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Home My WebLink AboutAPA2920FEDERAL ENERGY REGULATORY COMMISSION PROJECT No.7114 SUSITNA HYDROELECTRIC PROJECT DRAFT REPORT NOVEMBER 1985 DOCUMENT No.2920 Alaska Power Authority ===:::::::::::j DEFINITION AND COSTS OF THERMAL POWER AL TERNATIVE$ ITO SUSITNA ~=~lli3~®©@ JOINT VENTURE .- - J~, - SUSITNA HYDROELECTRIC PROJECT DEFINITION AND COSTS OF THERMAL POWER ALTERNATIVES TO SOSITNA Report by Harza-Ebasco Susitna Joint Venture ARLIS .Alaska Resources Library &Infonnatlon Servtces Anchorage,Alaska Prepared for Alaska Power Authority Draft Report November 1985 Document No.2920 Susitna File No.40.14,(-Itt~S I S<D f'lrl~ t'\Q '~'l J..C -- - - - NOTICE ANY QUESTIONS OR COMMENTS CONCERNING THIS REPORT SHOULD BE DIRECTED TO THE ALASKA POWER AUTHORITY SUSITNA PROJECT OFFICE f~ SUSITNA HYDROELECTRIC PROJECT DEFINITION AND COSTS OF THERMAL POWER ALTERNATIVES TO SUSITNA TABLE OF CONTENTS Page EXECUTIVE SUMMARY 1.0 INTRODUCTION .. . ..···· ··· · · · ··· ·· · · 1-1-1.1 HISTORIC SOURCES OF THERMAL ELECTRIC GENERATION .·1-1 1.2 THERMAL ENERGY SOURCES CONSIDERED FOR THE RAILBELT 1-3-1.2.1 MSW-Fired Power Plant 1-4·· · · · · · · ··1.2.2 Nuclear Power · ······1-4 1.2.3 Biomass-Fired Power Plants.· · · · 1-5 1.2.4 Coal-Fired Power Plants · ·· ···1-5 1.2.5 Uatural Gas-Fired Generation.·· ··1-6 1.2.6 Oil-Fired Generation.······ · · 1-7 ~1.2.7 Other Unconventional Thermal Sources •1-8 1.2.7.1 Fuel Cell s ·· · · ·· · ·· · · · 1-8 1.2.7.2 Sol ar Energy ·1-9-1.2.7.3 Geothermal 1-9·· · ·· · ·· 2.0 CRITERIA FOR CONCEPTUAL DEVELOPMENT · · ···2-1 2.1 COAL-FIRED .. .··· ··· · · 2-1 ~,2.1•1 Plant Size and Configurations 2-2 2.1.2 Steam Cycle Selection ·· ··2-4 2'.1.2.1 Boiler · ·· ··· · · 2-4-2.1.2.2 Turbi ne-Generator •2-4· · ·· · · ·2.1.2.3 Waste Heat Rejection 2-5 2.1.2.4 Feedwater System · ·· · 2-5 ~ 2.1 .3 Emission Control s · · · · ···· · ··2-6 2.1.3.1 Sulfur Dioxide Removal · · · · · 2-6 2.1.3.2 Particulate Removal ···· · 2-6 2.1.4 Fuel Yard · · · ·· · · · · 2-7 2.2 NATURAL GAS FIRED .· ··· ·· ··2-8 ,....2.2.1 Simple-Cycle Plants · · · ··2-8 2.2.1.1 Plant and Unit Size 2-8 2.2.1.2 Plant Configuration.· · ···· · · · 2-8- .....2265C ; TABLE OF CONTENTS (Continued) 2.2.2 Combined-Cycle Plants .•.• Page 2-8 2.2.2.1 Plant Size 2-8 2.2.2.2 Plant Configuration.2-9 2.2.2.3 Steam Cycle Selection . . . • . . ...2-9 3.1 PLANT DESCRIPTION ..• 3.0 THE COAL PLANT ALTERNATIVE 3.1.1 General Arrangement of the Plant .. 3.1.2 Major Plant Components and Functions. 3.1.2.1 Fuel Receiving,Processing,Storage, and Reclaim ....••..... 3.1.2.2 Combustion Air Supply .•. 3.1.2.3 Steam Generator . 3.1.2.4 Turbine-Generator . 3.1.2.5 Feedwater and Condensate Systems 3.1.2.6 Flue Gas Cleaning Systems .... 3.1.2.7 Solid Waste-Handling and Disposal 3.1.2.8 Water and Wastewater Treatment .••. 3.1.3 Plant Operating Parameters .. 3.2.1 Basis of Estimates. 3-1 3-1 3-1 3-1 3-1 3-7 3-7 3-9 3-9 3-10 3-12 3-12 3-13 3-13 3-14 3-14 3-17 3-17 3-17 3-19 3-19. . . Boiler Efficiency .. Plant Auxiliary Loads Heat Balance . . . . . ••••. Turbine-Generator Operating Parameters .•. . • • . . Net Output and Heat Rates . Other Operating Parameters 3.1.3.1 3.1.3.2 3.1.3.3 3.1.3.4 3.1.3.5 3.1.3.6 3.2 CAPITAL COST ESTIMATES ... -- .- - 3.2.1.1 Plant Concept in Accordance With Description ••••....0 •• 3.2.1.2 Labor Assumptions . 3.2.1.3 Financial Assumptions .••.• 3.2.1.4 Site-Specific Assumptions .•. 3.2.1.5 Items Specifically Not Included 3.2.1.6 Included Indirect Costs .••..... 3.2.1.7 Professional Services ....• 3-19 3-19 3-20 3-20 3-20 3-21 3-21 2265C ii - TABLE OF CONTENTS (Continued) 3.2.2 Details of Estimates. 3.2.2.1 Beluga Site. 3.2.2.2 Nenana Site . Page 3-21 3-21 3-25 3.2.3 Comparison of APA Capital Cost Estimates to Estimates for Similar Plants in Alaska.3-29 3.3 O&M COSTS . . . . . . . . . . • . . . . . . . . .3-31 3.3.1 O&M Cost Development Based on Utility Data. 3.3.1.1 3.3.1.2 _3.3.1.3 3.3.1.4 3.3.1.5 3.3.1.6 3.3.1.7 3.3.1.8 3.3.1.9 P1ant-Staff and Wages ..... FGD System Maintenance Costs . Landfill Costs ....•. Chemical Makeup Costs (Lime and Limestone ......•.. Particulate Removal System Maintenance.. . . ....... Boiler Maintenance Costs •.... Coal-Handling Equipment Maintenance .. Turbine-Generator Maintenance Costs .• Other Costs (Cooling Tower,Water Treatment,and Lubricant Costs) 3-33 3-34 3-34 3-36 3-36 3-37 3-37 3-37 3-37 3-38 ,..... 3.3.2 O&M Costs Development Based on Vendor Data and Engineering Review ... 3.3.2.1 Basis for Costs . 3.3.2.2 Costs . 3-38 3-38 3-39 3.3.3 Comparison of APA Coal-Fired Plant O&M Costs to Those Developed by Others.. . . . .3-53 - 4.0 THE GAS-FIREDCT ALTERNATIVE. 4.1 PLANT DESCRIPTION . • • . 4.1.1 General Arrangement . 4.1.2 Major Plant Components and Functions. 4.1.2.1 Turbine-Generator Package. 4.1.2.2 Plant Auxi1ia~Systems. 4.1.3 P1 ant Operating Parameters ...•.. 2265C iii 4-1 4-1 4-1 4-3 4-3 4-3 4-7 l§~'''~''~~'---'''''''''-----''''''----~----------''-i------ ,'... TABLE OF CONTENTS (Continued) 4.1.3.1 Turbine-Generator Efficiencies 4.1.3.2 Plant Auxiliary Loads .•• 4.1.3.3 Net Output and Heat Rates. 4.2 CAPITAL COST ESTIMATE ..• 4.2.1 Basis of Estimate •. 4.2.2 Details of Estimate 4.3 O&M COSTS .•..•••... 4.3.1 O&M Cost Estimate Based on Utility Data Page 4-8 4-10 4-10 4-11 4-11 4-15 4-15 4-19 4.3.1.1 Plant Staff and Wages . . • • • •4-21 4.3.1.2 Consumable Material Costs.. . . ..•4-21 4.3.1.3 Major Overhaul or Annual Maintenance Costs . . . . • . . • . . . • .4-21 4.3.1.4 Minor Overhaul Costs . . • • • .4-2'2 4.3.2 O&M Costs Development Based on Vendor Data and Engineering Review.. . . . . . •4-22 -4.3.2.1 Basi s for Costs ..•.• 4.3.2.2 Actual Costs Developed 4-22 4-23 4.3.3 Review of Developed Simple-Cycle Plant 0&~1 Costs . . . . . . . . . . . .4-33 5.0 THE GAS-FIRED,COMBINED-CYCLE PLANT ALTERNATIVE 5-1 5.1 PLANT DESCRIPTION . . . •... . . . • . . 5.1.1 General Arrangement ....••........ 5.1.2 Description of Major Plant Components and Their Functions •.•.... 5.1.2.1 CT Equipment ••..•. 5.1.2.2 Steam Cycle Equipment .. 5.1.3 Plant Operating Parameters ... 5.1.3.1 Turbine-Generator Efficiency 5.1.3.2 Plant Auxiliary Loads .• 5.1.3.3 Operating Configurations .. 5.1.3.4 Net Output and Heat Rates .. 5-1 5-1 5-1 5-1 5-5 5-8 5-9 5-9 5-11 5-11 2265C iv TABLE OF CONTENTS (Continued) 5.3 O&M COST ESTIMATE ..••.. 5.2 CAPITAL COST ESTIMATE .... 5.2.1 Basis of Estimate .• 5.2.2 Details of Estimate Page 5-12 5-12 5-16 5-18 5-18 5-19 5-19 5-19 5-21 Plant Staff and Wages .. Water Costs . . . . . . . . . . . . • . Major Overhaul or Annual Maintenance •••..•. Consumable Materials ..5.3.1.4 5.3.1 O&M Costs Based on Utility Data 5.3.1.1 5.3.1.2 5.3.1.3 -- 5-21 5-21 5-22 ..- 5.3.2 O&M Costs Development Based on Vendor Data and Engi neeri ng Analysi s . • • . . . • . 5.3.2.1 Basis for Costs ••.....•.• 5.3.2.2 Actual Costs Developed ••.•. 5.3.3 Review of Developed Combined-Cycle Plant O&M Costs •.. • •.'. . . . • . • • • • . •5-27 APPENDIX A -DETAIL CAPITAL COST ESTIMATES FOR COAL PLANT ALTERNATIVE APPENDIX B -DETAILED CAPITAL COST ESTIMATES FOR THE GAS-FIRED CT ALTERNATIVE APPENDIX C -DETAIL CAPITAL COST ESTIMATES FOR THE GAS-FIRED COMBINED- CYCLE PLANT ALTERNATIVE - 2265C v TABLE OF CONTENTS (Continued) LIST OF TABLES,-Table No.Page ~~3-1 PERFORMANCE COAL lIL TIMATE ANALYSIS,PERCENT BY WEIGHT 3-8 3-2 AUXILIARY LOAD 3-15 3-3 PLANT oPERATING PARAMETERS 3-18 f~3-4 CAPITAL COST ESTIMATES BELUGA·200 MW COAL-FIRED POWER PLANT INITIAL UNIT 3-22 ~3-5 CAPITAL COST ESTIMATE BELUGA 200 MW COAL-FIRED - POWER PLANT EXTENSION UNIT 3-23 --.3-6 CAPITAL COST SUMMARY BELUGA COAL-FIRED POWER PLANT TWO UNIT 3-24 3-7 CAPITAL COST ESTIMATE NENANA 200 MW COAL-FIRED POWER PLANT INITIAL UNIT 3-26 3-8 CAPITAL COST ESTIMATE NENANA 200 MW COAL-FIRED POWER PLANT EXTENSION UNIT CAPITAL COST ESTIMATE 3-27 3-9 CAPITAL COST SUMMARY NENANA COAL-FIRED-'POWER PLANT TWO UNITS 3-28 3-10 PLANT COST COMPARISONS 3-29 -.3-11 CAPITAL COST VARIANCES FOR ITEMS NOT INCLUDED OR DIFFERING SIGNIFICANTLY IN COST COMPARISON 3-32 3-12 SPECIFIC UTILITY REPORTED DATA O&M COST ESTIMATE BACKUP 200 MW COAL PLANT 1983 DOLLARS 3-35 3-13 PLANT PERSONNEL BY CATEGORY 3-40 3-14 MANUFACTURERS WORKHOURS LABOR AND SPARE PARTS COST ESTIMATE OF ANNUAL OVERHAUL OR REPAIR FOR A 200 MW ~t.!ll'1l STEAM TURBINE GENERATOR 3-47 3-15 MANUFACTURERS WORKHOUR LABOR AND MATERIAL COST ESTIMATE FOR ANNUAL OVERHAUL OR REPAIR OF A 200 MW COAL-FIRED BOILER 1983 DOLLARS 3-48 - 2265C vi TABLE OF CONTENTS (Continued) LIST OF TABLES (Continued) --Table No.Page 3-16 ANNUAL OVERHAUL OR REPAIR COST OF BAGHOUSE 200 MW COAL-FIRED PLANT 3-49 3-17 COOLING TOWER ANNUAL MAINTENANCE EXPENSES COST ESTI~~TE 200 MW COAL-FIRED POWER PLANT 3-50 3-18 ANNUAL OVERHAUL OR COSTS DRY FLUE GAS DESULFURIZATION SYSTEM 200 MW COAL-FIRED POWER PLANT 1983 DOLLARS 3-51 3-19 200 MW COAL-FIRED POWER PLANT SUMMARY OF O&M COSTS 3-52 4-1 SIMPLE-CYCLE PERFORMANCE SUr~RY 4-9 4-2 CAPITAL COST ESTIMATE SIMPLE-CYCLE CT INITIAL UNIT 4-16 4-3 CAPITAL COST ESTIMATE SIMPLE-CYCLE CT EXTENSION UNIT 4-17 4-4 CAPITAL COST SUMMARY SIMPLE-CYCLE CT POWER PLANT THREE UNITS 4-18 4-5 O&M COST ESTIMATE UTILITY REPORTED DATA O&M COST ESTIMATE 260 MW NET SIMPLE-CYCLE CT PLANT 1983 $4-20 4-6 261 MW (net)SIMPLE-CYCLE CT PLANT PLANT STAFF 4-24 4-7 CONTIGUOUS 48 STATES CT GENERATING PLAN STAFF SIZE 4-24-4-8 MEDIA FILTER CHANGEOUT COST ESTIMATE FOR A WATER TREATMENT PLANT MIXED BED REGENERATED UNIT 4-26 ~ 4-9 SIMPLE-CYCLE CT PLANT INLET AIR FILTERING SYSTEM O&M COST ESTIMATE 4-27-4-10 SIMPLE-CYCLE CT PLANT EXHAUST DUCTING O&M COST ESTIMATE 4-29 4-11 MANUFACTURERS MANHOURS LABOR AND SPARE PARTS COST ESTIMATE FOR A 79 MW ISO RATED SIMPLE-CYCLE CT 4-31 4-12 261 MW SIMPLE-CYCLE CT POWER PLANT SUMMARY OF O&M COSTS 4-32 ~ 2265C vii -,~"----------~-----------~--------_........_-- ""'"TABLE OF CONTENTS (Continued) LIST OF TABLES (Continued) Table No.Page ~5-1 STEAM TURBINE-GENERATOR UNIT DESIGN PARAMETERS 5-6 5-2 COMBINED-CYCLE PLANT PERFORMANCE SUMMARY 5-10-5-3 CAPITAL COST ESTIMATE COMBINED-CYCLE POWER PLANT 5-13 5-4 CAPITAL COST SUMMARY COMBINED-CYCLE POWER PLANT 5-17 "" 5-5 UTILITY REPORTED DATA O&M COST ESTIMATE C~1BINED-CYCLE PLANT 5-20 5-6 MANUFACTURERS MANHOURS LABOR AND SPARE PARTS COST ESTIMATE FOR A WASTE HEAT RECOVERY BOILER STEAM GENERATOR FOR AN ISO RATED 217 MW COMBINED-CYCLE PLANT 5-26 5-7 MANUFACTURERS MAINTENANCE COST ESTIMATE FOR A COMBINED- CYCLE PLANT 60 MW STEAM TURBINE AND GENERATOR 5-28 5-8 -AIR COOLED CONDENSER O&M COST ESTIMATE FOR 230 MW COMBINED-CYCLE PLANT 5-29 5-9 230 MW COMBINED-CYCLE POWER PLANT SUMMARY OF O&M COSTS 5-30"- 2265C viii -, r~' TABLE OF CONTENTS (Continued) LIST OF FIGURES Figure No.Page """3-1 COAL PLANT SITING 3-2 3-2 PLOT PLAN OF COAL PLANT 3-3 3-3 COAL PLANT ARRANGEMENT 3-4 3-4 COAL PLANT ARRAIJGEMENT 3-5 3-5 200 MW COAL-FIRED POWER PLANT HEAT BALANCE 3-16 ,....4-1 GENERAL ARRANGEMENT OF THE CT PLANT 4-2 5-1 200 MW COMBINED-CYCLE POWER PLANT GENERAL ARRANGEMENT PLAN 5-2 ~ 5-2 200 MW COMBINED-CYCLE POWER PLANT GENERAL ARRANGEMENT SECTIONS 5-3 5-3 217 MW COMBINED-CYCLE POWER PLANT HEAT BALANCE DIAGRAM 5-4- ..... - - 2265C ix ~._--_.---_.---._---------..------------------ -' .... r""'" , ~, 1.0 INTRODUCTION The Susitna Hydroelectric Project is presented as the best alternative for future generation of the bulk of the electrical energy needed by the State of Alaska in the early Twenty-First Century.The thermal (heat)sources of electrical generation which must be considered in order to determine whether Susitna is indeed the best alternative are presented in this document • The availab1 e thermal a1 ternatives are defined and descri bed,and those that are true alternatives in terms of capacity and availability are then developed further.Technical definition,capital cost,and O&M costs are developed in sufficient detail to be used with existing industry models for analysis of the alternatives. 1.1 HISTORIC SOURCES OF THERMAL ELECTRIC GENERATION The sources of electric generation using thermal energy may be placed in two categories.The first category is that utilizing directly fired combustion engines as the prime mover.This includes piston-type internal combustion engines,which may utilize a variety of fuels, including gasoline,diesel fuel,alcohol,natural gas or producer gas, and combustion turbines (CTs)which generally use natural gas,propane, or petroleum di still ate as a fuel.The second category uses an indirectly heated medium expanded through an engine,such as a turbine, as the prime mover.Of the several thermal power cycles available in this category,the Rankine steam cycle is used almost exclusively.The heat sources used for this steam cycle include combustion of fossil fuels,biomass and waste prOducts,nuclear fusion,and geothermal energy. Internal combustion reciprocating engines are utilized for generation of electricity as emergency backup power in remote areas,or where the total demand for electricity is relatively small.Diesel engines, 4135C 1 -1 12/16/85 ,-'..........'-...,-,------,----------------------------------- using petroleum distillate,are,by far,the most common type.Diesel generating units are available in sizes ranging from fractional megawatts up to the 25 MW range.They are reliable,can be started ve~quickly,and may be used for either base load or peaking power. Drawbacks to the use of diesel are size limitation,frequent maintenance,and requirements for a ready supply of relatively expensive fuel.- CTs are used to provide quick delivery and construction (in one year or less)of.on-line capacity in sizes from 1 MW to 120 MW.The larger machines,however,are limited to 50 Hz service.CTs utilize an open Brayton cycle wherein air is compressed,heated by combustion with a fuel,and expanded through the turbine,producing mechanical energy and driving a generator.They are quick starting,follow load easily,are available at low capital cost,and provide significant operating and planning flexibility.Disadvantages of CTs are that they are less reli abl e than many al ternati ves,can requi re frequent expensi ve mai ntenance,have shorter 1i ves,use rel ati vely expensive fuel sand lose efficiency when operated at part load. - l~ The planning and operating flexibility attributed to CTs is derived from the different cycle configurations available.Although a simple-cycle CT may be used for base load,intermediate,peaking,or standby service,it is best suited for peaking or standby.The simple addition of regenerative heating of combustion air,utilizing heat from the exhausted gases,improves the cycle efficiency significantly.This makes the unit better suited for intermediate or base loading,but reduces reliability due to increased operating temperatures.Another configuration is to utilize the hot exhaust gas for steam generation by adding a Rankine cycle steam turbine generator to the system.This combination of Brayton cycle CT with a Rankine cycle steam plant is called a combined-cycle plant.Combined-cycle plants are the best suited arrangement for base load applications. 4l35C 1-2 12/16/85 ~I --'---""""""--------------,,-------,------------__ -. - - - Steam-electric generating stations may be characterized according to their heat source,geothermal,nuclear,or combustion.Geothermal plants are practical only where large quantities of steam or heat are available from the earth,such as Rekjavik,Iceland;Geysers, California;or Yellowstone,Wyoming.The plants are usually very expensive,inefficient,and small in size (l MW to 20 MW)due to the low quality and quantity of steam.The exception being the 66 ~M units at Geysers,California. Nuclear power plants rely on the heat of fission of transuranic elements for generation of steam -to produce electricity.Although the early nuclear power plants were built in the 50 MW to 200 MW range, present day designs are 800 MW and larger.Nuclear power has very high capital costs,a long design-construct lead time,is very slow to bring on-line,and is plagued with environmental,safety,and licensing problems.Very low fuel costs and high reliability are also characteristic of nuclear power plants. The overwhelming majority of steam-electric generating stations use chemical combustion of fuel as their source of heat for generation of steam.Most use the fossil fuels:coal,oil,and natural gas,with coal being predominant.Other fuels which are used are wood (biomass) and Municipal Solid Waste (MSW).Biomass-fired plants tend to be smaller in size,60 MW or less,the most common around 10 MW.This size limitation reflects the costs of transport and handling of a sometimes unreliable fuel source.Plants which burn MSW are built 'for the primary purpose of waste volume reduction.Their capital costs are quite high,and their reliability,operating costs,and useful life are hi ghly vari abl e. Fossil fuel-fired steam-electric generating stations are available in any capacity from 10 MW to 1,000 MW.However,economies of scale apply,and subject to availability and load requirements,larger plants may produce less expensive electricity.Coal is the fossil fuel most 4135C 1-3 12/16/85 - .- - ...... - - .- - - often used because of low cost compared to oil and gas.While coal-fired plants are more costly to build than oi1-or gas-fired plants,they have low fuel costs,are extremely reliable,have a long IJsefu1 1ife,and are the most used and proven technology for generati ng electricity. 1.2 THERMAL ENERGY SOURCES CONSIDERED FOR THE RAILBELT The Rai1be1t Region of Alaska is rich in local energy resources and in resources available from adjacent areas.Depletable resources available include coal,oil,and natural gas.While the renewable resource of biomass from forests is also available,its accessibility and quantity are uncertain.Additionally,geothermal,MSW,and nuclear power were all considered as energy sources for the Rai1be1t. Each of these resources is discussed below in tenns of the specific parameters of each which affect its viability as an alternative.These parameters of evaluation vary from technology to technology,but are considered in tenns of the criteria of fuel availability,reliability of the technology,size and total energy capacity,regulatory requirements,capital cost,and siting.Those technologies which are selected as viable are then evaluated in detail • 1.2.1 MSW-Fired Power Plant MSW is omnipresent with civilization.The sheer volume of MSW created by an urban area which must be disposed of in a safe,environmentally sound manner,creates the need for volume reduction.The best volume-reduction method found to date is combustion.Combustion creates the possibility of steam-electricity generation.However, given a waste creation rate of approximately 5-1/2 pounds of refuse per person per day,the entire State of Alaska will produce only enough MSW in 1985 to support a 50 MW power plant.MSW cannot,even allowing for population growth,provide a significant alternative to the Susitna project. 4135C 1-4 12/16/85 ,-_.._----------,---------.--1_-.........----------------- ,.." ..- - .-. 1.2.2 Nucl ear Power There are over 150 nuclear power plants operating or under construction in the United States.Some have been in operation for more than 20 years.HO\'Iever,the costs of legally imposed constraints has prevented commitment of any new nuclear plants in the U.S.for several years. There are no nuclear plants in operation or under consideration for Alaska.The nuclear steam-electric alternative for Alaska was addressed in detail in the Railbe1t Electric Power Alternatives Study (Battelle 1981).A suitable site could be found in the Rai1belt and the plant could be designed and built to meet all geological, envi ronmental,safety,and operati anal requi rements. The generating capacity of commercially available nuclear plants is 800 MW to 1,100 MW.For an isolated system,such as that represented by th~Railbelt,to depend on essentially all of its power from a single unit,a 100 percent standby reserve would be required. A nuclear plant requires a refueling shutdown period of approximately 30 days every 12 to 18 months.This operating criteria will al so act to force the construction and maintenance of a 100-percent standby reserve.This reserve would be needed at least once every 12 months during refueling and would,therefore,need to be a real and dependable source of electricity. In view of the incompatibility of the unit sizes with Railbelt demand in the Year 2000 (an 800 MW nuclear plant would be approximately 95 percent of the estimated total peak of approximately 850 MW),nuclear power is not considered a desirable option to the Susitna project . 4135C 1-5 12/16/85 - .... - 1.2.3 Biomass-Fired Power Plants Biomass fuels,primarily wood and agricultural wastes,have been used for many years as sources of energy for electric generation.There are size limitations on biomass plants,generally due to the quality and quantity of fuel available (Bethel 1979 and Jamison 1979).The capacity of biomass plants is usually limited to 60 MW or less.As an a1 ternative to Susitna,the potenti a1 bi omass-generated el ectri c capacity is insufficient.First,it has been estimated that biomass could provide no more than 0.5 to 5.0 percent of future Rai1be1t electric energy needs (Battelle 1981).Second,the main source of biomass in Alaska is wood.The life cycle for growing trees to a useful size as fuel is in excess of 100 years.For this reason,the fuel is considered nonrenewable. 1.2.4 Coal-Fired Power Plants There are several coal fields in Alaska of which three are considered economically viable as sources of coal for electric generation.These are the Matanuska,Beluga,and Nenana fields. The Matanuska field is good quality bituminous coal,but is small.The surface minable resources will be exhausted by the single plant presently proposed for the resource (Allied-Signal 1984)• The Beluga field is an extensive one consisting of low sulfur,high moisture,subbituminous coal.Development of a surface mine for export and domestic use by Diamond Alaska is presently in the permit application stage.A mine-mouth power plant using Beluga coal has'been proposed by the mine developer.The coal reserves are sufficient to support several 8 to 12 mi'l1ion tons per year mines (Weirco 1984). 4135C 1-6 12/16/85 - - - - The Nenana field is located in the northern Railbelt near Healy and is currently being mined for domestic use and export.With further development,the field can supply the necessary increased capacity for an electri c-generati ng faci 1ity. Coal -fired steam-electric generating stations are the most widely uti 1i zed type of base load generation.There are severaltechnol ogi es for combusting coal to generate steam.The most advanced and most efficient is pulverized coal combustion.Pulverized coal-fired boilers are available in sizes from 10 MW to 1,200 MW.However,the smaller sizes,50 MW and below,tend to be less cost effective.than larger stoker-fired,grate-type boilers. Drawbacks to using coal for electric generation in Alaska are primarily environmental.Air quality,water quality,and land use impacts can be significant;however,technology does exist which can mitigate these impacts to acceptable levels. The presence of fuels and the status of the technologies for combustion and envi ronmental control s make coal -fi red,steam-el ectric generation a viable alternative to the Susitna project. 1.2.5 Natural Gas-Fired Generation Most of the electricity consumed in Alaska is produced from natural gas.Suppl ies of natural gas are fully developed and readily available in the Cook Inlet area.There is some question regarding whether or not the supply could provide all of Alaska's electrical needs into the 21st century.However,supplies are available to allow planning generation through Year 2000.Additionally,North Slope natural gas may become available if a pipeline is built. -4l35C 1 -7 12/16/85 - - .- There are two well-developed technologies available for combustion of natural gas to produce electricity;there are simple-cycle CTs,and combi ned-cycl e CTs.Either technology can be used to supply electricity incapacities from 10 ~1W to several hundred megawatts per plant.They can be used for base load,intermediate,or peak load; however,the combined cycle is more suited to base load than is the simple cycle.Both technologies are presently used extensively in the Railbelt and will be considered as alternatives to Susitna. Natural gas-fired,steam-electric generation is also a possible alt~rnative to Susitna.However,it is not considered further because the combined-cycle plant is less expensive to build and operates at a higher efficiency. An additional factor to be considered is the Fuel Use Act.This Federal law prohibits construction of new gas-fired electrical generation for anything except peaking unless an exemption is granted by the Federal Government.All Alaska utility-requested exemptions have been granted to date;however,the political nature of this Ilpermission"to construct creates additional uncertainty when planning to use this electric-generation resource. 1.2.6 Oil-Fired Generation Petroleum distillates and residual fuels can be used in three ways to generate electricity.These are oil~fired steam-electric generation, CTs {either simple-or combined-cycle},and diesel engines. Oil-fired,steam-electric generation is not being built or planned anywhere in the U.S.due to a combination of high fuel cost, alternative uses of petroleum products,and the legal prohibition by the Fuel Use Act.If use of petroleum distillate is considered for electric generation,then,like natural gas,the lower capital cost and 4135C 1-8 12/16/85 [ I ¢"'"I .... - higher efficiency alternative of a combined-cycle plant would be chosen for a base load plant while a simple-cycle CT unit is more cost effective for peak load applications. Diesel generation is commercially available in sizes from fractional megawatts up to 25 MW.Larger sizes can be designed,but are not readily available,are overly complex,and would likely operate with reduced reliability. The availability of petroleum distillate or residuals for electric generation is questionable.Although there are very large petroleum resources in Alaska,alternative uses (export),relatively high prices, and a lack of refining capacity require that oil-fired generation not be an alternative to Susitna.The one potential exception would be if small or peaking generation were to be an absolute requirement in an area where natural gas cannot be made available.In all likelihood,an oil-fired CT generation plant would be constructed in that locale. 1.2.7 Other Unconventional Thermal Sources There are several developing or potential resources which could have application for electric generation in the Railbelt.These resources, discussed below,are fuel cells,solar energy,and geothermal energy. 1.2.7.1 Fuel Ce 11 s In a fuel cell,the chemical reaction of oxidation of fuel is performed in an electrolyte bath with an anode and cathode present.The energy of oxidation is directly converted to electricity.Hydrogen is the most common fuel for reaction in the cell and is produced from methane, coal gas,or one of several other fuel sources.Plants which would utilize fuel cells will be easily variable in size,as well as fuel source.A typical 'tstack"of fuel cells will produce 500 amps of direct current at 300 volts.Any number of "stacks or single modules" can be grouped together to provide the required plant capacity. 4l35C 1-9 12/16/85 ..... ~, ,- - - The present stage of development of fuel cell technology is experimental.Some demonstration plants up to 10 MW in size have been built in the U.S.and in Tokyo (EPRI 1985).The availability, operating experience,reliability,and manufacturing capacity do not exist at present for this technology to be seriously considered . 1.2.7.2 Solar Energy There are two existing methods for converting solar energy to electricity.These are photovo1taic cells and solar thermal conversion (Battelle 1981).Photovo1taic cells convert solar energy directly to electricity by the activation of electrons in photosensitive substances.Thermal conversion requires heating a fluid medium,such as water,and mechanically operating a generator as in a Rankine steam cycle. The limiting criteria for either method are the amount of solar energy available,the efficiency of conversion,and the ability to store large quantities of energy for both the diurnal and seasoned cycles which will be encountered. The limitation of the available solar energy in Alaska,combined with a winter peaking system,result in rejection of solar energy or a viable a1ternati ve. 1.2.7.3 Geothermal There are several geothermal energy resources in Alaska.These consist of hot springs in the northern Rai1be1t near Fairbanks,To1oma,and Baker,and hot igneous rock in the Wrange1 Mountains,Mt.Spurs,Double Peak,and Iliamna.Very little is known of the potential (if any)of these geothermal system. .... 4135C 1 -10 12/16/85 - _. ""'" Development of geothermal energy is very expensive compared to the conventional alternatives ($3,500+/kW versus $2,500/kW).Extensive steam collection and heat transfer system are usually required.The units are typically small,S MW to 50 MW,and their location is frequently remote from load centers. Lack of detailed information,geographical diversity,and expected high development costs make geothermal energy a poor candidate for an alternative to Susitna. 4135C 1-11 12/16/85 ~, 2.0 CRITERIA FOR CONCEPTUAL DEVELOPMENT The thermal alternatives selected,from those discussed in Section 1.2, for development as economically and technically viable alternatives to Susitna,are coal-fi red steam-electri c generation and natural gas-fi red CT generation.The criteria which guided the conceptual design of these alternatives are discussed here. 2.1 COAL-FIRED Coal-fi red power plants are presently an integral part of the total power supply for the Railbelt.This is especially true of the northern Railbelt where Fairbanks Municipal Utility System (FMUS),Golden Valley Electric Association (GVEA),the University of Alaska Fairbanks,and Fort Wainwright all operate coal-fired power plants.The plants range in size from 1.5 MW to 26.5 MW.The pUblic utility plants included are four coal units at FMUS Chena Station of 5.0,2.5,1.5,and 20.0 MW size for Units 1 through 4 and the GVEA Healy plant of 26.5 MW.These plants exist due to the abundance and availability of coal in Nenana. The southern Railbelt also has readily available coal supplies in the Beluga and Matanuska areas,where several coal plants have been proposed.Coal has not previously been developed for electric power generation in the southern Rai1belt due to the historical abundance and low cost of natural gas from the Cook Inlet gas fields. Although there are some relatively exotic alternatives,such as coal gasification available,the proven feasible and most economic utilization of coal,as a source of electricity,is a pulverized coal-fired,steam-electric generating station.The only viable alternatives are stoker-fired plants or fluidized bed combustion units.It has been repeatedly shown,through 40 years of operation, that stoker-fired plants do not compete well economically with pulverized coal plants in sizes above the 25 MW to 50 MW range. Fluidized bed combustion is an emerging technology that is very 4548C 2-1 12/16/85 .'__.~'•'_-"F """""__----------------- I successful in the 5 MW to 50 MW range.The technology for larger plants t 100 MW to 300 MW t is promising;however t the first plants in the 100 MW to 200 MW range are only now being constructed.It is not practical to propose unproved technology as a viable alternate to the Susitna project.Therefore t pul veri zed coal fi ri ng was sel ected as the most appropriate technology. 2.1.1 Plant Size and Configurations The economics of construction and operation of coal-fired power plants dictates a size range of 100 MW to "300 MW for smaller power pools (Power Engineering 1983).Although economics of scale dictate that larger power plants cost less to build and operate on a $/kW and $/MWh basis t the size of the utility/power pool and the cost of unplanned outages for that uti 1ity dictate that smaller util ities and power pool s are economically better off with smaller (100 MW to 300 MW)coal-fired units. The 1982 Rai1belt alternatives study selected a 200 MW coal-fired power plant as a representative unit size that would be reasonable for a system expansion analysis.Further analysis has subsequently been conducted to confi nn that thi s si ze is the most economical coal option for the without-Susitna plan. In reviewing the assumptions for the appropriate size of a hypothetical coal-fired power plantt an evaluation of the options for unit size ranging from 100 MW to 400 MW was performend.The evaluation considered the tradeoff between two major driving forces or factors: economies of scale and unplanned outages. As the size of power plant units increases t economies of scale are realized as lower capital and O&M costs are derived on an unit-kilowatt basis.For example t a single 400 MW unit has a capital cost of about 80 percent of two 200 MW units and requires about 60 percent of the operations and maintenance staff. 4548C 2-2 12/16/85 ,-"-,,-----..'------.,~,--~~---__r_-----~'I"'""",----.,,----~------------- -- .- - The factor of reliability and unplanned outages recognizes that the output of a utility system is made up of diverse generation stations, all combining their capacity to meet the load.The loss of the largest si ngl e generati ng uni t represents the desi gn basi s for the rel i abi 1i ty and loss of load analysis. A tradeoff between the two factors of economies of scale and the impact of unplanned outages was performed using the optimized generation planning (OGP)model.Within that model,the reliability assessment is based upon determining the cumulative capacity outages of the system. As generating unit sizes become larger,more capacity is installed to meet the reliability requirement specified in the model.Another calculation performed in the OGP analysis is spinning reserve.The spinning reserve criteria provides the grid with the capability of meeting system load should the largest unit experience an unplanned outage. Since any hypothetical coal-fired unit larger than 200 MW would represent the largest unit in a without-Susitna system,a number of OGP expansion planning analyses were performed.The unit size evaluation initially consisted of allowing the OGP expansion planning program to select among 100 t<1W,200 MW,300 MW,and 400 MW units.(Sizes up to 600 MW were considered,but never selected by the program.)The resulting system plan included 100 MW and 200 MW units.In the next step,unit sizes of only 100 MW,150 MW,200 MW,and 250 MW were made available for system expansion.The program then selected a mixture of 150 MW and 200 MW units.An expansion planning program using only 200 MW units showed that the total present worth of the mixture of 150 MW and 200 MW units was essentially the same as the present worth of the program that limited plants to 200 MW as the only size.The 200 MW expansion program utilized in the license application was therefore validated and retained. 4548C 2-3 12/16/85 - ..... r- I I 2.1.2 Steam Cycle Selection Boilers,turbines,and feedwater equipment are commercially available in several pressure/temperature ratings and configurations for steam-electric generating plants in the size range considered here.An overall criteria for equipment selection was to provide proven, reliable equipment with long records of high availability at the best possible efficiencies. 2.1.2.1 Boiler A 2,500 psig/l,000°F/1 ,OOO°F boiler was selected to optimize boiler efficiency and fuel usage.This optimization results in higher capital costs than for an 1,800 psig or 1,450 psig cycle,but over the 30-year life of the plant,it will be paid back in increased output and lower heat rate.Single reheat to 1 ,OOO°F was selected to obtain an approximate four percent cycle gain. The selection of the number of coal pUlverizers (mills)was determined after review of the coal analysis.The Nenana and Beluga coals both have low hargrove index (28 to 32,average of 30),which indicates a ve~hard coal and high ash content,which,in turn,means a lot of pyrites or other hard tramp material will reach the mills.This will result in a great deal of wear and resulting maintenance on the mills. Therefore,a design using five mills rather than a standard four was chosen.This allows full load operation with one mill out for maintenance at any given time. 2.1.2.2 Turbine-Generator Tandem compound flow turbines are virtually a utility standard.The presence of a reheat cycle means there will be a high pressure turbine with intermediate pressure (reheat)and low pressure turbines. Efficient operation of the plant dictates that regenerative feedwater 4548C 2-4 12/16/85 ~,_w---~---__---_'_IIIlii"'4"''1'''''''''''-__------r------_'_'''Ijif~,'-'''''-------- - - - heating with cascading heater drains be used.Op~imizing this cycle, as discussed below in Section 2.1.2.4,will result in the lowest practical turbine heat rate.The turbine is provided with intermediate and low pressure steam extraction for supplying the required heat to the feedwater heaters. The generator design criteria will conform to standard utility practices.It will operate with a power factor of 0.85 at design conditions and shall be supplied with a hydrogen cooling system. 2.1.2.3 Waste Heat Rejection Best turbine performance is realized with the lowest possible exhaust pressure.The condenser will be designed to operate at two inches of mercury absolute backpressure.This is the best vacuum practical and is readily achievable given a low temperature heat sink. In the Alaskan climate,the low ambient temperatures will ensure being able to design a cooling tower which will provide sufficient cool circulating water for maintaining the required two-inch HgA of condenser pressure.A potential problem will be dealing with the extreme cold weather to prevent icing of the tower and creation of local ice fog.Both problems can be dealt with by utilizing a wet/dry design.That is,in warm months the tower will operate as a wet tower.However,when icing conditions prevail,the hot circulating water will be cooled in dry sections and the wet sections will be i sol ated. 2.1.2.4 Feedwater System Ebasco has performed repeated feedwater train optimization designs for 2,400 psig/l,OOO°F/l,OOO°F base load steam systems.The design settled on for optimum increased efficiency versus increasing capital cost is a seven-heater cycle.This includes four low pressure closed feedwater 4548C 2-5 12/16/85 - - - - ~' - heaters,an open deaerating feedwater heater,and two intermediate pressure feedwater heaters.The basic criteria for selecting the number of regeneration heaters in a cycle is economic.The increased efficiency realized by recovering the heat of condensation that is otherwise rejected through the condensers must be worth more than the capital and operating cost of the additional equipment. 2.1.3 Emi ss ion Co nt ro 1s 2.1.3.1 Sul fur Dioxide Removal Selection of the appropriate 50 2 removal equipment is as much a function of regulatory criteria as it is engineering criteria.Review of the Best Available Control Technology (BACT)to be applied for low sulfur coal on existing and under construction power plants show that no plants using less than 0.3 percent sulfur coal are operating or planned.Of those plants using coal with less than one percent sul fur, either wet (venturi)scrubbers or dry scrubbers are used.More recent designs are utilizing the dry scrubber systems which offer the best control of operating emission rates with less capital and operating costs than wet systems.Dry scrubbing was selected as most applicable for the very low sulfur (0.17 percent)Alaskan coal. Detenni nation of the actual operati ng parameters of the scrubber will follow from the determination of the plants emission rate,which is a purely regulatory function.Review of existing and planned plants in the U.S.determined that one plant is being constructed which will utilize a 0.32 percent sulfur coal and a d~scrubber with a resulting 50 2 capture rate of 80 percent (Power 1985).An 50 2 capture rate of 75 percent for the 0.17 percent sulfur Alaskan coal is proposed. 4548C 2-6 12/16/85 "-'...........--------,-,-------------,.......----------------- - 2.1.3.2 Particulate Removal The selection of a fabric filter for flue gas particulate removal is dictated by two reinforcing factors.The resistivity of ash from low sulfur coal is typically low enough to create problems for operation of an electrostatic precipitator.Also.the calcium oxides (CaO)and gypsum (CaS0 3 and CaS0 4 ).which will be present in the flue gas downstream of the scrubber.wi 11 add to the desi gn prob1 em.It is necessa~to design for dust collection over a wide range of ash.CaO, S02'and caso 4 concentrations in the flue gas.The possibility of operating for brief periods with the S02 scrubbing system off,means the electrostatic precipitator (ESP)will need to be greatly overdesigned.This variation of concentrations does not affect a fabric filter collector. Three criteria affect the primary design of a fabric filter dust collection system.The cleaning method,bag material selection,and air-to-c10th ratio.The proven design of reverse air cleaning with high temperature fiberglass bags and aconservattve net air-to-c10th ratio of 3.0 to 1.0 are assumed in this analysis.- 2.1.4 Fuel Yard - - The criteria for design of the fuel yard are reliability and size of fuel supply.A simple to operate and maintain radial stackout system was chosen for both re1i ability and low capital cost.An emergency stackout conveyor was added for reliability.Two underground reclaim hoppers are included.one for normal use at the active fuel pile.and an emergency reclaim at the dead storage fuel pile. Due to the extreme weather conditions that exist at the proposed site, it is necessa~to plan for a potential long interruption of fuel supply.For this reason,a gO-day rather than a more standard 60-day full load total on-site fuel supply is planned. 4548C 2-7 12/16/85 ~'I~II~_'---"""--------------------------------- ,~ 2.2 NATURAL GAS FIRED 2.2.1 Simple-Cycle Plants 2.2.1.1 Plant and Unit Size The primary criteria for selection of both unit size and plant size is economic.That is,to be considered a vi able technical and economic alternative to the Susitna hydroturbines,the units must be the least cost,most reliable,and should be available in size or combination of units that can replace single Susitna generating units.The large frame industrial gas-fired turbine selected is the largest commercially available that has both wide range utility application experience and with which the Alaskan Railbelt utilities have operating experience. - - - - - 2.2.1.2 Plant Configuration Since the purpose of these alternatives is to be considered as alternatives to Susitna project generation capacity,the complete natural gas-fired CT plant will,as nearly as practical,be sized to meet the needs of and conform to current practices of the Railbelt utilities.At International Standards Organization (ISO)conditions, 59°F at sea level,each unit is 80 MW.A three-unit plant with a total ISO rating of 240 MW and a net rating of 262 MW at the design ambient temperature of 30°F was chosen.It is planned that an initial single unit with switchyard,water treatment,and other auxiliary equipment for a complete three-unit plant would be built.The second and third units would be added as required. The three-unit configuration was selected to optimize total plant cost.Construction of the initial unit at the site will include site development costs,and the basic switchyard.By planning the development and electrical equipment to include future units,the capital cost of the future units and the total plant is reduced. 4548C 2-8 12/16/85 --...........--·-··,------------..,..,.....--·.....-----...-----1-------,------------ - ,.". .... - .- Planning for more than three 80 MW CT's (ISO)with construction of the first unit would,however,burden the initial units capital cost heavily for generating capacity which may be as much as 10 years in the future. 2.2.2 Combined-Cycle Plants 2.2.2.1 Plant Size The initial bUilding blocks for the combined-cycle plant are CTs identical to those used for the simple-cycle plant.By using two CTs, each with a Heat Recovery Steam Generator (HRSG),and a single steam turbine,a plant with an ISO rating of 217 MW and a net rating of 230 MW at the design ambient temperature of 30°F was chosen. 2.2.2.2 Plant Configuration As described above,the plant will consist of two CTs and a single steam turbine.This will allow construction of the plant in stages or as a complete plant.The initial CT installation would include electrical and auxiliary support.equipment to serve the entire plant. This wi'll simplify installation of the second CT and the steam turbine. 2.2.2.3 Steam Cycle Selection The steam cycle used is detennined by the level of complexity of the HRSG design.HRSGs may be single,duel,or even triple pressure units.With each additional higher pressure feedwater loop adding expense and complexity with the benefit of increased thermal efficiency.For simplicity of design and operation and to minimize capital cost,a single pressure HRSG was chosen • 4548C 2-9 12/16/85 ----_.,-----------------------....-------------------- ""'"I - 3.0 THE COAL PLANT ALTERNATIVE 3.1 PLANT DESCRIPTION The plant described is a single 200 MW (net)coal-fired,steam-electric generating station which may be built at either a Beluga or a Nenana site (See Figure 3-1).Other than location and fuel receiving facilities,all basic plant operating parameters are identical. Differences in capital cost due to site conditions and construction are addressed in the Capital Costs Section,3.2. 3.1.1 General Arrangement of the Plant The plot plan of the plant is shown in Figure 3-2.Plant site development is configured around the initial siting of a 200 MW unit with the planned addition of_a second.The plant site will occupy approximately 110 acres,excluding waste disposal facilities for air quality control system effluent.The generating station proper, consisting of the boiler house,turbine building,flue gas scrubber, precipitator,and chimney will be centrally located.Other buildings and facilities on the site include an administration bUilding, mai ntenance bui 1di ng,warehouse,parki ng lot,switchyard,cool i ng tower,coal receiving,processing,storing,and retrieval facility,and wastewater holding and treatment facilities.General arrangement drawings of the power plant are presented in Figures 3-3 and 3-4. 3.1.2 Major Plant Components and Functions 3.1.2.1 Fuel Receiving,Processing,Storage,and Reclaim At the Nenana site,coal is received at a coal unloading station consisting of an enclosed rail car thaw shed,enclosed rotary car dump, - 2499C 3-1 10/31/85 LEGEND "PROPOSED DAM SITES COAL-FIRED PLANT SITES FIGURE 3-1LOCATIONMt~P SITE OF COAL-FIRED ALTERNATIVE AT NEN'ANA ALASKA LOCATION MAP SITE OF COAL-FIRED ALTERNATIVE AT BELUGA • • ~'~'_M44J_zm:;;w """'__'1"'I ·--------..,.,,__.........-.--------------,--_ J>OI,lI"'~i1O'Ieu''''''G 1'I.O.>.'T"""l>lT~e.,;,I..t>l"'"-.'---------.. -.~ .CI~Cl""'AT!R L!NE.'S~"'-FP 1 t Rl;.1'"LlI"N --====:::~~~:=:.:--..:-.::..:=.:--:::::..::=-==.=---, .......~~",."""u-....-..-..-.... Z 1 •17 A- N r -- e L t E D !II ) I I j I I I 1 I I I 1 I \ \ \ \--.;-·~~.-:....-:..--_:..-.:--.:.--'-...:...._--.:...-:.-~..:--..:--'---::::eotrT"<'"l./sw.,.a<=..... eul~!'G I' o -N Q 1-I ,~IQ II IZ ...,.'7 IS 20 ZI 10()t>&TE IlEYISlOII " '5\oirl'Cl'l yARP I -~~::-.8 ACCi.SS ~~~-. .----l- ---- /"'.I N_ H L D J H [ f----.--------- I I I I I .1 I I I I I ~1:r I ....,......,1..0:> I I 1 IL1 I !-+--+~)I I----'01 ! /1~~~~====::::=::::::=:--~==============~~< o FIGURE 3-2 ,--'-~~~ALASlCA ~AUTHORITY p SllSITMA HTDIKlEL[CTRIC PlOOJEC7 THERMAL ALTERNATIVE ZOO HW COAL FIRED POWER PLANT SITE PLAN Q SCALE'•<loa'....~ 10 II I~,<;11 I.,~ DlY.HECHAIlICAL 'Ofl AVJI.Nf' CH 20 21 APA 2'I~Z.I~O M-SP-OOt I I' I A B N o E F L -N o p Q G120iJNO Floo:? ~':_:::::::_-::-=:::-7,--,---;-..:.....---:;------;;-------:----,..-----""'7=------=------- 10 12 "l~15 '"" -- ( ME-Z Z AN I NE o £ H L " N_ o FIGURE 3-3 THERMAL ALTERNATIVE 200 H.J COAL FIRED POWER PlANT GENERAL ARRANGEMENT PLANS G 10 "12 11 I~15 I.17 "I DIV.~>PO 25'2.I~C .~----f------"!"--r--i H-GA-002 20.21 r A 8 c o f G !I.I l! ~C~";frp) ,-~Ly A.C',;olJ .1 OrT'l..£1"" ! 1~ OPE.12A'ING.FLoOe ,......, ." -N ~ L ~ ~ 0 .Ii GI< P-- G. --'- .- Q ~-·-""--.'i "REVISION • c l) F E R~,)1G e.L.!:c.."'II('O".l'C EQU'~I """""iin: F SECTION B Dcie I II I'(,q hll II I ,I]W 1,1 ~,,-i _:-li__\'-l ~--'-'-L,. "'-axw ,~=AT.)f~ J Q 21 M-GA'-OO, DATE APA Z-;92.lltO 21 ~- THERMAl...ALTERNATIVE 200 MW COAL FIRED POWER PLANT GENERAL ARRANGEMENT PLAN &SECTIONS FIGURE 3-4 " o CH SCALE 1IIb=I'-Q O:N~ Dfl. ~~,;;~fff ALASKA POWER AUTHORITYF==='S;:;USl~T1<:;;A'"'H~YOR=OE=L;::EC::;T:;;-Rl:;-;C:-;:P:::ROJE=:::CT:;---~P /I 1 17 i : :r;'I(IMA~Y I I AJ~r:AjJ i.,..,N 16IS ~==F~F~If=,==7 r I~ SECTION A I II A 0 C 10 11 lZ I !,J. """ automatic conveyor. 3,400-ton coal pile car positioner,hopper,ice-lump breaker,and recelvlng This system will accept a unit train of approximately capacity and stockpile it in the active storage area of the for crushing,reclaiming,and tran~port to the plant. - ..... -- If the plant is located at a Beluga site,the coal system wi'll differ only in the receiving area.Coal will be received by truck rather than rail.There will be a multiple truck thaw shed and dual truck dump with receiving hopper.Otherwise,the coal-handling system will be the same as for a Nenana site. From the unloading station,coal is transported by belt-conveyor to the crushing and sampling house.Here the coal is crushed to a uniform size before transport either to storage or after further crushing directly to the coal silos in the powerhouse.Normal operation will result in the coal being sent to the coal yard for storage via the transfer tower,stackout conveyor,and radial stacker.All coal will be sampled lias received ll at the crushing and sampling house using an approved ASME sampling method.In the event of downstream equipment fai 1ure,the coal-handl i ng system may be emptied vi a an emergency conveyor to the emergency stackout pile. Coal is normally retrieved from an underground reclaim hopper which is located in the live storage pile south of the radial stacker so as to al so be accessi bl e for retri evi ng coal from the dead storage pi le.In the event of equipment failure,coal may also be reclaimed from the underground emergency reclaim hopper located at the end of the dead storage pile nearest the powerhouse. Reclaimed coal is conveyed to the crushing and sampling house via the transfer tower and reversible conveyor.Here the coal is crushed to size for the coal pulverizers before being transported to the coal silos in the powerhouse.Crushed coal from the coal yard is distributed by the coal tripper into the coal silos for metering to the main plant coal pulverizers. 2499C 3-6 10/31/85 ~.<!~~_MJ4 ----",....,.,---- - ~, 3.1.2.2 Combustion Air Supply Combustion air for burning pulverized coal in the boiler is supplied from two sources.The primary air fans provide air to the coal pul veri zers for the purpose of conveyi ng the pUl veri zed coal from the pulverizers to the burners in the boiler walls.Two secondary air fans provide the bulk of the combustion air to the boiler separately from the primary air system.All combustion air is preheated by regenerative air heaters and/or by a glycol/steam air heating system. Regenerative air heaters recover heat from the existing flue gas to preheat the combustion air. 3.1.2.3 Stearn Generator Coal is metered by gravimetric feeders to the pulverizers (coal mills), pul veri zed,then conveyed to the boiler by primary air as described above.There will be a total of five pulverizers which will distribute coal to the boiler for combustion at the rate of 135 ton/hr.The pulverizers are sized to maintain maximum continuous rating (MCR)with one pulverizer out of service when burning performance coal.Steam will be produced in the main boiler at 2,520 psig and 1,005°F for the purpose of delivering approximately 1.46 x 10 6 lbs/hr to the steam turbine generator set. The coals to be burned at the Beluga and Nenana sites are very similar.Both are low-sulfur,subbituminous,Type C coals with relatively high ash and moisture contents.The performance coal analysis follows in Table 3-1. The boiler consists of a waterwall section known as the furnace. Combustion takes place here and steam is generated in water-tube membrane walls from the radiant and convective heat transfer.The convective sections start at the furnace exit pl ane and consi st of a superheat section where steam is heated to a temperature well above the 2499C 3-7 10/31/85 TABLE 3-1 PERFORMANCE COAL ULTIMATE ANALYSIS.PERCENT BY WEIGHT Element/Compound Be 1uga J../'!:../Nenana ~/ "",...Hydrogen 2.9 -3.8 3.6 Carbon 44.7 -45.4 47.2 Oxygen 14.4 -15.8 15.5-Nitrogen 0.7 1.05 Sulfur 0.14 -0.20 0.12 Water 24.9 -28.0 26.1 Ash 7.9 -9.9 6.4 ~ Higher Heating Value,Btu/l b 7,600 7,600 1/SR I,1974. ~/Diamond Shamrock.1983. !/Hazen Research tests performed for FMUS . .-. - ..... ""'" ,~ 2499C 3-8 10/31/85 _".....-'---.........------_-----~"I'"r--..---_....,"'------------------- - -, saturation point,a reheat section where lower pressure steam returned from the high-pressure turbine is reheated before returning to the turbine,and an economizer section where incoming subcoo1ed feedwater is heated by the exiting flue gas.Flue gas exits the boiler breeching and goes to the regenerative air heaters where it is cooled to 350°F. It then enters the dry 50 2 removal system. Although most of the coal IS ash content is carried away with the flue gas as "fly ash,"15 to 40 percent of the ash in the coal remains in the boiler as bottom ash and/or slag.This byproduct of combustion is collected in the bottom of the boiler.A water-sealed bottom ash hopper provides both ash cooling and a vacuum seal for the boiler.The bottom ash is removed by drag chains and broken by clinker grinders. 3.1.2.4 Turbine-Generator The turbine is the prime mover for the power plant.It converts the thermal energy in the steam to mechanical energy.It is directly connected to the generator which converts mechanical energy to electrical energy.In order to accomplish this process,the main steam supply from the plant boiler is:1)routed to the stearn turbine generator;2)expanded in the high-pressure section of the turbine; 3)returned to the boiler reheater section;4)reheated and returned to the turbine where it is further expanded in the intermediate pressure section;and 5)sUbsequently expanded through the low-pressure turbine section.The steam exhausted from the low-pressure section is condensed in the main condenser and returned to the boiler for steam generation via a series of pumps and heat exchangers. 3.1.2.5 Feedwater and Condensate Systems Expanded and cooled steam is exhausted from the turbine to the water-cooled condenser.The condenser,maintained at a vacuum to increase turbine efficiency,cools the steam sufficiently for it to 2499C 3-9 10/31/85 - condense and be pumped back to the boil er to repeat the cyc1 e. Circulating water passing through tubes in the condenser carries away the heat of condensation to a cooling tower where the excess heat is rejected to the atmosphere. A cooling tower of the wet/dry design will be utilized to provide cooling for the main condenser.Condensation of the exhausted steam by the cooling water maintains two-inch HgA condenser pressure.Water flow from the cooling tower to the condenser is approximately 87,900 gpm at 71°F dry bulb and 59°F wet bulb ambient conditions.Heat rejection from the plant cooling tower is approximately 1.0 x 10 9 Btu/hr when the turbine is exhausting 1.346 x 10 6 1bs/hr of steam at full load.During winter operations,the dry portion of the cooling tower is employed at the Nenana site to 1essen the occurrence of ice fog.The plant performance is not greatly affected due to the large temperature differential which exists between the circulating water and the ambi ent ai r. The condensed water in the well of the condenser is p~ped via condensate pumps and boiler feedwater pumps through low-pressure and high-pressure feedwater heaters.In these heaters,steam is used to elevate the temperature of the feedwater prior to entering the boiler. Significant increases in cycle efficiency are realized through feedwater heating.The steam that condenses as the feedwater is heated flows to the next lower pressure heater where additional energy ;s removed from the condensate.The drains eventually are led to the condenser. 3~1.2.6 Flue Gas Cleaning Systems Flue gas from the main boiler is exhausted to a semidry Flue Gas Desu1furization System (FGDS)for S02 removal.The FGDS will consist of three spray absorber vessels using a quick lime [Ca{OH)2]slurry, of which two are sufficient to maintain proper flue gas sulfur -2499C 3-10 10/31/85 ~~llll~~__-'F""""'-------'------'ff"""--r---------------...,...--- ~- removal.Lime may be received by either truck or rail.is stored in silos.mixed with water to form the quick lime slurry.and pumped to atomizers in the spray vessels.The lime slurry is atomized into the flue gas where 502 is captured to fonn CaS0 3 and CaS0 4 both of which are solid products.The FGDS will be designed to remove 75 percent of the sulfur dioxide from the gas stream at the unit1s rated load which corresponds to 1.6 x 10 6 acfm at 350°F.Control of the spray dryer will be governed by gas temperature and 50 2 concentration of the exiting flue gas.The consumption of lime by the system is expected to average 1.900 pounds per hour.The solids formed are removed in the fabric filter (baghouse)downstream of the scrubber. The scrubber is referred to as II dry II because the amount of water injected into the flue gas is controlled to maintain the gas temperature above its adiabatic saturation point by a specified margin. usually 50°F or more.Two absorption vessels are required for operation at full load.one is a spare.Other equipment will include a powdered lime receiving.storing.and handling system.slurry mix tanks,slurry pumps,piping and the atomizers in the dry scrubber vessel s. Fly ash entrained in the flue gas stream,along with the calcium sulfates and·remaining lime in the gas,are removed by the fabric filter.In the fabric filter,flue gas passes through a cloth filter media in the form of cylindrical bags.When passing from outside to inside the bag,a minimum of 99.9 percent of all solids in the gas stream are collected on the outside of the cloth bags.The baghouse will consist of eight or more compartments.When the bags are dirty, each compartment is isolated as required,the bags cleaned by passing air or cleaned flue gas through in the reverse direction,solids are collected in a hopper under the bags.and the compartment placed back in service.The solids collected in the hoppers are removed by a dry (vacuum)ash-handling system.then transported and stored in silos for later disposal offsite. 2499C 3-11 10/31/85 ~'-'-~~------'F"'i -----------_----------------~-- - - - The baghouse system i nc1 udes the baghouse proper,upstream and downstream ductwork,isolation dampers,ash transport,and storage and handling equipment. Flue gas exiting the baghouse is exhausted to the main plant stack through an induced draft fan.If conditions require,supplemental clean air heated by process steam may be injected into the flue gas stream to avoid plume formation when discharged to the atmosphere. 3.1.2.7 Solid Waste-Handling and Disposal There are three solid waste sources to be considered at a coal-fired power plant.The first two derive directly from the combustion of coal.They are bottom ash from the boiler and fly ash from the baghouse.Both must be disposed of in an imperviously lined landfill. The third waste stream consists of the various sludges and solids from the water treatment and wastewater management facilities.These come from various sources,such as settling ponds and clarifier blowdown. The sludge wastes are potentially haiardous and must be chemically stabilized before being landfilled with the bottom ash and fly ash. Wet bottom ash is removed from the boiler bottom ash hopper by drag chain conveyors by which it is transported to elevated,enclosed bottom ash storage silos.Both the fly ash,which is handled dry and stored in silos,and the bottom ash are transported to an offsite landfill by truck. 3.1.2.8 Water and Wastewater Treatment A central generating station is a user of large quantities of water. In addition to potable and domestic water,uses are for boiler makeup (condensate),lime slurry,circulating water makeup,and fire protection.Water for fire protection and the bottom ash hopper requires the least treatment,and will be supplied from either a 2499C 3-12 10/31/85 -'il!q/III~~"-------""'"f""-------"""-----~--------~------------ - - ,..., - settling pond via pumps or directly from the primary water source (such as a Ranney well system).Potable and domestic water,along with cooling tower makeup (due to evaporation and b10wdown),and lime slurry water require more treatment.This will consist of settling basins, clarifiers,and chemical addition.The greatest amount of treatment is required for boiler feedwater makeup.Using the potable water system as a source,this water will be demineralized in an ion exchange system which is itself a user of water and a source of wastewater. The plant will create several wastewater streams which require treatment prior to being released.The waste streams to be treated include sewage,clarifier backwash,demineralizer backwash,condensate polishing backwash,boiler blowdown,cooling tower blowdown,coal pile runoff,and storm drains.Depending on the relative cleanliness of each stream,these flows will be held up in settling ponds,run through clarifiers,and neutralized,as required,to meet standards for release to the environment.Settling ponds,clarifiers,chemical addition systems,and sludge-handling equipment necessary to perform these functions are included in the plant. 3.1.3 Plant Operating Parameters 3.1.3.1 Boiler Efficiency In accordance with the standards of the American Boiler Manufacturer's Association,the plant's boiler efficiency was calculated using the heat loss method.Using this method,the total heat input to the boiler,the total heat losses,and the difference,which is the heat available,were determined.Efficiency is given as the heat available as steam divided by the heat input expressed as a percentage. The boiler inputs for combustion are the fuel (coal)and combustion air.The higher heating value of the fuel is used to determine the 2499C f $4iZ# 3-13 10/31/85 ;~ ,~ - - ..- I~ - heat input to the boiler.Heat input with the combustion air is virtually negligible,but is calculated based upon the air's heat content above standard temperature and pressure (STP). There are several heat losses from the bo"iler.They are:1)the heat contained in the flue gas and fly ash exiting the regenerative air heaters;2)the heat contained in the bottom ash;3)radiation losses; 4)leakage of air;5)manufacturer's margin;6)unburned carbon;and 7)boiler blowdown. The calculated efficiency of the boiler for these plants using a coal analysis representati ve of ei ther pl ant is 83.77 percent.Thi sis slightly lower than for many coal-fired plants,but it reflects the relatively low heating value and high moisture and ash content of the fuels being burned. 3.1.3.2 Plant Auxiliary Loads The power plant will consume approximately eight percent of the electricity generated when operating at full load.This consumption, used to operate the various systems which comprise the plant,is referred to as the plant auxiliary load.The components of the total estimated auxiliary load are listed in Table 3-2. With the plant gross output of 217,636 kW,the auxilia~load is 7.99 percent of the gross capacity. 3.1.3.3 Heat Balance The heat balance for the plant is presented as Figure 3-5.The plant uses a seven-heater cycle,with four low-pressure heaters,a deaerator, and two high-pressure heaters.Reheat steam is used for the final high-pressure heater,intermediate turbine extraction steam for the second high-pressure heater and the deaerator,and low-pressure extraction for the low-pressure heaters. 2499C 3-14 10/31/85 ~'~~-~-----_-------~-'-"--"'-~""'r,h-_-~------------------ - - - - - - - TABLE 3-2 AUXI LIARY LOAD Steam Generator including 10 and FD Fans Turbine Generator Coal Handling System Ash Handling System Boiler Feed Pumps Miscellaneous Pumps Makeup Demineralizer Condensate Polishing Wastewater Treatment System Cranes and Lifting Equipment Turbine and Boiler Bldg.HVAC Total P1 ant Auxil i ary Load 2499C 3-15 4,000 kW 420 kW 2,500 kW 800 kW 3,100 kW 3,000 kW 200 kW 200 kW 275 kW 275 kW 2.600 kW 17,370 kW 10/31/85 Sl£ET l.OF I. H_.Q CI 25ll5.B F U!lll7.~I' 1'!S2..I H 100< 1!)1' r-- i I ... HI PRESS TURIl I I I I"'~!l§.!h_!L _ ~5F 2fI7.q H ,--_._---_. I I I I :1474Sll8.ll ,34'l.B I' ,328.7 H, I I, !~--."--------------------r-=:: I .·II',II. I I·.!I·.I I·.I I ·'f---'4------'ii'--------Jjf I .~'55173.0 iI136l.5 H I I BFFT I 2.!ill]N Hll ~76~.K1 o ILL 0: ...,:.ClJ ~1~,; <D;t'J- ;21~~ ,,, I 1, I, 1, 1,, Cl ~a... I I f 111.I!I FTO l-:3..BFTO I 15.1!1 FTC I :-i 1///11//11/VIII II/Ill 8.1'.1'.;---I f i '4 I 556..3 P 241 B PO'02."I P I 52.fi<J P,'..am Ill'I 1'...401 IlF I "--,..,........1~7"-I I.,~o 3F 1 1'...~51'r .....--~-i--I ",-lo--.....:.-W',,-...._'!§!'_'f._"",,"_8£-...,rBlERATOR ~..2>.f---J ..........r ......~- ,:'!G5.IlH .'::-J.37'l.~H _'::-J_:m.IlH,32L7H"Z'I8.5H .'::-J.l"'1"17.8H :~,488.1!1 F 3"56.B F I '"::34'1.I!I F 264.3 F 'gJ";Ill.Il D.C.Ill.Il 0.C.:~"Ill.B 0.C. :~~I I':-::: :d~:::~~X :: I >-1 I I 1 •4 I I :U ~9---L3.W~~~~----~i..!~~~-1-------=>--7--~ ,387.1 H 33ll..I H r I .------------------------------------------L--=-~~~~-~-~-~-~---------------_1 PERFORMANCE LEGEND GROSS GEHERATlON AUXrLlAAY POW'ER NET OUTPUT BOILER EFF. l<W KW KY -, 217636.17411.82.53 83.53 84.53 lET STAHON I-£AT RATE BTll/Oi_Hfl 10-416- 1112"11. 1l!17l!. O----FLO\I-LBSIHR P----PRES6URE-LlISISll.tN ABS. F----TEMPERATURE-F H----ENTHALPY-8TU1LB FTD-TERMINAl...OfFFERENCE !FJ ELEP-EXPANSI0N LIIE END POINT \JEEP-USED ENERGY EIoIJ POINT 0.C.-Dlll\IN COOL£R APPROACH (F I S.C.-SL9:OOL I Hll (Fl ~---STEJ¥1 ------.....TEREXTl'\ACT JON STEIlM SHErr ~ 1. 217638.I()I lOPO I!.8!l P.F.45.PSIG HZ TlJRBINE Wf£!'l4TE RAHNl 217S38.~'" AT l~L.Biffi nt'lOTTLE FLOoI,2+l11li psto 1I100./liIOO.F SiE~Taf'ERATrnE,48i1.II FFVT AND 2.III Ill.HG.AIlS.EXHAUST PRESSURE GENERATOR RATING 260000.1(\1'"AT iI.85 P.F AND 45.PSlG H2 PRESS. L-__-,-_--'I-=:;-~ I , I , I , J , I ,,, I , I , I , I , I , , I,,,, I , J I I I I I I I I I I I I J I J I J I J I , J , J I I=-::r..,."""f:.dai...~-1- COI(,:e~ ~35~17.G El.EP lilll_8 H ~~i>21.3 H 128l!.0 13'15.3 1-' GENERATOR 0UTPUl217636 E.L 3311.K'oI "'T45.PSIG HZ M,L.750.K\I FTD 3.29 P "- 145.1 F I I I I ! I i "'II.L::r .''";l~m 'iO.1ON t'llO- "'l-~ I 5.1iI ,'1411.IF lilla.lH FlO ojl.L::r .'.,:::i~.; ~E= 1 5.S 7.116 P "----17"12 F !lNE iii i ::--:-:~-:-r--..-----:--.-..--.~.------..."-:---..--..--1)j I ' I !. . I I I ;.-';':134~5.""'3'*H----------1 I I i I I I I 17l.2f 14[zH 11!.i1 m.e.11I.i1 o.c.,, I I , ~_!'5j!2J,-Q ..! lSI!.1 F HB.1H ,,, r I ~_13t~5~_------------------------,._---.----r1 8a5H FIGURE 3-5 lESSlflE IlACX PRESStR:GEN OUTPUT Ill.H:;ASS KW 2.i!iI 217S38. TUlB HEAT RATE BTUlK'o'-H'I 7SSe.II ALASKA POWER AUTHOR I TY &J51 TNA CllAL -flRED AI.TERHA n ve HEAT BAlA'CE SHEET l.OF I. DATE &'211184 NC'"rORKEBASCO SCALE-NONE DIY.--1--fJ~"-'--=-r....:..:,r----:~aIlFL8'1'EI.-'":z.'" .------,r------.----REV-IS-l-ON-----,---.---.AI'PRIJVEIJ---l'Dl.$!.L 1-----,-----1 - - - - - 3.1.3.4 Turbine-Generator Operating Parameters At a full load of 1.46 x 10 6 1b/hr of main steam to the turbine,the generator output is 217,636 kW.The turbine is a tandem compound flow design with two intermediate pressure extraction points and four low-pressure extraction points and an extraction between the intermediate and low-pressure turbine piping in the crossover.The generator's power factor is 0.85 operating with a 45 psig hydrogen cooli ng system and two inches Hg Abs back pressure.The generator rating is 260,000 kVA. 3.1.3.5 Net Output and Heat Rates The net output of the station will be 200,230 kW at full load after allowing for auxiliary loads.The turbine will have a gross heat rate of 7,858 Btu/kWh at full load.This is a direct measure of the amount of heat energy as steam required to produce a kilowatt hour at the generator bus.The net station heat rate is calculated based on the turbine heat rate,boiler efficiency,and subtraction of the auxiliary load to obtain the net output of the unit at full load.The net station heat rate is approximately 10,300 Btu/kWh. The plant will be designed to have a capacity net factor of 80 percent of full load rating based on a 365-day year.The plant will produce a net of 1,402 GWh at the main transformer.This allows for time at partial load down to 100 MW net,with an availability of 90 percent or 7,884 hours per year.This is a conservative design parameter for this type of plant which considers the harsh environment at the proposed sites. 3.1.3.6 Other Operating Parameters The plant mass flow rates and other operating parameters are summarized in Table 3-3. -. 2499C 3-17 10/31/85 "'"" - .-. - prl:h, TABLE 3-3 PLANT OPERATING PARAMETERS Fuel Consumption Steam Generated/Pressure/Temperature Reheat Steam Flow Flue Gas Volume Lime Consumption Particulate Collection Efficiency Turbine Throttle Steam Flow Turbine Exhaust Waste Heat Rejected Circulating Water Flow)at 90°F. Gross Generation Station Auxiliary Loads Net Generation Gross Turbine Heat Rate Net Station Heat Rate 2499C 3-18 Nenana/Beluga 135 tons/hr 1)460,0001b/hr 2,505 psia/l)005°F 1,270,9961b/hr 1.6·x 106 ac fm 1 ,895 1bs/hr 99.9 percent 1,456,1281b/hr 1,395 x 10 6 lbs/hr 1 x 10 9 Btu/hr 87,900.gpm 217 MW 17 MW 200 MW 7,858 Btu/kWh 10,300 Btu/kWh 10/31/85 -- - ,~ - - - - 3.2 CAPITAL COST ESTIMATES Separate capital cost estimates were prepared for the Beluga and Nenana sites.Further,separate estimates were prepared for the initial 200 MW unit at an undeveloped IIGreenfie1d ll plant site and a second 200 MW unit addition at that site.The estimates were prepared in 1983 dollars and escal ated to 1985 dollars using Ebasco I s Composite Index of Direct Cost for Electric Generating Plants (escalation factor of 1.0394).The Composite Index is based on historical data and reflects annual changes in cost of material s,equipment,and labor rates~ The coal plant and all SUbsequent estimates were prepared using two different data sources.Ebasco maintains a data base of plant cost estimates.This data includes material quantity estimates,labor quantity estimates,basic materials (steel,concrete,pipe,etc.)rates and labor rates.Based on the conceptual engineering design,the quantities are estimated from this data base for the size of plant being built.The rates were modified for the Alaska market and applied to the quantities to obtain costs.The second data source consists of equipment vendor quotes.The manufacturer's of the major equipment were requested to submit budget quotes for the boilers, turbine-generators,S02 scrubbers,and other major equipment.This was used with the Ebasco data to make a complete estimate. 3.2.1 Basis of Estimates 3.2.1.1 Plant Concept in Accordance With Description The plant concept is described in Section 3.1 of this document, utilizing Beluga or Nenana coal. 2499C 3-19 12/16/85 - .~. -- 3.2.1.2 Labor Assumptions Wage rates are based on Anchorage union agreements for work south of 63 degrees latitude north and include workmens compensation,FICA,and public liability property damage. o Each workday will consist of ten hours of labor o Each work week will consist of six workdays o Sufficient craft personnel will be available o Labor will be housed and fed at on-site labor camps o Labor productivity is taken as liaverage U.S.1i with no adjustment 3.2.1.3 Financial Assumptions The estimate does not include allowance for Funds Used During Construction (AFUDC)(frequently called interest during construction). It is also assumed that the project is exempt from sales tax. 3.2.1.4 Site-Specific Assumptions Beluga: o Clearing and grubbing of brush and trees up to 25 feet tall is requi red o Eighty-foot long piles with heavy foundations will be required o Delivery of coal and 1ime will be by truck o 2499C A barge-unloading facility for heavy equipment is included 12/16/85 3-20 - Nenana: o o o o Clearing and grubbing identical to Beluga Pilings and foundations identical to Beluga Delivery of coal will be by rail Delivery of lime will be by either rail or truck 3.2.1.5 Items Specifically Not Included - o o o o o Land and land rights Owner's costs Operating and maintenance costs Spare parts and special tools Maintenance machinery,laboratory,and office equipment - -. - ,.... 3.2.1.6 Included Indirect Costs o Construction management local hire personnel o Casual premium pay (other than schedule 60-hour week) o Construction management automotive equipment o Construction management office and expenses o Temporary warehouse for prepurchased equipment o Road maintenance equipment o Gravel air strip o Ten-mile 69 kV tempora~transmission line o Labor camp,food service,housekeeping o Barge freight/off-site unloading adjustment o Security guard service o Craft transportation to and from labor camp o Final construction cleanup 3.2.1.7 Professional Services Professional services are based on a standard workday for engineering, design,site support engineering,and construction management services. 2499C 3-21 12/16/85 '~"•-'_~'8I ,"_I Plf~-----_ ..... - ,~ """ 3.2.2 Details of Estimates 3.2.2.1 Beluga Site Building a plant at a Beluga site is based on the premise that a major coal mine(s)will be opened there and that a coal export facility will be built.These assumptions are quite realistic.At least one major coal company is currently preparing an envi ronmental impact statement (EIS)for both the mine and export facility. Tables 3-4 and 3-5 present the summary level of the detailed estimates for the Beluga initial 200 MW unit and the Beluga extension 200 MW unit,respectively.The detail estimates are in Appendix A.Table 3-6 presents the capital cost summary for the Beluga coal-fired power plant including other related plant costs. 3.2.2.2 Nenana Site The estimate for a coal-fired plant to be located at a Nenana site will be for a plant of the same size,type,and general configuration as that previously described for the Beluga power plant.Site-specific differences only are addressed here.Items which are not addressed are the same as for the Beluga power plant.The coal to be burned at Nenana is similar to the Beluga coal in details of analysis for ash, water,and heat content.However,the coa,l will be received by rail rather than truck.The coal-handling system is different in design and operation only with respect to receiving coal via a rotary rail car damper. Transmission facilities are the same i'n concept as for the Beluga plant,but reflect only ten miles of transmission for Nenana while Beluga has 48 miles of 230 kV transmission line. 2499C 3-22 12/16/85 -:'~"""'""-----------------"'=-=-------~ .....TABLE 3-4 CAPITAL COST ESTI~1ATE BELUGA 200 MW COAL-FIRED POWER PLANT INITIAL UNIT (1985 $in 1,000s) ..- Account Total Total Total ""'"Number Description Amount Materials Installation 1-Improvements to site 4,170 1 ,212 2,958 ~2.Earthwork and piling 34,998 15,158 19,840 3.Cire water system 8,364 4,074 4,290 4.Concrete 20,808 3,850 16,958 5.Stret stl11 ft eqp 27,960 .10,909 17,051 6.Buildings 18,662 6,016 12,646 7.Turbine generator 19,503 16,777 2,726 8.Stm gener and access 43,887 24,552 19,335 9.AQCS 55,197 30,842 24,355 1O.Other mechan equip 20,368 15,063 5,305 11.Coal and ash hnd1 equip 23,327 13,650 9,677 12.Piping 28,649 10,104 18,545 13.Insul ation 7,038 593 6,445 14.Instrumentation 7,230 6,650 580 15.Electrical equipment 58,894 21 ,483 37,411 16.Pai nti ng 2,276 159 2,117 17.Off-site facilities 13,771 6,169 7,602 18.Waterfront facility 8,018 1,932 6,086 19.Substation/t-line 23,733 13,381 10,352 71-Indirect const cost 41,891 °41,891 72.Professional services 55,907 °55,907 ;l(~ 10O.Contingency 68,9a9 23,093 45,896 99.Total project cost $593,640 $225,667 $367,973 300.Total cost wlo contingency 524,651 202,574 322,077 - 2499C 3-23 ..r .. 12/16/85 TABLE 3-5 CAPITAL COST ESTIr1ATE BELUGA 200 MW COAL-FIRED POWER PLANT EXTENSION UNIT (1985 $in 1,000s) Account Total Total Total F--Number Description Amount Materi al s Installation l.Improvements to site 332 174 158 2.Earthwork and piling 14,094 7,656 6,438 3.Cire water system 7,650 3,822 3,828 4.Concrete 13,469 2,613 10,856.....5.Strct stl/lft eqp 19,493 8,493 11,000 6.Bui 1di ngs 9,331 _3,263 6,068 7.Turbine generator 18,872 16,138 2,734 ~8.Stm gener and access 43,855 23,616 20,239 9.AQCS 41 ,034 21 ,887 19,147 10.Other mechan equip 14,219 10,288 3,931 1l.Coal and ash hnd1 equip 5,715 3,513 2,202 12.Piping 26,012 9,223 16,789 13.Insulation 7,000 571 6,429 14.Instrumentation 6,954 6,396 558 ,~)15.Electrical equipment 45,375 18,499 26,876 16.Painting 2,171 132 2,039 17.Off-site facilities 3,600 561 3,039 19.Substation/T-line 18,596 11 ,284 7,312 7l.Indirect const cost 27,159 0 27,159 72.Profes,sional ·services 14,052 0 14,052 r"'"100.Contingency 46,403 17,775 28,628 99.Total project cost $385,386 $165,904 $219,482 300.Total cost w/o contingency 338,983 148,129 190,854 2499C 3-24 12/16/85 ...... i - TABLE 3-6 CAPITAL COST SUMMARY BELUGA COAL-FIRED POWER PLANT TWO UNIT (1985 $in 1,000s) Unit 1 Estimate Unit 2 Estimate Subtotal Items Not Included in Estimate Town Site Cost Owners Cost (at 2-1/2%of Direct Project) Startup,Spare Parts,and Special Tools Maintenance Shop Machinery,Laboratory Equipment,and Office Furniture $593,640 385,386 $979,026 $18,333 24,476 11,044 2,209 Land (200 acres at $10,920 per acre)2,209 Subtotal $58,271 Project Total Cost $1,037,297 Average Cost per kwl/$2,593 1/Based on Two Unit Nominal Net Capacity of 400,000 kW,Average cost is presented in actual dollars,not 1,000s. 2499C 3-25 12/16/85 -- Indirects for Nenana are also simi~ar to Beluga.The differences are 1 i sted below: o Fifteen-mile 69 kV temporary transmission line o No barge or off-site special handling or unloading adjustment Tables 3-7 and 3-8 present the summary level of the capital cost estimates for the Nenana initial 200 MW unit and the Nenana extension 200 MW unit,respectively.The detailed estimates are included in Appendix A. A capital cost summary presenting the total costs of two 200 MW units at the Nenana site is shown in Table 3-9.These costs are converted to 1985 dollars and owner1s costs,cost of tools and spare parts, maintenance and laboratory equipment costs,and land costs are added to arrive at a total cost of $2,702 per kW. 3.2.3 Comparison of APA Capital Cost Estimates to Estimates for Similar Pl ants inA1aska There are two comparable coal-fired power plant estimates available for comparison to the Alaska Power Authority Beluga site estimate ..These are the 170 MW (150 MW net)power plant,as presented by Signal Energy Systems and the Beluga 150 MW (140 MW net)coal-fired power plant project proposed by Diamond Alaska Coal.The costs of the three plants are compared below in Table 3-10.There are no comparable estimates available for the Nenana site. Details of the Signal Energy 'estimate were not available for comparison to either of the other estimates.However,the Di amend estimate was available,and the most notable differences are listed below: - 2499C 3-26 12/16/85 - TABLE 3-7 CAPITAL COST ESTIMATE NENANA 200 MW COAL-FIRED POWER PLANT INITIAL UNIT (1985 $in 1,000s) Account Total Total Total-Number Descri pti on Amount Materials Installation l.Improvements to site 8,399 2,565 5,824 2.Earthwork and piling 42,350 17,133 25,217 3.Ci rc water system 8,261 3,930 4,331 4.Concrete 30,950 6,522 24,428 5.Strct stl/lft eqp 30,141 11 ,322 18,819 6.Buildings 19,269 5,974 13,295 7.Turbine generator 18,851 16,097 2,754 8.Stm gener and access 43,085 23,557 19,528 9.AQCS 55,768 30,779 24,989 10.Other mechan equip 20,219 14,675 5,544 1l.Coal and ash hndl equip 27,235 16,390 10,845 12.Pi pi ng 30,127 9,765 20,362 13.Insulation 8,436 827 7,609 14.Instrumentation 6,966 6,380 586 15.Electrical equipment 63,823 24,652 39,171 16.Pai nti ng 2,467 165 2,302 17.Off-site facilities 21 ,037 7,339 13,698 19.Substation/t-line 10,788 7,956 2,832 7l.Indirect const cost 55,575 °55,575 72.Professional services 57,911 0 57,911 10O.Contingency 78,065 24,723 53,342 99.Total project cost $639,713 $230,751 $408,962 300.Total cost w/o contingency 561 ,648 206,028 355,620 - - 2499C 3-27 12/16/85 ",-,_"--_....--,,---------------"''"'--.------------------ TABLE 3-8 CAPITAL COST ESTIMATE NENANA 200 MW COAL-FIRED POWER PLANT EXTENSION UNIT CAPITAL COST ESTIMATE (1985 $in 1,000s) Account Total Total Total Number Desc ri pti on Amount Materi al s Install ation l.Improvements to site 461 226 235 2.Earthwork and pil ing 16,572 8,283 8,289 3.Cire water system 8,113 3,854 4,259 4.Concrete 16,339 3,636 12,703,..5.Stret stl/lft'eqp 20,435 8,485 11 ,950 6.Bui 1di ngs 9,809 3,397 6,412 7.Turbi ne generator 19,139 16,376 2,753 8.Stm gener and access 43,497 23,970 19,527 9.AQCS 41,588 21 ,833 19,755 1O.Other mechan equip 13,779 9,863 3,916 1l.Coal and ash hndl equip 6,525 3,612 2,913 12.Piping 27,745 9,838 17,907 13.Insulation 7,473 820 6,653 14.Instrumentation 6,966 6,380 586 15.Electrical equipment 53,650 19,463 34,187 16.Painting 2,358 157 2,201 17.Off-site facilities 3,199 601 2,598 19.Substation/t-line 3,152 1,736 1,416 7l.Indirect const cost 33,968 °33,968 72.Professional services 16,531 °16,531 10O.Contingency 48,417 17,104 31 ,313 99.Total project cos~$399,706 $159,634 $240,072 300.Total cost w/o contingency 351 ,289 142,530 208,759 2499C 3-28 12/16/85 TABLE 3-9 CAPITAL COST SUMMARY NENANA COAL-FIRED POWER PLANT TWO UNITS (1985 $in l~OOOs) Unit 1 Estimate Unit 2 Estimate Subtotal Items Not Included in Estimate Owners Cost (at 2-1/2%of Direct Project) Startup,Spare Parts,and Special Tools· Maintenance Shop Machinery,Laboratory Equipment~and Office Furniture Land (200 acres at $10~920 per acre) Subtotal Project Total Cost Average Cost per kwl/ $639 ~713 399,706 $1,039,419 $25,985 11 ,044 2,209 2,209 $41,447 $1 ,080,866 $2,702 1/Based on Two Unit Nominal Net Capacity of 400,000 kW.Average cost per kWis presented in actual dollars,not in 1,000s. -2499C 3-29 12/16/85 -_.__.----._--------~----------------------- - Plant Estimate TABLE 3-10 PLANT COST COMPARISONS Total Cost ($x 000) Net Capacity Unit Cost - .... APA Beluga Plant Diamond Alaska Beluga Plant Matanuska Power Project 2499C $1,037,297 $319,553 $375,000 3-30 2 -200 MW 1 -141 MW 1 -153 MW $2,593/kW $2,266/kW $2 ,451 /kW 12/16/85 ITEMS INCLUDED IN THE APA PLANT AND NOT IN THE DI~~OND PLANT o A complete coal-handling system with thaw shed,stackout and reclaim,90-day storage,nine conveyors,crushing,and sampling o A 20-mile access road o A 48-mile 230 kV transmission line ..... o o o A ten-mile temporary 69 kV transmission line Moori ng and dock faci 1i ty Ranney well system o Substation ITEMS DIFFERING SIGNIFICANTLY BETWEEN THE TWO PLANTS o Boiler -APA estimate is for a 2,500 psi,Diamond's is 1,450 psi. .... , o o o 2499C Pilings,Foundations and Earthwork -The APA estimate includes 80-foot piles with foundations.The Diamond estimates appear to include only spread footings.Additionally,there is not allowance for earthwork or concrete apparent in the estimate. Structural Steel -The Diamond estimate includes 1,650 tons of steel;the APA estimate is 4,740 tons. Electrical -Diamond's electrical installation includes 139,177 work hours.The APA estimate has over 400,000 work hours for electrical installation,not including the transmission lines. 12/16/85 3-31 ~~_"fii/7il;i__•__",,__~_ o Step-Up Facilities -In addition to the transmission line,the APA estimate includes a step-up transformer yard which is not in the Diamond estimate. ~, i"""", o Site Development -Diamond estimate is for a site already partially developed for the coal port,development costs are $1,359,600.The APA estimate is for an undeveloped site with development costs of $4,076,000. o Piping -With a higher pressure boiler and turbine,all steam piping in the APA estimate will be more expensive. o Camp Costs -The Diamond estimate uses $5G/day,the APA estimate $63/day. o Total Work Hours -The Di amond estimate i ncl udes a total of 1,672,387 work hours.This is less than half the 3,467,000 hours used in the APA estimate. o Union Versus Nonunion -The Diamond estimate assumes the ready availability of nonunion labor.The APA estimate uses union labor in accordance with Anchorage union agreements. o Turbine Bypass -The APA estimate includes design for the main steam to bypass the turbine.In the event of unit trip,steam will d~lP to the condenser to facilitate a rapid restart of the plant (a common practice in Europe and Canada at remote site locations).The Diamond estimate does not appear to include this. The addition of the details in Table 3-11 and associated costs to the Diamond estimate results in an adjusted price of $2,965/kW. 2499C 3-32 12/16/85 '-'-----.......---------------------------------------- '"'"TABLE 3-11 CAPITAL COST VARIANCES FOR ITEMS NOT INCLUDED OR DIFFERING SIGNIFICANTLY IN COST COMPARISON .... .... Item Coal handl i ng 1/ Access roads 2/ Transmission line and step up ?:.../ Mooring and dock facilities y Ranney well system?:.../ Boiler Earthwork pilings and concrete 1/ Site development 1/ Camp costs ~/ Turbine bypass system ~/ Total Estimated Cost Differential of 200 MW Plant over 140 MW Plant $13,580,000 1,037,000 25,404,000 7,838 ,000 3,084,000 3,300,000 35,000,000 1,697,000 2,536,000 2,850,000 $96,326,000 Differential Unit Cost $/kW (net) 96 7 180 56 21 23 248 12 19 20 683 1/Based on scaled costs of 200 MW plant. 2/Same case as used for 200 MW plant. 3/Based on Diamond 1 s hours to construct. 2499C 3-33 12/16/85 ~'i "';;;:::;::O__""""'__--•.:Z_,__,,__,_"'_ - P"""'' - 3.3 O&M COSTS In order to utilize the OGP model and Multiple Area Production Simulation Program (MAPS),it is necessary that O&M costs,exclusive of fuel costs,be developed for the plants.These costs are required in a fonnat which will segregate them into "fixedll and i1 variable"categories. Fixed costs are those which occur in a plant and do not vary regardless of the level of operation,provided the plant is maintained in an operating condition.Fixed costs are measured in dollars per kilowatt ($/kW)•.Vari able costs are those which occur only if a plant generates energy and which vary,in total,directly with the energy produced. Variable costs are measured in dollars per megawatt hour ($/MW~). Two independent approaches were used in developing the coal plant O&M costs.Initially,utility contacts and utility data were the primary source of data to_be used.The utility data was analyzed and modified for the specific site,uti 1ities and pl ant,and the costs presented in Section 3.3.1 of this report were generated.Preliminary review of these results indicated that further work would be required due to the fact that some of the data was "soft"and several assumptions were required to fill the gaps.Consequently,an independent build-up of O&M costs was performed.This was based on vendor equipment data, operational parameters,Ebasco's data fi les,and engi neeri ng judgment. This second O&M cost estimate is that used for analysis and is presented in Section 3.3.2 of this report. It was not possible to directly compare the details of the APA-developed O&M costs with those developed by Diamond Alaska or the Matanuska Power Project since details of those estimates are not available.However,a brief summary comparison to the Diamond Alaska costs is presented in Section 3.3.3. 2499C 3-34 12/16/85 Utility-based O&M costs were developed in 1983 dollars and escalated to 1985 doll ars (escal ation factor of 1.0638).O&M costs based on vendor data and engineering analysis were developed in 1982 dollars and escalated to 1985 dollars (escalation factor of 1.1046).Both used the GNP Implicit Price Deflator. 3.3.1 O&M Cost Development Based on Utility Data The analysis of data for existing coal-fired power plants fixed and variable O&M costs reviewed units in the lower 48 states,since there are presently no operational coal-fired power plants of this size range in Alaska.The selection criteria was to evaluate plants not only in the 200 MW size range,but also to evaluate plants burning coal with characteristics similar to Alaska coals.It was also considered desirable in the selection process to evaluate coal plants with similar flue gas particulate and sulfur removal equipment.- As can be seen in the attached summary Table 3~12,the plants considered in the evaluation were as follows: o o o o o o Huntington No.1 {Utah Power &Light} Parish Plant (Houston Power &Light) Southwest Plant (Springfield City Utility) Asbury Plant (Empire Di strict) Dave Johnson (Pacific Power &Light) Hawthorne No.3 (Kansas City Power &Light) The differences between coal pl ants surveyed and the Al aska Power Authority coal plant are discussed below. 3.3.1.1 Plant Staff and Wages Because of the higher wage rate in Alaska ($37/hr)versus the average in the lower 48 ($26/hr),the total cost of labor is significantly higher in Alaska.In addition,due to the remote location of the ..- 2499C 3-35 12/16/85 .~.,~....._.~"';'_..mm ---~_ f -E 1 J )1 ]1 ]1 I 1 i j J 1 TABLE 3-12 SPECIFIC UTILITY REPORTED DATA OIM COST ESTIMATE BACKUP 200 MW COAL PLANT 1983 DOLLARS Operating Characteristics Utah Pil Huntington 11 Houston Pil Parish Plant Spri ngfi el d City Utilities Empire District Southwest Plant Asbury Plant Pacific Power and light D.Johnston Unit 13 Adjusted Kansas City Power Alaska Annual and Light OIM Costs 121 Hawthorne '3 (1985$)-- Plant Rated Capacity (MW) o Coal HHV Btullb o No.Total Staff o Fixed labor Costs $/kW/yr o Plant Ht.Rate BtulkWh o Sulfur in Fuel (I) o Flue Gas Desulfurization Maintenance Cost o landfill Disposal Costs o Chem.Makeup Cost limestone o Precipitator'Baghouse o Boiler Maint.Costs o Coal Handling Equip.Maint. o Turbine/Gen.Maint.Cost o Cooling Tower Maint.Cost o Water and Waste Treatment System Costs o Lubricant Cost o Total Maintenance Cost o Variable Maintenance Cost ($/MW Hr) 415 MW 11.900 125 51 21.74 9.883 .5 $660.000 11 $200.000- $330.000 $910.000 $1,100,000 $800,000 $350,000 $100.000 $300,000 $50,000 71 $4 ,800,000 TIl $1.1"5 570 MW 415 MW 200 MW 220 MW 235 KW 200 MW 8,600 12,000 11.500 7,800 12,000 7,600 100 51 90 51 42 51 90 51 100 51 123 13.'3"0 16.1"5 15.'9"2 31.'0"2 32.Tl 50.35 10.400 11,008 10.542 11,101 11.949 10,300 5 3.5 5.4 .45 3.0 0.2 $500,000 11 $500.000 11 $50,000 2/$630,000 1/$550,000 11 $355,100 N/A "'31 N/A '31 N/A '!I N/A '31 N/A "31 $1.750,000 $250,000-$200,000-$200,000-$400.000-$300,000-$1,400,000 $1,200,000 $700,000 $500,000 $1,150~000 $900,000 $510,500 $1,000,000 $800,000 $625.000 $3,100,000 $500,000 $856.000 $1,030.000 $200,000 ~I $277,000 $210,000 $200,000 91 $494,000 $400,000 $250,000 $220,000 $380,000 $400,000-$222,000 $100,000 $80,000 NIA .!!I N/A !!/NIA ..!!I $100,000 $343,000 $100,000 101 $140,000 101 $420,000 $250,000 $175,000 $50,000 7/$50,000 T7 $50.000 !!$80.000 71 N/A $80,000 $4,873,0001Jj $2,880.000 TIl $2,062,000 $6,370,000 -$3,100,000 $5,942,600 $1.U7 $.Tl7 $1.29 $3.62 $1.65 $4.51 111 1/Costs are annualized average per unit for scrubber.fans,ducts,and breeching on site where multiple units exist. ~I Costs are annual maintenance estimate for electrostatic precipitator only.. "'31 Landfill is onsite with pondin9i Haulage charges were reported under $50,000 annually and other costs were not reported. 1"1 Bottom ash/FGD sludge sold at $3.50/ton.. 01 Staffing level is per unit average for reported plant total which is higher.Hourly rate averaged $26.00 with fringes. 01 Cost estimate is per unit average,otherwise reported per unit rating. 71 LUbe oil is for turbine and generator lubrication onlYi balance of plant exclUded. TIl Individual unit estimate based on multiple units at one site. '9"1 Pulverizers are ball mill type. TOI Boiler and cooling tower water treatment cost only. TTl Plant has once through cooling from lake at site. 111 Adjusted OIM cost estimates incluae Alaska labor rates of $37/hr and transportation costs for each person once per week at $100 roundtrip. lJI Based on net generation of 1,401,600 MWh at a CF of 80 percent. 2499C ~I - plants in Alaska,(central interior or in the Beluga field),staff levels used are higher {l23}than in the lower 48.Also,transport to and from the site is included. 3.3.1.2 FGD System Maintenance Costs The FGD system maintenance costs are a weighted average based on the costs of the five units listed which have scrubbing systems.Although these systems are not identical,it is felt that lower costs for the simpler system to be used in Alaska are offset by location and the need for high efficiency with very low sulfur coal. 3.3.1.3 landfill Costs A large majority of the plants surveyed by Harza-Ebasco employ onsite disposal of scrubber sludge and ash in evaporation ponds.Because a majority of the plants are in arid areas of the western United States, evaporation can be counted upon to eliminate water runoff from the disposed sludge and ash. Recent power plant designs approved by the EPA and state authorities have required a more permanent solution to the scrubber sludge and ash disposal problems.This solution has taken the form of byproduct sale or providing stabilized sludge landfills.Harza-Ebasco developed costs associated with an environmentally acceptable approach to stabilized sludge landfill operations.The concept employed is similar to that utilized at other stabilized sludge landfills in the utility industry. It consists of excavation of a ground area,installation of an impermeable barrier to protect groundwater,and the disposal of a blend of stabilized sludge (a mixture of scrubber sludge,ash,and lime to act as a setting agent),which resembles low grade concrete. -2499C 3-37 12/16/85 ~;.._u~_=-----_-~,----.---.---------------------------- -- - 3.3.1.4 Chemical Makeup Costs (Lime and Limestone) The cost for FGD chemicals is a widely varying cost factor between utilities in the lower 48.As documented in the EPRJ Report CS-2916. the costs vary significantly in various parts of the country.Because there is no source of lime in Alaska.Harza-Ebasco developed the costs based upon discussions with Seattle.Washington finns.These costs reflect the high transportation charge for delivery to the Cook Inlet ($190/ton).In comparison.if the power plant were located in Seattle. Washi ngton.the annual cost for the FGD system \'iou1d be approximately $240.000.rather than the $1,260,000 Alaska_estimate. 3.3.1.5 Particulate Removal System Maintenance The survey showed that a much higher cost is associated with particulate removal system maintenance than the 0.1 to 0.2 mils/kWh initially assumed by the Power Authority.This higher maintenance cost was the subject of review by Harza-Ebasco.The two highest cost plants were discarded and a weighted average of the four remaining was used. 3.3.1.6 Boiler Maintenance Costs The boiler maintenance costs reflected in the survey confonn to the values obtained from boiler manufacturers for their equipment.The wide range of costs are typical of what may result.Therefore.the figure used is the weighted average of the six plants surveyed. 3.3.1.7 Coal-Handling Equipment Maintenance The costs used in the Harza-Ebasco estimate of coal-handling equipment operation and maintenance reflect data obtained by telephone conversations with coal-handling equipment manufacturers confirming that found during the utility survey.Due to the high moisture.low ..... 2499C 3-38 12/16/85 - .-. hargrove grindabi1ity,and the extreme problems to be encountered in the freeze thaw cycles of the fuel,the average weighted cost of the six utilities surveyed was doubled for this application. 3.3.1.8 Turbine-Generator Maintenance Costs The costs used for maintenance of the turbine-generator are derived from the weighted average of the data supplied by the utilities.This estimate compares favorably to that received from equipment manufacturers. 3.3.1.9 Other Costs (Cooling Tower,Water Treatment, and Lubricant Costs) Cooling Tower Due to the severe nature of the climate where the cooling tower will operate,it is not felt that lower 48 O&M costs are applicable . .Therefore,after review of vendor data,$100,000 per year was allocated for operating and maintaining the tower.This allows for annual partial fill replacement due to freeze damage and normal maintenance • Water Treatment The weighted average of the six surveyed utilities costs were used. Lubricati n9 Oi 1 Based on review of the utility data,$80,000 per year was allocated for all lube oil replacement. 2499C 3-39 12/16/85 ..... - ..... .... - 3.3.2 O&M Costs Development Based on Vendor Data and Engineering Review 3.3.2.1 Basis for Costs In order to identify and categorize all costs into either fixed or vari able categories some basic assumptions were necessary.The costs of all management,engineering,and operations and maintenance staff maintained for the plant may be considered as fixed costs.This is due to the fact that,provided the plant is maintained in a "rea dy-to-operate"state,the enti re staff is requi red regardl ess of the level of operation.This staff will perform all of the day-to-day routine tasks necessary to operate and maintain the plant. All consumable materials costs will be considered as variable costs. This will include chemicals,lime,gasoline,lubricants and oils,and expendable operating items.Although some items may be expended regardless of the level of plant operation,these are a relatively small cost when compared to major vari abl e costs of 1ime and chemical s and are not worth identifying separately. The costs of landfilling the wastes created by the plant are treated as vari abl e.Some small portion of the total wastes stream will be fixed.However,the major waste flows will consi st of fly ash,bottom ash,and water treatment sludge.All of which will vary directly with the plant load . Repair,overhaul,and nonperiodic maintenance costs are handled in two ways.Repair or overhaul of minor equipment is assumed to be performed by the utilities penuanent staff.The labor costs are included in the staff fixed labor element,and the material costs are included in the variable materials costs.Repair or overhaul of the major systems and equipment is performed by an outside contracted firm and occurs as a function of hours of operation.All of these costs are treated as variable costs. 2499C 3-40 12/16/85 -',,----------------------------------------- 3.3.2.2 Costs Plant Staff The total plant operating staff,not including support personnel,will consist of 122 persons.This will include general plant management, main plant maintenance,operations,outside yard and buildings,and coal system operations.The breakdown of personnel into these categories is shown in Table 3-13.This is a somewhat large staff for this size plant when compared to staffing of similar plants in the contiguous 48 states.There are two main reasons for the higher level of staffing.First,the Alaskan utilities recognize the shortage of equipment manufacturers'support available in Alaska.In response,the utilities perfonn more intensive maointenance than would otherwise be the case.Secondly,the coal plants will be located at remote sites with employees staying at camps.It is necessary under these conditions to staff at a level which can handle foreseeable emergencies.Additional factors which increase the staff size are extreme weather conditions and intensive operation of the FGDS. Several utilities with operating power plants were contacted to determine staffing levels.Those utilities,plant names and sizes,and staffing levels are listed below: No. Utility Plant Employed Capacity Pacific Power &Light Wyodek Pl ant 114 332 MW Platte River Power Authority Rawhide Plant 110 250 MW Basi n El ectri c Lee Olds Pl ant 120 219 MW Louiseville Gas &Electric Cane Run No.5 100 176 MW -Springfield City Utilities Southwest Power 88 196 MW Plant Sunflower Electric Cooperative Hayes Pl ant 150 319 MW 2499C 3-41 12/16/85 TABLE 3-13 PLANT PERSONNEL BY CATEGORY- General Plant Management 1 P1 ant Superi ntendent 1 General Supervisor 2 Plant Engineers 1 Clerk 1 Secretary /Recepti oni st 6 Subtotal Main Plant Maintenance Crew 12 Electrical Maintenance Supervisors 6 Foremen 12 Mechanical Maintenance (four shifts -three millwrights/shift) 12 General Mai ntenance Ass;stants 8 Laborers 1 Engi neer 1 Cl erk 53 Subtotal Operations Crew 4 Shi ft Supervi so rs 4 FGD System Operators 4 Generati ng Operators 4 Boiler Control Operators 4 Assistant Operators 2 Chemical Technicians 22 Subtotal - Outside Yard ~nd Buildings 1 Supervi sor 2 Foremen 6 Electrical Maintenance 4 Coal System Operators 4 Mechanical Maintenance 3 Loader Operators 12 Pl ant Sec uri ty Personnel 4 Laborers 4 Central Stores 41 Subtotal 122 TOTAL PLANT PERSONNEL 2499C 3-42 12/16/85 '-'--......_-------------------------------------_. TABLE 3-13 PLANT PERSONNEL BY CATEGORY (CONTINUED) Support Personnel 1 Superv;sor 8 Cook;ng 8 Housekeeping 5 Transportation 3 Medical 25 TOTAL SUPPORT PERSONNEL-. 2499C 3-43 ~~lf"'l'l'!_ 12/16/85 - - The average of the utilities listed above is 46 persons for every 100 MW of capacity.However,this is a very misleading indicator because of the high plant staff and administration that is not sensitive to equipment size.This staffing level would result in a staff of 100 for the 217 MW power plant.The staff level of 122 compares favorably with this number when the reasons for a large staff are considered. In addition to the plant operating and maintenance staff,there will be a support staff necessary to maintain the camp,provide transportation, and give medical attention as needed.This staff will consist of 25 persons as 1i sted in Tabl e 3-13. The cost for the total staff of 147 persons is $11,120,000 per year in 1982 dollars.This is based on 147 persons working 2,080 hours per year at a average 1982 cost of $36.40 per hour. Consumable Materials Lime for the FGDS will be the largest nonfuel consumable materials expense item.Consumption of lime is expected to average 1,900 pounds per hour of full load operation.Based on a capacity factor of 80 percent,approximately 6,650 tons of lime will be consumed per year. There is no readily available source of lime in Alaska.Until a source is developed it wi 11 be necessary to assume purchase of 1ime in the lower 48 states with shipment to Alaska by barge.The estimated delivered cost of lime is $172 per ton in 1982 dollars,which results in an annual cost of $1,143,800 for lime. Chemical consumption will occur for water purification and for treatment of condensate and circulating water.These costs are broken down into the areas of primary water treatment,demineralization,and chemical addition for the circulato~water system (cooling tower). -,..."-- 2499C 3-44 12/16/85 Primary water treatment will supply makeup for the potable water system,the circulating water system,and the deminera1izers.Total requirements are expected to be approximately 485 gpm.This will consist of 200 gpm for potable water,225 gpm for circulatory water and 60 gpm for condensate makeup (demi nera1 i zers).The cost per gallon of primary treated water is approximately $0.0027.This results in a total annual cost of $607,300 as shown below:...., Primary Water Treatment Costs Potable Water (200 gpm){60 min/hr}{8,760 hr/yr}{$.0027 gal)=$283,800 Circulating Water (225 gpm){60 min/hr){8,760 hr/yr)($.0027 ga1}(0.80 cf)=255,400 Condensate Makeup (60 gpm}(60 min/hr)(8,760 hr/yr}($.0027 ga1)(0.80 cf)=68,100 TOTAL $607,300 The circulating water system requires chlorine addition during summer months to control growth of algae and other micro-organisms. Additional,chemicals will be added for pH control,antisca1ing,and corrosion inhibition.The expected annual cost of these chemicals is $25,000. Demineralization of primary treated water for condensate makeup will be performed through two 60 gpm deminera1izer trains.These will each consume $3,830 in chemicals per year.Additionally,acid and caustic will be added to the condensate system.The total condensate chemical costs are: ..- Deminera1izer (2 trains at $3,830/train/year)= Acid and Caustic = TOTAl $7,660 33,000 $40,660 The total for all chemical consumption and water treatment is $672,960. 2499C 3-45 12/16/85 -~'''''''''---''Il$'W"''91-=''·.-=.---~__..._._i"',~_ .... ....' Costs for lubricants,oils,and gasoline or diesel fall into three categories.These are transportation vehicles,heavy equipment (bulldozers,etc.),and plant equipment (turbine,pumps,etc.).A total of six transportation vehicles were assumed for the plant,there are four pickup trucks,one van,and one bus.Additionally,there will be five pieces of heavy equipment at the plant consisting of two bulldozers,one flatbed truck,one panel truck,and one dump truck . The annual costs of the transportation and heavy equipment including fuel,lubricants,and maintenance materials is listed below: TRANSPORTATION AND HEAVY EQUIPMENT COSTS - 4 1 1 2 1 1 1 Item Pickup Trucks Van Bus Bull dozers Flatbed Truck Panel Truck Dump Truck Unit Cost at $3,000/truck/yr at $4,000/yr at $8,000/yr at $20,000/unit/yr at $10,000/yr at $8,000/yr at $10,OOO/yr Total Cost 1/ $12,000 4,000 8,000 40,000 10,000 8,000 10,000 $92,000 1/Cost of lube,oil,fuel,parts,and non1abor maintenance charges. Oi 1 and 1ubricants for the turbi ne-generator,boi 1er feedwater pumP and turbine,and other equipment are expected to total approximately $50,000 per year as detailed below: - ..... ,.,.. Turbine lube oil (5,000 gal.at $4.00/ga1) Other lube oils (2,500 gal.at 4.00/gal) Greases and miscellaneous TOTAL 2499C 3-46 $20,000 10,000 20,000 $50,000 12/16/85 ------------------------------ Solid Waste Disposal Landfill disposal of solid waste,as previously mentioned,is a variable cost.There are three waste streams to be handled;these are bottom ash,fly ash,and wastewater treatment sludge.The estimated quantities of these to be handled annually are: Fly ash (includes captured dry scrubber products) Bottom ash Wastewater sludge TOTAL 57,650 TPY 6,050 TPY 2,000 TPY 65,700 TPY - It is expected that landfill costs,either by contract or by the operating utility,will be $25 per ton in 1982 dollars.This is compatible with current costs of landfilling MSW in an EPA approved landfill.The total annual solid waste disposal cost will be $1,642,500. Repair and Overhaul Costs As described in section 3.3.2.1,Basis for Costs,repair and overhaul costs for minor equipment is covered elsewhere.This section deals with repair and overhaul (often referred to as replacement and renewal) of major equipment only.This equipment includes the turbine-generator,boiler,flue gas cleaning equipment,and cooling towers.Repair and/or overhaul will be necessary as a result of actual hours of operation of the equipment.These costs are,therefore, considered variable.The actual repair or overhaul is typically performed by the original equipment manufacturer or other specialist under contract. In each case,original equipment manufacturers were contacted for data regarding overhaul and repair frequency and costs.The vendor data, 2499C 3-47 12/16/85 ~'·'''''_''''__M ·--,~_-----__w_-----_ together with Ebasco1s experience,was used to create Tables 3-14 through 3-18,which document the expected costs.Those total annual costs for each major equipment section are: ..- Turbine-Generator Boil er Flue Gas Cleaning FGOS Baghouse Cooling Tower TOTAL Sumnary $246,751 1,351,200 40,020 183,667 41 ,384 $1,863,022 F ! - The total costs developed are presented in Table 3-19.The costs are significantly higher than equivalent costs for lower 48 states operating plants,but are within the range of fossil plants nonfuel costs reported by OOE.l/ The areas where costs are higher are in staff costs,consumable materials (lime),and solid waste disposal.The staff costs are significantly higher due to the larger staff size,the remote location of the plant,and the higher Alas~an wage rate.Lime costs are an order of magnitude above lower 48 costs due to the lack of a ready source of lime in Alaska.Solid waste disposal costs are higher because of the plan for dry offsite landfill 48 plants utilize onsite ponds for disposal. 1/00E/EIA-0455{82),UHistorical Plant Cost and Annual Production Expenses for Selected Electric Plants 1982.11 2499C 3-48 12/16/85 1 )j ).~i 1 1 )J »!J l i i TABLE 3-14 MANUFACTURERS WORKHOURS LABOR AND SPARE PARTS COST ESTIMATE OF ANNUAL OVERHAUL OR REPAIR FOR A 2DO HW STEAM TURBINE-GENERATOR Inspection Average Shift Labor Maintenance and/or Repair Manhours Crew Required Cost (f Parts Total Annual Item Interval Required Size (8 hours)$36/hr Cost Cost Cost Buckets 40.000/5 yr 4.800 20 30 $172.800 0 $172.800 $34.560 Shells 24.000/3 yr 960 12 10 $34.560 0 $34.560 $11.508 Bolting 24.000/3 yr 1.600 10 20 $57.600 $5.000 $62.600 $20,845 Diaphragm 40,000/5 yr 3,200 20 20 $115,200 0 $115,200 $23,040 Valves 40.000/5 yr 640 8 10 $23.040 saO.000 $103.040 $20.608 w Lube System 8.000'11 yr 320 4 10 $11.520 $5.000 $16,520 $16.520 I ~Bearings 40.000/5 yr 1.920 12 20 $69.120 $10.000 $79,120 $15,8241.0 H2 System 8.000/1 yr 128 4 4 $4.608 $30.000 $34,608 $34,600 Meggar Field 40,000/5 yr 256 4 8 $9.216 $2,000 $11.216 $2,240 Field Removal 40,000/5 yr 192 8 ;;$6,900 $iO.OOO $16,900 ....."1Inl\.~,~ou Load Gear 40.000/5 yr 160 10 2 $5,760 0 $5,760 $1,152 EHC Unit 24.000/3 yr 64 4 2 $2.300 $20,000 $22.300 $6,690 Excitation System 8.000/1 yr 64 4 2 $2.300 $35.000 $37.300 !...Rt300 ESTIMATED AVERAGE ANNUAL TOTAL COST $246,751 Estimate of manhours.inspection interval.and spark parts cost are suggested estimates by turbine generator manufacturer for scheduled overhaul shutdown in 3-5 year intervals. SOURCE:General Electric Company and Ebasco 1984. 2499C- - I I ----,--j -~-1 -1 ---J ))1 )1 1 )J }j TABLE 3-15 MANUFACTURERS WORKHOUR LABOR AND MATERIAL COST ESTIMATE FOR ANNUAL OVERHAUL OR REPAIR OF A 200 MW COAL-FIRED BOILER!I 1983 DOLLARS Inspection Average Shifts Labor Average Maintenance and/or Repair ~lanhours Crew RCQ'd Cost @ Materials Total Annual Item Interval (hrs)Requi red Size (8 hr)$36/hr Cost Cost Cost Waten/alls 8,uOO/l yr 800 10 10 $28,800 $100,000 $129,000 $129,000 Economizer 8,000/1 yr 320 4 10 $10,800 $20,000 $30,800 $30,800 Super Heater Reheater 8,000/1 yr 240 3 10 $100,000 $80,000 $180,000 $180,000 Steam Drum 4,000/6 mo 192 4 b $140,000 $110,000 $250,000 $500,000 w Convection Section 2,000 192 4 6 $20,000 $20,000 $40,000 $160,000I U1a Flyash Removal 2,000 400 10 5 $14,400 $50,000 $64,400 $257,600 Boil er Contra 1s 4,000/6 mo 192 2 12 $7,200 $40,000 $47,200 $94,400 Dlllu.o",,';'7'o.~Q l\l\l\4:l\l\...n "'n .oI"Il"-'nnn.$60,000 $80,800 $80,800lUi....1 ....\;1 v.vvv uuu c.u ,JU ~£U,OUU ESTIMATED TOTAL AVERAGE ANNUAL COST $1,351,200 -- 1/Cost estimate data is based on manufacturers experience with boilers burning low sulfur,high ash,low heating value (7680 BTU/lb),low grindability western type coal. 2499C TABLE 3-16 ANNUAL OVERHAUL OR REPAIR COST OF BAGHOUSE 200 MW COAL-FIRED PLANT 1/ Mai ntenance Mai ntenance Activi ty Interval Total Cost Annual Cost ~, $690,480BagReplacement48months 172,620 7,672 bags at $90/bag-Labor cost @ $36/hr 44,188 11 ,047 2 men/8-hr shift per 100 bags '""" TOTAL ANNUAL EXPENSES $734,668 $183,667 l/Based upon phone interviews and original equipment quotation by Joy ManUfacturing Inc. - - ..... ""'" 2499C 3-51 12/16/85 - - TABLE 3-17 COOLING TOWER ANNUAL MAINTENANCE EXPENSES COST ESTIMATE l/ 200 MW COAL-FIRED POWER PLANT -Annual Equipment Description Costs Fill Replacement (one section/Yl")$15,000 Gear Reducer 3,200 ~Subtotal $18,200 Labor (640 manhour for one section)$23,040 (1)Gear Reducer 4 (manhour)144 Subtotal $23,184 TOTAL ANNUAL COST ESTIMATE $41 ,384- 1/Cost estimate obtai ned from the Marl E!Y Cool i n9 Tower Company. ....., 2499C 3-52 12/16/85 ~,~_.-------""'1-------=-------"---------------- TABLE 3-18 ANNUAL OVERHAUL OR REPAIR COSTS DRY FLUE GAS DESULFURIZATION SYSTEM 200 MWCOAL-FIRED POWER PLANT 1983 DOLLARS MAINTENANCE ACTIVITIES F,, System Component Absorber/Atomizer Wheel Inserts for 2-75 HP Rotary Atomizer Maintenance Pumps: 2 Feedpumps 2 Material Transfer 3 Lime Milk Transfer Frequency 8,000 hrs Total Estimated Maintenance Cost Subtotal Labor $720 720 $2,000 2,000 2,000 Total Parts $500 10,000 $4,800 4,800 6,_000 Annual Avg. $1 ,220 17,720 $6,800 6,800 8,000 $40,020 1/Typical costs estimated were provided by Joy Manufacturing Company 'for a dry scrubbi ng system. 2499C 3-53 12/16/85 '~.;......_n"'-r---------.......---..,.-..-,-~----_--I TABLE 3-19 200 MW COAL-FIRED POWER PLANT SU~~RY OF O&M COSTS (1985 DOLLARS) Total Cost (in 1 ,000s)Unit Cost Fixed Costs-Staff $12,283 $61 .42/kW/yr 1/ Vari ab1 e Costs Consumable Materials Lime $1,260 .-Water Treatment 743 Vehicles 102 Lubricants 55 Waste Disposal $1,814 Overhaul and Repair $2,058 Total Vari ab1 e Costs $6,032 $4.30/MWh '£/ Total Nonfue1 Costs $18,315 $91.58/kW/yr .:U $13.06/MWh '£/ r 1/Based on net plant capacity of 200 kW. 2/Based on plant annual generation of 1,402,000 MWh at the design capacity factor of 80 percent 2499C 3-54 12/16/85 3.3.3 Comparison of APA Coal-Fired Plant O&M Costs to Those Developed by Others Diamond Alaska's January,1985 feasibility study for a 140 MW (net) power plant built at Beluga presented both fixed and variable costs on a an annual basis for the plant.Those costs are tabulated below in 1985 dollars: Fixed Costs Vari abl e Costs Total Annual Cost $13,000,000 $4,500,000 Unit Cost 1/ $92.86/kWyr $4.59/MWh .- 1/Based on 140 MW (net)and an 80 p1ercent capacity factor • 2499C 3-55 12/16/85 ..... 4.1 4.0 THE GAS-FIRED CT ~_TERNATIVE PLANT DESCRIPTION .- -- - ,f"""< The CT plant design is based on using three gas-fired simple-cycle CT units,rated by the manufacturer at a nominal ISO output of 80 MW each • Each CT is a large frame,industrial type with an axial flow multi staged compressor and power turbine on a common shaft.The CT is directly coupled to an electric generator,and can be started, synchronized,and loaded in about one-half hour under normal conditions. Each CT generator package also includes an inlet air filtration system, fuel system,lubricating oil cooling system,and various minor subsystems,as required,furnished by the manufacturer.Inlet air preheati ng,usi ng a heat exchanger,wi 11 a1 so be necessary.Each uni t will utilize water injection for NO x contY·ol. 4.1.1 General Arrangement The general arrangement of the CT plant i!i presented in Figure 4-1. The typical plant will consist of three ltlrge frame,industrial type CT generators with a gross output of 269 MW E~lectrical. The ,power generation facility proper will consist of three CT generators,three separate inlet air filtll"ation systems,starting motors,motor control centers,and 1ubriciition systems to support each CT generator.The electrical interface rl~qui rements to the local utility will require separate switchgear compartments complete with generator breaker,potential and current transfonners,disconnect link for auxiliary feeder,and a power takeoff.The fuel system will be capable of utilizing natural gas,mixed gas,or liqUid petroleum di sti 11 ate for fuel. 2557C 4-1 10/31/85 ~-,----------------._-_.----------_._-------_.._--------------- o E L H _ -N o Q I I j I ~ ! I I ! I I I~ i I ---J--L l HO lDATE REVISlOM o FIGURE 4-1 HARZA-£BASCOT ALASKA POWER AUTHORITY S".JSTTNA .;orM rotrJ.l1lE ~l P SUSITNA H'IllROElECTRIC P",RO!:::JE~C~T ----1 >'~ II 12 -n ,..I~I''8 I THERMAL ALTERNATIVE 26 I MW SIMPLE CYCLE PLANT GENERAL ARRANGEMENT SCAl£'31,2.1'·0 I A?PRO'I~J'-CATEr,P~N~H~E~CH~A~NJ~C~ALu=====:J APA-2ljQZ.140I~JOHNSON -rT I M-GA-OOI 20 21 22 n Q 4.1.2 Major Plant Components and Functions 4.1.2.1 Turbi ne-Generator Package The gas turbine-generators are lI pac kaged"units and,as such,include all auxiliary equipment.The package includes the simple-cycle CT,a totally enclosed generator with water-to-aircooling,13,800 V 60 Hz,a CT control system consisting of free-standing panels located in the main control room,inclUding the control panel for CT and generator, and the motor control center for unit auxil i ary equipment,generator excitation equipment,CT auxiliary equipment,13.8 kV switchgear, master control panel for overall operation and monitori ng,one transformer rated at 1,000 kVA,13.8/14.6 kV for the ~OO hp cranking motor and a second transformer rated at 1,000 kVA,13.8 kV/480 V for supplying additional auxiliary loads,switchgear and motor control centers,and electrical protection equipment. Other major electrical equipment includes a 110 MVA step-up transformer with a 13.8 kV low-voltage winding and a 138 kV high-voltage Winding. This transformer is connected to the generator switchgear via nonsegregated insulated bus. 4.1.2.2 Plant Auxi1ia~Systems The plant aUXiliary support systems described in this section represent those necessary to operate a simple-cycle CT facility.These systems include natural gas fuel supply system,water injection system, lubrication system,starting and cooldown systems,accessory drive system,inlet and exhaust systems,waste control systems,and fire protection system. 2557C 4-3 10/31/85 Natural Gas Fuel System Clean natural gas is supplied to the nozzles at the combustion chamber by the fuel supply system which consists of the following: ,.... , o o o o Fuel gas strainer -mounted off the turbine generator base Stainless steel on-base fuel piping with carbon steel flanges Combined fuel gas stop and control valves.These valves are located in an explosion proof,vented cabinet on the accessory base. Instruments for the gas fuel system,including: Wall mounted,fuel gas inlet pressure gage Line mounted,gas control valve discharge pressure gage Wall mounted,gas stop/ratio valve discharge pressure gage - Water Injection System for NO x Reduction The water injection system consists of pumping and metering equipment for supplying water to the combustion system for NO x abatement.The control system provides NO x emission control with minimum water injection and minimum degradation in heat rate by modulating the water injection rate proportional to fuel consumption. Water quality required is: Heavy Duty Units Total dissolved solids Total trace metals (sodium +potassium + vanadium +lead) pH 2557C 4-4 5 ppm maximum 0.5 ppm maximum 6.5 -7.5 10/31/85 Lubrication System The turbine~generator~reduction gear~and accessory gear share a common lubrication system.The system is vented to atmosphere and includes the following equipment: o Main lubrication oil pump (shaft-driven from the accessory gear) o Oil reservoir integral with the turbine base: o Full-flow ac motor-driven auxiliary lubrication oil pump with dc emergency backup o ac motor-driven auxiliary hydraulic oil pump o Dual lUbrication oil finned U-tube heat exchangers o Dual ~full-flow five micron filters ~ I f o Stainless steel piping downstream of filters~external to turbi ne shell - o Instruments for control~indication~and protection of the lubrication oil system Starting and Cool down Systems The starting system includes the drive equipment to bring the unit to self-sustaining speed during the starting cycle.The cooldown system provides uniform cooling of the rotor after shutdown.The turbine is ready to restart any time after it has come to rest.These systems include the following equipment: 2557C 4-5 10/31/85 o Electric starting motor o Hydrau1i~torque converter o Hydraulically operated,solenoid controlled jaw clutch with automatic disengagement at turbine self-sustaining speed o Connection to turbine through accessory gear o ·E1ectronYdrau1ic rotor-turning device with a dc motor-driven pump,mounted on the torque converter (the turbine shaft is turned through a 40 degree arc at approximately three-minute intervals during the cool down period) Accessory Drive System Accessories driven through or driven by the turbine accessory gear drive system are: -- o o o o o Starting device Accessory coupling to the gas turbine compressor Lubricating oil pump Liquid fuel pump Hydraulic oil pump Inlet and Exhaust Systems Inlet System -The "inlet system arrangement includes the filter compartment,silencing,ducting,trash screens,plenum,support structure,walkways,and ladder. o 2557C Filter Compartment -The filter compartment is elevated above the unit.The compartment contains a self-cleaning filter, access door,lights,and instruments. 10/31/85 4-6 ..... o Ducting including transition section is connected to the compartment and directs airflow into the inlet plenum. o Inlet silencers are included in the ducting to attenuate sounds emi tti ng from the compresso r i nl et. o Support structure,walkway,and ladder. Exhaust System -The exhaust system arrangement includes a plenum and expansion joint.After exiting the last turbine stage,the exhaust gases enter an exhaust diffuser section which terminates in a series of turning vanes directing the gases from an axial to a radial direction into the plenum.The gas then flows to the side through an expansion joi nt. Fire Protection System Due to the cold climate conditions existing for much of the year,fire protection will be based on standard halon systems rather than water systems.Automatic halon systems will be installed for high risk areas,and manual systems will be used for low risk areas.Also,each system selected shall be compatible with any of the specific hazards it is intended to combat • 4.1.3 Plant Operating Parameters The operation of the 240 MW (ISO)rated simple-cycle plant is greatly affected by site conditions,such as ambient air temperatures. Additionally,the air emissions control methods necessary to meet local requirements will affect the operation.Since these units will be sited at or near sea level,ambient temperature is the single most important variable affecting plant performance. 2557C 4-7 10/31/85 The standard ISO rating for a turbine is based on factory test block conditions.The ambient air temperature is 59°F,air inlet and exhaust losses for filters,silencers,and ductwork are nominal values,air emission control devices are not utilized and plant support loads are not considered.The ISO rating for the proposed units is shown on Tabl e 4-1. The power output,heat rate,fuel consumption,air flow,exhaust temperature and unit efficiency are all interrelated and dependent on the ambient site conditions.Ambient air temperature and the· corresponding air density,affects the air flow through the compressor and turbine.Since the gas turbines are volumetric devices,cold high-density air increases the mass flow through the machines,which increases the power output and reduces the heat rate. The method of NO x emissions control selected for the gas turbine cycles is water injection.The injection of high-pressure water into the combustion zones controls the gas temperatures thereby limiting the formation of NO x •The net performance effect of water injection is to slightly increase the maximum power output and the heat rate. The effect of the air inlet and exhaust ductwork,filters,and silencers is to restrict the air flow due to friction losses. Consequently,this inefficiency increases the heat rate and reduces the power output. The simple-cycle plant performance at various ambient temperature conditions operating at sea level with water injection for NO x control is presented in Table 4-1. 4.1.3.1 Turbine-Generator Efficiency The thermal efficiencies reported the net salable power for a given amount of gas turbine fuel energy input expressed as a percentage.All 2557C 4-8 10/31/85 TABLE 4-1 SIMPLE-CYCLE PERFORMANCE SUMMARY (3 Combustion Turbines) Gross ---------------Net 1/2/-------------- Site Ambient ISO 5/_23 0 30 0 59 0 71 0 (Design) Output,kW Net 80,000 307,500 262,100 237,700 226,600 Heat Rate Btu/kWhr (HHV)10,660 11 ,700 12,000 12,200 12,300 Heat Consumption,Btu/hr x 10 6 HHV ~./852.8 1 ,203 1,054 967 932 ,.,..Thermal Efficiency,(HHV)4/29%28%28%28% Heat inputs are for a single unit and outputs,except ISO,are for three units. ..... 1/Auxi1 i ary power assumed at approximately one percent for gas turbi ne plus fixed plant load • ~/Water injection was utilized in all net calculations. 3/ 4/Overall cyc1 e efficiency with auxi 1i ary power losses ;nc1 uded. 5/Gross single unit output rating without corrections for site,plant loads,water injection,or temperature. 2557C 4-9 10/31/85 .- ...... inlet and exhaust duct losses.mechanical gearing losses.electric generator losses.and auxiliary plant loads are accounted for.Note that the efficiency changes only slightly with the ambient temperature but that the rating changes significantly . 4.1.3.2 Plant Auxiliary Loads The simple-cycle facility ratings are net values assuming an overall plant auxiliary load of approximately 2.5 percent.The auxiliary loads fall into two categories:1)CTauxiliary power and control;and 2)plant loads.The CT loads are approximately one percent of the gross gas turbine output. Combustion turbine related loads include:lube oil heaters and pumps • cooling fans.water injection pumps.enclosure heaters.and cooling water pumps.The fixed plant load estimated at 4,000 kW consists of: lighting,service water pumps,heating,ventilation and air conditioning equipment,water demineralizer pumps,and maintenance equipment. 4.1.3.3 Net Output and Heat Rates The net output from the plant consisting of three simple-cycle gas turbines varies from a high of 308 MW at -23°F to a low of 227 MW at 71°F.The net plant output at site conditions of 30°F is 262 MW. The net plant heat rate ;s a measure of the input energy to produce a salable kilowatt of electri~ity.The heat rate is inversely proportioned to the plant efficiency.The heat rates,as all of the plant operating characteristics,are based on the lower heating value of the fuel,which is normally accepted for gas turbine ratings.The fuel lower heating value,or net heating value,does not include the energy required to vaporize the water formed during combustion which is 2557C 4-10 10/31/85 ""'" lost in the flue gas.The lower heating value heat rate of 10,900 Btu/kW based on the plant operating at 30°F corresponds to a higher heating value heat rate of 12,000 Btu/kW. 4.2 CAPITAL COST ESTIMATE 4.2.1 Basis of Estimate Two conceptual estimates for simple-cycle CTs were prepared.Both are for single unit simple-cycle CTs.They differ because one estimate is for a new unit at a completely undeveloped site,while the second estimate is for a new unit or add-on at an existing site.The complete three-unit plant,as described,will consist of one unit corresponding to the fi rst estimate and two add-on uni ts . .The estimates are based on a scope that includes facilities and systems required for self sustaining units.The estimates were prepared in 1983 dollars and escalated to 1985 dollars using Ebasco1s Composite Index of Direct Cost for Electric Generating Plants (es~alation factor 1.0394).The Composite Index is based on historical data and reflects annual changes in cost of materials,equipment,and labor rates.The conceptual estimates were prepared in the Ebasco Code of Accounts.The estimates are based on a scope that includes the facilities and systems required for self-sustaining units,based on the following: General o Wage rates applicable to Anchorage union agreements south of 63 degrees latitude,including Workmen's Compensation,FICA, and Public Liability Property Damage insurance rates,as calculated by Ebasco. o A work week consisting of working ten hours per day,six days per week. 2557C 4-11 10/31/85 o Sufficient craftsmen available to meet project requirements without labor camps. o Professional services including engineering,design,related services,and construction management based on a generic plant of comparable size. o o o 0 0 0 0 ".". 0 ~--- 0 ~ o o o o 2557C Land and land rights not included. Allowance for AFUDC not included. Client cost not iflc1uded. Permanent town for plant operating personnel not included. Capital cost of gas pipeline not included. Operating and maintenance costs not included. Contingency included at the rate of 12 percent for material and 15 percent for installation. Construction performed on a contract basis. Project being exempt from sales/use taxes. Labor productivity being "average U.S.1t with no Alaska adjustment. Spare parts and special tools not included. Startup costs not included. Maintenance machinery,laboratory,and office equipment not i nc1 uded. 10/31/85 4-12 -~..~--"""'_-~._--------~-'----r----------------------------- ,....Ci vi 1 o Clearing or demolition on existing site as necessary for new facility. o No dewatering of excavated areas is assumed. ~.,o No asphalt or concrete paving is included. F I I o A 1.5-mile access road is included. o Fencing perimeter of 75 acres plant site plus interior security fencing as required. o Simple-cycle building 100 ft x 192 ft x 70 ft eave height. Mechanical - o General Electric provided a budgetary quotation for an 80 MW G.E.PG7l11E gas turbine.and the necessary auxiliary equipment. o Piping and insulation '~ o Large bore and small bore p1p1ng s1z1ng and quantities are based on historical data from similar units. ~ i - E1 ectrica1 o Pricing is based on historical data from similar units and in accordance with representative historical inflation indices. o Indirect construction cost 2557C 4-13 10/31/85 _,~-.--'f""""'---------.----'--------.......--__..------------------ Indi rect Cost a Indirect construction cost is priced in accordance with Ebasco experience based on a contract job.Included in indirect costs are: Construction management local hire personnel Casual premium pay (other than scheduled 60-hour week) Construction management automotive equipment Construction management office and expenses Temporary warehouse for prepurehased equipment Road maintenance equipment Offsite unloading and hauling Security guard service Final construction cleanup -a Testing is assumed to be the contractor's responsibility and witnessed by construction management personnel. a Temporary power is assumed to be furnished without cost to contractors., Professional Services .... - a 2557C The professional services estimate is based on a ·standardized workday package for engineering,design,related services, consulting engineering,provided by Ebasco Site Support Eng'ineering (ESSE),and design and construction management servi ces. 10/31/85 4-14 r 4.2.2 Details of Estimate The capital cost estimates were prepared in a format which presents the total for each line item,as well as the materials costs and installation cost for each item.The summaries of the initial plant· and extension plant are presented in Tables 4-2 and 4-3,respectively. The details of these estimates are in Appendix B. These estimates were used to establish the total cost of a three-unit simple-cycle CT plant,as shown in Table 4-4.The total plant cost was developed by summing the capital costs of the initial CT and two extension units and adding items not included in the capital costs. Owner1s costs are expected to be only one percent of the total direct costs.This is significantly less than for the coal plants,reflecting the simplicity of and shorter construction period for CTs.Startup, spare parts,and special tools are expected to be 0.5 percent of total direct cost.Also.significantly less than for the coal-fired plant. Maintenance equipment.laboratories.offices,and the land for the site are assumed to already exist.This assumption was made by agreement with the major Railbelt utilities that new simple-cycle CT plants will be constructed at existing sites. 4.3 O&M COSTS In order to utilize the OGP model and MAPS,it is necessary that the plant1s O&M costs,exclusive of fuel costs,be developed for input to the models.These costs are required in a format which will segregate them into lIFixedli and "Variable"categories. Fixed costs are those which occur in a plant and do not vary regardless of the level of operation,provided the plant is maintained in an operating condition.Fixed costs are measured in $/kW.Variable costs 2557C 4-15 10/31/85 TABLE 4-2 CAPITAL COST ESTIMATE SIMPLE-CYCLE CT,.,.,.INITIAL UNIT (1985 $in 1,000s) Account Total Number Description Total Amount Total Materi a1 s Install ati on- l.Improvements to Site 1,139 305 834 2.Earthwork and Piling 695 98 597 f'~4.Concrete 1,044 238 806 5.Strct st1/1ft Equipment 2,088 1,306 782 6.BUildings 1,790 695 1,095 7.Turbine Generator 13,518 12,812 706 10.Other Meehan Equip 1,005 646 359 12.Piping 794 271 523 13.Insulation 134 38 96,.,..,14.Instrumentation 165 103 62 15.Electrical Equipment 2,836 1,560 1 ,276 16.Pai nti ng 218 47 171-17.Off-Site Facilities 2,024 310 1,714 7l.Indi rect Const Cost 4,478 0 4,478 72.Professional Services 2,181 0 2,181 100.Contingency 4,563 2,211 2,352 99.Total Project Cost $38,672 $20,640 $18,032 .300.Total Cost w/o Contingency 34,109 18,429 15,680 2557C 4-16 10/31/85 TABLE 4-3 CAPITAL COST ESTIMATE SIMPLE-CYCLE CT EXTENSION UNIT (1985 $in 1,000s) Account Total Number Description Total Amount Total Materials Installation .- 2.Earthwork and Piling 695 98 597 4.Concrete 1,044 238 806 5.Strct stl/Lft EqUipment 2,088 1,306 782 6.Bui 1di ngs 1,790 695 1,095 7.Turbine Generator .13,518 12,812 706 10.Other Mechan Equipment 1,005 646 359 12.Piping 794 271 523 I""'"13.Insulation 134 38 96 14.Instrumentation 165 103 62 15.Electrical Equipment 2,184 1,560 624 16.Painting 218 47 171 71.Indirect Canst Cost 2,078 0 2,078 72.Professional Services 1,306 0 1,306 100.Conti ngency 3,518 2,138 1,380 99.Total Project Cost $30,537 $19,952 $10,585 300.Total Cost wlo Contingency 27,019 17,814 9,205 I""'" - ..... i - 2557C 4-17 10/31/85 ~,---------------------------....----------- TABLE 4-4 CAPITAL COST SUMMARY SIMPLE-CYCLE CT POWER PLANT THREE UNITS (1985 $in 1,000s) Di rect Project Costs Unit 1 Estimate Unit 2 Estimate Unit 3 Estimate Subtotal Items Not Included in Estimate Owners Cost (at 1%of Direct Project) Startup,Spare Parts,and Special Tools (0.5%of Direct Project) $38,672 30,537 30,537 $99,746 $997 499 Maintenance Shop Machinery,Laboratory Equipment,and .Office Furniture (Equipment Already Exists) Land (Installed at EXisting Site) Subtotal Project Total Cost Average Cost per kwll For 3 unit,261 MW plant $1,496 $101.242 $386 ..,., 11 Based on the three-unit total net rating of 262 MW per unit at design condition of 30°F.Actual ISO rating is 80 MW.Average cost per kW is in whole dollars,not l,OOOs .. 2557C 4-18 10/31/85 :~I~"---If'i"J4ii '""""'_ ,..., - ""'"' are those which occur only if a plant generates energy and which varies,in total,directly with the energy produced.Variable costs are measured in $/MWh. In developing the O&M costs to be used,the initial sources of data for analysis were utility data and vendor data.The data was analyzed and is presented in Section 4.3.1.However,much of the utility data was from the lower 48 states.The Alaskan utilities operate substantially differently from lower 48 utilities,and they are currently in a state of change regarding policy for operating staff and maintenance procedures.For these reasons,an independent engineering build-up of O&M costs was performed.This was based on vendor equipment data, operational parameters,Ebasco's data files,and engineering judgment. This O&M cost estimate is presented in Section 4.3.2 of this report. The two estimates are evaluated in Section 4.3.3. 4.3.1 O&M Cost Estimate Based on Utility Data The information data base utilized for the simple-cycle CT plant was drawn from:1)utility information supplied by Alaskan utilities; 2}lower 48 utility information;and 3)CT generator equipment manufacturers.The resulting data is shown in Table 4-5.The.uti1 ity data O&M costs were developed in 1983 dollars and were escalated in 1985 dollars using the GNP Implicit Price Deflator (escalation factor 1.0638)....'.._.~~i."ut:4t1 ~1;.j)-"A~~(".-I \ lt was 'tRe pi illidl)goal 1~<1ata search to qual'f)-i-flfol"lTlaLinn \, basQd oa i aOIll~Aa.:I 262 MW powec:::81ock.I."e:e~'Util itt Fe1391"tet1 'i1liOl1llatioli was not uSUally 'aval1able for this three-Ulli t P0ft'€l'"Block-.! coafig"otiOIi.8ecatls€af.these difforoRces ..the utility information was averaged and adjusted utilizing the following assumptions: 1.Plant staffing was based on a nominal net power block ratings ranging from 77 MW to 340 MW.At multiple unit sites,plant staff was reported for the CT plant only. - 2557C J J ))I <))i J »I 1 <j TABLE 4-5 O&M COST ESTIMATE UTILITY REPORTED DATA O&M COST ESTIMATE 260 MW NET SIMPLE-CYCLE CT PLANT 1983 $ Anchorage Arizona Public COIIIlIonwea1th Florida Power COlllllonwealth Municipal Service Compa~*Edison Compa~-Bartow P.l.-Edison Company -Power &lfght APA P1 ant Cost Description Yuma Plant Crawford St.Petersburg Calumet Plant No.1 1983$1995$ Plant Rat f ng 157.2 MW 208.0 MW 222.8 MW 297.0 MW 77MW 261 MW 261 MW Plant Staff 15 15 20 20 7 25 25 Ffxed l!bOr Cost!! $/kW/yrj $5.16 $3.90 $6.31 $4.73 $6.81 $7.17 $7.63 Fuel Cost (Annual)$2.391.000 $2.037.000 $5.489.000 $2.999.000 $8.130.200 -iO>Plant Heat RateI N (Btu/kWh)14.565 16.587 13.459 16.897 22.000 12.000 12.000a Annual Operating Schedule (Hrs/Yr)1.800 500 600 600 3.200 7.000 7.000 Consumab1es lube.Oil.etc.$50.000 $25.000 $30.000 $45.000 $20.000 $148.300 $157.800 Major Overhaul Costs (Annual)$200.000 $550.000 $650.000 $550.000 $700.000 $575.000 $612.000 Minor Overhaul Costs (Annual)$185.000 $250.000 $302.700 $250.000 $200.000 $328.100 $349.000 Total Mafntenance Cost $435.000 $825.000 $992.700 $845.000 $920.000 $1.051.400 $1.118.800 OIM Variable Cost U/MWH)$1.31 $7.93 $7.42 $4.74 $3.73 $0.57 $0.61 1/Plant staffing where units are located at large thermal installations was average reported by utfl ity for the specific fnstallatfon.'1/labor cost for Alaskan utility personnel are $36/hr.lower 48 utility is $26/hr. 2bb7C .- - - 2.Variable maintenance costs were based on the unit run times and power generation levels as estimated by the utilities. 3.Total annual maintenance costs were annualized and spread over the operating period.For example a major overhaul cost scheduled to occur at 60,000 hours was adjusted .by the ratio of 8,000/60,000 hours to arrive at a yearly cost. 4.3.1.1 Plant Staff and Wages Staff levels selected for the Alaska 262 MW plant were based on an average expected staff of 21 personnel to operate and maintain the three-unit plant plus four security personnel.At a total cost of $36.00/hr (1983)and 2,080 hrs/yr/person}the total plant staff of 25 results in an annual staff cost of $1,872,000. 4.3.1.2 Consumable Material Costs Included in consumable expenses are the material costs of operating and maintaining the demineralized water system for water injection into the gas turbines,and the cost of lUbricating oils,greases,gaskets,and minor hardware.The time of actual operation of the lower 48 states utility plants is not as representative of the planned Alaskan plant operation as are the Anchorage Municipal Light and Power {AMLP}Plant No.1 operating hours.For this reason,the consumable material costs of AMLP were used to generate the planned plant cost land as hours of operation and capacity. 4.3.1.3 Major Overhaul or Annual Maintenance Costs This cost item includes inspection and major overhaul of the compressor,combustor,entire hot gas path,turbine,and generator in accordance with manufacturer1s recommendations.The costs derived for the new plant are well below those reported by AMLP (for older less f'" , 2557C 4-21 10/31/85 --,,...------......-------------------------------- - maintained plants),but are in line with those experienced by other 0.$.utilities.The cost of $575,000 per year is based on the average per MW cost of the four lower 48 utilities. 4.3.1.4 Minor Overhaul Costs The equipment manufacture~recommend frequent (annual or semi-annual) i nspecti on of the mi nor equi pment,turbi ne beari ngs,and other accessible items.These are the annual costs for those inspections and resulting maintenance or repairs.Minor inspection and repairs are performed at prescribed intervals of operating hours (i.e.,3,500, 7,000,etc).As such these costs are a function of operati ng time. The work performed is also a function of the number of machines to be inspected,repaired,etc.As is expected,the AMLP minor repair costs are hi gher for the plant si ze than are the lower 48 uti1 i ties minor repair costs.As an estimate of the new plant costs the AMlP costs we~e used and modified based on the number of machines (four at AMLP Plant No.1 and three at the APA plant)and the number of operating hours. 4.3.2 O&M Costs Development Based on Vendor Data and Engineering Review 4.3.2.1 Basis for Costs In order to identify and categorize all costs into either fixed or variable categories some basic assumptions were necessary.The costs of all management,engineering,operations and maintenance staff maintained for the plant may be considered as fixed costs.This is due to the fact that,provided the plant is maintained in a lI rea dy to operate ll state,the entire staff is required regardless of the level of operation.This staff will perform all of the day-to-day routine tasks necessary to operate and maintain the plant. 2557C 4-22 10/31/85 ~,--&---------.......------------------------------- .... ....,. All consumable materials costs wi'll be considered as variable costs. This will include chemicals,gasoline,lubricants,gaskets and oils, and expendable operating items.This is acceptable since it is relatively easy to maintain a CT in a ready-to-operate condition. Repair,overhaul,and nonperiodic maintenance costs are handled in two ways.Repair or overhaul of minor equipment is assumed to be performed by the utility permanent staff.The labor costs are included in the staff fixed labor element,and the material costs are included in the variable materials costs.Repair or overhaul of the major systems and equipment is performed by an outside fi nn and occurs as a function of hours of operation.All of these costs are treated as variable costs. These costs were developed in 1982 dollars and escalated to 1985 using the GNP implicit price deflator (escalation factor of 1.1046). 4.3.2.2 Actual Costs Developed Plant Staff The total plant staff will consist of 26 persons.This will include a plant superintendent,operators,and maintenance personnel.The actual "operating"staff will be quite small compared to the maintenance staff.This reflects the fact that all three units can be started, operated,and shut down remotely by a system dispatch center.Should an on-duty operator require assistance,the maintenance personnel will be available.The plant staff is described in Table 4-6 . The simple-cycle CT plants will not be at a remote location and therefore do not require large staff for emergencies or any permanent support facilities. 2557C 4-23 10/31/85 - TABLE 4-6 262 MW (net) SIMPLE-CYCLE CT PLANT PLANT STAFF Superintendent Pl ant Operators Maintenance Foreman Mechanical Maintenance Electrical Maintenance General Maintenance Security Total Plant 1 4 1 4 4 9 3 26 - ..... - Staff sizes for CT plants in the contiguous 48 states were reviewed to determine whether or not the above estimate is consistent.As shown Table 4-7,these plants have smaller staffs than that estimated as necessary for the Alaska plant. TABLE 4-7 CONTIGUOUS 48 STATES CT GENERATING PLAN STAFF SIZE Size Number of Utility Plant (MW)Employees Arizona Public Service Co.Yuma Plant 157.2 15 Commonwealth Edison Co.Crawford 208 15 Commonwealth Edison Co.Calumet 297 20 Florida Power Corporation St.Petersburg 223 20 Florida Power &Light Co.Lauderdale 821 48 Florida Power Corporation DeBary 401 23 This data indicates an average plant staff for CT plants of slightly less than seven persons per 100 MW of installed capacity.This would indicate a staff size of 17 or 18 persons for the plant in question. 2557C 4-24 10/31/85 - ,~ - ~- The staff size of 26 is felt to be consistent with this in view of the fact that the other utility plants average 351 MW in size and probably realize some efficiency of scale for staff size. The total cost in 1982 dollars,of this staff,is $2,077,500.This is based on 26 persons working 2,195 hours per year at an average wage cost of $36.00 per hour.The additional hours above the standard work-year of 2,080 hours allows for coverage of plant operation with only four shifts. Consumable Materials Water treatment for the water injection systems will utilize a regeneration demineralizer system and filters.This system will require regular maintenance and periodic replacement of the demineralizer bed materials and filters.Since the units are to be built at existing plant sites,the assumption is that a potable water system al ready exi sts and primary treatment will not be necessary. Demineralized water required per unit is 28 gpm,resulting in a total 84 gpm three-unit requirement.Two 60 gpm demineralizer trains will be util i zed to supply the water i njecti on system.The annual cost of bed materials for each train is $3,830 and the cost of acid and caustic is $16,500 per train.This results in a total demineralize materials cost of $40,660 as presented in Table 4-8. The inlet air filtration system will consist of high efficiency prefilter and an initial separator (dropout)zone.The inertial separator will require cleaning,but not any material replacement.The hi gh efficiency prefi 1ters will requi re peri odic fil ter cell changeout. Changeout frequency will vary depending on local air quality conditions.It is anticipated that each filter unit will be charged out twice per year for each of the three units.The estimated cost of materials for each filter unit of $8,000 is presented in Table 4-9 resulting in a total annual inlet filter system material cost of $48,000. 2557C 4-25 12/16/85 TABLE 4-8 MEDIA FILTER CHANGEOUT COST ESTIr~TE FOR A WATER TREATMENT PLANT MIXED BED REGENERATED UNITl/ Media . Change Out System Component Interval Amount and Cost/Train Fixed Annual Cost Total Amount Annual Cost for 2 units Sulfuric Acid and Caustic ""'"Sand Filter Cation Bed Anion Bed Mixed Bed Carbon Filter 2 yrs 5 yrs 3 yrs 3-5 yrs 2 yrs 12 Ft3($50/ft3) 22 Ft 3($100/ft 3 ) 22 Ft 3($260/ft 3 ) 7 ft 3 ($116-$260/ft 3) 12 ft 3 ($50/ft3 ) $300 440 1,910 880 300 $3,830/Unit $7,660 33,000 $40,660 2557C 4-26 10/31/85 _'...."......,........_...'!"'!"i:&:ilii&__IiiiipG&Wk_.------_ TABLE 4-9 SIMPLE-CYCLE CT PLANT INLET AIR FILTERING SYSTEM O&M COST ESTIMATE 11 System Component (3)High Efficiency Prefilter (2 filter change/yr) Parts Cost $8,000/filter (3-)Labor Cost 3 men at 8 hr each changeout TOTAL COSTS Annual Cost $48,000 $48,000 - 11 Information obtained from Anchorage Municipal Light &Power 2557C 4-27 10/31/85 ~..~"!lI1S'Nlitl.'I""'1.............._,~--------_ Consumption of lubricating oil,grease,and miscellaneous items,such as gaskets and small hardware,is a variable expense.These materials are consumed as a function of operating hours.The largest single usage of lube oil will be the three turbine-generator sets.While the lubricating oil will seldom require changing,oil will be lost from the system through cleaning,leakage past bearing journals,and filter changeout.Makeup for these losses will be in the range of 6,000 gallons per year.With a delivered cost of $400 per gallon,the resultant annual cost for three units is $72,000. Lubricating oil for other equipment will be minor in comparison to the turbine-generator requirements.These uses are for pumps,motors, fans,and other small equipment.This expense item,coupled with minor hardware items,such as gaskets,nuts and bolts,valve repair parts, etc.,are expected to .total approximately $5,000 per year for the three-unit plant. The turbi ne exhaust system will wear or degrade as a functi on of hours of unit operation.Acoustical panels,expansion joints,and the turbine exhaust breeching will wear due to temperature,exhaust gas components,and startup and shutdown temperature gradients.The exact number of acoustical panels and expansion joints installed per unit is uncertain until the plant layout is final.It is likely,however,that some of these wi 11 requi re replacement every three to fi ve yea rs.For this reason,an annual variable cost allowance covering these panels and three expansion joints of $45,000 is used.The breakdown of expected costs is shown in Table 4-10. Waste Di sposal There will be two waste streams from the plant.The first will be sanitary wastes.It is assumed that with modification at the time of construction,the existing site sanitary facilities will be capable of handling/disposing of this stream.The second waste stream is the - 2557C 4-28 10/31/85 ~-"".._,---_.------,--------------------------- TABLE 4-10 SIMPLE-CYCLE CT PLANT EXHAUST DUCTING O&M COST ESTIMATE 1/ Variable Units System Description Annual Cost (3 )Acoustic Silencing Panels (spares).$30,000 (3)Expansion Joints and Duct Breeching (spares)5,000 -Labor Costs 3 men at 24 hrs 7,776 Welding Consumables,etc.1,500 TOTAL COSTS $44,276 1/Cost estimate as obtained from General Electric Company for a typical PG 7111 E Install ation. - .- ~",~9"""'""""" 2557C 4-29 10/31/85 - - -- - """" effluent from the deminera1izer system.Since it is the only waste stream to be dealt with,it will not be worthwhile to provide on-site treatment and disposal.Rather,the effluent will be held in on-site holding tanks for removal by tank car to an off-site treatment facility.Each deminera1izer train will produce 200 gallons of backwash waste water per day.This will result in an annual effluent stream of 146,000 gallons per year to be transported,treated and disposed of.The estimated cost for this service is SO.30/ga110n for a total annual cost of $43,800. Repair and Overhaul Costs As described in Section 4.3.2.1,Basis for Costs,repair and overhaul costs for minor equipment is covered elsewhere.This section deals with repair and overhaul of major equipment only.Repair and/or overhaul will be necessary as a result of actual hours of operation of the equipment.These costs are,therefore,considered variable. Each complete generating set consisting of turbine,generator, compressor,and combustor is treated as a unit for both minor and major overhaul activities.Further,need for repair of a single component such as the lube oil cooler,will result in an outage of the unit.A listing of the inspections and descriptions of associated repair work is included in Section 4.3.1.This work is normally performed by an outside service contractor,frequently the vendor that supplied the generating units.The average annual costs of the three types of inspections are shown in Table 4-11.The total shown is for a single unit.The three-unit plant total annual repair and overhaul costs will be $715,500. Table 4-12 presents the total estimated operating and maintenance costs of $7.96/kW/yr for fixed costs and $0.53/MWh for variable costs.The fixed costs are in line with,although they are higher than,the range of fixed costs that exist in the lower 48 states. 2557C 4-30 10/31/85 J 1 J )-.1 J ") 1 I J )1 J 1 1 I 11 TABLE 4-11 MANUFACTURERS MANHOURS LABOR AND SPARE PARTS COST ESTIMATE FOR A 79 MW ISO RATED SIMPLE-CYCLE CT 1/ Manhours.parts cost.crew sfze and suggested mafntenance fntervals are approxfmate manufacturers estfmate based on ffeld experfence for a typfcal base loaded CT operatfng for approxfmately 8.000 hrs/yr on natural gas fuel. SOURCE:General Electrfc Company and Ebasco 1984. 2!i57C TABLE 4-12 262 MW SIMPLE-CYCLE CT POWER PLANT SUMMARY OF O&M COSTS (1985 $) Total Cost (In 1,000s) Fixed Costs Unit Cost Staff Variable Consumable Materials Water Treatment Lubrications Inlet Air Filtration Turbi ne Exhaust Waste Disposal Overhaul and Repair Total Variable.Cost Total Nonfue1 Costs $2,295 $45 85 53 50 $48 $790 $1,071 $3,366 $8.76/kW/yr l/> 0.58/MWh '£:./ $12.90/kW/yr .!/ 1.84/MWh '£:./ 1/Based on net plant unit capacity of 262,000 kW. 2/Based on annual plant generation of 1,829,000 MWh at design capacity capacity factor of 80 percent . ..- - ..... 2557C 4-32 10/31/85 i~,,~,_.__'Ill _Iif...".._---"-rll..w~~>--------~.,.,.__._Oll>i"'l_,~_ .... .- The variable costs are much lower than those found in the lower 48 states.The one single reason for this is the base loading of these units.Review of lower 48 states annual operating hours for CT~/ show annual operating hours in the hundreds for most units and in the 1,000 to 5,000 range for all others.The Alaskan units will operate 8,000 hours per year. 4.3.3 Review of Developed Simple-Cycle Plant O&M Costs The two different estimated O&M costs for a three-unit simple-cycle plant built in Alaska taken from Tables 4-5 and 4-12,are presented below.Al so presented are the costs for Chugach El ectri c Associ ati on (CEA)and AMLP. Uti 1ity /Basi s APA-based on until- ity data revi ew (Tabl e 4-5) APA-based on engi- nearing review (Table 4-12) CEA (Beluga plant) AMLP (Plant No.2) Fixed Unit Cost $/kW/Yr 7.63 8.76 11 .21 12.79 Variable Unit Cost $/MWh/Yr 0.61 0.58 1.40 0.92 ..... i - The fixed and variable unit costs estimated for the APA plants are significantly lower than those for the Railbelt utilities.The fixed costs for the Railbelt utilities are higher because both plants referred to consist of a number of smaller,older units,and both combined-cycle and simple-cycle units.These plants are representative 1/"Historical Pl ant Costs and Annual Production Expenses for Selected Electric Plants,1982,11 DOE/EIA-0455(82). - ·~:I 2557C 4-33 10/31/85 - of the Railbelt plants to be operated in the foreseeable future.This mix of smaller,older plants has higher maintenance and operational staff requirements than is to be expected with new plants consisting of identical units. Variable costs are a function of the capacity factors of these plants. The APA plants variable costs are based on a capacity factor of 80 percent while the CEA and AMLP plants each operate at a capacity factor of 50 percent.In summary,although the APA estimated O&M costs are lower than the utility reported costs,the differences are justifiable. The small difference between the two independently estimated O&M costs, 10 percent and 17 percent for fixed and variable,respectively,can be attributed to variance in assumptions and conservatism in the higher estimate.The O&~cost data which will be used is that developed based on engineering review and manufacturer's data -that is $8.76/kW/yr fixed and $0.58/MWh variable. r 2557C 4-34 10/31/85 5.1 5.0 THE GAS-FIRED,COMBINED-CYCL.E PLANT ALTERNATIVE PLANT DESCRIPTION 5.1.1 General Arrangement The combined-cycle alternative consists of two sets of two CT generators each eXhausting into a waste HRSG.The two HRSGs supply steam to a single steam turbine.Each CT generator will be a large frame industrial type unit identical to the CT utilized for the simple-cycle plant thermal alternative.The CTs,HRSG,and steam turbine-generator set are arranged to minimize hot gas ductwork and steam piping.The arrangement is shown in Figures 5-1 and 5-2. 5.1.2 Description of Major Plant Components and Their Functions The plant major equipment consists of two sets of CT generators,two HRSGs,one steam turbine-generator,an air-cooled condenser,and a feedwater train. 5.1.2.1 CT Equipment The two CT generators with attendant equipment will be identical to that described for the simp1e~cyc1e power plant in Section 4.1.2.The CT performance is sl i ght1y derated due to the increase in exhaust pressure associated with the HRSG.For the actual design conditions at an Alaska site the gross output rating of each CT is approximately 89 MW.The heat balance for the plant is presented in Figure 5-3. 2565C ·~,,~~,._rmw_,.,."...,_--- 10/31/85 5-1 __n -_---_ I'n:'-Q -'I III i---r II'fPASS EXHAUST !iT"'< DHAUST :r"'LEMU" OFFICE I ___~~~~~~l --==t=--:=----~ At--------4sF===~===1===~~===o====~rl;;;i;~~ ______----"%'-0 HEAT !lECOW£OY -+-----.-1 STU>1 lOOERAro~ t'lA!II IOU.U!>lU!L.--r------J TlUlISf<ll"Il'!R ~~--+-----...J.---llJx ---t7lH--3l --+f1++--.-J.-W+.l-- BOILER FEED PUMP'S ------;1---- DEAERATOIl -------l-J! ..eo V SllTiCHQAI JIeO.2. CHEMICAL J:l'JECTlm4 SUD --~ IL_ o, g... (I -~ PLAN -220 Mil NOMINAL RATHH 2 THERMAL ALTERNATIVE 230 M'rI CO/'18INED CYCLE POWER PLANT GENERAL ARRANGEMENT PLAN r I c F1GURE 5-1 o h_ -- HAlUA -£1JAKQ -AU.5U.Pm/iER AUTHORITY "5lJH,*,)Or/'ff~ susrr...HYIlflOELECTRlC P1'lOJEcY -1 8 "'-....-oo~ Q I.. IOl'~-Q \ \ POOft ~.!.r!...r--:"':'_'_-!.:IZ:...._L_~I1'-...!..~__...,...--!I"S'1-.....:.!.~--!I.:.'~fll'--!.:'9~---'~.....:.:..'...;'22";;':'-_~. [ -- II1BINED CYCLE PLANT III ...! II 12 n II>17 Ie, I j .I 1 __J.._2 01 P; I J I J.....--~._,,--_•..J SEC 1 .U 19-'-1-I. SECTION -B I1-GA-:).O'1 i5 ~--------- -----'-,'~"\-----,--J ~ ."--'--- II --EXHb.U5l' r..u:..::T ''=====------------=:==-~---=-----====tr ~;j ·--lO'·'..---1 _Lr-;---,~,1 STE......TUR BY-FlLSS {OP .ISCHARGE,STEJHRSG0 • T •• GAS TURBINE GENERATOR NO .1 I I I I ~------r--------,-----... I I I I I I I I l---I GAS TU~BINE I EXHAUST GAS I .2~8'7.lJ Q I 918 T I WI H I '>.I P +t"-KIlSG I STACK I GAS I 2"!IO.ILER BLOWDCIWN -:;.2:Q 'nz T '>27 H 000 • 17.3 Q '"TZ'lO P HEAT RECOVERY STEAM GENERATOR nl."•n,T ~.'"... TO HRSG NO.2 FROM HRSG MO.2 COMPRESFI~TEIlED~;;'fNLET .: I I I I AIR INLET--____~-~;.-:-~--------I,,~~-------.... STACK GAS"- -----.....------ WATER INJECTION FUEL GAS--e,.:~------------- .,T .... ".•II I I I I I I t TO GAS ITURBINENOl.2--_I~;;~-------------zs.•....•--------,.0 T - zoc;o P' H G K A B c -r i' i; !" o 2 3 7 ~l-•..,...-.l!-a II ...- - IT"" ,.... 5.1.2.2 Steam Cycle Equipment HRSGs and Ducting The HRSGs are considered part of the steam plant,although they will be housed together with the CTs in a large common building. Each HRSG package (one for each gas turbine exhaust)will include the steam generator complete with ductwork from the CT to the steam generator,a bypass damper and bypass stack,and a steam generator exhaust stack.The HRSG performance output of each HRSG shall be 300,000 lbs/hr of 900 psig,955°F steam when supplied with feedwater at 250°F and 2,417,000 lb/hr of exhaust gas at 973°F.Designed for continuous operation,the HRSGs will include an evaporative section,a superheat section,and an economizer.All steam generator controls will be located ina common area in the central control room. During startup and other load conditions,the bypass damper may be utilized to provide operational flexibility.By opening the bypass damper and closing the louvered HRSG inlet dampers,the CT exhaust is routed to the stack and does not reach the steam generator. Steam Turbine and Generator The steam produced in both HRSGs will be conveyed to a common turbine-generator set.The turbine-generator will be a tandem compound,multistage condensing unit,with one extraction for feedwater heating,mounted on a pedestal with a top exhaust going to the air cooled condenser.Design parameters for the turbine-generator are shown on Table 5-1.The 'turbine-generator ratings are based on a four-inch HgA or less condenser back pressure which can be maintained anytime ambient outside temperature is 71°F or less.Lower condenser pressures,during cool months,will result in slightly greater power generation. """' 2565C 5-5 10/31/85 TABLE 5-1 STEAM TURBINE-GENERATOR UNIT DESIGN PARAMETERS ,..- I Tu rbi ne Type: Generator Type: Multistage,single extraction condensing, top exhaust Hydrogen-cooled unit rated 65+MW at 13.8 kV with 30 psig hydrogen pressure at 10°C Common base mounted with direct-drive couplings.Accessories include mUltiple inlet control valves,electric hydraulic control system,lubricating oil system with all pumps and heat exchangers for cooling water hook-up,gland seal steam system and generator cooling.Excitation compartment complete with static excitation equipment.Switchgear compartment comp1 ete with generator and breaker potential transformers. r - - Perfonnance: Steam Turbine Generator Features: Base Rating Steam Inlet Pressure Steam Inlet Temperature Exhaust Pressure Exhaust Temperature Speed Steam Rate 60 MW 850 psig 950°F 4.A..HgA 125°F 3,600 rpm 510,000 lb/hr - 2565C 10/31/85 5-6 ~_.._-",,---------.....,._---------------------------- - - - - ..... The steam turbine-generator set will be furnished complete with lubricating oil and electrohydraulic control systems,as well as the gland seal system,and the generator cooling and sealing equipment. In addition to the CT generators,steam generators,and steam turbi ne, the steam cycle will include the feedwater pumps,condensate pumps, vacuum pumps,deaerator,instrument and service air compressors,motor control centers,and control room. Waste Heat Rejection Heat will be rejected from the steam cycle at the outside mounted air-cooled condenser where air flowing across cooling fins absorbs heat condensing the exhausted steam.The condenser will be vertical forced draft with de-icing equipment as suggested by manufacturer.Condensate from the condenser will be pumped first to the condensate storage tank and then to the feedwater heater-. Electrical Equipment The unit auxiliary transformer is 10 MVA,13.8/4.16 kV.The secondarY winding supplies 4.16 kV switchgear.This 4.16 kV switchgear supplies large motor drives (e.g.,boiler feed water)plus three 4.16 kV/480 V transformers with a combined capacity of 3,000 kVA.These transformers supply smaller motors and mi scell aneous loads vi a motor control centers. Other major electrical equipment includes a 250 MVA transfonner with two 13.8 kV windings and one 138 kV winding.This transformer would be connected to the two gas turbine-driven generator switchgear line-ups via a nonsegregated insulated bus duct.The output of the steam turbi ne-dri ven generator sWitchgear woul d be connected by the same type of bus to a 110 MVA transformer with a 13.8 kV low-voltage winding and a 138 kV high-voltage winding.Other equipment that will be identical to that required for the simple-cycle unit is still applicable. - 2565C 5-7 10/31/85 ·-......----,---_--,---~~--------i~---~--------------- IJ:lIillIIrt I - Miscellaneous Systems In addition to the potable and service water system,this plant will require makeup water for the steam cycle.To purify the makeup water a demi neral i zi ng system wi 11 be requi red. Blowdown from the HRSGs and waste from the demineralizer and the condensate polisher represent additional waste-handling capacity requi rements.These waste streams wi 11 requi re hol d-up and treatment prtor to discharge in accordance with regulations. 5.1.3 .Plant Operating Parameters The combined-cycle plant is affected by site conditions similar to the simple-cycle plant previously discussed.The turbine performance is affected primarily by the ambient temperature which in turn affect the operation of the steam cycle.As CT output increases with increased air flow at lower ambient temperatures the steam produced in the HRSG also increases.Surrmary of plant operating pa-rametersis presented below: PLANT OPERATING PARAMETERS - .- Fuel Consumption (Full Load) Steam Generation (Full Load) Steam Pressures/Temperature Gross Generating Capacity Station Auxiliary Loads Net Generation Gross Station Heat Rate at Full Load Net Station Heat Rate at Full Load Net Station Rate at 3D-Percent Load 2,110 x 10 6 Btu/hr 5.1 x 10 5 1b/hr 2,400 psia/1,000°F 378,300 kW 7,400 kW 229,900 kW 8,900 Btu/kWh 9,200 Btu/kWh 12,600 Btu/kWh The performance of the gas turbine-generator is slightly reduced from that for a simple-cycle configuration due to the higher exhaust pressure of the HRSG.However,the energy lost by the simple cycle in the turbine exhaust is available for the steam cycle. 2565C 5-8 10/31/85 - - ..... The ambient site temperatures wi 11 a1 so di rect1y affect the performance of the air-cooled condenser selected for this alternative.The performance of an air-cooled condenser improves with ambient temperatures below the design temperature.Lower ambient temperatures lower the turbine back pressure which increases the steam turbine generator output.However,for these calculations,a four-inch HgAbs condenser pressure has been assumed for all ambient temperatures. Actual possible power output will be slightly greater during cooler portions of the year.Table 5-2 shows performance as a function of ambient temperature. 5.1.3.1 Turbine-Generator Efficiency Similarly to the simple cycle,the combined-cycle thermal efficiencies reported are the percent of net salable power for a given fuel energy input to the gas turbines.All mechanical losses,electrical losses, and auxiliary loads has been deducted from the gross power generated. The energy recovered with the addition of the HRSG and steam turbine accounts for approximately a ten percent increase in the thermal efficiency over the simple cycle,with a predicted net thermal efficiency of 37 percent. 5.1.3.2 Plant Auxiliary Loads The combined-cycle plant ratings are net values assuming an overall plant auxiliary load of approximately three percent.The auxiliary loads fall into three categories:1)CT aUXiliary power and control, 2)steam cycle loads,and 3)plant loads.The CT auxiliary loads are estimated at approximately one percent of the gas turbine site corrected output.The steam cycle auxiliary loads are estimated at four percent of the steam turbine-generator,and consists of boiler feed pumps,condensate pumps,cooling tower fans,and makeup water treatment equipment.The balance of plant load estimated at 3,300 kW includes plant lighting,heating and cooling,air compressors,and maintenance equipment . 2565C 5-9 10/31/85 -------;-------------------------_._"------~-- TABLE 5-2 COMBINED-CYCLE PLANT PERFORMANCE SUMMARY (2 CTs Required) -Site Ambient Temp of _23 0 _30 0 59 0 71 ° (design) J!$ISR Output kW Netl/262,400 229,900 212,600 204,900 Heat Rate Btu/kWh (HHV )9,200 9,200 9,200 9,200 Heat Consumption x 10 6 Btu/hr 2,430 2,110 1 ,952 1,881 Thermal Efficiency,(HHV)~/371.37%371.37% - - - - 1/Auxiliary power assumed at approximately one percent for gas turbine, four percent steam turbine cycle and fixed plant load. ~/Water injection was utilized in all set calculations. ~/Overall cycle efficiency with auxiliary power losses included. - 2565C 5-10 10/31/85 - ..... .- ~- 5.1.3.3 Operating Configurations The combined-cycle configuration may be operated in several other modes,in addition to the full combined cycle.Either gas turbine and associated HRSG may be operated alone with the steam turbine operating at approximately half capacity.The most inefficient operation will be with the steam turbine operating at less than full throttle flow. Al so,one or both gas turbi nes may be operated as simpl e-cycle machi nes by bypassing the HRSGs.The heat rates for simple-cycle operation will match those for the simple-cycle alternative.and the heat rate for the half capacity combined cycle will approach that of the full combined cycl e. 5.1.3.4 Net Output and Heat Rates The net output from the combined-cycle plant with both gas turbines and steam turbine operating varies from a high of 262 MW at -23°F.to a low of 205 MW at 71°F.The net output at site conditions of 30°F is 230 MW. The net plant heat rate,bdS~d on the fuel higher heating value,for the combined cycle is the same for all ambient temperatures.The heat rate of the gas turbines increases slightly in the combined cycle just as in the simple cycle;however,the incremental heat lost in the gas turbine exhaust at higher ambient temperatures is recovered in the steam cycle which levelizes the net heat rate of the combined cycle. The steam cycle heat rate is more dependent on the type of equipment, operating parameters,and auxiliary loads,and less dependent on ambient temperatures than are the CTs . 2565C 5-11 10/31/85 - - 5.2 CAPITAL COST ESTIMATE 5.2.1 Basis of Estimate A single conceptual estimate was prepared for the combined-cycle plant.The complete plant as estimated is for a three-unit, combined-cycle,gas-fired plant.Two of the units are gas-fired CTs, while the third is a steam turbine unit.The configuration and operation of the plant is as described in Section 5.1. This conceptual estimate is prepared in the Ebasco Code of Accounts,- and is presented in Table 5-3.The estimate is for a complete combined cycle facility and excludes owner1s cost (including Land and AFUDC). The estimate has a base pricing level of January,1983 dollars and is escalated to 1985 dollars using Ebasco's Composite Index of Direct Cost for Electric Generating Plants (Escalation factor of 1.0394). The estimate is based on the following: 1.Wage rates applicabl e to Anchorage uni on agreements south of 63 degrees latitude,including Workmen's Compensation,FICA, and Public Liability Property Damage insurance rates,as calculated by Ebasco. 2.A work week consisting of working ten hours per day,six days per week. 3.Sufficient craftsmen available to meet project requirements without 1abor camps.' 4.Professional services including engineering,design,related services,and construction management,based on generic plant of comparable size. 2565C 5-12 10/31/85 ,~'''''''---~~-----r--_W----'I----------F"""""------------------ TABLE 5-3 CAPITAL COST ESTIMATE COMBINED-CYCLE POWER PLANT (1985 $) ..... - 2565C 5-13 10/31/85 "--,-..-""""'"I"',..--,---"'r"""""--,----------.,......r-------_---------- 5.Land and Land Rights not included. 6.Allowance for AFUDC not included. 7.Client cost not included. 8.Pennanent town for plant operating personnel not included.- 9.Capital cost of gas pipeline not included. 10.O&M costs not included. 11.Contingency included at the rate of 12 percent for materi al and 15 percent for installation. 12.Construction perfonned on a contract basis. 13.Project being exempt from sales/use taxes. 14.Labor productivity being "average U.S.II with no Alaska adjustment. 15.Spare parts and special tools not included. 16.Startup costs not included. ..... - 17.Maintenance machine~,1aborato~,and office equipment not i nc1 uded. Civil (Categories 1,2,3,4,5,6,16, 17,and 18) Clearing is assumed based on scrub brush and trees up to 25 feet.Some rock excavation is assumed in deep cuts.No dewatering of excavated areas is assumed.Waste would be trucked to disposal on an off-site 2565C 5-14 10/31/85 ~~;--"""''''''''''I''r·''_iiZi---''''---'''''''-----------'''i·-------------------- - facility.The capital cost of constructing the off-site facility is not included.No asphalt or concrete paving is included.A 1.5-mile access road is included.Air-cooled condenser used in lieu of cooling tower/circulating water lines. Mechanical (Categories 7,8,9,10,and 14) General Electric provided a budgetary quotation for one 227 MW G.E. STAG 207E plant consisting of two MS 7001E gas turbines,two HRSGs,one steam turbine-generator,and the necess~~auxiliary equipment.Water treatment system pricing is based on a Illinois Water Treatment Company quotation.GEA Power Cooling Systems Inc. provided budgetary quotation for a direct air cooled condenser system. Piping and Insulation (Categories 12 and 13) Large bore and small bore piping'sizing and quantities are based on historical data from similar units. "..,. Electrical (Categories 15 and 19) 'Pricing is based on hi storical data from simil ar uni ts and in accordance with representative historical inflation indices. Indirect Construction Cost Indirect construction cost is priced in accordance with Ebasco experience based on a contract job.Included in indirect costs are: - - o o o o o 2565C Construction management local hire personnel Casual premium pay (other than scheduled 60-hour week) Construction management automotive equipment Construction management office and expenses Temporary warehouse for prepurchased equipment 5-15 10/31/85 .-~::_-----_._--_._- - o o o o o Road maintenance equipment Ten-mile 25 kV temporary transmission line Offsite unloading and hauling Security guard service Final construction cleanup - Testing is assumed to be the contractor's responsibility and witnessed by construction management personnel.Temporary power is assumed to be furnished without cost to contractors. Professional Services The professional services estimate is based on a standardized workday package for engineering,design,related services,consulting engineering,ESSE engineering,and design and construction management Services. 5.2.2 Details of Estimate The capital cost estimate was prepared in a format identical to that used for the CT plant.The summary of the initial plant cost estimate is presented in Table 5-4.The details of these estimates are in Appendix C. The total plant cost was developed by summing the capital costs of the CTs and the steam unit and adding items not included in the capital costs. Owner1s costs are expected to be only 1-1/2 percent of the total direct costs.This is significantly less than for the coal plants,reflecting the simplicity and shorter construction period for CTs.Startup,spare parts,and special tools are expected to be 0.75 percent of total direct costs,also significantly less than for the coal-fired plant. Maintenance equipment,laboratories,offices,and the land for the site 2565C 5-16 10/31/85 -. - .- TABLE 5-4 CAPITAL COST SUMMARY COMBINED-CYCLE POWER PLANT (1985 $in 1,000s) Direct Project Costs Items Not Included in Estimate Owners Cost (at 1-1/2%of Direct Project) Startup,Spare Parts,and Special Tools (at 0.75%of Direct Project) Maintenance Shop Machinery,Laboratory Equipment, Office Furniture (Equipment Already Exists) Land {Installed at Existing Site} Subtotal Project Total Cost Average Cost per kwl/ For 230 MW Plant $146,138 2,192 1,096 and 0 0 $3,288 $149,426 $650 1/Based on the design condition ratings at 30°F for CT ratings.With a -gross capacity of 237.3 MW and auxiliary loads of 7,447 kW,the net capacity is 230 MW.Average Cost per kW is presented in whole dollars,not 1,000s. -2565C 5-17 10/31/85 ..... ""'"I - are assumed to already exist.This assumption was made by agreement with the major Rai1be1t utilities that new combined-cycle plants will be constructed at existing sites. 5.3 O&M COST ESTIMATE The combined-cycle plant O&M data,just as the coal plant and CT plant data,will be utilized as input to both the OGP and MAPS models.This data too then must be developed in tenns of fixed and variable costs. The cost definitions are identical with those given in Section 4.3 for the simple-cycle plants. Also like the CT plant,A1as~an utility data,contiguous 48 states utility data,and vendor data were gathered and analyzed.Section 5.3.1 presents the O&M costs developed from analysis of the utility data.Section 5.3.2 presents the results of an independent cost buildup based on vendor data and engineering analysis.The two estimates are compared in Section 5.3.3. 5.3.1 O&M Costs Based on Utility Data The information data base utilized for the combined-cycle plant was drawn from:1)utility infonnation supplied by Alaskan utilities; 2)lower 48 utility infonnation;and 3)CT generator equipment manufacturers.All utility costs were received based on 1983 dollars and the results escalated to 1985 using the GNP implicit price deflator (esca1 ati on factor of 1.0638).The method of categori zi ng and adjusting the data for individual utilities for comparison purposes on a unifonn basis are discussed below. The utilities contacted whose combined-cycle plant data was used were: o Anchorage Municipal Power and Light -Plant No.2 o Chugach Electric Association -Beluga Plant 2565C 5-18 10/31/85 ~.~""~-----!jil4IIiji---'----'""~~------------~-------------- o o o o Houston Light and Power -T.M.Wharton Plant Portland General Electric -Beaver Plant Public Service of Oklahoma -Comanche Station Arizona Public Service -Santan Station - ""'", These plants studied va~in size from 160 MW to 500 MW.The comparison of these plants for each line item shown on Table 5-5 is di scussed below. 5.3.1.1 Plant Staff and Wages There are two main differences for the higher labor costs for the Alaska plants,staff size,and wage rates.The average staff size of the lower 48 utilities was approximately 6.5 person per 100 MW of capacity,while the Alaska plants averaged over nine persons per 100 MW.This reflects the higher hours of operation for the Alaska p1 ans and resu1 ts in a staff of 21.Wage rates for A1 ask.an personnel are approximately $10 per hour higher than lower 48 states,i.e.,$36 versus $26. 5.3.1.2 Water Costs The plant will consume demineralized water for injection into the two CT and condensate mak.eup to the steam cycle.The cost of treatment varies from plant to plant as shown in Table 5-5.The reasons for the variance are the quantity of water used and the quality of the raw water to be demineralized,based on 150 gpm demineralization and approximately $0.50 cost per 100 gallons.The expected cost is $315,400. 5.3.1.3 Major Overhaul or Annual Maintenance The costs of equipment overhaul was derived after review of utility data and original equipment manufacturer's data.These include the two CTs,the HRSGs,steam turbine,and air-cooled condenser.The costs in Table 5-5 are the weighted average of the utility costs. 2565C 5-19 10/31/85 I -1 J B I J -.1 J J j II j i j D TABLE 5-5 UTILITY REPORTED DATA O&M COST ESTIMATE COMBINED-CYCLE PLANT -- Chugach Houston Portland Pub.Srv.Arfzona Anchorage Electrfc lfght &Power G.E.Okla.Pub.Srv. Munfcfpal Beluga T.M.Wharton Beaver Comanche San tan Alaska Plant Cost Descrfptfon Plant No.2 Sfte Plant (300 MW)Plant Statfon Statfon 1983$1985$ Plant Ratfng (MW)160 MW 178 MW 300 MW 500 MW 255 MW 289 MW 230 MWY 230 M~/ Pl ant Staff!!15 17 28 20 20 15 21 21 Ffxed Labor!! Cost $/kW/yrY $11.59 $10.76 $5.05 $2.16 $4.24 $4.29 $6.86 $7.27 Plant Heat Rate 11.000 BTU 12.500 BTU 9.650 BTU 8.800 BTU 9.445 BTU 8.860 BTU 9.200 BTU 9.200 BTU kllfl klnl kWfl klnl kWfl klnl kWh-k""lin 01 Operatfng SChedule 8.000 Hr 8.000 Hr 6.500 Hr 1.000 Hr 2.000 Hr 2.000 Hr 7.000 Hr 7.000 HrI N Hrs/Yr.Yr Yr Yr Yr Yr Yr Yr Yr0 Water Costs $350.820 $320.000 $200.000 N/A $11.680 N/A $315.400 $335.500 (Injected)No Yes Yes No No No Yes Yes Major Overhaul Cost (Annual)$200.000 $162.500 $500.000 $200.000 $400.000 $450.000 $282.000 $300.000 Mf nor Overhaul Cost (Annual)$89.700 $70.000 $200.000 $250.000 $200.000 $300.000 $151.000 $160.000 Consumables Lube.011.etc.$60.000 $80.000 $130.000 $90.000 $65.000 $110.000 $80.000 $85.000 Total Mafntenance Costs (Annual)$700.520 $854.500 $1.030.000 $1.080.000 $1.341.680 $1,720.000 $828.400 $880.500 Varfable Costs $/MWh $.b5 $.60 $.53 $2.16 $2.63 $2.98 $.51 SO.55 !!Plant stafffng where unfts are located at large thermal fnstallatfons was average for combfned cycle plant reported by utflfty for the specfffc fnstallatfon. 2/Lower 48 utflfty labor costs were 26/hr.All are based on 52 weeks/year.and 40 hour weeks. ~/230 HW at ISO translates to 230 MW at 30°F. -- 2565C """5.3.1.4 Consumable Materials The costs of turbine lube oil,grease,chemicals,and miscellaneous hardware for the plant were estimated based on review of uti1 ity data. 5.3.2 O&M Costs Development Based on Vendor Data and Engineering Ana1ysi s 5.3.2.1 Basis for Costs The costs of all management,engineering,operations and maintenance staff maintained for the plant may be considered as fixed costs.This is due to the fact that,provided the plant is maintained in a Uready to operate U state,the entire staff is required regardless of the level of operation.This staff will perform all of the day-to-day routine tasks necessary to operate and maintain the plant. All consumable materials costs will be considered as variable costs. This will include chemicals,gasoline,lubricants and oils,and expendable operating items. The costs of disposal of the wastes created by the plant are treated as variable.Some small portion of the total wastes stream will be fixed.However,the major waste flows will consist of water treatment sludge,which will vary directly with the plant load. Repair,overhaul,and nonperiodic maintenance costs are handled in two ways.Repair or overhaul of minor equipment ;s assumed to be performed by the utilities permanent staff.The labor costs are included in the staff fixed labor element,and the material costs are included in the variable materials costs.Repair or overhaul of the major systems and equipment is performed by an outside contracted firm and occurs as a function of hours of operation.All of these costs are treated as variable costs. 2565C 5-21 10/31/85 This set of costs was developed in 1982 dollars and escalated to 1985 dollars uS'ing the GNP implicit price deflator (escalation factor of 1.1046). 5.3.2.2 Actual Costs Developed Plant Staff The total plant operating staff,not including support personnel,will consist of 35 persons.This will include general plant management, plant maintenance,operations,and security.The breakdown of personnel into these categories is shown below. 230 MW (NET) COMBINED-CYCLE PLANT PLANT STAFF - Superi ntendent Pl ant Operators Maintenance Foreman Mechanical El ectrical General Security Total 1 8 1 5 5 12 3 35 This is a somewhat large staff for this size plant when compared to staffing of similar plants in the contiguous 48 states.There is one main reason for the higher level of staffing.The Alaskan utilities recognize the shortage of equipment manufacturers'support for their base loaded primary generation plants in Alaska.In response the utilities perform more intensive maintenance than would otherwise be the case. The annual cost for the staff of 35 persons wi"be $2,760,000 or $l2.00/kW/yr.This is based on a 42-hour work week,52 weeks per year, 2565C 5-22 10/31/85 _,_.,'f"""'1""""".,.ru -:--~--------_ - at an average wage rate of $36.40 per hour.The 42-hour week is used to accommodate personnel requirements for three-shift operation throughout the year. Consumable Materials Costs for consumable items will vary directly with plant generation. Consumable materials for the combined-cycle plant are in two categories,chemicals and materials for water treatment and lubricating oil,grease,and miscellaneous hardware items. Water treatment will be identical to that described for the CT plant, except that a total system capacity of 120 gpm is required.The average maximum demand wi 11 be 28 gpm for each CT,6 gpm (one percent b10wdown makeup),and 5 gpm for margin for the steam system for a total of 111 gpm.Two 60 gpm deminera1izer will be able to meet the demand. The costs of operation will be: - Deminera1izer (2 trains at $3,830/yr) Acid and caustic Total $7,660 33,000 $40,660 - - Consumption of lubricating oil,grease,and miscellaneous items,such as gaskets and small hardware,is a variable expense.The largest single usage of lube oil will be the three turbine generator sets. While the lUbricating oil will seldom require changing,oil will be lost from the system through cleaning,leakage part bearing journals, and fil ter changeout.Makeup for these losses will be in the range of 6,000 gallons per year for the simple-cycle CTs and 1,000 gallons per year for the steam turbine.With a delivered cost of $4.00 per gallon, the resultant annual cost for three units is $52,000. LUbricating oil for other equipment will be minor in comparison to the turbine-generator requirements.These uses are for pumps,motors, 2565C 5-23 12/16/85 '_.,..,----,..f------.----,--------....------------------------- fans,and other small equipment.This expense item,coupled with minor hardware items,such as gaskets,nuts and bolts,valve repair parts, etc.,are expected to total approximately $10,000 per year for the three-unit plant.This is higher than the CT plant,and reflects the fact that maintenance of the steam and feedwater cycles will be more costly than that of a CT.1,}. ~---The inlet air filtration system will consist of high efficiency '\J~--~lter and an~separator (dropout)zone.The inertial -I separator will require cleaning,but not any material replacement.The high efficiency prefilters will require periodic filter cell changeout. Changeout frequency will vary depending on local air quality conditions.It is anticipated that each filter unit will be changed out twice per year for each of the two units.The estimated cost of materials for each filter unit is $8,000 resulting in a total annual inlet filter system material cost of $32,000. - The turbine exhaust system will wear or degrade as a function of hours of unit operation.Acoustical panels,expansion joints,and the turbine exhaust breeching will wear due to temperature,exhaust gas components,and startup and shutdown temperature gradients.The exact number of acoustical panels and expansion joints installed per unit is uncertain until the plant layout is final.It is likely,however,that some of these will require replacement every three to five years.For this reason,an annual variable cost allowance covering these panels and three expansion joints of $30,000 for two gas turbines is used. Waste Disposal -There will be three waste streams from the plant.The first will 'be sanitary wastes.It is assumed that with modification at the time of construction,the existing site sanitary facilities will be capable of handling/disposing of this stream.The second and third waste streams are the effluent from the demineralizer system and the boiler -2565C 5-24 10/31/85 - - blowdown.The effluent will be held on site for treatment.Each dem;neralizer train will produce 200 gallons of backwash wastewater per day.Boiler blowdown will be approximately 6 gpm and will total as much as 8,640 gallons per day.This will result in planning for a daily effluent stream of 8,840 gallons to be treated and disposed of daily.The estimated cost for this onsite service is $0.03/gallon for a total annual cost of $77,200. Repair and Overhaul Costs Annual or periodic repair and overhaul (replacement and renewal)of major equipment will be necessary as a result of actual hours of operation.These costs are therefore considered variable.This work is outside contract work and therefore separate from the labor costs detailed previously.The major equipment included is: o o o o Two CT generators Two HRSGs One steam turbine-generator One air-cooled condenser - CT Generator These pieces of equipment will recei ve identical service as those discussed in Section 4.3.2.2.That is,inspections and overhaul will be performed on each turbine,in accordance with the schedule and costs outlined on Table 4-11.The total annual cost then will be $477,000 for the two CTs. HRSG The schedule and costs for maintenance of the waste HRSGs are listed in Table 5-6.The table was developed inclusive of both HRSGs at the plant.The total annual cost is expected to be $157,000. 2565C 5-25 10/31/85 ----,.-------------------------------- 1 J j )j i I 1 J :D -J J J 1 1 J )J 1 TABLE b-6 MANUFACTURERS MANHOURS LABOR AND SPARE PARTS COST ESTIMATE FOR A WASTE HEAT RECOVERY BOILER STEAM GENERATOR FOR AN ISO RATED 230 MW COMBINED-CYCLE PLANT !I Inspection Average Shift Labor Average System ,Interval Manhours Crew Required Cost @ Parts Total Annual Components (hrs)Requi red Size 8 hr $36/hr Cost Cost Cost - Economizer. Evaporator 8.000 48 3 2 $1.800 $5.000 $6.800 $6,800 Steam Drum' Mud Drum 8.000 56 7 1 $2,160 $20,000 $22.160 $22.160 Super Heater 8,000 64 8 1 $2.592 $18.000 $20,000 $20.600 Pumps 720 16 2 1 $216 $3.000 .$3.200 $12,800 Valves 1.000 16 2 1 $108 $2.000 $2,110 $16,800 Gauges 1.400 16 2 1 $108 $1.200 $1,300 $8.140 Switches 2.000 16 2 1 $108 $1,200 $1,300 $5.200 Duct Work 4.000 16 2 1 $576 $5.000 $5.580 $11.160 Expansion Joints 720 32 4 1 $1.100 $5,000 $6.100 $24.400 Activators 6.000 16 2 1 $576 $10,000 $10.500 $14.000 Dampers 6,000 32 4 1 $1.152 $10.000 $11.200 ~900 TOTAL COST $156.960 J!Maintenance inspection intervals,manhours.labor cost and parts cost were based on a natural gaS-fired CT operating base load 8.000 hr/yr.with a yearly shutdown for boiler drum inspection and tube side washdown.as reviewed by boiler manufacturers. SOURCE:Babcock &Wilcox.Foster Wheeler Energy Company,and Ebasco 1984. 2b65C ~ I - Steam Turbi ne-Generator The steam turbine-generator has a schedule for overhaul maintenance separate from the CT generator.That schedule and associated costs are presented in Table 5-7.The total annual costs are $56,828~ Air-Cooled Condenser The fixed costs associated with the plant's air-cooled condenser consist of gearbox changeout,fan blade replacement,and in some instances,motor replacement.The cost eStimate for fixed costs is $35,300 as presented in Table 5-8. Total Overhaul and Repair Costs The total estimated annual overhaul and repair costs are somewhat higher than for the three-unit,CT plant.This is a direct result of the higher cost of maintaining the combined-cycle plant's steam cycle. 5.3.3 Review of Developed Combined-Cycle Plant O&M Costs The two independently estimat~d sets of O&M costs are compared below in 1985 doll ars: -Utility/Basis. Based on utility data revi ew (Tabl e 5-5) Based on engineer- ing review (Table 5-9) Fixed Unit Cost $7.27/kWyr $13.26/kWyr Variable Total Nonfuel Unit Cost Total Cost Unit Costs $0.55 MWh $2,553,300 $ll.lO/kWyr $0.66 MWh $4,119,000 $17.9l/kWyr The difference in variable unit costs between the two estimates of $0.05/MWh is small and attributed to variations in the assumptions made to arrive at those costs.Fixed costs difference between the two estimates are significant and result directly from the difference in estimated staff size and the small difference of $0.40/hr in estimated average wage rate. 2565C 5-27 10/31/85 -",..----'!""""'----........------------,---,------------------ 1 1 J I 1 1 1 ))1 .~J 1 i )1 1 TABLE 5-7 MANUFACTURERS MAINTENANCE COST ESTIMATE FOR A C~JNED-CYCLE PLANT bO MW STEAM TURBINE AND GENERATO~ Inspection Average Shift Labor Average System &Interval Manhours Crew Required Cost @ Parts Total Annual Components (hrs)Required Size 8 hr $36/hr Cost Cost Cost Shells 24.000 200 8 3 $7.200 0 $7.200 $2.400 Bolting 24.000 120 5 3 $4.320 $5.000 $9.320 $3.100 Diaphragm 24.000 500 10 6 $18.000 0 $18.000 $6.000 Valves 4.000 50 6 1 $1.800 $8.000 $9.800 $19.600 Lube System 4.000 40 5 1 $1.440 $2.000 $3.440 $6.880 Bearings 40.000 240 10 3 $8.640 $15.000 $23.640 $4.728 "2 System 8.000 45 3 5 $1.620 $8.000 $9.620 $9.620 Meggar 1 $864 $1,000 $1.864 $372Field40.000 24 3 Fiel d Removal 40.000 240 8 30 $8.640 $10.000 $18.640 -.!.l..728 ESTIMATED AVG.ANNUAL TOTAL COST $56.828 1/The turbine generator inspection intervals.manhours.crew size and parts costs are based on -Manufacturers field experience for an annualized average cost. 2/Parts cost are based on normal quantity of consumables.gaskets.etc ••zero parts cost was -assessed for turbine shells and diaphragms assuming no thermal distortions.cracking etc. SOURCE:General Electric Company and Ebasco 1984. 2b!>6C - TABLE 5-8 AIR COOLED CONDENSER O&M COST ESTIr~TE FOR 230 MW COMBINED-CYCLE PLANT Cost,$ Spare.Parts Cost Fan Blade $7,000 Gearbox 10,000 Lube Oil 500 E1 ectric Motor 3,000 $20,500 Mai ntenance-Labor-Gearbox Changeout 400 MWh/Gearbox $14,400 ~Fan Blade Replacement 8 MWh/fan 288 r-C1 ean Fi n Tubes 3 MWh/section 108 $14,796 TOTAL ANNUAL COSTS $35,296 - ,.,.. - 2565C 5-29 10/31/85 TABLE 5-9 230 MW COMBINED-CYCLE POWER PLANT SUMMARY OF O&M COSTS (1985 $) """"Total Unit Cost Cost (In l,OOOs) Fixed Costs Staff $3,049 $l3.26/kW/yrl/ Variable Costs Consumable Materials Water Treatment $45 Lubrications 68 Inlet Air Filtration 35 Turbi ne Exhaust 33 Waste Disposal $85 -Overhaul and Repair $804 Total Variable Costs $1,070 0.66/MWh ~/ Total Nonfuel Costs $4,119 $l7.9l/kW/yr .,l/ $2.56/MWh '.£/ 1/Based on net plant capacity of 230,000 kW. 2/Based on annual plant generation of 1,612,000 MWh at the design capacity factor of 80 percent. 2565C 5-30 10/31/85 -_.,-,---__---,------------'-9r==-----------------