildings and equipment are in good condition considering the age of the plant. It is well maintained and the senior staff has been at the plant since the early days of operation. This section is a brief summary of the inspection; details are presented in the "Results of Inspection" section of this report and Attachment A. ° Substructures and foundations are in good condition. 0 Structural steel frame and bridge crane are in good condition. o Buildings are in fair condition. There is no heating or ventilating system and F.D. fan air makeup from inside the building causes high 0049c. 112382 1 Rev: 0 Issue Date: 12/15/82 negative pressure in the building. 0 One circulating water well shows reduced capacity. Circulating water pumps and piping have been rebuilt and reconditioned within the last three years and are in good condition. 0 The coal handling tripper is in only serviceable condition. Coal bunkers are in good condition but their design causes operating problems. 0 The turbine-generator units are in good to excellent condition considering their age. ° The three boilers are each limited to 40,000 lb/hr due to air quality limitations and lower coal quality. They have been well maintained and are in fair condition considering their age. The controls are obsolete. 0 Mechanical dust collectors are in good condition. ° The pump ends of the boiler feed pumps are in good condition; however, turbine-end controls are inoperable. Two BFP turbines are being replaced with electric motors. ° No. 2 and 3 condensate pumps are experiencing cavitation and may need replacement soon. 0 Main condensers No. 2 and 3 were retubed within the last year and are in excellent condition: No. 1 has never been retubed. The air ejectors are in good condition. oO The feedwater heaters and the deaerator are in good condition. 0 Condensate make-up surface condensers are in good condition. 0049c.112382 2 Rev: 0 Issue Date: 12/15/82 0 Two evaporators are in good condition, two are out of commission. The chemical feed equipment is in good condition. oO Service air compressor is in fair condition. 0 The ash handling system works well but does experience fires due to carbon carryover during hard boiler firing. There is a problem with excessive dust at the dustless unloader. 0 Both high pressure and low pressure steam piping have flanged connections, with resultant high maintenance. Steam piping insulation is in poor condition with the exception of the extraction steam piping which has an aluminum jacket and is in good condition. Feedwater piping has flanged connections; insulation and lagging are jin good condition. Bearing cooling water piping is in good condition. Oo Boiler and boiler feed pump controls are obsolete and inadequate. The voltage and governor controls for Units 1, 2 and 3 in the Unit 5 control room are in excellent condition. 0 The 4160-480 volt transformers are operating satisfactorily. 0 The 4.16 kV switchgear is operating satisfactorily. A single fault could result in the loss of all circuits. oO The motor control centers are basically in good condition. Spare parts are not available. 0 The 480 volt load centers are suitable for integration into renovation plans. oO Renovation plans should include new wiring. 0049c.112382 3 Rev: 0 Issue Date: 12/15/82 oO Lighting is substandard in all areas and renovation should include a complete new lighting system. oO Motors must be evaluated on a case basis. If a pump is replaced, the motor must also be replaced. 0 The existing battery is suitable for continued usage. Plant Description and Operating History Units 1, 2 and 3, housed in a 66' x 206' x 40' building between First Avenue and the Chena River (Photo 1), were placed in service in 1952 and 1953. During their early years of operation they were in baseload service. Since Chena 5 went into operation in 1972 these units are used for intermediate-load service and are operated mostly in cold weather when electricity and steam demand is greatest. Table 1 lists their operating hours by year since 1972. Units 1, 2 and 3 are coal-fired, 50,000 1b/hr boilers supplying steam to 5-MW, 2-MW, and 1.5-MW single extraction-type steam turbine/generators, respectively. Most extraction steam is sent to the district steam heating system (DSHS). The DSHS supplies an average of 40,000 lb/hr in winter and 10,000 1b/hr in summer of steam to the downtown district, with a historical maximum load of 59,000 lb/hr. The initial phase of the district hot water system, installed in 1982, will raise the winter average extraction rate for district heating to 55000 lb/hr with an expected peak of 70,000 lb/hr. ») The boilers were designed to operate on coal having an as received heating value of 8900 Btu/lb. Approximately two years after the units were placed in service, the heating value began to decline and it presently averages 7850 Btu/]b. Plant operators expect the value may deteriorate to 7500 Btu/1b in the future. 0049c.112382 4 Rev: 0 Issue Date: 12/15/82 The output of each boiler is presently limited to 40,000 lb/hr due to environmental restrictions set by agreement with the Alaska Department of Environmental Conservation. Coincidentally, the decline of coal quality and the age and condition of the boilers also limits output to approximately 40,000 1b/hr. Coal is supplied by the Usibeli Coal Company from mines located near Healey, Alaska. Coal is delivered by train and unloaded in a track hopper located north of the Chena River. (See Photo 2.) It is conveyed to the plant over a bridge crossing the river to bucket elevators which then feed the trippers for Units 1, 2 and 3 and for Unit 5. Results of Inspection The inspection results are organized according to major equipment categories to facilitate use of the report as a companion to the restoration plan presented in conceptual design Scenario #1. 1.0 Site Development The site is in good order and has no major problems. 2.0 Substructures and Foundations The plant is constructed on a foundation mat located approximately 20 feet below grade. The foundation mat and the building walls, up to the operating floor (El. 443), are in good condition. No significant cracking or leaking was observed. 0049c.112382 5 3.0 4.0 Rev: 0 Issue Date: 12/15/82 Structural Features A braced structural steel frame supports the floors and building walls and roof. Riveted connections are used throughout the structure. The structural frame is dirty and needs to be painted for appearances purposes. It has not been allowed to rust or deteriorate, except under the windows where water leakage occurs (item 4.0 par. 3). A 20 ton bridge crane serves the turbine room. It is also designed to service, through an access well in the operating floor, equipment located in the basement below the turbine room. The crane has been well maintained and is in good condition. Buildings An insulated metal sandwich panel siding is used throughout. The roof is of insulated built-up construction placed on a metal roof deck. Single Pane casement type windows are used throughout the building. All of these building features appear to be in fair condition. There is no heating or ventilating system. Waste heat from the boilers is relied upon to keep the building warm during the winter. The forced draft fan draws air from inside the building. In the winter when the building is closed this causes a severe negative pressure inside the building. Air is drawn through cracks in doors and windows and between the laps in the siding, as evidenced by dirt streaks at the inside joints of the siding. During the winter a sheet of ice builds up from condensation which occurs on the inside of the windows. This sheet then melts and water runs into the building; in some cases down onto the top of switchgear and motor centers. (See Photo No. 3.) Ice falling off the windows poses a hazard 0049c.112382 6 5.0 6.0 Rev: 0 Issue Date: 12/15/82 to equipment and personnel. The high negative pressure and the water dripping off windows have been problems for MUS during the life of the plant. There are two fans which can blow outside air into the building. One is located in the roof above the turbine-generators; the other is above the Unit 4 gas turbine heat recovery boiler. These fans are not normally used due to excess noise, lack of control (there is no speed or pitch control), and, when they are used during cold weather, frost accumulates on interior building and equipment surfaces. Circulating Water System There are three wells located on the site which have a total capacity of about 6,000 gal/min. One of these wells is showing a markedly reduced capacity due to pluggage of the intake screens. Well water is pumped into four concrete tanks on the west end of the basement. These tanks have a volume of 15,000 gallons each. Circulating water is drawn from the tanks by the circulating water pumps, and then circulated through the turbine condensers. (See Photo No. 4.) Upon leaving the turbine condensers, the warmed water then flows to the city water treatment plant where it is used as feedwater and to the river. Average flow to the city water company is approximately 1,800 gal/min. The circulating water pumps and piping are all in good condition having been rebuilt, recoated with rust inhibiting paint, and reinsulated within the last three years. Circulating water pumps and motors are inspected and tested annually and periodically replaced as needed. Coal Handling Equipment Coal is dumped from the bucket elevators into chutes feeding a traveling tripper belt conveyor. The conveyor is furnished with 20° idlers, an 18-inch wide belt and double discharge chutes. The conveyor is 30 years 0049c.112382 7 Rev: 0 Issue Date: 12/15/82 old and has a capacity of 60 tons per hours. Work has been done to maintain the chutes at wear points and a few idlers have been replaced. Belts have been replaced approximately every 5 years. Otherwise, the tripper has not undergone a major restoration. The tripper is in serviceable but not good condition. (See Photo No. 5.) The bunkers are steel riveted catenary bottomed bunkers of 200 ton working capacity. The bunkers are in good condition but the rounded bottoms are an out-moded design and cause operating problems. Coal hangs up inside the bunkers at the rounded bottoms and between the outlets and causes occasional fires and other maintenance and operating problems. (See Photo No. 6.) An under-bunker drag chain conveyor is used to withdraw coal from the bunkers and feed the gravimetric weigh-belt feeders. The under-bunker conveyor is 27 years old and has not had a major overhaul. Occasional repairs have been made to keep it in service. (See Photo No. 7.) The scales have been taken out of service in the weigh feeders. (See Photo No. 8.) Coal is normally fed by gravity through the feeder housings of Units land2. \ The belt on the feeder for Unit 3 is still in service because Unit 3 is offset from the bunkers far enough to make gravity feeding through the feeder housing impractical. A gravity (bypass) chute located partway up the side of the bunker is provided for Unit 3. Because the chute is located partway up the side of the bunker, when coal gets halfway down in the bunker the coal is then below the angle of withdrawal and the bypass chute is of no use. The plant experiences problems with coal flow in cold weather due to the coal freezing to the bunker sides, hopper sides, and mass freezing. Plant operating practice includes spraying fuel oi] onto the coal at the railcar unloading area to alleviate the freezing problems. 0049c.112382 8 Rev: 0 Issue Date: 12/15/82 7.0 Turbine Generator Units The turbine-generators are rated as follows: Nominal Guaranteed Unit 1 5 MW 5.5 MW Unit 2 2 MW 2.2 MW Unit 3 1.5 MW 1.8 MW 7.1 Turbines 1, 2 and 3 The turbine blading is inspected bi-annually; the turbine bearings are inspected annually. All] three turbines are in excellent condition, considering their age. (See Photo No. 9.) The unit 1 lube of] pump is driven by the governor shaft. The Owner is currently changing over to a pump driven directly off the turbine shaft. The condition of the turbine lube oi] cooler and storage tank, located in the basement directly underneath the turbine generators, is good. ni 7.2 Generators 1, 2 and 3 The generators have been inspected and tested on a regular basis during recent years. These inspections and tests indicate that they are in good condition. 0049c.112382 9 Rev: 0 Issue Date: 12/15/82 Generator 1 has had the rotating exciter replaced with a new solid state exciter complete with voltage regulator. Generator 2 has a new, recently installed voltage regulator. Present plans include the installation of a new solid state exciter for this unit also in the near future. 8.0 Steam Generators Attachment A is the Babcock and Wilcox Report of Boiler Inspection of September 28, 29 and 30, 1982. Boilers are the most costly of all equipment, both in terms of initial capital cost and ongoing operations and maintenance costs. For this reason, the inspection of the boilers was the most thorough of the entire plant. Morrison-Knudsen Company, Inc. contracted with Babcock and Wilcox Co. for the boiler inspection. M-K personnel were present during the boiler inspection. M-K comments and additions to Attachment A are listed below: a) The ash handling system was replaced in 1972 with a totally pneumatic United Conveyor Corporation system of pipe, replaceable wear-back elbows, pneumatic valves, and Link-Belt clinker grinders on bottom ash hoppers. b) The note on page one should read: "These units were down-rated to 40,000 lb/hr because of air quality limitations set by the State of Alaska. They also seem to be limited to 40,000 lb/hr because of the reduced heating value of the coal." c) On page 2, Superheater, "...tube failures in the first row, first element." Since these tube failures occur about once every three years, M-K considers this problem to be relatively minor. 0049c.112382 10 Rev: 0 Issue Date: 12/15/82 d) Page 3, 1.D. Fan, "The I.D. fan was found in fair condition with erosion found on the wheel and housing." All three I.D. fans have been completely rebuilt and rebalanced, including rotors, bearings, and casings, in the last two years. M-K considers the I.D. fans to be in good condition. Past erosion of the impellers is evidence of carryover of fine ash. (See Photo No. 10.) e) The stacks were all replaced within the past five years due to corrosion. The replacements are of thicker metal which is a higher alloy material and should last twenty years more. (See Photo No. 11.) f) On page 4, "...in approximately 15 years of operation" should read 30 years. g) Unit 3 economizer is in poor condition due to a freeze-up which recently occurred. h) On page 3, operational problems are discussed. With respect to coal quality, the size and gradation is suspected as being a contributing factor. The coal size varies, but is frequently on the order of 50% less than 1/4". The high proportion of fines may be the cause of uneven burning which sometimes occurs. One result is that burning ash is carried over into the ash collection system, damaging piping and joints. i) The steam coil air preheaters are not used. This is due to freezing of condensate and corrosion inside the steam coils. Currently, the forced draft fan intake is from the building interior. j) The brickwork around the mud drums at the operating floor level is cracked in several places. 0049c.112382 11 Rev: 0 Issue Date: 12/15/82 Additional discussion of the problems and recommendations are included in Scenario 1 Conceptual Design. 9.0 Air Correction Equipment 10.0 0049 The steam generators are equipped with western precipitator mechanical dust collectors. These dust collectors are not sufficient when the boilers are fired above 40,000 lb/hr. Boiler output is limited to 40,000 lb/hr by Alaska Department of Environmental Conservation. The mechanical collectors have an efficiency of 80% and appear to be in good condition. They are inspected annually. Mechanical Equipment 10.1 Major Pumps Although there is an occasional problem with thrust bearings, the Ingersoll-Rand pump end of the boiler feed pumps are in good condition. However, the steam turbine drives are a continual problem due mainly to inoperable controls. The boiler feedpump turbines are manually controlled from the boiler firing isle whenever possible and this is adequate for baseloading situations. Two boiler feedpump turbines were manufactured by General Electric, one by Westinghouse. Two turbines are being replaced at this time with motors. Boiler feedwater control on these units will then be by flow control valves. (See Photos No. 12 and 13.) 10.2 Miscellaneous Pumps Other pumps such as circulating water pumps, condensate pumps, evaporator coil drain pumps, bearing cooling water pumps, distilled c.112382 12 Rev: 0 Issue Date: 12/15/82 water pumps, and treated water pumps all are inspected periodically and when excessive wear in the impellers is evident they are replaced rather than repaired. Plant personnel report that No. 2 and 3 condensate pumps are experiencing some cavitation and may need replacement soon. See Table 2 for status of pumps. 10.3 Condenser and Auxiliaries Main condensers nos. 2 and 3 were retubed within the last year and are in excellent condition. No. 1 main condenser has never been retubed and plant personnel report that No. 1 main condenser has four plugged tubes. The condensers are cleaned every 3 or 4 weeks. Plugs are shot through the tubes 2 or 3 times and every third or fourth cleaning a high pressure water wash is performed. Approximately 1 man-day is required for each condenser per cleaning. The shell side of the condensers appear to be in serviceable condition. The air ejectors also appear to be in good condition. (See Photos No. 14 and TSE) 10.4 Feedwater Heaters There are two high-pressure feedwater heaters in parallel in the system. Plant-personnel report that one heater was inspected about 15 years ago; and they report excellent performance from these heaters. (See Photo No. 16.) The fact that no the feedwater heater tubes have ever been plugged indicates that water quality at the Chena Station Units 1, 2 and 3 is excellent. It is possible, however, that erosion of baffle plates, tube supports, wear of tubes, and corrosion of the shell has 0049c.112382 13 Rev: 0O Issue Date: 12/15/82 occurred. The existence and extent of erosion, wear, or corrosion is unknown, as the feedwater heaters were not opened during this inspection. Since the cost of replacing these heaters is relatively minor, inspection of the units was not considered cvitical. The vertical deaerating feedwater heater, with attached horizontal storage, is in good condition. It is inspected annually for tray deterioration. 10.5 Water Treatment Equipment Water is drawn from the three wells, passes through the condensers as cooling water then goes to the city water plant. After being lime softened and chlorinated at the city water plant to become potable water, some of it is drawn back into the Chena Power Plant and run through the demineralizer in Unit 5. Water then goes from the demineralizer in Unit 5 to the evaporators in Units 1, 2, 3. (See Photo No. 17.) The product steam from these evaporators is introduced back into the system as low pressure steam to the deaerator heater. Condensate make-up is accomplished by condensing low pressure steam in surface condensers. These have been retubed recently and are in good condition. River water, approximately 300 gpm, is used as cooling water and leaves the surface condensers at 105 F°. There are four evaporators in the Chena Units 1, 2, and 3 building on the operating floor. The two at the east end are in good condition. The two at the west end are out of commission because prior to construction of Unit 5 water from the city water treatment plant was 0049c.112382 14 Rev: 0 Issue Date: 12/15/82 run directly to the evaporators, without going through a demineralizer. This resulted in extensive fouling of the evaporator internals. Unit 1, 2, and 3 chemical feed equipment is in good condition. It consists of two 100 gallon tanks of NALCO 352, two 100 gallon tanks of amine, two 100 gallon tanks of NAOH, and one 100 gallon tank of chelate. See Photo No. 18. One small (1/2 hp) reciprocating pump serves each chemical feed tank. 10.6 Compressed Air Equipment The instrument air for Units 1, 2, and 3 is supplied from the Unit 5 system, and the compressors for Units 1, 2, and 3 are in standby. (See Photo No. 19.) The service air compressor is in use and is in fair condition. (See Photo No. 20.) It is cross-connected to Unit 5. 10.7 Ash Handling System Ash is pulled from the bottom, fly, and multiclone ash hoppers with two Nash size 4001 mechanical exhausters located in Unit 5. The ash piping in Units 1, 2, and 3 join the common header for Unit 5. (See Photo No. 21.) This vacuum pneumatic ash handling system installed in 1970 works well. The only abnormal problems experienced with ash collection are related to fires in the ash piping which are caused by carbon carryover when the boilers are fired very hard. This results in overheating of conveyor piping, expansion joint failure and swing gate malfunction. It is a United Conveyor Company System with Link Belt clinker grinders on bottom ash hoppers and replaceable wear-back elbows. Valves are pneumatically actuated. 0049c¢.112382 15 Rev: 0 Issue Date: _ 12/15/82 Another problem experienced is excessive dust at the dustless unloader when unloading the ash silo into trucks. This problem is aggravated by surge of very fine ash, which are the result of segregation of ash in the silo. It is likely that the scraper bars and spray nozzles in the dustless unloader need adjustment or replacement. A vertical pipe for prevention of segregation of coarse from fine ash within the silo was removed. Replacement of this could alleviate dust surges to some degree. 10.8 Tanks Condensate storage for Units 1, 2, and 3 is located in Unit 5. 10.9 Fire Protection A portion of Chena Units 1, 2, and 3 is protected by a wet pipe sprinkler system which is in good condition. However, there is no fire protection system in the turbine-generator bay, the motor control centers, the switchgear, or the substation. 11.0 Piping Systems All high pressure and low pressure steam piping and feedwater piping has flanged connections and asbestos insulation. Most insulation on this piping is in poor condition, partly due to the need for frequent access to flanges to prevent leakage. Sootblower piping is not insulated. (See Photos No. 22 and 23.) All steam and feedwater valves should be replaced with new weld-end valves to reduce maintenance related to flanged connections. All asbestos insulation should be replaced with new calcium silicate or fiberglass insulation. Extraction steam piping has aluminum jacketing and appears to be in good condition. 0049c. 112382 16 Rev: 0 Issue Date: 12/15/82 The bearing cooling water piping has threaded connections and no insulation. It is in good condition. In some places, particularly around pumps, the arrangement is awkward and if revisions are required, they will be difficult. (See Photo No. 12.) 12.0 Controls and Instrumentation 13.0 0049 Controls for boilers 1, 2, and 3 are located either locally or centralized on panels located at the firing isles on the operating floor. (See Photos No. 24 and 28.) They are obsolete and inadequate. The boiler stoker controls were manufactured by Republic, which is no longer in business, so replacement parts are either picked up from salvage or custom made. (See Photo No. 25.) The boiler feedpump turbine controls are a longstanding problem (see item 10.1). The controls for the one steam turbine which is to remain should be replaced. Voltage and governor controls for Units 1, 2 and 3 were installed in the Unit 5 control room when Unit 5 was constructed. (See Photo No. 26.) These are in excellent condition. Steam flow from each boiler is measured using an orifice flow meter on the steam header from the boiler. These are calibrated on a periodic basis. Electrical Systems and Equipment 13.1 Auxiliary and Miscellaneous Transformers The 4160-480 volt transformers for each of the three units have been in service continuously without signs of trouble. It was not possible to conduct a detailed inspection since transformer deterioration, particularly at this voltage and with this type of ¢.112382 17 Rev: 0 Issue Date: 12/15/82 transformer, is not something that can be quantified. There is no particular reason to anticipate problems in the future. Statistics for similar units form the only base for evaluation. Small transformers, of the type utilized for lighting and receptacles were not evaluated, partially for the reasons stated above and in addition, because it was obvious that increased transformer capacity would be required to bring the lighting system up to date. 13.2 Switchgear and Accessories The 4.16 kV switchgear assembly, referred to as the old substation, serves a number of 4.16 kV feeders feeding the downtown area of Fairbanks, the three turbine generators (Units 1, 2 and 3), the three unit auxiliary transformers (A, B and C) and the 4.16-12.5 kV transformers interconnecting the 4.16 and 12.5 kV systems. (See Photo No. 27.) This latter transformer is located in the outdoor 69/12.5 kV substation. The operating record for this switchgear is generally good. One circuit breaker (panel 17) has failed due to water entering the panel through the conduit. The structural assembly, including the main bus is approximately 30 years old. The Unit 1 circuit breaker (panel 5), based upon the style number on the arc chute, appears to be a model 50DH250D unit and is one of the original circuit breakers. The remaining breakers appear to be model 50DH250E units that were installed in approximately 1972. The newer units are electrically and mechanically interchangeable with the original units. The operating personnel could not provide data as to why the circuit breakers were replaced. The alignment of switchgear includes generator auxiliary equipment and control devices for some of the 12.5 kV feeders as well as 4.16 kV circuit breakers. Included for the generators are the exciters, 0049c.112382 18 Rev: O Issue Date: 12/15/82 field circuit breakers and all generator protection. In addition, governor control and synchronizing facilities are located on the switchgear. These were utilized until the new control board was installed in the Unit 5 control room. The exact condition of the switchgear cannot be determined by inspection. Any plan for its continued use must include testing by qualified personnel and repair and/or replacement of substandard components. The switchgear is of the single bus type, without provisions for sectionalizing under fault conditions. A single fault could result in the loss of all circuits. 13.3 Motor Control Centers and Load Centers The motor control centers are basically in good condition. Unfortunately, their age (approximately 30 years) precludes the possibility of obtaining spare parts. When a circuit breaker fails, which is not too uncommon, it is necessary to have special mounting hardware fabricated. Similarly, parts for upgrading the starters are , not available. Because of this tack of parts, any renovation of the old plant should include replacing the motor control centers. The 480 volt load centers, unlike the motor control centers, utilize circuit breakers of a type that are still available. The circuit breakers have been tested at regular intervals during recent years under a maintenance program that is being continued. The load centers are suitable for integration into any renovation plans. Any such plan however, should include more complete testing by qualified personnel and repair of any questionable items. 0049c.112382 19 Rev: 0 Issue Date: 12/15/82 13.4 Wiring Systems The original wire utilized throughout the plant was of the rubber insulated type, subject to considerable deterioration with time. At present, approximately 50 percent of the power and control wire has been replaced. It is not possible to identify the specific circuits that have been changed out, however. Generally, if a motor or other electrical device has been changed or replaced, so has the wire. This is not sufficient criteria to identify all new wire. Renovation plans should include new wiring. 13.5 Lighting The plant lighting is substandard in all areas of the old installation. The original incandescent type fixtures are badly deteriorated. In many locations, they have been replaced on a one-for-one basis with fluorescent or high pressure discharge lamps, however the light distribution is still poor. Renovation plans should include a complete new lighting system. 13.6 Motors As pumps have been rebuilt, their drive motors have been substantially rebuilt through disassembly, baking, dipping, etc., and are thus in good condition. In those cases where a pump had to be replaced, a new drive motor has been provided also. As a result some number of motors are reusable in a renovated system. Specific cases, however, will have to be evaluated individually since the final mechanical requirements will dictate the need for pump replacement. If a pump is to be replaced, the motor will have to be replaced also since the motor housings are not compatible with most new equipment. 0049c.112382 20 Rev: 0 Issue Date: 12/15/82 13.7 Batteries and Emergency Power Systems The existing battery is suitable for continued usage. When it deteriorates in the future, it can then be replaced. This is practical since the normal life of a storage battery is less than the design life for the plant. It is not anticipated that the dc loads will be increased due to a renovation of boilers 1, 2 and 3. 0049c.112382 21 Year 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 TABLE 1 Rev: 0 Issue Date: OPERATING HOURS FOR UNITS 1, 2, AND 3 Unit 1 4,508 3,836 7,108 4,956 5,400 3,698 5,190 4,028 4,914 7,866 Unit 2 6,336 Loe 6,970 2,886 4,690 4,430 4,958 4,146 3,822 6,889 12/15/82 __ Unit 3 5,230 3,396 752 3,464 5,770 4,034 500 474 se 1,146 The following is a availability. list of equipment with manufacturer and model TABLE 2 number, Rev: uv Issue Date: 12/1 2 status of obsolescence as an indication of parts' Equipment Manufacturer Nameplate Data Status Unit 1 2 3 1 2 3 1 2 3 Serial No, 5-A-9958 lubes are made up and Main Condenser Elliott Westinghouse __ Westinghouse _.. 2000 sq ft replaced_as_ needed. 2-1/2 Impellers, seals, and Ingersoll- Ingersoll- Ingersoll- 250 gpm bearings are customer Boiler Feed Pumps Rand Rand Rand 1810 ft head made, as needed. Impellers and seals custom Ingersoll- Size Size Size made or entire pump Circulating H20 Pumps Rand . Westinghouse Westinghouse 12-AFV__8-AF 8-AF replaced. Impellers and seals custom Nameplate Size Size made or entire pump Condensate Pumps Westinghouse Westinghouse Westinghouse missing 22 EA 22 EA replaced, Equipment ae Manufacturer __ Nameplate Data Status S. No. S. No. Deaerating Heater Swartwout -_ 21012279, r Trays are custom made Griscom- Serial No, 38856A, Type SSU, Tubes would be made up F.W. Stage Heat. Size 15-6-160 and replaced as needed. Size 161-A-192 Evaporators Russell Co, Bentube Evaporator Type R Parts must be custom made. Ingersoll- Ingersoll- Entire pump replaced as Evaporator Feed Pumps Rand . Rand Model_A, Type 1-1/2 RV-5, 5 hp needed, Surface Condensers Worthington 4OO_sq ft, Serial 1385247 Retubed as necessary. istilled Water Pumps Inge Geol Model A, Type 2RV-7-1/2 | Rebuilt 11/82. _ Ran __ | Serial No. SA-9962-2 Air Ejectors Westinghouse Size D-2 _ Parts custom made, as required, or obtained from instrument Air Compressor Joy Joy B351B-K3351B-K_ 10 hp surplus. Parts custom made, as required, or obtained from Service Air Compressor Joy Class WG-9, Size 11X-9, 75 hp surplus, ATTACHMENT A T0 CHENA FEASIBILITY STUDY PLANT INSPECTION REPORT 3 3 Fi : & 4 Photo 1 Chena Station Looking Northwest Photo 2 Coal Car Unloading Bldg. and Conveyor Bridge Across Chena River Photo 3 480 Volt Switchgear Photo 4 Circulating Water Pumps Photo 5 Tripper Conveyor Photo 6 Coal Bunker and Under-Bunker Conveyor Photo 7 Units 1, 2, 3, Coal Bunker Catenary Bottom and Conveyor Photo 8 Units 1 and 3 Weigh Belt Feeders Photo 9 Turbine Generators 1,253 >) 4 ° Pp ° = a Induced Draft Fan Photo 11 Induced Draft Fan and Stack Photo 12 Boiler Feed Pumps Photo 13 Boiler Feed Pump Turbines Photo 14 Unit 1 Main Condenser Photo 15 Steam Operated Air Ejectors Photo 16 Feedwater Stage Heaters Photo 17 Evaporator at East End of Building Water Treatment Chemical Tanks Photo 18 Instrument Air Compressors Service Air Compressor a oO a N ° ° p p ° ° <= = a a Photo 21 Unit 3 Multiclone and Ash Pipint Photo 22 Sootblower Piping Photo 23 Basement Bracing and Steam Piping Photo 24 Units 1, 2, 3 Gauge Board Photo 25 Grate Controls and Drive, Boiler No. 2 Photo 26 Units: Iene..3 Turbine Generator Control Photo 27 4 KV Switchgear Photo 28 Boiler Units 1, 2, and 3 Firing Isle ATTACHMENT A FAIRBANKS MUNICIPAL UTILITY SYSTEM B&W REFERENCE NO. F-1747 - F-2334 DESIGN CONDITIONS Steam Flow 50,000 1b/hr @ 7500F and 625 psi How Fired Chain Grate Stoker Fuel Lignite Feedwater Temperature 2700F Present Coal BTU 7,850 BTU/1b NOTE: These units were down-rated to 40,000 1b/hr because of the poor BTU content of the coal The boilers on this job are three B&W F-Type boilers with a chain grate stoker. Units 1 & 2 were supplied under B&W Contract F-1797 and Unit 3 under B&W Contract F-2334. At the time of the inspection, Units 1 & 3 were off the line, and Unit 2 was operating. The furnace and stoker was inspected on Unit 1 with the drum, FD and ID fan, economizer and cyclones inspected on Unit 3. This report could not ‘have been written without the exceptional cooperation of the Morrison-Knudsen and Fairbanks Municipal Utility System personnel. FURNACE The furnace was found in good condition. All walls were clean with ash build-up noted on the rear arch. Slag build-up is occurring on the nose of the front arch. Overfire air is supplied just under the front arch by an auxiliary fan. Data should be taken to determine if the overfire air fan is supplying adequate amounts of air. Tube metal thicknesses of the front wall, screen tubes, and side walls were checked with everything found in order. No tube thicknesses were below the minimum requirement tube thickness and almost all were still above the design thickness. A copy of the data is located at the end of this report. The refractory on the front was found to contain many cracks. The refractory on both side walls was found in the same condition. Because ° of the type of coal being burned, the screen tubes’ must be hand lanced at least once a shift in order to keep the slagging under control. SUPERHEATER The superheater on Unit 1 was inspected and found in good condition. One tie was found broken which holds the leading two superheater tubes to the rest of the bundle. This allowed the element to swing forward about six inches into the gas lane. Tube thickness readingswere found to be in order with no readings below the design thickness. Slag has been a problem in this area, so it was recommended to install additional sootblowers in the area. Presently, each unit has two G9B type sootblowers. One problem that the customer has had with the superheater has been with tube failures in the first row (forward most) first element (closest to center). The tube lasts about three years and then becomes distorted and brittle, eventually causing it to fail. More data is needed to determine the exact cause of the failure in order to implement a proper solution. STOKER AND ASH HANDLING These units have a B&W chain grate stoker. All were found in good condition. During the thirty years of operation, less than two dozen grate keys have had to be replaced. No other grate work is on record as having been done. The compartmented stoker and air box seals are leaking in several places. The ash dumping valves under the grate are warped causing leakge of combustion air. This air leakage condition affects proper air distribution to the burning fuel. Observation of operations revealed problems with carry-over of unburned carbon in the ash hopper. Underfire air dampers were adjusted redistributing combustion air greatly reducing carryover, but not eliminating it. This condition only exists at or near the present capacity of 40,000 1b/hr (50,000 1b/hr full load). FD and ID FAN, DUCTS, and FLUES The FD fan was found in good condition with no problems noted. Presently, it is difficult to provide sufficient combustion air at the max operating load of 40,000 lb/hr. This may be caused by the lower BTU coal being burned as well as. the bad seals on the compartmented air boxes and the ash dumping valves under the grate. The ID fan was found in fair condition with erosion found on the wheel and housing. : If the unit is to be reinstated to 50,000 1b/hr a study should be performed to determine if there is adequate FD and ID fan capacity. All ducts were found in good condition. Little or no maintenance has been done on them in the past. All three stacks have been replaced within the last five years. ECONOMIZERS - DRUMS No boiler tubes have been lost (excluding superheater tubes) in approximately 15 years of operation which indicates the feedwater treatment is being proper- ly maintained. Only the drums of Unit 3 were available for inspection The steam drum was found in fair condition with pitting and oxidation noted. This is the result of the unit setting idle with a normal water level. Presently, the unit is the last to be put on-line and is used for only a couple of months during the winter. The mud drum was found in better condition with only some oxidation noted. No sludge build-up was evident. Although the drums of the other two boilers could not be checked, the customer stated that they are in much better condition. The economizers for all three units are currently running well and without problems. All have worked well in the past. DUST COLLECTORS The dust collectors for Unit 3 were checked and found to be in good condition. All were free of pluggage. Whenever a unit is down the customer inspects the collectors and performs any necessary repair work before the unit is put back on line. Presently, the collectors are able to remove the ash from the flue gas, but if capacity is increased, emissions should be checked to determine if additional collectors are required. CONCLUSIONS Overall, the units were found in good condition. Obviously, they have been well maintained. If the units are to be run for another twenty years, several items need attention. 1. 10. iT. Determine if adequate amounts of overfire air are being supplied and act accordingly. Renew bad brickwork and refractory throughout the boiler. Install IK sootblowers behind the screen tubes. Renew broken superheater ties on Unit 1, and check to see that all ties are intact on Units 2 and 3. Install IK sootblowers in the superheater. Perform a study to determine the cause of the superheater tube failures, and act accordingly. Renew the compartmented stoker air box seals. Renew the ash dumping valves under the grate. After the seals have been redone, determine if sufficient combustion air. can be supplied at 40,000 1b/hr with the present type of coal. Repair the erosion on the ID fan. Perform a study on the drums of Units 1, 2, and 3, and determine the extent of pitting and oxidation, and whether acid cleaning is necessary. If a maximum boiler steaming capacity of 50,000 1b/hr is to be maintained firing the present high ash, low BTU fuel, it appears that the following items will have to be studied in greater detail. i Or 35 4 FD and ID fan capacity Dust collector capacity Grate size - Greater gas pass pluggage leading to the installation of additional sootblowers. Cnt 42 in operation = looking touae cis Sreat ecch anc stoker feeder Unit FL Stoker bec’ @s seen wl th a Cobalt Liver Unit #2 sicker Fire as seen +heou dh & ecleal + Vilyer Scceey Tubes at the ceae df} the furnace Unit #2 { —" iy Greate and coc Feeder - Unit | Note +he con cli troy ot she brick work ch ar Te . Le wv £ L Vat Super heater element oeT oF position because oF a broken re Vat | C onteel Lor COcl Pee chey act 2 Ox; dation ia mid Clower) decom Ont 3 st Cam ‘ A “4 Ont 3 \ pul © adetion ancl Cop peg ) cly ow Cxidebion of Cuclone st pec ates WEPe* Geom Unt 3 gns 120-2 BABCOCK & WILCOX Resign Thickness ~ ZI. + | | Minivavem Thickness - O33 Desian Thickness- 150 | IbO 1,170 68 (G7 a ee Minivan Thickaas - 09% LeSy LSI en( besign Thickness £50 |. )66 | 163 Lb2 NbZ 13) Winimuin 1h chess 083° Foot We 165 165 173 -)bS 16S AMPA ie2 design Thickness ibd | 70 ATO 16s : ate | + + + + +. } ee ee eee customer ©. ake _ Ng U+ i) Sys LL sugect UT Readings ~ furnace wall “Tohe« 80S7120-2 = BABCOCK & WILCOX | 236 |23) | 240 | 233 |.24; [23¢ | 23S 227 | .242 s22b 24D 247 | 233 23 | 166 bt A702 Lb6 bt | 66 (BZ AZZ. 16 3 162 CUSTOMER SUBJECT e BPS 120-1 BABCOCK & WILCOX Su pect ter Suber | | ie | Descan eu S20 Sm M2210) 2 DyeT ue ie [244 [24 7 Liew be Niniravan Thi ekness- (03 | [ ~ Rape aio. 22M SN ZF [.2u6 hax / 238 —— cusTOMER sa Scloanks Mua Url S46 : SUBJECT Sauer chines supec hest 5 ec$ien Rev: 0 Rev. Date: CHENA FEASIBILITY STUDY W.O. NO. 4036 APPENDIX C OUTLINE PERFORMANCE SPECIFICATIONS FOR NEW EQUIPMENT REQUIRED 02/18/83 Rev: 0 Rev. Date: 02/18/83 SCENARIO 2 8.1 Boiler Type - Spreader stoker/traveling grate or Pulverized Coal Steam Flow - 150,000 1b/hr Steam Pressure/Temp. - 890 psia/950°F Final Feedwater Temp/Enthalpy - 301°F/270.7 Btu/1b Fuel - coal, run of mine crushed to minus 3/4" 7,850 Btu/1lb., 9.4% ash, 28% moisture Overall Dimensions - 26'W x 35'6"L x 43'(grate to drum) F.D. Fan - 100 HP TD: Fan |=) 250) HP Coal Pulverizer 9.1 Topping Turbine Generator Throttle Flow - 150,000 lb/hr Throttle Pressure/Temp. - 850 psig/950°F Exhaust Pressure/Temp. - 600 psig/870°F Weight - Location - Mezzanine, near Units 1, 2 & 3 9.2 L.O. Conditioner, Pump and Storage Tank Extend system for Units 1, 2 & 3 9.3 Crane Extend crane from units 1, 2, and 3 0028c .010583 Cari Rev: 0 Rev. Date: _02/18/83 10.1 Precipitator Type - Dry electrostatic precipitator Gas Flow - 44,119 scfm Gas Temp. - 330°F Cleaning Efficiency - 94% Power required - 30 kw Overall Dimensions - 18'W x 31'L x 57'H Approximate Weight - 250 tons Location - North of new boiler building 11.1 Boiler Feed Pumps Type - Horizontal centrifugal Flow Capacity - 200 gpm each, 2-60% capacity Inlet/Outlet Pressure - 90/1020 psia Driver - 300 HP Motor Weight - 9100 lbs Location - Basement 11.2 Misc. Pumps Sump pumps Glycol pumps Glycol heater condensate pumps 11.3 Condenser and Auxiliaries The existing condenser, air ejectors and condensate pumps will be used. Condenser for Unit 1 will be reconditioned and retubed. 0028c.010583 C= 2 = Rev: 0 Rev. Date: _ 02/18/83 11.4 Feedwater Heaters A. 0028c.010583 HP Heater Type - Two pass, shell and tube with desuperheat, condensing and subcooling zones Material - Stainless steel tubes, carbon steel shell Approx. Surface Area - 700 s.f. Tubeside operating conditions: Feedwater Flow - 154,500 1b/hr Feedwater Inlet/Outlet Temp. - 229°F/301°F Shell Side Operating Conditions: Shell Pressure - 65 psia Steam Flow - 11,010 1b/hr Steam Temp. - 350°F Steam Enthalpy - 1,207 Btu/1b Drain Outlet Flow - 11,010 1b/hr Drain Outlet Temp. - 239°F Drain Outlet Enthalpy - 207.43 Btu/1b Overall Dimensions - 21" diameter, 34' tube length Location - Elevation 470' Deaerator Material - Carbon Steel Operating Pressure - 5 psig Storage - 5 minutes Deaerator Effluent Flow - 154,500 Deaerator Effluent Temp. - 301°F Cais Rev: 0 Rev. Date: 02/18/83 Overall Dimensions - Storage tank 6' diameter, 8' long, overall height 10' Location - Elevation 485! 11.5 Water Treatment Equipment Evaporator capacity - 33,000 Ibs/hr Evaporator chemical feed Cycle chemical feed Water quality control - sample rack and water quality panel 11.6 Compressed Air Equipment Station Air Compressor and Air receiver Pressure - 125 psig Location - Basement 11.7) Ash Handling Fuel Burned - 14.5 tons/hr Percent Ash - 11% Total Ash Flow - 34.8 tons/day Scope - Pneumatic system includes bottom ash hopper and clinker grinder, ash piping, valves, fittings and elbows with replaceable wear backs (system will be tied to existing vacuum producers and silo). 11.8 Tanks Condensate Storage Tank Capacity - 2 at 25,000 gallons each Material - Stainless Steel 0028c .010583 C- 4 - Rev: 0 Rev. Date: _02/18/83 Weight - 16,000 lbs each Boiler Blowdown Tank 11.9 Fire Protection System CO, flooding system for coal bunker, interior spaces of lube oil and hydrogen cooled equipment. Zone type sprinklers for the building. Hose stations and portable extinguishers as required. 11.10 Misc. Equipment Extension of Unit 5 vacuum cleaning system. 0028c.010583 (ea Rev: 0 Rev. Date: 02/18/83 SCENARIO 3 8.2 Boiler Type - Spreader stoker, traveling grate Or Pulverized Coal Steam Flow - 286,000 lb/hr Steam Pressure/Temp. - 890 psia/950°F Final Feedwater Temp./Enthalpy - 453°F/433.42 Btu/1b Fuel - Low grade coal Run of mine crushed to 3/4" minus 7,850 Btu/1b 9.4% ash 0.2% sulphur 28% moisture Overall Dimensions - 39'W x 39'L x 90'H F.D. FAn - 150 HP 1.D. Fan - 350 HP Coal Pulverizer 9.1 Turbine Generator Throttle Flow - 286,000 lb/hr Throttle Pressure/Temp. - 850 psig/950°F Backpressure - 2.5" Hg Automatic extraction - 25 psia 0028c.010583 C- 6 - Rev: 0 Rev. Date: Uncontrolled extractions - 435.5 psia 196 psia 78 psia Overall Dimensions - 11' x 39! Location - North end of new building 9.2 Turbine Lube Oi] Conditioner, Pump and Storage Tank Location - Basement 9.3 Crane Extend crane from Unit 5 10.1 Precipitator Type - Dry electrostatic precipitator Gas Flow - 72,553 scfm Gas Temp. - 330°F Collection Efficiency - 97% Power required - 50 kw Overall Dimensions - 30' W x 31' L x 60' H Approx. Weight - 450 Tons Location - Turbine building roof 11.1 Boiler Feed Pumps Type - horizontal Flow Capacity - 390 gpm each, 2-60% capacity 0028c.010583 Cea 02/18/83 Rev: 0 Rev. Date: —_ 02/18/83 Inlet/Outlet Pressure - 90/1060 psia Driver - 350 HP motor Weight - 9,500 Ibs Location - Basement 11.2 Misc. Pumps Closed cooling water pumps: Type - Horizontal Capacity - 790 gpm, 2-100% capacity Total Head - 35 feet Motor - 15 HP Weight - 770 lbs Location - Basement Sump pumps: Glycol pumps: Glycol heater condensate pumps: 11.3 Condensers Dry Condenser Type - four cell, A-frame forced draft, air cooled condenser; non-condensible removal system, controls & freeze protection equipment included. 0028c .010583 (Coat t= Rev: 0 Rev. Date: _ 02/18/83 Operating Pressure - 6" HgA Summer 2.5" HgA Winter Summer Ambient Air Design Temp. - 60°F db Materials - Carbon steel inner tubes and headers, aluminum outer tubes and fins Fans - Four 50 hp variable pitch fans Overall Dimensions - 60' x 70' x 35' High Location - North of new building Steam jet air ejector system included Condensate Pumps Type - Vertical Capacity - 2-100% Discharge - 100 ps. Motor - 40 hp each Location - North end of basement Wet Condenser Type - Tube and shell Operating Pressure - 6" HgA Summer 2.5" HgA Winter Materials - Carbon steel shellside Stainless steel tubeside Tubeside - Inlet cooling water - 33°F Outlet cooling water - 60°F 0028c .010583 Cao Rev: 0 Rev. Date: _ 02/18/83 Flow - 1,578,000 1b/hr Overall Dimensions - 42" diameter, 10' long Steam jet ejector system included. Condensate Pumps Type - Vertical turbine Capacity - 2-100% capacity Discharge Pressure - 100 psi Motor - 15 hp each 11.4 Feedwater Heaters Type - Two pass, shell and tube with desuperheat, condensing and subcooling zones Material - Stainless steel tubes, carbon steel shell A. Feedwater Heater No. 1 Tubeside operating conditions: Max. Feedwater Flow - 236,661 lb/hr Feedwater Inlet/Outlet Temp. - 108.7°F/235°F Shell side operating conditions: Shell Pressure - 25 psia Max. Steam Flow - 26,155 lb/hr Steam Enthalpy - 1,207.1 Btu/1lb 0028c.010583 C- 10 - Rev: 0 Rev. Date: — 02/18/83 Max. Drain Outlet Flow - 26,155 lb/hr Drain Outlet Temp. - 118.7°F Drain Outlet Enthalpy - 86.67 Btu/1b Dimensions - 29" diameter, 41' long B. Feedwater Heater No. 3 Tubeside operating conditions: Feedwater Flow - 294,600 lb/hr Feedwater Inlet/Outlet Temp. - 312°F/380°F Shell side operating conditions: Shell Pressure - 196 psia Steam Flow - 18,500 lb/hr Steam Enthalpy - 1,341.2 Btu/1b Drain Inlet Flow - 22,206 1b/hr Drain Inlet Temp. - 390°F Drain Inlet Enthalpy - 364.7 Btu/1b Drain Outlet Flow - 40,707 lb/hr Drain Outlet Temp. - 322°F Drain Outlet Enthalpy - 292.3 Btu/1b Dimensions - 27" diameter, 37' long 0028c.010583 Coeur Rev: 0 Rev. Date: 02/18/83 C. Feedwater Heater No. 4 Tubeside operating conditions: Feedwater Flow - 294,600 lb/hr Feedwater Inlet Temp./Outlet Temp. - 380°F/453°F Shell side operating conditions: Shell Pressure - 435.5 psia Steam Flow - 22,206 1b/hr Steam Enthalpy - 1,413.8 Btu/hr Drain Outlet Flow - 22,206 lb/hr Drain Outlet Temp. - 390°F Drain Outlet Enthalpy - 364.7 Btu/1b Dimensions - 26" diameter, 31' long D. Deaerator Material - Carbon steel Operating Pressure - 78 psia Storage Capacity - 5 minutes Max. Condensate Flow - 236,661 lb/hr Condensate Temp./Enthalpy - 235°F/203.6 Btu/1b Max. Drive Steam Flow - 19,929 lb/hr Drive Steam Pressure - 78 psia Drive Steam Enthalpy - 1284.6 Btu/1b Deaerator Effluent Flow - 294,600 lb/hr 0028c .010583 ConlZes Rev: 0 Rev. Date: 02/18/83 Deaerator Effluent Temp./Enthalpy - 310°F/280.3 Btu/1b Dimensions - storage tank 8' diameter, 12' long Total Height - 17! 11.5 Water Treatment Equipment Evaporator Capacity - 9000 lbs/hr Evaporator Chemical Feed System Cycle Chemical Feed System Water Quality Control - sample rack and water quality panel Surface Condenser Cooling Water Chlorination System 11.6 Compressed Air System Air Compressor Capacity - 400 scfm (each of 2) After Cooler Discharge Pressure - 125 psig Air Receiver Capacity - 2 at 400 gallons each Air Dryer, Prefilter, Afterfilter - 300 scfm 11.7 Ash Handling Fuel Burned - 24 tons/hr Percent Ash - 10% Total Ash Flow - 57.6 tons/day Silo Capacity - 5 days Scope - Pneumatic system includes bottom ash clinker grinder, ash piping, fittings and replaceable wear back elbows, vacuum producer, silo, cyclone separators, unloader, filter. 0028c .010583 Corsa Rev: 0 Rev. Date: — 02/18/83 11.8 Tanks Condensate storage tank: Capacity - 2 at 25,000 gallons each Material - Stainless steel Weight - 16,000 Ibs each Boiler blowdown tank Closed cooling water head tank: Capacity - 700 gallons Material - Carbon steel Weight - 1600 lbs. 11.9 Fire Protection System CO, flooding system for coal bunker and interior spaces of lube oil and hydrogen cooled equipment. Zone type sprinkler system for building. Hose stations and portable extinguishers as required. 0028c.010583 C> 14 \> Rev: 0 Rev. Date: _ 02/18/83 11.10 Misc. Equipment Extension of Unit 5 vacuum cleaning system. Closed cooling water heat exchanger: Type - Two pass, shell and tube Materials - SS tubes, CS shell Capacity - 2-100% Duty - 4.3 million Btu/hr Component Cooling Water Flow - 720 gpm Dimensions - 13" diameter, 17' long Weight - 2500 Ibs. 0028c .010583 Ca=15== Rev: 0 Rev. Date: 02/18/83 CHENA FEASIBILITY STUDY W.O. NO. 4036 APPENDIX D CRITERIA AND ASSUMPTIONS Rev: 0 Rev. Date: 2/18/83 APPENDIX D Criteria and Assumptions D.1 General 1. Plant elevation 443 feet above sea level. 2. Environmental factors: Winter normal daily high temp: scat Fy Winter " iu low temp: -22 °F Summer" "high temp: ou Summer" i low temp: SOnGE Winter design dry bulb @ 99% : _-51 °F Summer design dry bulb @ 2.5%: ye” Summer design wet bulb @ 2.5%: 60 °F 3. Cost of coal per ton from Usabelli $2.07/MMBtu @ $32.28/ton + escalation based on 8500 Btu/1bm $1.92/MMBtu @ $30.00/ton based on 7850 Btu/1bm 4. Poker Flats Average Coal Analysis, November 1981 (adjusted to as received basis) Carbon 45 Hydrogen S00) Nitrogen 1 Oxygen 15 Sulphur 0.19 Total Moisture 28% Ash 9.42% Heating Value 7,850 Btu/1b. 5. Coal ash analysis - Poker Flats Average Coal Analysis, November 1981 Si 0, - 40.8% by weight Al, 0, - 21.3% Fe, 0, - 7.6% Na, 0 - 1.1% Ky ON 221% THO, =) tas Ca 0 - 16.2% Mg O - 2.7% 6. Plant on-stream factor = 85% 7. Seismic zone 3. Foundation type: spread footings, continuous building mat. 0015c.012883 [D) et pal Rev: 0 Rev. Date: 2/18/83 8. Soil studies available: No permafrost. Frost penetration = 8 feet. 9. New equipment design factor = 1.2 X operating flows 10. New coal delivery system capacity = 150 ton/hour to plant interface. 38°F winter 42°F summer 6,500 gpm max. 11.Well water, temp. 33°F winter 59°F summer 12. River water, temp. 13. Raw water analysis: Mineral Lab Report of River Water Analysis, May 1972. 14. Total extraction capacity to DSHS = 135,000 1b/hr through turbine Units 1, 2 and 3. D.2 Data on Existing Units 1. Turbine-Generator Data Unit #1 Unit #2 Unit #3 TURBINE Manufacturer Elliott Westinghouse Westinghouse KW 5,000 2,000 1,500 RPM 3,600 3,600 Max KW 5,500 2,500 1,875 Steam pressure, psig 600 600 600 Steam temperature, °F 750 750 750 Extraction steam pressure, psig 50 50 50 Max extraction flow, lb/hr 60,000 40,000 35,000 Exhaust pressure, inittgA 1-5) 15 lao) Serial No. 18024 GENERATOR KVA 6,250 2,500 1,875 Voltage vac 4,160 4,160 4,160 Current amps 868 347 260 Phases 3 3 3 Stator temperature rise, °C 6 Rotor temperature rise, °C 8.5 RPM 3,600 Power factor, % 80 80 80 Frequency, hz 60 Exciter current, amps 238 168 168 Exciter voltage, v 125 125 125 Serial No. 18-9737 0015c .012883 Deore Rev: 0 Rev. Date: 2/18/83 2. Boilers 1,2, and 3: Actual efficiency = 66% Nameplate design conditions: Steam flow = 50,000 1b/hr Steam temperature = 750°F Steam pressure = 675 psig Fuel = lignite coal Firing method: chain grate stoker Feedwater temperature = 335°F. 3. Units 1,2,3 F.D. Fan Motor voltage = 480 V, 25 hp @ 1175 rpm I1.D. Fan Motor voltage = 480 V, 100 hp © 1785 rpm 4. Existing coal bunker capacity= 200 tons for Units 1, 2, 3. 5. Efficiency of mechanical dust collector for Chena 1, 2, 3= 80%. 6. Stack height above grade: Units 1, 2, 3 = 82.5 feet. 7. No. 3 multiclone nameplate data Western Precipitator Corp. Type: 9VGA12 Size: 55-5 Model: P217C2A Serial: 2906 8. Ist & 2nd effect evaporator nameplate data Manufacturer: Griscom-Russel Company U-69 WP Shell 150 Ibs or 30" VAC HSB WP Tubes 150 Ibs 13169 Max shell 366°F Temps tubes 450°F 38568A 1951 9. East-end evaporators (being used) nameplate data Manufacturer: Griscom-Russel Company Size 161-A-192 Serial 54S90A 1954 Shell 150 psi & 50" VAC 366°F Tubes 150 psi 450°F 10. No. 1 Hotwell pumps 6" inlet, 4" outlet, 15 h.p. 1750 rpm, Westinghouse, quantity - two 11. No. 3 Hotwell pump 4" inlet, 2" outlet, 15 h.p., 1750 rpm, Westinghouse 12. Units 2,3: Circ. Pumps (Raw H,0 Pumps) Westinghouse Size 8AF Serial A9960 30 h.p., 1750 rpm Unit 1: Circ Pumps Ingersoll-Rand Size 12-AFV 0015c.012883 D- 3 Rev: 0 Rev. Date: 2/18/83 13. Unit 5 Boiler, press = 915 psig temp. = 905°F flow = 200,000 1b/hr efficiency = 81% Turbine Throttle Conditions press. = 850 psig temp. = 900°F Turbine Heat Rate = 10,835 btu/kwh Feedwater, temp. 335°F Existing coal bunker capacity 450 tons Stack height above grade: = 158 feet. 14. District Steam Heating System (DSHS) Current average steam load to DSHS: Winter = 40,000 lb/hr = 40 X 10° Btu/hr Summer = 10,000 1b/hr = 10 X 10° Btu/hr 6 Average steam load to district heating after installation of initial phase of hot water system: Winter = 55 x 10° Btu/hr. Gross capacity of existing Units 1, 2, 3 and 5 = 175,000 lb/hr steam to DHS. Firm capacity (gross capacity - largest Unit) = 115,000 lb/hr steam to DHS. 15. Average 1981-82 electrical demand on Chena: Winter = 23.2 MW, Peak = 26. Summer = 19.2 MW, Peak = 19. (From 5 Year System Analysis & Long Range Master Plan - R.W. Beck, Page T=4) 5 8 16. No of operating personnel per shift = four 17. Condensate return from existing DSHS, temp. = 138 °F 18. Waste heat rate from Units 1, 2, 3 and 5 condenser circulating water = 20 x 107 Btu/hr., average D.3 Data and Assumptions for Individual Scenarios Scenario 1 is referred to as Unit 7-1, Scenario 2 as Unit 7-2, Scenario 3 as Unit 7-3 and Scenario 4 as Unit 7-4 1. Hot water heating system: 248°F leaving plant 138°F return to plant 2. Coal boiler efficiency = 81%, Units 7-2, 7-3, 7-4 0015c.012883 Deana: 10. Rev: 0 Rev. Date: 2/18/83 Feedwater temperature = 301°F for Units 7-2. 453°F for Unit 7-3. Use existing wells and pumps for Unit 7-2 and 7-4. Feedwater system for Unit 7-3 to include three feedwater heaters, one deaerator, two 100% capacity motor drive feedwater pumps. Feedwater system for Unit 7-2 to include one feedwater heater, one deaerator, and two 100% capacity motor drive feedwater pumps. Coal bunker capacity for Units 7-2, 7-4 = 350 tons. Coal bunker capacity for Unit 7-3 = 540 tons. Flue gas exit temperature for Unit 7-2, 7-3, = 330°F. Scenario 1 = 360°F Stack Stack height above grade: Unit 7-1 = 180 feet Unit 7-2 = 180 feet Unit 7-3 = 180 feet Unit 7-2 = 11 feet Unit 7-3 = 14 feet Inside stack diameter: Unit 7-1 = 11 feet Unit 7-1* Unit 7-2 Unit 7-3 Heat input: Btu/hr 221.3 x 10° 225.7 x 10° 371.1 x 10° Fuel consumption: Ton/hr 14.1 14.4 23.6 Steam production: 1b/hr 150,000 150,000 286 , 000 Throttle Steam temperature, ale : - ce 700 950 950 Throttle Steam pressure, psig 600 850 850 Flue gas mass flow, lb/hr wet 223,000 227,419 373,980 Flue gas volume flow, DSCFM 43,263 44,119 72,553 Flue gas volume flow, ACFM 77,665 76,303 125,479 Particulate emissions, gr/dscf 0.1 0.1 0.05 SO, emission, ppm, (lb/hr) 374(77) 374(78) 374(129) NO. emission, ppm, (1b/hr) 375(78) 375(79) 375(129) CO emission, ppm, (1b/hr) 137(28) 137(29) 137(47) Flue gas molecular weight (1b/1b-mole, dry) 30.68 30.68 30.68 0015c.012883 Deen! Rev: 0 Rev. Date: 2/18/83 11. MSW MSW boiler efficiency = 65% MSW density = 18.5 1b/ft? MSW design flow rate = 182 ton/day (Based on Telecon Report MK-TC-12 of 9/10/82 between Bill Lewis of M-K and Don Moore of Fairbanks North Star Borough) MSW storage pit capacity = three days Refuse Derived Fuel Analysis Combustibles 55.8% (by weight) Ash 25.0 Moisture 19.2 Municipal Solid Waste Analysis (Based on "Environmental Assessment of a Waste-To-Energy Process": Braintree Municipal Incorporated, Midwest Research Inst., EPA-600/7-80-149, Table 6 Pg. 21) H,0 19.21% (by weight) Ash 25.00 (Includes glass, metal, etc.) Cc 27.63 H 3.60 0 edna S 0.91 N 0.17 Heat Value 4,500 Btu/1b 12. Auxiliary system voltages: Unit 7-2 Unit 7-3 Unit 7-4 480 Volt 480 Volt 480 Volt 4160 Volt 0015c.012883 De=e6 Rev: 0 Rev. Date: _ 02/18/83 CHENA FEASIBILITY STUDY W.0. NO. 4036 APPENDIX E REFERENCES APPENDIX E References Acres American Incorporated. July 1981. City of Fairbanks, Alaska, District Heating System Development, Final Engineering Report. Alaska Systems Coordinating Council. November 1982. 20-Year Energy and Peak-Load Forecast Summary. Anderson, F.M. and M.F. Geigor. 1978. Annual Management Report 1978 Yukon Area. Alaska Department of Fish and Game. Juneau, Alaska. Babcock and Wilcox Co. 37th Edition. Steam, Its Generation and Use. Baldig, G.O. 1976. Alaska Water Assessment, Water Availability and Use in the Alaska Region. Alaska Water Study Committee. R. W. Beck and Associates, Inc. March 1982. Electric Utility Five-Year Sys- tems Analysis and Long Range Master Plan, Municipal Utilities System, City of Fairbanks, Alaska. Beelman, J. 1983. Personnel Communication, Alaska Department of Environment Conservation. 0126c.021883 Ee Environmental Services Department. 1979. Air Quality Attainment Plan - Part I_and II. Fairbanks North Star Borough. Fairbanks, Alaska. Environmental Services Division. 1982. Air Quality Attainment Plan - Volume 2 "A Decision Making Guide". Fairbanks North Star Borough. Fairbanks, Alaska. Joy, R. 1982. Personnel Communication, Fairbanks North Star Borough. Municipal Utilities System - Power Plant Statistics, 01/24/83. National Oceanography and Atmospheric Administration. 1979. Climatic Atlas of the United States. U.S. GPO. Roen Design Associates, Inc. and Bell-Walker Engineers, Inc. May 1982. Water System Master Plan, City of Fairbanks, Alaska, Municipal Utilities System. Sierra Research. 1982. Carbon Monoxide Air Quality Trends in Fairbanks, Alaska. Prepared for the Fairbanks North Star Borough by Sierra Research, Sacramento, California. Py U.S. Army Corps. of Engineers. 1980. Final Environmental Impact Statement, Prudhoe Bay Oi] Field Waterflood Project. U.S. GPO. 0126c .021883 Euan