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Natural Gas-Fired Combined-Cycle Power Plant Alternative for the Railbelt Region of Alaska, Vol XIII, August 1982
Natural Gas-Fired Combined- Cycle Power Plant Alternative for the Railbelt Region of Alaska Volume XIII Ebasco Services Incorporated August 1982 Prepared for the Office of the Governor State of Alaska Division of Policy Development and Planning and the Governor’s Policy Review Committee under Contract 2311204417 #%Battelle Pacific Northwest Laboratories LEGAL NOTICE This report was prepared by Battelle as an account of sponsored research activities. Neither Sponsor nor Battelle nor any person acting on behalf of either: MAKES ANY WARRANTY OR _ REPRESENTATION, EXPRESS OR IMPLIED, with respect to the accuracy, completeness, or usefulness of the information contained in this report, or that the use of any informa- tion, apparatus, process, or composition disclosed in this report may not infringe privately owned rights; or Assumes any liabilities with respect to the use of, or for damages result- ing from the use of, any information, apparatus, process, or composition disclosed in this report. Natural Gas-Fired Combined-Cycle Power Plant Alternative for the Railbelt Region of Alaska Volume XIII Ebasco Services Incorporated Bellevue, Washington 98004 August 1982 Prepared for the Office of the Governor State of Alaska Division of Policy Development and Planning and the Governor's Policy Review Committee under Contract 2311204417 Battelle Pacific Northwest Laboratories Richland, Washington 99352 ACKNOWLEDGMENTS The major portion of this report was prepared by the Bellevue, Washington, and Newport Beach, California, offices of Ebasco Services Incorporated. Their work includes the Introduction, Technical Description, Environmental and Engi- neering Siting Constraints, Environmental and Socioeconomic Considerations and Institutional Considerations. Capital cost estimates were prepared by S. J. Groves and Sons of Redmond, Washington, and reviewed by the Ebasco cost estimating department in New York City. Cost of energy estimates were pre- pared by Battelle, Pacific Northwest Laboratories of Richland, Washington. iii PREFACE The state of Alaska, Office of the Governor, commissioned Battelle, Pacific Northwest Laboratories (Battelle-Northwest) to perform a Railbelt Electric Power Alternatives Study. The primary objective of this study was to develop and analyze long-range plans for electrical energy development for the Railbelt Region (see Volume I). These plans will be used as the basis for recommendations to the Governor and Legislature for Railbelt electric power development, including whether Alaska should concentrate its efforts on development of the hydroelectric potential of the Susitna River or pursue other electric power alternatives. The availability of low cost natural gas in the Cook Inlet Region has resulted in the development of an electric power system based largely on use of natural gas for electricity generation. Continued use of natural gas for electricity production may present operational system planning, cost and environmental advantages in comparison with alternative energy resources. The operational system planning and potential cost advantages of con- tinued natural gas use are related largely to the conversion technologies available for use with natural gas. Natural gas is suitable for use with combustion turbines and combined-cycle plants. These technologies provide good operational flexibility, being suitable for both baseload and load- following operation. Combustion turbines and, to a lesser extent, combined- cycle plants are available in relatively small unit capacities and are modular in nature. These characteristics, combined with relatively short construction lead times, facilitate capacity addition planning. Finally, capital costs of combustion turbines and combined-cycle plants are generally modest. This characteristic, combined with short construction lead times, results in low capital investment for natural gas-fired facilities. Environmental advantages of continued natural gas use accrue from the clean products of natural gas combustion and from the relatively low waste heat rejected from certain natural gas-based conversion technologies. Natural gas combustion products contain no particulates or oxides of sulfur. Formation of nitrogen oxides is controlled in combustion turbines and combined-cycle plants by water injection. Combined-cycle plants operate at high conversion effectiveness, minimizing the waste heat rejected to the environment. Continued use of natural gas for generation of electricity, while pre- senting the advantages discussed above, is also beset by potentially severe constraints. Chief among these is the continued availability of natural gas at prices competitive with other primary energy resources, and provisions of the Fuels Use Act restricting use of natural gas for electricity generation. An assessment of future natural gas availability and prices in the Railbelt Region, conducted in conjunction with the Railbelt Electric Power Alternatives Study (Battelle 1982), indicates that under certain conditions, natural gas supplies will continue to be available to the Railbelt Region, albeit at higher prices than in the past. It also appears that exemption from provision of the Fuels Use Act might be obtained under certain conditions. Thus, in view of the potential advantages presented by contrived natural gas use for electricity generation, and because of the possibility of avoiaing the chief constraints to future use of natural gas, it appeared to be desir- able to examine in depth one or more of the electric generation technologies suitable for continued use of natural gas for electricity generation in the Railbelt Region. Conversion technologies suitable for use with natural gas include steam electric plants, combustion turbines, combined-cycle plants and fuel cells. A combined-cycle plant was selected for study for several reasons. Combinea- cycle plants exhibit very favorable conversion efficiencies compared to combus- tion turbines or steam-electric units. The technology, though relatively new, is well established in the utility industry, including two Alaskan applica- tions. Though greater than for combustion turbines, costs of combined-cycle plants are generally less than costs of comparable steam-electric facilities. Many plant components, such as the combustion. turbines, are factory-assembled, minimizing the cost premiums and longer construction times often associated with Alaskan installations. Available plant sizes (90 MW and greater) are suitable for the modest growth in electrical demand forecast for the Railbelt Region. This report, Volume XIII of a series of seventeen reports, documents the findings of this study. vi Other power-generating alternatives selected for in-aepth study included pulverized coal steamelectric power plants, the Chakachamna hydroelectric project, the Browne hydroelectric project, large wind energy conversion sys- tems and coal-gasification combined-cycle power plants. These alternatives are examined in the following reports: Ebasco Services, Inc. 1982. Coal-Fired Steam-Electric Power Plant Alternatives for the Railbelt Region of Alaska. Prepared by Ebasco Services Incorporated and Battelle, Pacific Northwest Laboratories for the Office of the Governor, State of Alaska, Juneau, Alaska. Ebasco Services, Inc. 1982. Chakachamna Hydroelectric Alternative for the Railbelt Region of Alaska. Prepared by Ebasco Services Incorporated and Battelle, Pacific Northwest Laboratories for the Office of the Governor, State of Alaska, Juneau, Alaska. Ebasco Services, Inc. 1982. Browne Hydroelectric Alternative for the Railbelt Region of Alaska. Prepared by Ebasco Services Incor- porated and Battelle, Pacific Northwest Laboratories for the Office of the Governor, State of Alaska, Juneau, Alaska. Ebasco Services, Inc. 1982. Wind Energy Alternative for the Railbelt Region of Alaska. Prepared by Ebasco Services Incorporated and Battelle, Pacific Northwest Laboratories for the Office of the Governor, State of Alaska, Juneau, Alaska. Ebasco Services, Inc. 1982. Coal-Gasification Combined-Cycle Power Plant Alternative for the Railbelt Region of Alaska. Prepared by Ebasco Services Incorporated and Battelle, Pacific Northwest Laboratories for the Office of the Governor, State of Alaska, Juneau, Alaska. vii SUMMARY. Potential operational, systems planning, cost and environmental advan- tages may accrue from continued use of natural gas for generation of electric energy in the Railbelt Region. The most promising currently available tech- nology for future capacity addition using natural gas appears to be natural gas-fired combined-cycle plants. The purpose of this study is to examine the technical, economic, environmental and institutional characteristics of natural gas-fired combined-cycle plants of suitable capacity for the Railbelt Region. The plant design selected for study is a nominal 200-MW natural gas-fired combined-cycle plant utilizing two combustion turbines of 74.5 MW capacity each ana a heat recovery steam generator supplying a steam turbine generator of 50 MW rated capacity. Gross plant rating is thus 208 MW; net rating, less internal loads, is 198 MW at standard conditions. The annual average heat rate is estimated to be approximately 8200 Btu/kWh. A forced outage rate of 8 percent and a scheduled outage rate of 7 percent would provide an equivalent annual availability of 86 percent. Heat rejection is by mechanical draft wet/ dry cooling tower. The plant would be located in the Beluga area, northwest of Cook Inlet. Natural gas is assumed to be supplied by pipeline from the Beluga Field. Power would be transmitted by 345-kV line approximately 75 miles to the proposed Anchorage-Fairbanks intertie. Overnight capital cost for the proposed plant was estimated to be 1001 $/kW. Working capital (30-day emergency distillate supply plus 30-day O&M costs) was estimated to be 52 $/kW. Fixed and variable operation and main- tenance costs were estimated to be 7.25 $/kW/yr and 1.69 mills/kWh, respec- tively. Levelized busbar energy costs were estimated for various capacity factors and years of first commercial operation using forecasted Cook Inlet natural gas prices prepared elsewhere in the Railbelt Electric Power Alterna- tives Study. For a 1990 startup date and an 85 percent capacity factor, a levelized busbar power cost of 46.5 mills/kWh was estimated. All costs are in January 1982 dollars. ix Environmental effects of the proposed plant are anticipated to be modest. NO, emissions would be controlled to the applicable NO, standard of 0.014 volume percent of total flue gas; the only other gaseous release of potential significance would be CO, . Gross water requirements total 1060 gpm at full power, of which 870 gpm would be consumed and 190 gpm discharged. Estimated land requirements for the plant are 2-1/2 acres plus land required for trans- mission line, gas pipeline and access road right-of-ways. The estimated peak construction work force of 400 personnel could produce severe boom-bust effects in the Beluga area. Principal constraints to development include the continued availability of Cook Inlet natural gas, and Fuels Use Act prohibitions on use of natural gas for baseload electricity generation. Ample natural gas for the proposed plant appears to be available providing Pacific Alaska liquefied natural gas commitments are relinquished. Fuels Use Act exemptions could potentially be obtained if: a) waste heat from the plant were utilized for district heating or process heating; or b) if the State established statutory requirements favoring use of natural gas for electricity generation. CONTENTS ACKNOWLE DGMENTS PREFACE SUMMARY 1.0 INTRODUCTION 2.0 TECHNICAL DESCRIPTION 7 . . . Ze 2n2 2.3 2.4 2.5 2.6 PROCESS AND AUXILIARY SYSTEMS DESCRIPTION 2.1.1 Combustion Turbine Plant 2.1.2 Steam Plant . : ‘ p 2.1.3 Electric Plant : : . FUEL SUPPLY : i H : 7 : TRANSMISSION SYSTEM . SITE SERVICES 2.4.1 Access Roads . 2.4.2 Construction Water Supply 2.4.3 Construction Transmission Lines 2.4.4 Airstrip : . : 2.4.5 Landing Facility . . . 2.4.6 Construction Camp Facilities CONSTRUCTION OPERATION AND MAINTENANCE 2.6.1 General Operating Procedures 2.6.2 Operating Parameters 2.6.3 Plant Life . 2 7 ° > 2.6.4 Operating Work Force xi iii 2 2.18 2.23 2.26 2.27 2.29 eed 2.29 2.29 30 30 2.30 2.32 2.32 2.34 3.0 COST 4.0 Sail 3.2 3.3 3.4 2.6.5 General Maintenance Requirements . ESTIMATES . CAPITAL COSTS 3.1.1 Construction Costs 3.1.2 Payout Schedule 3.1.3 Capital Cost Escalation 3.1.4 Economics of Scale 3.1.5 Working Capital OPERATION AND MAINTENANCE COSTS 3.2.1 Operation and Maintenance Costs 3.2.2 Escalation 3.2.3 Economics of Scale FUEL AND FUEL TRANSPORTATION COSTS . COST OF ENERGY . ENVIRONMENTAL AND ENGINEERING SITING CONSTRAINTS 4.1 4.2 ENVIRONMENTAL SITING CONSTRAINTS 4.1.1 Water Resources 4.1.2 Air Resources 4.1.3 Aquatic and Marine Ecology 4.1.4 Terrestrial Ecology 4.1.5 Socioeconomic Constraints ENGINEERING SITING CONSTRAINTS 4.2.1 Site Topography and Geotechnical Characteristics . : 4.2.2 Access Road, Transmission Line, and Fuel Supply Considerations 4.2.3 Water Supply Considerations . xii 235 5.0 ENVIRONMENTAL AND SOCIOECONOMIC CONSIDERATIONS 5.1 WATER RESOURCE EFFECTS 5.2 AIR RESOURCE EFFECTS 5.3 AQUATIC AND MARINE ECOSYSTEM EFFECTS 5.4 TERRESTRIAL ECOSYSTEM EFFECTS . 5.5 SOCIOECONOMIC EFFECTS 6.0 INSTITUTIONAL CONSIDERATIONS 6.1 FEDERAL REQUIREMENTS 7 ‘: . : 6.1.1 Air . . . . . . 6.1.2 Water . . . - . 7 6.1.3 Solid Waste . : . . : 6.1.4 Power Plant and Industrial Fuels Use Act 6.1.5 Other Federal Requirements . b 6.2 STATE REQUIREMENTS . : : 7 , 7 6.3 LOCAL REQUIREMENTS . . ° . 6.4 LICENSING SCHEDULE . . : : - 7.0 REFERENCES . : : ° . . . xiii non Oo DD DW ao an aon Da Oo wo -10 Study Area Process Flow Diagram Plant Arrangement and Plot Plan Plant Water Balance . One-Line Diagram Beluga Area Station Switchyard Willow Substation ' ‘< FIGURES Construction Work Force Requirements Project Schedule Cost of Energy Versus Capacity Factor and Year of First Commercial Operation. xiv Hes 2e3 Zao) Geld 2220 eee 2.28 (each eek} 3.8 2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8 2.9 2.10 2.11 2.12 3.1 3.2 3.3 3.4 5.1 6.1 6.2 TABLES _ Combustion Turbine with Generator Design Parameters Gas Compressor Design Parameters . : Heat Recovery Steam Generator Design Parameters Steam Turbine Generator Unit Design Parameters . Demineralizer System Design Parameters . Condenser Design Parameters . Wet-Dry Cooling Tower Design Parameters Pump Design Parameters Miscellaneous Equipment Design Parameters Fuel Oil and Condensate Tank Design Parameters Estimated Natural Gas Requirements: Chugach Beluga Station 7 . 7 . Plant Staffing Requirements Bid Line Item Costs for a Natural Gas-Fired Combined Cycle 200-MW Station 7 ‘ 7 : a Payout Schedule for a Natural Gas-Fired Combined-Cycle 200-MW Station 7 7 : . : Estimated Natural Gas Acquisition Cost for Chugach Electric Association Without Pacific Alaska LNG Plant Year-of-Occurrence Energy Costs . Primary Environmental Effects Federal Regulatory Requirements State Regulatory Requirements XV 2.5 2.6 2.12 2.13 2.14 2.16 2.16 2.17 2.18 2a19 2.25 2.36 30 3.3 3.6 369 5.2 6.2 6.3 1.0 INTRODUCTION The use of combustion turbine generators in combination with steam tur- bine generators to generate electricity is a mature technology that has gained wide use within the past 15 years. A power plant of this type, called a combined-cycle plant, uses a combustion turbine generator to produce part of the plant total output. Combustion turbine exhaust, directed to a heat recovery boiler, generates high-pressure steam. This steam enters a steam turbine generator where additional power is produced. In a large plant of this type, several combustion turbine generators, each with individual heat recovery boilers, would generate steam for a single steam turbine generator. Although steam turbine generators have been in utility service for over 60 years, and combustion turbine units since the late 1950s, the use of these units in a combined-cycle plant did not start until 1965. This type of plant is presently being used in the Railbelt at the Sullivan Station of Anchorage Municipal] Light and Power and at the Beluga Station of Chugach Electric Associ- ation, Inc. Both of these plants utilize the plentiful supply of presently inexpensive local natural gas as fuel. Among the advantages of this technology are: mature technology, proven equipment and systems relatively low capital cost high efficiency modular design relatively short construction time capable of cycling as well as base load service. Disadvantages of this technology are: premium hydrocarbon fuels normally required combustion turbines limited in size - now up to 100 MW. Combined-cycle plant sizes are a function of the size and number of com bustion turbine units utilized. At the low end of the range, a combustion turbine of 10 MW size could be used while at the high end, a 100-MW unit could be used. For each 2 MW of combustion turbine capacity, a nominal 1 MW of steam turbine capacity can be provided. A combined-cycle plant with a total output ol of 100 MW, for example, could be built with two 35-MW combustion turbine generators and one 30-MW steam turbine generator. In the alternative described in this document, a 200-MW nominal plant size was selected for a potential site in the Beluga area on the west side of Cook Inlet (Figure 1.1). This site is one of several gas fields located in the Cook Inlet area. This plant would include two 74.5-MW natural gas-fired combustion turbine generators, individual unfired heat recovery steam generators, and one 59-MW steam turbine generator. This design basis was used because it reflects the size of equipment that is presently available and expected to still be widely used in the 1985-1990 time period. 1.2 7 ys : Sab towne — - acreettt — Bey > , eusere ¥ iy : . ~ are y ene : J ivan Reve 0 5 ae ew ai Cnr es, < : = 1 . f | fy ks coon 1 a) 4 ~—— woouaWat | *. Ne = / te. } on ‘ £ “ ‘ n ~ a **-eresoe, ___| pase J _ eetitres Me nay i lw 3 os g y wt ARGEND ¥ GD onsriaco west fom Sie - he GAS FIELD FIGURE 1.1. Study Area 2.0 TECHNICAL DESCRIPTION 2.1 PROCESS AND AUXILIARY SYSTEMS DESCRIPTION The natural gas-fired combined-cycle turbine plant design envisioned is based on using two currently available General Electric gas turbine genera- tors, rated approximately 74.5 MW each in combination with a General Electric steam turbine generator rated at approximately 59 MW. Other manufacturer's turbines of similar size could be used within the general concept of the design, but it must be pointed out that the specific plant -output and various specific design parameters may be expected to change accordingly. At International Standards Organization (ISO) referenced conditions (59°F and sea level), plant output in the combined-cycle mode will be 208 MW gross, of which approximately 10 MW will be utilized for internal auxiliary loads, resulting in a net plant output of 198 MW. The heat rate of the station will be approximately 8200 Btu/kWh. The gas turbines can burn either natural gas, distillate oi] or residual fuel oil. The plant design is based on using Alaska natural gas, with distill- ate oil as a suggested emergency standby back-up fuel. Main steam of 850 psig, 900°F, has been selected for the steam cycle, based on the gas turbine exhaust temperature of 985°F. This design uses a conservative 85°F approach temperature for the main steam, and falls in the range of readily available steam turbine generator sets. For actual steam generation, a conservative 40°F approach temperature has been used on the feedwater heater, the economizer and the evaporator sections in the steam generator. A 1500 psig main steam system could also be used on a plant of this size; however, the actual steam production would be slightly lower at 1500 psig, 900°F, because the limiting factor on the steam generation is the heat available in the gas above the evaporator approach temperature, i.e., at the steam saturation temperature plus 40°F. In an effort to more effectively utilize the lower temperature exhaust gases, a 50 psig saturated heating steam cycle has been included in the steam generator design. The steam turbine used for this design will be a full con- densing turbine, bottom exhausting with the condenser mounted underneath. rel Nitrogen oxide (NO,) control can be either by steam or water injection. Water injection has been selected for this design because steam injection would require 250 psig steam, which is not readily available. The major process flows for this plant are shown in Figure 2.1. The natural gas supply (73,792 lb/hr) is compressed to supply 250 psig inlet gas at the combustors of each gas turbine unit. Combusted gas is expanded through the gas turbine driving both the 74.5-MW generator and the integral free-shaft gas turbine air compressor on each unit. Exhaust gas from each turbine flows through dual-pressure steam generators (one for each gas turbine, where the heat is utilized to generate 850 psig superheated steam used to drive the steam turbine generator, and 50 psig saturated steam for the building heating system. The gas is exhausted to the stack on exiting the steam generator. A bypass damper and stack are provided for each steam generator so that the combustion turbine can be operated independently of its waste heat boiler. The combined main steam flow of 472,400 1b/hr at 850 psig and 900°F, is expanded through a common steam turbine driving a 59-MW generator. Exhaust steam from the turbine is condensed in a vacuum condenser, which in turn is cooled by the wet-dry cooling tower circulating water loop. The cooling tower can be operated either dry or wet, and is expected to operate in the dry moae during the winter months, eliminating the plume of fog and icing about the tower and reducing the plant makeup water requirements. Condensate is pumped from the condenser through a feedwater heater sec- tion in each of the steam generators to the deaerator, which removes oxygen and other gases from the water and forms a small storage tank for the feedwater. Feedwater pumps take suction from the deaerator to provide the steam generator with feedwater, where heat is absorbed from the hot gas turbine exhaust gas to convert the water to main steam, thus completing the closed feedwater cycle. The heating steam operates on a completely separate cycle from the main steam, the low-pressure (LP) feed pumps taking suction from the heating steam deaerator and feeding the LP section of the steam generators or the auxiliary heating steam boilers that will be utilized in the event of a gas turbine or 2a2 fic 472,400 LB/HR - 8BSOPSIG -900°F 501410 BTU/HR f TOSWITCHYARD MAIN STREAM FROM OTHER €& TRANSMISSION UNIT SYSTEM DRY-WET TRANSFORMER GENERATOR MECHANICAL DRAFT COOLING TO OTHER STM TOWER GENERATOR DENSA’ FROM OTHER STM GENERATOR HP SAT. STM, +0 DEAERATOR CONES TE CIRCULATING WATER cayx BouERE BS0PSIG-900°F Pt LP HTG STEAM BYPASS : : TOHTE COILS eeane vans 80,000 LB/HR-SO PSIG SAT-EA BOILER EXH TO STACK 215 *10°LB/HR COND RETURNS \ EACH ST) FROM HTS TOAUX HTS STM BOILERS TO OTHER STM GENERAT: ' ' BYPASS | Campers! SUPERHEATER DUAL PRESSURE STEAM GENERATOR (TYP 2 PLCS) - 215 «10% UB/HR EACH TURBINE BYPASS STACKS TO SWITCHYARD ETRANSMISSION U.P FEED PUMPS STEM TRANSFORMER T ‘ GAS TURBINE UNIT ricter ke _ AMBIENT (TYP 2 PLCS) TO OTHER GAS TURB UNIT TO OTHER STM GENERATOR FROM OTHER STM HP. FEED PUMPS FROM DEMIN WATER SYSTEM NO x INJECTION SKID ' | 75Mw COMBUSTOR NATURAL GAS FROM SUPPLIER 1586 x 10* BTU/HR (73,792 LB/HR USING 21500 BTU/LBS GAS FIGURE 2.1, Process Flow Diagram gas generator shutdown. The low-pressure, 50 psig, saturated steam is taken from the steam generator LP drums or auxiliary boilers to the building steam heating coils. Condensate returns from the heating coils are fea back to the heating steam deaerator. Makeup water for both feedwater cycles is supplied from the condensate storage tank, which is steam heated to maintain a 40°F minimium condensate temperature. For the high-pressure (HP) cycles, make-up water will be sup- plied via the condenser hotwell; LP make-up water will be supplied to the deaerator storage tank. The condensate storage tank will be elevated slightly to provide gravity make-up feed to the condenser hot well. A 150 gpm net output, two-train demineralizer complete with demineralizer tank is used to supply turbine injection water and steam generator make-up. Plant cold start is based on using distillate fuel from the emergency fuel tanks on one of the gas turbines. A diesel generator started on com pressed air will provide the power for starting the gas turbine. The diesel generator can be sized to also power the gas compressors for cold start using gas fuel on the gas turbines if required or preferred; however, two or more diesel generators may be needed to meet such a requirement. It should be noted that an incoming main gas pressure of 175 psig has been assumed in sizing the gas compressors. Larger compressors requiring more power will be required if the assumed gas mains pressure is not available. 2.1.1 Combustion Turbine Plant Each combustion turbine is a large-frame industrial-type with an axial flow multi-staged compressor and power turbine on a common shaft. The combus- tion turbine is directly coupled to an electric generator, and can be started, synchronized, and loaded in about one-half hour under normal conditions. Each combustion turbine generator package also includes an inlet air fil- tration system, fuel system, water injection system, lube oi] cooling system, and various minor subsystems as required and furnished by the manufacturer. The design parameters for each combustion turbine with generator are presented in Table 2.1. 2.4 TABLE 2.1. Combustion Turbine with Generator Design Parameters (based on General Electric MS7001E or equal, two required) Turbine Type: Simple-cycle, single-shaft, three bearing. Generator Type: Hydrogen-cooled unit rated 110 MVA at Ls8)KVe 0-9) pioliwith 30 psig hydrogen pressure at 10 C. Performance: (Each Turbine) Base Rating 74,450 kW at ISO Conditions (59°F, S.L.) Heat Rate (LHV) 10,655 Btu/kWh Air Flow 597 lbs/sec Turbine Exhaust Temp 985 °F Turbine Inlet Temp 1985°F Inlet Pressure Drop 5 in. water Exhaust Pressure Drop 10 in. water Dimensions (turbine generator only) 29 ft wide by 70 ft long by 13 ft high Combustion Turbine Features: Accessory compartment complete with starting motor, motor control center for all base-mounted motors, lubrication system, hydraulic control system, atomizing air system, and cooling water system. Excitation compartment complete with static excitation equipment. Switchgear compartment complete with generator breaker, potential transformers, disconnect link for auxiliary feeder, and a customer power takeoff. Fuel system capable of utilizing natural gas, mixed gas fuel, or liquid fuel. Fire protection system (low-pressure C02). NO, Control system utilizing water injection. 219 The inlet air filter is a high-efficiency glass fiber-type suitable for removing particulates from the inlet air. The use of an evaporative cooler has not been anticipated but a cooler could be added later if further study justifies the expenditure. The fuel system includes the gas compressor (Table 2.2), the fuel oil forwarding skid and the fuel gas metering equipment. The combustion turbine is furnished with one liquid and one gas fuel nozzle in each of the ten annu- lar combustors. Liquid fuel is pumped from the fuel forwarding skid to the combustion turbine, where a high-pressure pump forwards the fuel to the fuel nozzles. Gaseous fuel must be furnished to the combustion turbine at about 250 psig. Since only one gas fuel nozzle is furnished in each combustor, this requires that the heating value of the gas fuel be fairly constant (#10 percent). TABLE 2.2. Gas Compressor Design Parameters Type: Barrel-type multistage centrifugal compressor complete with motor and gearing, frame mounted as a complete unit Number Required: 2-100 percent capacity Performance: Capacity (each compressor) 30,000 SCFM l Inlet Pressure 175(a) psig at 90 F Discharge Pressure 275 psig at 163 F Service Natural Gas Compressor Features: 1,200 BHP 2-Stage Lube and seal oil system Tilting pad type journal bearings Kingsbury-type thrust bearing Balance piston Steel case Interstage seals and shaft end seals Motor: 4-kV, 3-phase, 60-hz, 1,500-HP rating (a) Assumed prevailing gas mains pressure. 2.6 The water injection system is used to limit the emissions of oxides of nitrogen (NO,). Water is pumped from the demineralized water storage tank and injected directly into the combustors. This limits the peak flame tem perature which in turn limits the formation of thermal NO. The injection rate is a function of load, ambient temperature, and the type of fuel. Typical water injection rates at base load are about 50 gpm for gas fuel and 75 gpm for oil per engine. Demineralized water is required to limit formation of deposits on the turbine blades. Other miscellaneous systems furnished with the combustion turbine include: the starting package complete with electric motor and torque converter; a lube oil system for bearing lubrication; a cooling water system for cooling the lube oil system; a CO, system for fire protection and generator purge; and a controls system for controlling the entire gas turbine generator package. The combustion turbines are normally operated from a central control room, but controls provided with the unit allow either local or remote unattended operation. Operation of the combustion turbines is essentially an automated process, but operator presence is required to achieve proper coordination with boiler control functions. Under normal conditions, all combustion turbines are in operation at their base load rating. The combustion turbines will be housed in a common building with the heat recovery steam generators and steam turbine to facilitate plant arrangement. The building will be 185 feet wide by 300 feet long and 90 feet nigh. The building will be of steel construction with aluminum sandwiched insulation siding, and will be served by an overhead crane. See Figure 2.2 for the plant arrangement. 2.1.2 Steam Plant The heat recovery steam generators are considered part of the steam plant, although physically the steam generators will be housed with the gas turbines in a common building. The heat recovery steam generator package includes the steam generator complete with ductwork from the combustion turbine to the steam generator, a aad 15-0 STEAM TURBINE 7 T GENERATOR oe'-0 1000 KWA AUXILIARY TRANSFORMER UNIT WO. 1) BATTERY COMPARTMENT GAS TURBINE AIR IWLET bucT uur 7 19" Wo'-0 COOLING COMPARTMENT TURBINE AIR INLET DUCT Curr OaTTERY COMPARTMENT 1000 KVA_ AUXILIARY TRANSFORMER (ama 0. 2) — 2 CRANE RAILS — =< 7 AU HTC rr SYS BR [_ 4 ' f [ ~DEMINERA. IZER = 0 maLM a 20 J VY TRANSFORMER OLESEL GEN owe COMP AIR SYS $ EvecTow | JN | COOLING WATER S¥S ew Z | CONTROL TRANS NET 7 7 fe Taste, The 1 [a =n eo + 1 7 a ! Qi nest 2 Beer 121 Contgen ‘SWITCH GEAR — : ; = forms TRANSFORMERS & 0°. = i CONDENSATE = pu ‘SWITCH GEA\ ena ‘coupensen PUneS. i e e FRAnsronnen ae MEAT RECOVERY STEAM GENERATOR 1 | oma i} ‘STACK ul ul fh i Hl Ih tsovation \ sy-rass quanonalL i 1 DAMPER XWAUST STACK emust \_warer d 1 ' rm RAINTENANCE FEED nae — Tag sean 4 bed eee MAINTE RACE PLATPOMe ARAL 1 | 1 1 i HI I x Tip! t | 4 vipll ry wear" A aN ced " eH my il ely fis 1 vik | ’ SFeln Soetnaton | | 1 a \ f TEN e ©z * ° ero e Panel) ae / a aoe \ o | ' \ GUE “Eypp Forronic Tyee pa + -EXITATION COMP = _— iT | EG IPMENT ACCESS OCR MBUSTICN TURBINE 4 STEAM TURBINE ARRANGEMENT FIGURE 2.2. 1000 KVA AUXILIARY TRANSFORMER (STARTING) Plant Arrangement and Plot Plan soven” ‘SwITcH- YARD MAIN TRANSFORMERS. waTer TREATHENT [Fe Son 1 1 ! | ! \ | MESSHALL~ _ TO AIRPORT OT PLAN ———— /® @ RECREATION BUILDING FAMILY STATUS HOUSING 4+ 1 sapiiempromenell 2.9 bypass damper and bypass stack, and a steam generator exhaust stack. The heat recovery steam generators are a dual-pressure design with a main steam outlet pressure of 850 psig at 900°F, and low-pressure outlet of 50 psig saturated steam. Each steam generator is designed to produce one-half of the plant's normal flow for steam, with a feedwater heater inlet temperature of 125°F. The heat recovery steam generators are designed for continuous operation. A111 steam generator controls will be located in a common area in the central control room. During start-up and other load conditions, the bypass damper may be operated to provide operational flexibility. By closing the bypass damper, the combustion turbine exhaust is routed to the stack and does not reach the steam generator. Design parameters for the heat recovery steam generators are shown in Table 2.3. The main steam produced in the heat recovery steam generators is conveyed to a common turbine generator set rated at a nominal 59,000 kW. The turbine generator will be a direct-connected multivalve, multistage condensing unit, mounted on a pedestal with a bottom exhaust for mounting the condenser under the turbine. The generator is designed for maximum capability of the turbine with a power factor of Og Design parameters for the turbine generator are shown in Table 2.4. The turbine generator set will be furnished complete with jube oi] and electrohydraulic control systems as well as the gland seal sys- tem, and the generator cooling and sealing equipment. The turbine generator will be located on a pedestal at one end of the common combustion turbine and steam generator building. In addition to the combustion generators, steam generators, steam turbine and condenser, the building will contain the feedwater pumps, condensate pumps, vacuum pumps, deaerator, instrument and service air compressors, motor control centers, control room, house boiler and diesel generator (see Figure 2.2). The house boiler will be sized to provide building heating and freeze protection during periods of unfired steam generator shut down. The diesel generator will be sized for black start-up service. The demineralizer will be used to supply both steam cycle make-up and turbine injection water for NO, control. The demineralizer will be a ol TABLE 2.3. Heat Recovery Steam Generator Design Parameters (two required) Type: Watertube, forced circulation (General Electric) or two drum natural circulation (Deltak or Henry Vogt), dual pressure. Performance: (Each Steam Generator) Main Steam Outlet Condition 850 psig, 900°F Quantity 236,200 lb/hr Heating Steam Outlet Condition 50 psig, saturated Quantity 80,000 1b/hr Steam production under normal operation shall be achieved with an exhaust gas flow through the boiler of 2,149,200 lb/hr at 985°F. Feedwater will be supplied to the unit at 125°F to the feedwater heater. Low-pressure heating steam feedwater will be supplied to theluniitvat L25iiF Heat Recovery Steam Generator Features: . Feedwater Heater . Economizer . Evaporator Section with Steam Drum .- Superheater Section . Economizer . Evaporator Section with Steam Drum aust Gas Bypass Damper with Separate Stack H.P H.P H.P H.P ee Eee Exh two-train unit, 150 gpm net output, and will be furnished complete with a 150,000-gallon demineralized water storage tank (see Table 2.5). Heat is rejected from the steam turbine cycle at the condenser where cir- culating cooling water flowing through the condenser tubes absorbs heat from the exhaust steam. The cooling water discharged from the condenser is circu- lated through the cooling tower where the heat is dissipated to the atmosphere. The cooled cooling water is pumped back to the condenser forming the circu- lating cooling water cycle. A branch from the cooling water loop is used to dissipate the heat from the combustion turbine generators, steam turbine ale TABLE 2.4. Steam Turbine Generator Unit Design Parameters (one required) Turbine Type: Multistage, straight condensing, bottom exhaust Generator Type: Hydrogen-cooled unit rated 59 MW at 13.8 kV 0.9 pf with 30 psig hydrogen pressure at 10°C Performance: Base Rating 59 MW Steam Inlet Pressure 850 psig Steam Inlet Temperature 900°F Exhaust Pressure 2 to 4" Hg Exhaust Temperature 92°F Speed 3600 rpm Steam Turbine Generator Features: Common base-mounted with direct-drive couplings. Accessories include multiple inlet control valves, electric hydraulic control system, lube oil] system with all pumps and heat exchangers for cooling water hook-up, gland steam system and generator cooling. Excitation compartment complete with static excitation equipment. Switch-gear compartment complete with generator breaker potential transformers. . generator, air compressors, and other miscellaneous equipment heat exchangers in a similar manner (Figure 2.3). The condenser design will be single shell, two pass, with a divided water box and hotwell. The hotwell will be designed to have sufficient storage to allow proper level control for surging and shall be properly baffled to keep the condensate at saturation temperature. Tube sheets should be Muntz metal, with inhibited Admiralty tubes except for 70-30 copper nickel tubes in air removal sections and impingement areas. The condenser design data is listed in Table 2.6. The cooling tower will be the wet-dry-type mechanical draft design of material most suitable for the cold weather conditions found in the Beluga area of Alaska (see Table 2.7). ols TABLE 2.5. Demineralizer System Design Parameters Demineralizer Type: Capacity: Effluent Conditions: Demineralized Water Storage Tank Type: Nominal capacity: Acid Supply Tank Capacity: Material of Construction: Caustic Tank Capacity: Material of Construction: Recirculation and Booster Pumps Type: Capacity: Two single-train systems, each with cation, and anion, exchanger vessels 75 gpm each train, including regeneration time pH at 77°F 7 = 0.05 Total dissolved solids 5 ppm Total metals 0.5 ppm Carbon steel, fixed dome roof, internal epoxy lining, steam heating coils, suitable insulation. 150,000 gal Suitable for 40 regenerations between fill-up Carbon steel Suitable for 40 regenerations between fill-up Carbon steel Horizontal centrifugal, end suction, cast stainless casing. 150 gpm at 150 TDH 2.14 ST°2 STACK SANITARY WASTE WATER, TREATMENT BOILER BLOWDOWN 46 (DRY TOWER OPERATION) 160 (WET TOWER OPERATION) To RECEIVING STREAM NOTES: TO POTABLE WATER: HVAC SUPPLY | ALL FLOWS ARE EXPRESSED IN GALLONS PER MINUTE (6PM). 2.FLOWS ARE DAILY AVERAGES AT 100% CAPACITY FACTOR. FIGURE 2.3. Plant Water Balance 1060 (WET TOWER OPERATION) 146 (DRY TOWER OPERATION) COOLING TOWER MAKE -uP —*——- (WET TOWER OPERATION. TABLE 2.6. Condenser Design Parameters (one required) Condenser Type: Single shell - 2 pass Performance: Heat Load 491 x 106 Btu/hr Saturation Temperature 92°F (1.5" Hg) Inlet Water Temperature 72°F Outlet Water Temperature 87°F Terminal Temperature Difference 5°F Cooling Water Flow 65,800 gpm Features: Single shell, 2 pass - 1" - 18 BWG Admiralty Tubes Divided water box and hotwell TABLE 2.7. Wet-Dry Cooling Tower Design Parameters (one required) Cooling Tower Type: Parallel Path Wet-Dry Performance: Heat Load Cooling Water Flow Inlet Water Temperature Outlet Water Temperature 501 x 106 Btu/hr 67,200 GPM 87°F 72°F Design Basis - 15°F approach to 10 percent of the time wet bulb temperature of 57 F at Anchorage. Design coldest dry bulb 97.5 percent of time is -20°F at Anchorage. Features: One fan required for each cell. Integral air cooled heat exchanger sections for "dry" cold weather use. 2.16 Three 50 percent capacity vertical pit-type circulating water pumps will be mounted in an enclosure at the cooling tower basin. The pumps will be mounted 4 feet above the water level and have self-lubricating, cutless rubber design shaft bearings (see Table 2.8). TABLE 2.8. Pump Design Parameters HP Boiler Feed Pumps: (3) 50 percent pumps required Type: Horizontal split-case, multistage, double- suction, frame-mounted complete with elec- tric motor drive and lube oil system. Performance: (Each Pump) Capacity 480 GPM 1 TDH 2615 ft at 250 F NPSH 20 to 24 ft Cooling Water Circulating (3) 50 percent pumps required Pumps: Type: Vertical shaft pit pumps with submerged suction, discharge column complete with vertical-mounted electric motor. Performance: (Each Pump) Capacity 22,500 GPM TDH 45 ft. Water Temperature 40 to 80 F Submerged Suction LP Heating Steam Boiler (3) 50 percent pumps required Feed Pumps: Type: Horizontal, single-stage centrifugal, aouble- suction frame-mounted complete with motor drive Performance: (Each Pump) Capacity 160 GPM TDH 250 ft Water Temperature 250 F NPSH LO} tow 2i fit ZoL7 Design parameters and other pertinent data on some of the major equipment previously referred to and other required equipment that has not been previ- ously addressed is provided in Tables 2.2, 2.9, and 2.10. TABLE 2.9. Air Compressors: Type: Performance: Diesel Generator: Type: Heating Steam Boiler: Type: Performance: Condensate Pumps: Type: Performance: 2.1.3 Electric Plant Generating Systems Miscellaneous Equipment Design Parameters Two required Reciprocating, single-cylinder, oil-free, water- cooled, frame—-mounted with motor. 50 ACFM each 115 psig discharge pressure One required Air-start, skid-mounted, multicylinder diesel complete with 1-1/2 MW generator, 0.8 pf One required Drum-type, water-tube 40,000 1b/hr 50 psig saturated (3) 50 percent pumps required Vertical-shaft single-stage centrifugal, complete with vertical-mounted motor. Vacuum suction, low NPSH, 480 GPM each pump, 150 ft TDH at 120°F Two types of prime movers are utilized for electrical generation, as shown in Figure 2.4: two gas fired combustion turbines with generators rated at 74.5 MW and one steam turbine generation unit rated at 59 MW. Each gas turbine will deliver approximately 80 MVA to the switchyard. The steam tur- bine will add 50 MVA, resulting in a total of 210 MVA delivered to the switchyard. eels TABLE 2.10. Fuel 011 Tanks: Service: Features: Condensate Tank: Size: Service: Features: Deaerator and Storage Tank: Type: Size: Water Flow Out: Steam Flow In: Design Pressure: Operating Pressure: Fuel Oil and Condensate Tank Design Parameters Two required Floating Roof per API 650 89,580 BBL per API standard 12C 5-96" courses, 120 ft diameter x 40 ft high (approximately 11 days supply) Distillate fuel, specific gravity of 0.82 to 0.86 Stairway, platform, floating-roof, seal-fixed roof supports One required Fixed Roof - carbon steel 150,000 gals (approx 5 days supply) Condensate storage Steam heating coils, suitable insulation, plastic lined One required Integral connected unit with deaerator mounted on top of 5-minute storage tank. Stainless steel troughs and baffle plates. 39,370 1b storage 472,400 1b/hr 50 psig 60 psig 25 psia 2.19 02°2 138 kv To EXISTING BRELUGA PLANT 138 kV TRANSFORMER Usd AUTO TRAN ZFORMER oe 200 MYA 138/345 kv N—T ~~ — 346 kv To WiLL ow INTERCHAN aS / ( 138KV MAIN RUS =—-138kv swyp MT-I MT-2 A STATION SERVICE a Mi-3 $0 MVA & MVA 8 MVA < 10 MVA q 18/138 KV 13.8/138 kV 13.8/138 kv SMvA 5 Mva UAT-I UAT- 2 : we oe 4 a. yI200 y1209A 75; qd 7.5 MVA AlEKV] 1A 4.16 ky Be rae MytgkV ch ye OA ) Zo0On 12004 12004 )3000A — 1200412008 -)3000A +) 200 12004 4lekv 3-4 tloky 3-h ) 200A )1@90A GEN k CRANK on Shove] GENEL “yotoetg GEN N22 ele 83 MA. 83MVA G7 MVA X ~~ 7 GAD TURAINES FIGURE 2.4, One-Line Diagram Gas Turbine Generators. These are "packaged" units and as such include all equipment required to support the turbine generator. The generators are nominally rated at 74.5 MW, 0.9 PF, 83 MVA, with generation voltage at 13.8 kV. The package generally includes: 1. 13.8-kV switchgear that houses the generator grounding transformer, and generator air circuit breaker. 2. Nonsegregated phase bus duct runs to the generator and main transformer. 3. A master control panel for overall operation and monitoring. 4. A unit auxiliary transformer 13.8/4.16 kV sized to support the ancil- lary load (assumed to be 2 MVA). 5. A 4.16-kV switchgear with air circuit breakers for other loads (e.g., 800-hp cranking motor). The largest load (gas compressor) is fed from the plant common 4.16-kV switchgear. The step-up transformers for each gas turbine are rated 80 MVA, 13.8/138 kV. Steam Turbine Generator. The generator is rated 59 MW, 0.9 P.F., 67 MVA, with generation voltage at 18 kV. The unit auxiliary transformer is a three- winding 15 MVA, 18-4.16/4.16 kV. The two secondary windings supply 4.16-kV busses 3A and 3B. The step-up transformer is rated 50 MVA, 18/138 kV. Station Service Transformer This transformer is used to supply power for the steam turbine generator auxiliaries required for startup. It is a three-winding, 10-MVA, 138-4.16/ 4.16-kV transformer. The two secondary winaings feed 4.16-kV common switch- gear busses CA and CB. Switchyard The switchyard is basically 138 kV consisting of seven bays, shown in Figure 2.5. One parameter for selecting this voltage was the inclusion of a tie line to the existing Beluga Combustion Turbine Plant that presently has a 138-kV tie line to Anchorage. eae e272 < p23, 20 15 15,13 x JOl0 WILLOW A gy main 345 KV AUTO TRANSF | A ys Sacer \0| MAIN \) TRANSF No.2 — x TIE LINE TO \9 EXISTING ™" BELUGA PLANT T m MAIN “| TRANSF J No. 3 za jaleolzs| so | so le jelje| se | SECTION A-A FIGURE 2.5. Beluga Area Station Switchyard Basically, the switchyard is a two bus arrangement with a main and a transfer bus. Each bay has a 138-kV circuit breaker, three disconnect switches and a 138-kV tower. The bus tie bay has a 138-kV circuit breaker and two dis- connect switches. The transmission voltage is 345 kV for export of approximately 200 MVA. An autotransformer, 345-kV circuit breaker and two disconnect switches com prise this portion. 2.2 FUEL SUPPLY The plant described in this report would be located in the Beluga area, northwest of Cook Inlet. Although a precise location is not specified, the plant would presumably draw upon natural gas supplied from the Beluga River Field, possibly supplemented by the nearby Lewis River and Ivan River Fields (Figure 1.1). The existing Beluga Station (Units 1-8) of the Chugach Electric Association is located at and supplied from the Beluga River Field. The plant described in this report would require approximately 306 Bcf of natural gas if operated at maximum availability (86 percent) over its antici- pated 25-year life. Although operation of maximum availability over the life time of the plant is unlikely, partial load operation would result in a higher heat rate, compensating for reductions in gas consumption attributable to operation at lower capacity factor than availability. The 1980 recoverable natural gas reserves of the Beluga River Field are estimated to be 767 Bcf (Secrest and Swift 1982). Of these, 310 Bcf is com mitted to Chugach Electric Association and 624 Bcf to Pacific Alaska LNG Association, resulting in a 167 Bcf overcommitment of recoverable reserves. Two currently untapped smaller fields, the Ivan River Field and the Lewis River Field, lie in fairly close proximity to the Beluga River Field. The recoverable reserves of these fields are estimated to be 26 and 90 Bcf, respectively. Both are currently overcommitted to Pacific Alaska LNG, the Ivan River Field at 106 Bcf and the Lewis River Field at 99 Bcf. cC<c Under the conservative assumption that the units of the existing Beluga Station are operated at maximum availability‘) for their remaining economic life, Chugach will require 396 Bcf of natural gas for continued operation beyond 1980 (Table 2.11). Under these assumptions, sufficient gas for continued operation of the existing Beluga Station units for their remaining life does not appear to exist unless: 1) Pacific Alaska LNG commitments are released, or 2) the existence of additional recoverable reserves is established. If, as thought probable, the Pacific Alaska LNG commitments are released, sufficient currently recoverable reserves would be available to support not only continued operation of the existing Beluga Station throughout its antici- pated life, but also to support additional natural gas-fired generating units. Using recoverable reserves of the Beluga Field only, the surplus of 371 Bcf over that required to support continued operation of the existing Beluga Station would easily support the proposed plant. Development of the Ivan River and Lewis River Fields would provide an additional 116 Bcf of recover- able reserves for a total surplus beyond the needs of the existing Beluga Station of 487 Bcf, sufficient gas for approximately 300 MW of installed combined-cycle capacity. : In conclusion, this analysis suggests that with relinquishment of Pacific Alaska LNG commitments, ample gas is available from the Beluga Field alone to support the 200-MW combined-cycle plant of the capacity described in this report. Development of the Ivan River and Lewis River Fields would provide sufficient gas to support over 300 MW of baseloaded combined-cycle capacity. Without relinquishment of the Pacific Alaska LNG commitments, recoverable reserves from the Beluga Area Fields are insufficient to support operation of the plant described in this report. (a) Except Unit 4, which is assumed to operate as a peaking unit at 10 percent capacity factor. 2.24 S2°2% TABLE 2.11. Estimated Natural Gas Requirements: Chugach Beluga Station Typical (2°¢) (a) (b) Annual Estimated Rated (a) (a) Remaining (a,c) Capacity (a,c) Natural Gas Capacity In-Service Estimated Plant Life Typical’”? Factor Heat Rate ‘"? Requirements Unit (MW) ___ Year ‘Retirement __(Years) Load Operation _ (4) __(Btu/kWh) (Bcf ) 1 14 1968 1988 8 Baseload 81 15,000 11.9 2 14 1968 1988 8 Baseload 81 15,000 11.9 3 51 1973 1993 13 Baseload 81 10,000 47.0 4 9.3 1976 1996 16 Cycling 10 15,000 2.0 5 60.0 1975 1995 15 Baseload 81 10,000 63.9 6 62.0 1976 20074) 274) Baseload 8l 7 62.0 1979 20074) 274) Baseload 81 8,760 asg(e) 8 54 1982 2007 25 Baseload 81 TOTAL 396 (a) From Battelle 1982. (b) Beyond 1980. (c) Unit 4 is assumed to operate as a peaking unit, and Units 7 and 8 assumed to operate in conjunction with Unit 6. (d) Units 6 and 7 are combustion turbines operating with Unit 8, a heat recovery steam generator and turbine. The operating life of Units 7 and 8 is assumed to extend until the end of life for Unit 8. (e) Assumes that Units 6 and 7 operate at 81 percent capacity at 15,000 Btu/kWh prior to 1982. 2.3 TRANSMISSION SYSTEM To transmit the 200 MW generated by this combined-cycle plant, prelimi- nary calculations were made for a 75-mile, 345-kV transmission line from the Beluga area to Willow. The following assumptions were made for this prelimi- nary estimation: e@ This line was considered independent of the existing network. e@ The line goes from Beluga to Willow, where the proposed Anchorage- Fairbanks intertie, which has sufficient capacity, will absorb the total generated power. e@ The existing system at Willow will be a 345-kV system as recommended by Commonwealth Associates, Inc. (1981). Three voltage levels were studied: 138 kV, 220 kV and 345 kV. A 138-kV voltage is too low to transmit the plant's power output the required distance; the surge impedance loading for this line would only be around 50 MW. A 230-kV voltage line has a surge impedance loading of 135 MW. This type of line with VAR compensation and adequate conductor size could adequately transmit the plant output. A 345-kV voltage line has a surge impedance loading of 300 MW. This line may need line reactors for open line and reclosing conditions. A double- circuit 230-kV transmission line may also be an attractive alternative. Initial investment may be higher than the 345 kV alternative because 230- 345 kV transformation at Willow has to be built and transmission towers for a double-circuit 230 kV may be heavier than the 345-kV towers. However, I,R losses may be lower. The results obtained from the preliminary study of these three alternatives are as follows: Line Size of Losses Voltage No. of Type of Conductor I9R Reactive (kV) Circuits Conductor —_ (MCM) Regulation (MW) Support 230 1 ACSR 636 11.9 percent 14.5 Capacitors 345 1) ACSR 795 3.5 percent 4.5 Reactors 230 (a) 2 ACSR 636 Be 3.8 (a) Estimated values. 2.26 From these preliminary calculations a 345-kV ACSR, single-circuit, 795 MCM is recommended. However, additional studies will have to be done to fully jus- tify these parameters. From an electrical point of view, interconnections with the transmission system may substantially modify the results. This line should not be studied independently (a complete system study is recommended). Capital investment and line losses of alternative line configurations will have to be fully evaluated. The lowest initial investment will be the single-circuit 230-kV line, but excessive losses appear to negate this alternative. Differential losses of 10 MW between the 345-kV and 230-kV alternates may result in $2,000,000 per year, for a load factor of 80 percent and a cost of 3 cents a kWh for energy. The 345 kV will have the advantage of uniform voltages with the system recom mended by Commonwealth Associates, Inc. (1981). To incorporate the proposed combined-cycle plant output, a 345-kV substa- tion at or near Willow (or some other convenient place) appears desirable and should have a configuration as depicted in Figure 2.6. The 345-kV lines to Anchorage, Beluga and Nenana would terminate here. This substation will pro- vide flexibility and reliability to the system load flow. Connecting this combined-cycle plant into the system at Willow avoids the underwater crossing of Knik Arm currently in use from the Chugach Beluga Sta- tion to Anchorage. 2.4 SITE SERVICES The construction and operation of a 200-MW combined-cycle power plant will require a number of related services to support all work activities at the site. These site services could include the following depending upon the actual location of the power plant: @ access roads construction water supply construction transmission lines airstrip landing facility construction camp. Sse) FAIRBANKS 274 VAAL TA | \\_ [| f / | 1 ER 1 OY Se en ¥ A | } yy NW Fe ¥ -—t —_ Willow Substation FIGURE 2.6. 2.28 2.4.1 Access Roads Gravel roads with a 9-inch gravel base will be required to connect the plant site with the equipment landing facility in the Beluga area. To the extent possible, existing roads will be used. Hence, no more than 5 miles of new road construction is anticipated. 2.4.2 Construction Water Supply A complete water supply, storage and distribution system will be installed. Due to the remote nature of a Beluga area site, a one million gallon water storage tank has been assumed with one-half of this storage capacity dedicated to fire protection purposes. Construction water supply to the project site should be at least 150 gpm. 2.4.3 Construction Transmission Lines Power requirements during the construction phase will be supplied by con- structing a 25-kV transmission line tapped from an existing transmission sys- tem. For a potential Beluga site, a transmission line length of 20 miles is assumed and will be derived from the existing Chugach Electric Association system at either the town of Beluga or Tyonek. 2.4.4 Airstrip For the general power plant location, the existing airstrip will be used. It is anticipated that all personnel travel will be by air with prearranged commercial charter carriers. All perishable goods will be flown in. Equip- ment for construction will be flown in only under extraordinary circumstances. The largest airplane that will be able to land on the strip will be the size of a DC-3. The airstrip will be lighted using an above-ground distribution system to provide for the possibility of night-time medical emergency traffic. A control tower will not be required. All air traffic will be on a Visual Flight Rule (VFR) basis only. 2.29 2.4.5 Landing Facility The site will use the existing marine landing facility to receive all construction materials, equipment and supplies. A paved, fenced interim stor- age area will be provided. A heavy-duty haulage road will be provided from the landing area to the access road. 2.4.6 Construction Camp Facilities A 500-bed labor camp will be provided. All personnel housed in this camp will be on single status. Provisions will be made to accommodate a work force containing females (separate bathroom and locker facilities). The camp will have its own well water supply. A sewage treatment facil- ity, waste incinerator, and garbage compactor will also be provided. The complex will also have a dining hall and recreation hall. Since it is unlikely that all personnel will be willing to come to the job-site on single status only, a mobile home park will be provided for 16 supervisory personnel in family status. These mobile homes will be approxi- mately 1000 Ft? each and could remain after completion of construction to house vendor personnel for repair work during plant operation. 2.5 CONSTRUCTION The number of workers necessary for construction of a 200-MW station will vary over the approximate 32-month construction period. Construction is esti- mated to peak in year two requiring a work force of approximately 400 person- nel. The distribution of this work force over the schedule duration is shown in Figure 2.7. Construction of this 200-MW station will follow normal acceptable con- struction methods. A program of this magnitude begins with orderly devel- opment of the following requirements: 1. construction camp and utility services, such as electric light and power, water for industrial and potable use and fire protection, sanitary facilities, telephone communications, etc. 2.30 WORKFORCE 350 300 250 200 /50 /00 ° 4 8 12 lo 20 24 28 32 MONTHS 7 NOTE: DOES NOT INCLUDE VENDOR PERSONNEL, OWNER PERSONNEL, OR A/E ENGINEERS LOCATED AT SITE. FIGURE 2.7. Construction Work force Requirements temporary construction office facilities (with heating and ventila- tion furnished by contractors as required) temporary and permanent access roads temporary enclosed and open laydown storage facilities delivery by landing craft of various types of construction equipment and vehicles, such as earth-moving equipment, concrete and materials hauling equipment, cranes, rigging equipment, welding equipment, trucks and other vehicles, tools, and other related types of con- struction equipment by landing craft temporary office and shop spaces for various subcontractors 2eo 7. settling basins to collect construction area storm runoff 8. permanent perimeter fencing and security facilities 9. safety and first aid facilities in strict compliance with OSHA regulations. Following completion of these site preparation activities, power plant systems construction will be initiated. The activities involved in the over- all construction process as well as the plant's detailed development schedule are presented in Figure 2.8. 2.6 OPERATION AND MAINTENANCE 2.6.1 General Operating Procedures The plant has been designed for operation as a base loaded plant. Hot starts are accomplished by starting and synchronizing the first gas turbine. The heat recovery steam generator is then loaded and the steam turbine started. After the steam turbine is up to speed, the second gas turbine is started, the second steam generator is loaded and the plant is brought up to load. Cold starts should be expected to take a minimum of 9 hours. The first gas turbine is started and synchronized with the bypass damper positioned to partially bypass the steam generator. The second gas turbine is started and synchronized in a similar manner. A vacuum is pulled in the condenser using the vacuum pumps and the steam turbine warmed through over the course of several hours in accordance with manufacturer's instructions. The by-pass dampers can be repositioned as required during the start-up period to control steam flow, and opened fully when the steam turbine is loaded. Plant systems will be operated from the control room located in the main plant building. Some of the systems and equipment will also be controlled from local stations. In general, controls are automatic, although operators can override the automatic controls and operate the plant manually. To supplement the operational controls, the station will be equipped with an a3 ce°2 ACTIVITY ENVIRONMENTAL MONITORING PREPARE APPLICATION AGENCY REVIEW PROJECT SCOPING CONCEPTUAL DESIGN ENGR. PROCURE & CONSTR. SCHED., ORDER COMBUSTION TUR- BINES & WASTE HEAT BOILERS & STM TURB. DETAILED ENGR. CON- STRUCTION DESIGN, PROCURE BALANCE OF PLANT CONSTRUCT PROJECT CHECKOUT, CALIB. STARTING, TESTING SITE SCREENING & SELECTION (SEE NOTE) | aa - PROJECT DESCRIP. + SCOPE APPVL » GEN'L ARRANGEMENTS - PURCH, ORD. TURB. - P.O. WASTE HT. BLR. & STM. TURB. * PROJECT SPEC. - DEL TURB. - DEL WASTE HT. BLR. - DEL STEAM TURB. - START DES. ~ BUDGET EST. - COMPLETE FON. DES. - DET. EST. S.C. - COMP. DES. C.C. - DET. EST. CC. - COMPLETE DES. C.C. » PURCH. ORD. DEMIN. + START SITE PREP. - START TURB. ERECT. - POWER FROM SYSTEM - START WASTE HT. BLA. ERECT. ~ START ERECT. STM. TURB. - START CHECK S.C. - TRIAL OPERATION - TRIAL OPERATION - TRIAL OPERATION - COM. OPER. OF S.C. » START CHECK C.C. - TRIAL OPERATION - COMMERCIAL OPERATION 10 20 30 40 50 60 70 TT —- NOTE TIS ASSUMED FOR SCHEDULING PUR- POSES THAT A SUITABLE SITE WILL HAVE BEEN SELECTED FOR INVESTI- GATION PRIOR TO THE INITIATION OF STUDIES WHICH ARE ILLUSTRATED BY THIS PROJECT SCHEDULE. THIS SITE SELECTION STUDY WILL REQUIRE AP- PROXIMATELY 6 to 9 MONTHS. er? @ 2 i Gd i @ | 9 meee ef 9 2. ee _——— COMMERICAL OPERATION (MONTH 74) START ENGINEERING CONSTRUCTION PERMIT FIGURE 2.8. Project Schedule alarm system, fire protection system, proper lighting, and a radiotelephone communication system. The diesel generator will be required to provide power for safe shutdown of the unit under trip and black-out conditions. 2.6.2 Operating Parameters Operating experience on gas-fired combined-cycle plants is somewhat limited when compared to coal or oil-fired power plants. Conclusions on oper- ating parameters are, therefore, based on the available data on gas-firea com bined cycle plants supplemented by EPRI data (EPRI 1979) and experience on gas turbines and steam turbines. It is expected that the forced outage rate will be about 8 percent. Operational experience on some earlier plants indicates higher forced outages in the first few years, but this is attributed to operational adjustments required for a new type of plant, and development of the current gas turbine design. It is expected that a slight increase in forced outages will occur as the plant ages, but the "technology development"-type outages experienced by some of the earlier plants are not anticipated. Variations in plant sizes should not affect the forced outage rate provided that the same "experience .factor" is characteristic of the gas turbines used. Cycling the plant will have a negative affect on all the plant machinery. Stress reversals encountered with peaking operation usually result in a higher forced outage rate. Combined-cycle plant reliability is very dependent on an adequate preven- tative maintenance program, and scheduled outrage rates can be expected to be about 7 percent. Again, plant size will not affect the scheduled outage rate but cycling service will necessitate more frequent inspections, which will result in a higher scheduled outage rate. An equivalent plant availability of approximately 86 percent should be obtained, with the forced and scheduled outage rates of 8 percent and 7 per- cent, respectively. The plant heat rate of approximately 8,200 Btu/kWh is not expected to vary significantly with plant size within the range of 100 MW to 400 MW, but should rise slightly as the plant ages. The heat rate will, however, vary 2.34 considerably with plant loading because as the efficiency of the gas turbines deteriorates rapidly as the load is reduced. At extremely low load conditions, in the 20 to 30 MW range, heat rates as high as 14,000 to 16,000 Btu/kWh should be anticipated. For a combined-cycle plant in load-following service, consid- eration should be given to using a steam turbine of relatively larger capacity and supplementary firing of the steam generators. Plant output could than be varied by adjusting the steam turbine output with duct burner firing. Duct- burner firing of the steam section will raise the heat rate, but offers a distinct advantage over heat rates obtained with part-load operation of the gas turbines. 2263) |) Plantultite The plant should have a 25-year life expectancy, based on the expected life of the gas turbine units. It is expected that the gas turbine units will be partially rebuilt a number of times during the scheduled (and unscheduled) outages. 2.6.4 Operating Work force The plant will require an operating staff of approximately 43 employees. Of this total, approximately 25 represent operating staff and 18 are mainte- nance personnel. A list of the plant's staffing requirements is presented in Table 2.12. Employment of these personnel will continue throughout the life of the plant. 2.6.5 General Maintenance Requirements To prevent mechanical failure, periodic maintenance will be performed on all pressure systems, rotating machinery, heat sensitive equipment, and other operating equipment to prevent malfunctions, leaks, corrosion and other such abnormalities. The periodic maintenance should be performed in accordance with an established maintenance program that will include the complete strip—down and major inspection of the turbines at intervals required or suggested by the equipment manufacturer. In addition, the maintenance programs will monitor the revegetation and erosion prevention programs initiated during the cleanup phase of construction. Trained maintenance crews will perform periodic maintenance and will correct malfunctions. In general, all major maintenance functions will be performed during the plant's annual scheduled outages. 2.35 TABLE 2.12. Plant Staffing Requirements Job Title 200-MW Unit Plant Superintendent i Operations Engineer a Shift Superintendent 4 Control Room Operators and Auxiliary Operators 4 Chemist 1 Results Engineer 1 Results Technician 1 Instrumentation and Controls Engineer 1 Instrumentation and Controls Technician 4 Storekeeper 1 Clerical 2 Maintenance Superintendent 1 Maintenance Engineer i Electrical/Mechanical Maintenance Foreman 2 Electrical/Mechanical Mechanics (6-Man Crews) 6 Instrumentation and Controls Maintenance Foreman ih Instrumentation and Controls Mechanics (2-Man Crews) 2 Labor Foreman i} Labor Crew 4 Fire Protection/Security Staff _4 TOTAL 43 NOTE: The above staffing is required for three 8-hour shifts and seven-days-a-week operation. 2.36 3.0 COST ESTIMATES 3.1 CAPITAL COSTS 3.1.1 Construction Costs Construction costs in January 1982 dollars have been developed for the major bid line items common to natural gas-fired combined-cycle power plants. These line item costs have been broken down into the following categories: labor and insurance, construction supplies, equipment repair labor, equipment rental, and permanent materials. Results of this analysis are presented in Table 3.1. The equivalent unit capital cost of the plant is 1001 $/kW. 3.1.2 Payout Schedule A payout schedule has been developed for the entire project and is pre- sented in Table 3.2. The payout schedule was based on a 32-month basis from start of construction to project completion. 3.1.3 Capital Cost Escalation Estimates of real escalation in capital costs for the plant are presented below. These estimates were developed from projected total escalation rates (including inflation) and subtracting a Gross National Product deflator series which is a measure of inflation. Materials and Construction Equipment Labor Year (Percent) (Percent) 1981 1.0 0.5 1982 1.2 Lied 1983 lez 1.7 1984 0.7 123 1985 -0- -0- 1986 -0.1 -0.1 1987 0.3 0.3 1988 0.8 0.8 1989 0 TsO 1990 Tol Led 1991 1.6 1.6 1992 - on 2.0 2.0 Sal ere TABLE 3.1. Bid Line Item Costs for a Natural Gas-Fired Combined-Cycle 200-MW Station(a) (January 1982 Dollars) Construction Equipment Labor and Construction Repair Equipment Permanent Total Bid Line Item Insurance Supplies Labor Rent Materials Direct Cost 1. Improvements to Site 95,600 109,700 83,700 13,800 302,800 2. Earthwork and Piling 313,000 2,666,300 87,300 151,600 3,218,200 3. Circulating Water system 2,455,600 484,400 16,100 28,500 4,400,000 7,384,600 4. Concrete 3,450,700 348,000 372,700 226,600 1,496,000 5,894,000 5. Structural Steel and Lift Equipment 305,000 1,900,000 2,205,000 6. Buildings 192,200 491,000 683,200 7. Heat Recovery Boilers, Gas 5,197,200 172,500 250,000 31,200,000 36,819,700 Turbines, and Generators 8. Steam Turbines and Generator 3,631,900 115,000 200,000 8,600,000 12,546,900 9. Other Mechanical Equipment 2,588, 700 115,000 65,000 4,946,200 7,714,900 10. Piping 3,164,500 345,000 120,000 4,500,000 8,129,500 11. Insulation and Logging 126,500 86,300 50,000 250,000 512,800 12. Instrumentation 379,500 46,000 10,000 700,000 1,135,500 13. Electrical Equipment 4,586,000 57,500 15,000 5,250,000 9,908,500 14. Painting 632,600 11,500 2,500 500,000 1,146,600 15. Off-Site Facilities 2,451,400 211,100 3,621,100 2,693,600 979,200 9,956,400 16. Waterfront Construction 14,400 31,800 23,700 131,700 201,600 17. Substation 948,800 23,000 10,000 4,035,500 5,017,300 18. Construction Camp Expenses 4,292,400 12,362,000 16,654,400 19. Indirect Construction Costs ay 26,341,900 4,313,900 1,301,600 1,588,700 33,546,100 Architect/Engineer Services(> SUBTOTAL 61,167,900 21,357,500 5,540,300 5,518,900 69,393,400 162,978,000 Contractor's Overhead and Profit 15,000, 00u Contingencies . 22,224,200 TOTAL PROJECT COST 200,202,200 (a) The project cost estimate was developed by S. J. Groves and Sons Company. No allowance has been made for land and land rights, client charges (owner's administration), taxes, interest during construction or transmission costs beyond the substation and switchyard. (b) Includes $14,816,200 for engineering services and $18,729,900 for other indirect costs including construction equipment and tools, construction related buildings and services, nonmanual staff salaries, and craft payroll related costs. TABLE 3.2. Payout Schedule for a Natural Gas-Fired Combined-Cycle 200 MW Station (January 1982 Dollars) Cost per Month Cumulative Cost Month (Dollars) (Dollars) i. 2,155,800 2,155,800 2 3,159,000 5,314,800 a 3,159,000 8,473,800 4, 4,054,400 12,528,200 5. 3,904,000 16,432,200 6. 3,904,500 20,336,700 Te 4,840,700 25,177,400 8. 3,988,400 29,165,800 9. 3,814,400 32,980,200 10. 6,045,300 39,025,500 11. 5,730,800 44,756,300 12. 6,761,300 51,517,600 13), 6,761,300 58,278,400 14, 7,817,000 66,095,900 15. 8,869,200 74,965,100 16. 8,869,200 83,834,300 iF 8,869,200 92,703,500 18. 8,869,200 101,572,700 19. 8,869,200 110,441,900 20); 9,166,600 119,608,500 21. 9,166,600 128,775,100 22) 9,166,600 137,941,700 23. 8,237,300 146,179,000 24, 7,499,500 153,678,500 25. 7,499,500 161,178,000 26. 7,499,500 168,677,500 ra 6,738,400 175,415,900 28. 6,738,400 182,154,300 29. 6,248,400 188,402,700 30. 6,174,100 194,576,800 31. 2,885,800 197,462,600 32. 2,739,600 200,202 ,200 3.3 3.1.4 Economics of Scale For combined-cycle systems, economies of scale can be realized for many site development costs, including temporary facilities, construction equip- ment, and construction labor. These savings, however, can only be brought about if facility capacity is increased through an increase in component capacity, and not through use of additional power generation units. For example, in the range of considered plant sizes (up to approximately 300 MW), utilization of 100-MW combustion turbines (current maximum unit size) and larger heat recovery boilers would necessitate only a slight increase in the construction work force over that required for smaller unit sizes and could be constructed within the same time frame. This would result in a cost reduction on a per-megawatt basis. If capacity was increased by use of additional power generation units, e.g., three 70-MW combustion turbines as opposed to two 100-MW units, this unit cost reduction would not be realized. 3.1.5 Working Capital Working capital costs, including a 30-day emergency distillate supply and 30-day 0&M cost, are estimated to be 52 $/kW. The cost of the emergency dis- tillate supply was based on a forecasted 1990 price for No. 2 fuel oil at 8.45 $/MM Btu (Battelle 1982). 3.2 OPERATION AND MAINTENANCE COSTS 3.2.1 Operation and Maintenance Costs The operation and maintenance costs for the 200-MW size plant, expressed in January 1982 dollars, are as follows: Fixed Costs Staff (43 Persons) $1,450,600 (7.25 $/kW/yr) Variable Costs 1.54 mills/kWh Consumables 0.15 mills/kWh 3.4 3.2.2 Escalation Estimated real escalation of fixed and variable operation and maintenance costs are as follows: Escalation Year (Percent) 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 MYND P RRP RRR RE . ° COCO WOONDAADAMN 3.2.3 Economics of Scale Costs associated with personnel salaries are generally the major compo- nent of operation and maintenance costs for energy generating facilities. In light of this fact, economies of scale would result from larger unit capacities because the personnel requirements are more a function of items of equipment and, therefore, would not increase in direct proportion to additional capacity. 3.3 FUEL AND FUEL TRANSPORTATION COSTS Estimated delivered costs for Cook Inlet natural gas to the Chugach Electric Association have been forecasted by Battelle, Pacific Northwest Laboratories (Battelle 1982). Cases with and without relinquishment of Pacific Alaska LNG commitments are developed in this report. In as much as it appears that insufficient recoverable reserves would be available in the Beluga area without relinquishment of the Pacific Alaska commitments, the "without" Pacific Alaska prices are used in the cost-of-energy estimates that follow. Forecasted natural gas prices to Chugach Electric Association through the time period considered in the Railbelt Electric Power Alternatives Study 3.0) are shown in Table 3.3. Prices beyond 2010 are assumed to escalate at 2 per- cent per annum for the cost-of-energy calculations of this report. Note that the forecasted natural gas costs of Table 3.3 are weighted costs, comprised of gas from Beluga, Alaska Gas and service company supplies and supplemental gas supplies. TABLE 3.3. Estimated Natural Gas Acquisition Cost for Chugach Electric Association Without Pacific Alaska LNG Plant, 1982 $, O Per- cent Inflation (Battelle 1982) Weighted Average Cost Year (8/Mcf) 1980 0.46 1981 0.45 1982 0.46 1983 0.46 1984 0.46 1985 0.51 1986 0.54 1987 0.66 1988 0.70 1989 0.78 1990 0.90 1991 1.53 1992 1.66 1993 1.87 1994 2.00 1995 a7 1996 4.46 1997 4.56 1998 4.68 1999 4.78 2000 4.91 3.4 COST OF ENERGY The estimated busbar energy cost for the natural gas combined-cycle plant described in this report is 46.5 mills per kilowatt-hour. This is a levelized lifetime cost, in January 1982 dollars, assuming a 1990 first year of 3.6 commercial operation and an 85 percent capacity factor. Estimated busbar energy costs for other capacity factors and other startup dates are shown in Figure 3.1. First and subsequent year energy costs and capital, O&M and fuel components are shown in Table 3.4. Year-of-occurrence costs are sensitive to escalating fuel costs. These costs are based on the following financial parameters: Debt Financing 100% Equity Financing 0% Interest on Debt 3% Federal Taxes 0% State Taxes 0% Bond Life 25 years General Inflation 0% The escalation factors given in Sections 3.1 and 3.2 were employed. Weighted average capital cost escalation factors were derived using a labor/material ratio of 40 percent/60 percent. 3.7 100 = = x 2 € Sa 80 Fa yn ° Oo < Oo x Ww 60 Zz w a“ < a wn a 40 a Ww N al Ww > eey ~ 20 a tty KE < 2 E wn Ww 0 20 40 60 80 100 CAPACITY FACTOR (3%) FIGURE 3.1. Cost of Energy Versus Capacity Factor and Year of First Commercial Operation (TCO) (January 1982 dollars) 3.8 TABLE 3.4. Year-of-Occurrence Energy Costs (1990 First Year of Operation; January 1982 dollars) Unit Unit Unit Total Capital Costs 0&M Costs Fuel Costs Unit Costs Year (mills/kWh) (mil1s/kWh) (mills/kWh) (mil1s/kWh) 1990 9.2 3.0 7.4 19.6 1991 92 BEO 1225 24.7 1992 952 350) 13.6 25.8 1993 9.2 3.0 1523 265) 1994 9.2 350) 16.4 28.6 1995 9.2 320 17.8 30.0 1996 9.2 3.0 36.6 48.7 1997 9.2 350 37.4 49.6 1998 9.2 350 38.4 50.6 1999 932 3.0 3962 51.4 2000 ey 320 40.3 52.4 2001 9.2 3.0 41.1 5323) 2002 9.2 3.0 41.9 54.1 2003 9.2 3.0 42.7 54.9 2004 9.2 3.0 43.5 BA7/ 2005 9.2 3.0 44.4 56.6 2006 952 340 45.3 5725 2007 9.2 3.0 46.2 58.4 2008 9.2 3.0 47.1 5953 2009 9.2 3.0 48.1 60.3 2010 9.2 340 49.1 6123 2011 9.2 3.0 50.0 62.2 2012 9.2 3.0 Sie 63.3 2013 9.2 320 521 64.2 2014 9t2 Sow) Sor 65.3 329 4.0 ENVIRONMENTAL AND ENGINEERING SITING LONSTRAINTS Council of Environmental Quality regulations implemented pursuant to the National Environmental Policy Act of 1969 require an environmental impact statement for projects requiring licenses or permits issued by a federal agency. The combined-cycle plant described in this report would require several federal permits, as discussed in Section 6. The statement must include a discussion and evaluation of alternatives to the proposed action. This requirement is usually satisfied for power generating projects through the evaluation of alternative sites and alternative energy generating tech- nologies. The purpose of such a study is to identify a preferred alternative and possibly viable alternative locations for the construction and operation of the generating station. This process can contribute to reduction in proj- ect costs through analysis of environmental and engineering siting constraints. This section presents many of the constraints that will be evaluated during a siting study. Special attention was given to their applicability to the general location considered in this study. It should be realized that many of the constraints placed upon the development of a natural gas-fired combined- cycle power plant are regulatory in nature; therefore, the discussion presented in this section is complemented by the identification of power plant licensing requirements presented in Section 6. 4.1 ENVIRONMENTAL SITING CONSTRAINTS Potential environmental siting constraints include effects on water resources, air resources, aquatic and marine ecology, terrestrial ecology and socioeconomic considerations. 4.1.1 Water Resources Water resource sit ng constraints generally center about two topics: water availability and water quality. Water availability is important from two perspectives. First, the power plant requires a reliable source of water for efficient operation. Second, the withdrawal of water for plant uses should not adversely impact the source from which the water is drawn. Siting 4.1 analyses generally attempt to minimize reduction in flow of potential water sources while maintaining plant reliability. For this reason, it is necessary to examine low flows as well as average yearly and monthly flows of potential water sources. Since combined-cycle technology minimizes water usage when compared with a similar-sized conventional steamelectric facility, water availability is not anticipated to be an overly constraining criterion. Estimated plant makeup water requirements are 1060 gpm, of which 914 gpm are for heat rejection system makeup and 156 gpm are for steam system, domes- tic and miscellaneous (see Table 5.1 in Section 5). Water supply alternatives include use of fresh surface water sources, groundwater sources or seawater. Seawater utilization would be limited to heat rejection system uses and a fresh water source would be required for steam system and domestic uses. Large rivers are not found at the Beluga location and therefore smaller streams will have to be examined to determine their suitability as a water source. Groundwater sources potentially exist in this area, with well yields estimated to be as high as 1000 gpm near the larger surface water bodies. Yields, however, range from 10 gpm to 100 gpm away from surface water bodies. Thus, it appears that adequate water supplies can be obtained from ground water near surface water bodies or by use of seawater for heat rejection system makeup and ground water for other uses. Investigation of specific streams may reveal sources of adequate magnitude. Existing water quality can represent a significant siting constraint. First, receiving stream water quality standards, if particularly stringent, could prohibit plant effluent discharge. Second, makeup water quality require- ments may mandate the provision of an extensive water treatment facility if the quality of the water source is inferior. This consideration should not prove restrictive at either potential plant location. The water quality of most other surface water resources is acceptable from a makeup water manage- ment viewpoint. However, if the plant utilizes a groundwater supply system, an extensive treatment system may be required since ground water is generally highly mineralized. 4.2 4.1.2 Air Resources Combined-cycle gas-fired units emit only one atmospheric pollutant of major concern--oxides of nitrogen (NOY). There are no PSD increments cur- rently set for NO, (see Section 6.1.1) and there are no nonattainment areas in the Railbelt Region with respect to the NO, standards. Therefore, there is very little in the way of siting constraints due to atmospheric emissions from combustion-turbine combined-cycle units. Nevertheless, regulatory compliance will be eased somewhat by judicious site selection. The regulatory issues discussed in Section 6.1.1 can be used to provide some guidance in this selection. Generally, areas designated as Class I for PSD purposes should be avoided when possible. The Tuxedni Wildlife Refuge and the Mount McKinley National Park are the only areas in the Railbelt Region currently designated as Class I. In addition, a nonattainment area designated for any pollutant should be avoided if reasonable alternatives are available. The Anchorage area is currently designated as nonattainment for carbon monoxide. Any potential for CO emissions must be analyzed carefully and controlled to the greatest extent possible. This may include potential emissions due to "upset" conditions when the facility is not operating at its most efficient levels, and it may also include CO emissions from secondary sources, such as construction ana associated automobile traffic. From a topographic point of view, enclosed areas with limited dispersion potential, such as deep valleys or sheltered basins, should also be avoided. The applicant will have to demonstrate that the ambient air quality standards (for NO.) will not be violated by facility operation. Compliance with these standards is better assured in open, exposed locations. 4.1.3 Aquatic and Marine Ecology Since the plant makeup and discharge requirements are relatively small (a maximum of 1060 gpm and 160 gpm, respectively), intake entrainment and impinge- ment and wastewater discharge impacts will probably not be major site consid erations. The major activity related to aquatic ecology performed during the siting process will, therefore, be an identification of exclusion and avoid— ance areas to be considered in association with intake and discharge structure 4.3 development. The delineation of these areas will be based primarily upon an inventory of fish spawning habitat and upstream migration pathways, fish nur- sery habitat and downstream migration pathways, important benthic habitat and rare and/or endangered species and their critical habitats. Should a marine intake or discharge be considered, impacts to the significant marine popula tions, including Beluga whales, will be addressed, but should not represent a constraint due to the small intake and discharge flows expected. 4.1.4 Terrestrial Ecology Since habitat loss is generally considered to represent the most signifi- cant impact on wildlife, the prime terrestrial ecology activity related to terrestrial ecology will be an identification of important wildlife areas, especially critical habitat of threatened or endangered species. Based upon this inventory, exclusion, avoidance and preference areas will be delineated and factored into the overall plant siting process. A number of important and sensitive species inhabit the potential site area, including moose, caribou, brown and black bear as well as small fur- bearers, such as lynx, beaver and muskrat. Also present are significant bird species including bald eagles and colonial nesting birds, such as seagulls, puffins and cormorants. Appropriate consideration of these species and their habitats will be required during the plant siting process. 4.1.5 Socioeconomic Constraints Major socioeconomic constraints center about potential land use conflicts and community and regional socioeconomic impacts of project activities. Two types of potential land use conflicts must be considered: exclusionary areas, where plant development would be prohibited; and avoidance areas, where plant development, while possible, is generally not desirable. Potential exclu- sionary land uses will consist of those areas that contain lands set aside for public purposes, areas protected and preserved by legislation (federal, state or local laws), areas related to national defense, areas in which a combined- cycle installation might preclude or not be compatible with local activities (e.g., urban areas or Indian reservations), or areas presenting safety consid- erations (e.g., aircraft facilities). Avoidance areas will generally include 4.4 areas of proven archeological or historical importance not under legislative protection as well as prime agricultural areas. Minimization of the boom/bust cycle will also be a prime socioeconomic consideration. Through the application of criteria pertaining to community housing, population, infrastructure and labor force, this consideration will be evaluated and preferred locations identified. Because of the potential for significant boom/bust-related impacts on small communities within the Beluga area, socioeconomic impact criteria will be heavily weighted in the overall site evaluation process. 4.2 ENGINEERING SITING CONSTRAINTS Potential engineering siting constraints that should be considered in the site-selection process include site topography and geotechnical character- istics, road access, transmission line access, water supply and fuel supply considerations. 4.2.1 Site Topography and Geotechnical Characteristics Principal topographic and geotechnical considerations include terrain, soil conditions, seismic activity and the availability of borrow material. In general, the power plant should be sited in relatively flat terrain. This will minimize the amount of required grading and excavation as well as mini- mize the potential for adverse environmental impacts due to rainfall runoff transport of suspended solids to nearby waterways. The plant should be sited above the 100-year floodplain of any major streams to avoid flooding. Poor soil conditions can cause significant construction problems due to poor suitability as a foundation for structures. The presence of highly organic soil (muskeg) in the Beluga area will probably require that extensive piles be placed under major building and equipment foundations. Potential seismic activity can also be an important site-differentiating factor, with preference given to those sites located in regions of low seismic activity. However, all potential Beluga sites fall within regions of high seismic activity (Zone 3). While this will not preclude development nor dif- ferentiate between the sites, it will increase construction costs because 4.5 more material will be required to ensure plant foundation stability. The loca- tion and extent of all faults within the general Beluga area should be studied during the site-selection process because the plant should not be sited in close proximity to fault lines. Finally, sites that contain an adequate supply of borrow material can be far less costly, especially if alternate sites would require haul of this material over long distances. 4.2.2 Access Road, Transmission Line and Fuel Supply Considerations Siting the proposed power plant in close proximity to existing roads, transmission lines and gas pipelines would minimize the cost associated with these required connection links and also minimize the environmental effects associated with land disturbance. For roads, the selected route should comply with established safety and reliability standards. For example, the maximum allowable grade for roads is approximately 6 percent. Route selection of roads, pipelines and transmission lines will also be affected by soil and meteorological conditions because potential frost heave problems and other soil-related characteristics can significantly add to the cost of road and pipeline facilities. Additional considerations for transmission line routing include wind, temperature and prospective ice load; these factors can signifi- cantly affect transmission line design. Accessibility to transmission is not expected to be a serious constraint for a Beluga site due to the presence of the transmission line serving the Chugach Electric Association Beluga Station. 4.2.3 Water Supply Considerations The power plant requires a reliable water supply. To ensure that this requirement is met, two criteria are generally employed during the siting process: e@ The plant should be sited within approximately 15 miles of an acceptable source of water, and e@ The plant should be sited where the maximum static head between the water source and the end use facility (the plant itself or a makeup water reservoir) is less than approximately 1500 feet. 4.6 The first criterion reflects the need to minimize right-of-way acquisi- tion; land disruption; associated construction-related environmental impacts; investment and operating costs; and the potential reliability problems associ- ated with “pumps-in-series" operation. The second criterion reflects the limits on the reliability of high-lift pumping operations. Observance of this criterion will minimize the need for system redundancies (e.g., a duplicate pipeline) as well as minimize the operating costs associated with water pumping. A discussion of potential water sources in the Beluga area is provided in Section 4.1.1. 4.7 5.0 ENVIRONMENTAL AND SOCIOECONOMIC CONSIDERATIONS The construction and operation of a 200-MW natural gas-fired combined- cycle generating facility will create changes or impacts to the land, water and socioeconomic environments in which it is located. A summary of the primary impacts of the plant on the environment is presented in Table 5.1. Following preliminary plant design, these primary effects are then analyzed and evaluated in light of existing environmental conditions to determine the potential significance of the impact and the need for additional mitigative measures. Further discussion of the impacts listed in Table 5.1 is provided below. 5.1 WATER RESOURCE EFFECTS Water resource impacts associated with the construction and operation of a combined-cycle power plant are generally mitigated through appropriate plant siting criteria and through a water and wastewater management program. The plant water system will normally employ water treatment and recycle to satisfy regulatory requirements on discharge and to minimize water consumption. Achievement of these water quality requirements will preclude adverse impacts on the water resource. A favorable attribute of natural gas-fired combined-cycle power plants is that, on a per-megawatt-basis, these facilities require much less water for cooling purposes than conventional "all steam" systems. For example, the esti- mated makeup water requirement at a 200-MW direct coal-fired steam-electric plant is 1947 gpm (wet cooling) (Ebasco Services Incorporated 1982) compared with an estimated 1060 gpm for the 200-MW combined-cycle plant described in this report. The difference is attributable to the superior thermal effi- ciency of the combined-cycle plant and to the reduced steam system makeup requirements. In addition, natural gas-fired combined-cycle power plants produce little solid waste, and therefore minimize disposal and wastewater treatment requirements generally associated with combustion technology byprod- ucts. Significant or difficult-to-mitigate water resource impacts should therefore not pose restrictive constraints on the development of this type of electric generating facility. Sel TABLE 5.1. Mic Particulate Emissions Sulfur Dioxide Emissions Nitrogen Oxide Emissions Water Plant Water Requirements Cooling Tower Makeup Other Requirements Plant Discharge Requirements Cooling Tower Blowdown Demineralizer Steam Generators Total Sanitary Treated Waste Floor Drains Aquatic and Marine Ecosystems Anadromous Fish Other Terrestrial Ecosystem Wildlife Habitat Food Chain Human Presence Land Plant Island Fuel Storage Transmission Road Gas Pipeline Socioeconomic Construction Work Force Operating Work Force Relocations Land Use Changes Recreation Capital Investment Operating Investment Fuel Investment Aesthetics Maximum Structure Height 5.2 Primary Environmental Effects Negligible. Negligible. Emissions variable - water injec- tion controlled to meet calculated NO, standard of 0.014 percent of total volume of gaseous emissions. 914 gpm 146. gpm 144 gpm 12 gpm 22_gpm 178 gpm 4 gpm 8 gpm No impact anticipated. No significant impact anticipated. Loss of habitat at the plant site and along access road corridor. No significant impact anticipated. Increased human presence at plant site and along access road corridor. 2 acres 1/2 acre 75 miles at 345-kV line (could shave existing transmission corri- dor for much of this distance). 5 miles of gravel road. Less than 10 miles of new corridor. Peak requirement of approximately 400 personnel. 43 personnel. None. Increased access to plant site and along road, gas pipeline and transmission corridors. See land use changes above. 70 percent within region. 30 percent outside region. 84 percent within region. 16 percent outside region. 100 percent within region. 50 feet 5.2 AIR RESOURCE EFFECTS Air quality impacts resulting from the operation of natural gas-fired combined-cycle facilities are generally limited to emissions of oxides of nitrogen (NO,). Emissions of NO, can be well controlled by reduction of peak combustion temperatures through water or steam injection. Sulfur oxides are not a significant pollutant because of the low sulfur content of natural gas. Achievement of regulatory requirements for New Source Performance Stan- dards will generally preclude any significant impact from these emissions on the air resource. Ice fog may be produced during cold weather conditions by water or steam injection; however, the requirement for water or steam injection may be elimi- nated when ice fog is deemed a traffic hazard. In addition, water vapor can be added to the air from the cooling tower. The formation of these plumes will be eliminated, however, by the use of a wet/dry cooling tower system. No offsite local climatic effects of system operation will be detectable. The assessment of impacts of this facility on broad-scale concerns, such as acid precipitation and CO, buildup, are not required from a regulatory viewpoint at this time, and such impacts may be deemed "not detectable." As with other combustion-based technologies, operation of a natural gas- fired combined-cycle plant will release carbon dioxide to the atmosphere. Increasing concern has been expressed regarding long-term effects of the increase in atmospheric CO, apparently resulting from combustion of fossil fuels. Of particular concern is the potential "greenhouse" effect of increased ‘atmospheric co, concentration. No feasible measures are currently available for control of CO, production other than possible regulation of the global amounts of fossil fuels burned. No controls on CO, production, however, currently exist. 5.3 AQUATIC AND MARINE ECOSYSTEM EFFECTS Potential impacts from water withdrawal and effluent discharge will be lowest on a per-megawatt basis for a combined-cycle plant in comparison with conventional steam electric plants. Proper design and location of the plant's intake and discharge structures should sufficiently mitigate any major adverse Died) effects. Attainment of regulatory requirements on plant discharges through properly engineered systems will mitigate any potential effects. 5.4 TERRESTRIAL ECOSYSTEM EFFECTS The greatest impact resulting from natural gas-fired combined-cycle power plants on the terrestrial biota is the loss of habitat due to human distur- bance. The amount of land required is generally small, approximately 2 to 6 acres for a 200-MW plant, although a much larger area may be required for road access and transmission and pipeline corridors (see Table 5.1). Signifi- cant populations of moose, caribou, black bear and waterfowl are located in the Cook Inlet area. Therefore, siting studies for the actual plant location and for road, gas pipeline, and transmission corridors should be performed to minimize impacts to these species. A carefully selected site should not significantly impact these populations. Some potential exists for the disturbance of the flora and fauna due to cooling tower drift emissions. Proper drift control devices should suffi- ciently mitigate this impact. 5.5 SOCIOECONOMIC EFFECTS Many of the communities located near the Cook Inlet region are small in population and have an infrastructure that is not highly developed. In light of this, the construction and operation of a 200-MW natural gas-fired combined- cycle plant has a high potential to impact these local communities and cause a boom/bust cycle. These impacts can be lessened by siting a combined-cycle plant near a community with a population greater than 500, or by siting in a location remote from any existing population center. While a construction camp will mitigate this impact to some degree, disruption of the area's infra— structure must be anticipated if the facility is located near one of the smaller communities, such as Tyonek. Since combined-cycle is a capital-intensive technology, the largest por- tion of expenditures outside the region will be attributed to equipment. Approximately 70 percent of the project capital expenditures will be spent in 5.4 the lower 48 states, while 30 percent will be spent within the Railbelt. The allocation of operating and maintenance expenditures spent outside the Railbelt will be approximately 16 percent. All fuel will be obtained from Railbelt sources. oE9 6.0 INSTITUTIONAL CONSIDERATIONS This section presents an inventory of major federal, state of Alaska, and local environmental regulatory requirements that will be associated with the development of a 200-MW natural gas-fired combined-cycle power plant in the Beluga area of Cook Inlet. The inventory is divided into three sections, set- ting forth federal, state and local environmental licensing requirements. Federal requirements are summarized in Table 6.1; and state requirements in Table 6.2. The discussion is limited to the major environmental regulatory require- ments. The identification of more specific requirements can be accomplished only after detailed studies regarding project design and location are avail- able. These requirements could be important in Alaska where much of the land is owned by the federal or state government. 6.1 FEDERAL REQUIREMENTS 6.1.1 Air Air pollution controls are placed on new fuel-burning power plants through the provisions of the Clean Air Act (CAA). The CAA is implemented primarily through permitting programs that would ensure compliance with national ambient air quality standards (NAAQS) and that would prevent significant deterioration in areas where NAAQS are being met. To obtain a permit, a power plant may be required to restrict emissions in accordance with new source performance standards (NSPS), national emission standards for hazardous air pollutants (NESHAP), and other, more constricting programs, such as best available con- trol technology (BACT) and lowest achievable emission rate (LAER). The permitting program and controls to which a power plant will be subject is partially dependent upon its location. Since the general plant location is situated in an area in which air pollution levels are in compliance with NAAQS, the plant will be subject to the prevention of significant deterioration (PSD) permitting program administered by the Environmental Protection Agency (EPA) in accordance with CAA sections 160-169. 6.1 TABLE 6.1. Agency U.S. Environmental Protection Agency U.S. Army Corps of Engineers Federal Aviation Administration National Marine Fisheries Service/Fish and Wildlife Service Advisory Council on Historic Preservation Economic Regula- tory Administration (Dept of Energy) All Federal Agencies Requirement National Pollutant Discharge Elimination System Prevention of Signifi- cant Deterioration Hazardous Waste Man- agement Facility Operation Permit Environmental Impact Statement Construction Activity in Navigable Water Discharge of Dredged Fill Material Air Navigation Approval Threatened or Endangered Species Review Determination that Site is not Archeologically Significant Determination that Site does not In- fringe on federal Tandmarks Exemption from Pro- hibition of Use of Natural Gas Executive Order No. 11990 Executive Order No. 11988 6.2 Federal Regulatory Requirements Scope Discharges to Water Air Emissions Hazardous Waste All Impacts Construction in Water Discharges to Water Air Space for Transmission Lines Air, Water, Land Land Use Land Use Fuel Use Development in Wetlands Development in Floodplains Statute or Authority — 33 USC 1251 et seqg.; section 1342 42 USC 7401 et seg.; section 7475 42 USC 6901 et seq.; section 6925 42 USC 4332; section 102 33 USC 401 et seq.; section 403 33 USC 1251 et seq.; section 1342 49 USC 1304, 1348, 1354, 1431, 1501 16 USC 1531 et seq. 16 USC 402 aa et seq. 16 USC 416 et seq. 42 USC 8301 et seq.; section 201, 212 Agency Alaska Department of Environmental Conservation Alaska Department of Natural Resources Alaska Office of the Governor Alaska Department of Fish and Game TABLE 6.2. Requirement State Certification that Discharges Comply with CWA and State Water Quality Requirements Air Quality Control Permit to Operate Solid Waste Management Facility Operation Water Rights Permit Coastal Use Permit Anadromous Fish Protection Permit Critical Habitat Permit State Regulatory Requirements Scope Discharges to Water Air Emissions Solid Waste Appropriation of Water Land Use Fish Protection Fish and Game Protection Statute or Authority 33 USC 1251 et seq.; section 1341 Alaska Statute 46.03.140 Alaska Statute 46.03.100 Alaska Statute 46.15.030-185 Alaska Statute 46.40 Alaska Statute 16.05.870 Alaska Statute 16.20.220 and .260 Currently, EPA retains authority to issue this PSD permit in the state of Alaska, although the state is now in the process of developing its own PSD permitting program which, when finalized, will transfer to the state this permitting authority. permits based on rules found in 40 CFR 32.21. Until that time, EPA will continue to issue these Under these rules, major sources of pollution cannot begin construction until a PSD permit has been issued. A combined-cycle power plant is consid- ered a major source if it has the potential to emit at least 250 tons per year 6.3 of any air pollutant after controls have been applied. To obtain a PSD per- mit, an applicant must demonstrate that the source or modification will comply with the NAAQS, the NSPS, BACT, the NESHAP, and PSD increments. In addition, the applicant must conduct analyses relative to the effects of the source on soils, vegetation, visibility and area growth. PSD increments are specified maximum allowable increases in the ambient concentrations of SO, and particulate matter. Since gas-fired turbines emit essentially none of these two pollutants, the major concern relative to compli- ance with air quality standards are the New Source Performance Standards and the ambient air quality standards for NO. Prevention-of-significant-deterioration regulations are based on classi- fication of regions with respect to existing air quality. Class I areas are essentially pristine areas and receive greatest protection under the Clean Air Act. Class I areas in Alaska include the Denali National Park and the Tuxedni Wildlife Refuge. If the plant is located within 10 km of a Class I area, additional pollution controls must be applied. Under rules promulgated on December 2, 1980 (45 FR 80084), new sources that require PSD permits may be required to conduct additional studies to determine the source's effects upon the visibility in the Class I area. Note that Clean Air Act section 165 requires that PSD permits be denied for sources that would cause adverse air impacts on Class I areas. 6.1.2 Water The preservation of the quality of the surface waters of the United States is accomplished in accordance with the Clean Water Act (CWA). There are two major regulatory programs mandated by this act with which a power plant incor- porating a steam cycle must comply. Controls will be imposed upon the discharge of pollutants by the power plant through the National Pollutant Discharge Elimination System (NPDES) per- mit. This permit is issued by the EPA pursuant to CWA section 402, and regula- tions for its issuance are found in 40 CFR 122. Application for an NPDES permit for a new source will trigger the environmental review requirements of the National Environmental Policy Act (NEPA). Because the discharge cannot 6.4 take place without a permit being issued, an application must be filed at least 180 days before the discharge is scheduled to commence. The EPA generally establishes effluent limitations for pollutant dis- charges on an industry-by-industry basis. Specific effluent limitations for natural gas-fired combined-cycle power plants have not, however, been issued. In cases such as this, the EPA generally applies the limitations from an industry that closely resembles the process in question. In light of this procedure, it can be expected that the effluent limitations for the steam electric generating station point source category will be applied to similar waste streams occurring at a combined-cycle power plant. These waste streams would include cooling tower blowdown, boiler blowdown, metal cleaning waste- waters and. low-volume waste discharges, such as demineralizer regeneration wastewater and floor drainage. Pursuant to Section 404 of the CWA, a permit must be obtained from the U.S. Army Corps of Engineers (Corps) to discharge dredged or fill material into waters of the United States. A natural gas-fired combined-cycle power plant may need a Section 404 permit for construction of water intake or out- fall structures, loading or unloading facilities and transmission lines. With respect to the same activities, a power plant may also be required to obtain a permit under Section 10 of the Rivers and Harbors Act of 1899 for the placement of structures or the conduct of work in or affecting navigable waters of the United States. This permit is also issued by the Corps using the same application forms and processing procedures as that required for the Section 404 permit. The processing of either of these permits can take 6 months or more, ana requires that an environmental impact statement (EIS) be prepared according to the requirements of NEPA. 6.1.3 Solid Waste The Resource Conservation and Recovery Act (RCRA), as amended in 1980, imposes controls upon the handling of solid waste in the United States. It should be realized that the definition of solid waste is very broad and includes all materials that are solid, semi-solid, liquid, or contained gases with a number of notable exceptions. At present, the major emphasis has been 6.5 placed upon the control of hazardous solid waste. A formal hazardous waste management program is currently being administered by the EPA. The program sets forth identification and handling requirements for sources of hazardous waste; marking and manifesting requirements for transporters of hazardous waste; and a permitting program for hazardous waste treatment, storage and disposal facilities. Natural gas-fired combined-cycle power plant waste that may be hazardous includes water treatment wastes, boiler blowdown, boiler cleaning wastes, cool- ing tower blowdown, floor drainage wastes, and sanitary and laboratory wastes. Accordingly, the owners and operators of the power plant may have to comply with the standards applicable to generators and transporters of hazardous waste, and may also be required to obtain an RCRA permit from the EPA to oper- ate a hazardous waste treatment, storage or disposal facility. The RCRA permit need only be obtained from the EPA if hazardous waste in amounts exceeding 1000 kg/month will be treated, stored or disposed of on the plant site. If the waste is transported offsite for disposal in a licensed facility (such as a municipal dump), a permit need not be obtained. Further- more, certain types of facilities, such as neutralization tanks, transport vehicles, vessels or containers used for neutralization of wastes that are hazardous only due to corrosivity (40 CFR 264.1(g)), have been excluded from RCRA permit requirements. (This exclusion does not apply to surface impoundments. ) If an RCRA permit for operation of a hazardous waste treatment, storage or disposal facility is necessary, it must be obtained before construction of the hazardous waste management facilities can be commenced. EPA only recently began accepting applications for RCRA permits from new treatment, storage and disposal facilities. Although no such permits have been issued yet, EPA anticipates the processing of RCRA permits to take at least 1 year. 6.1.4 Power Plant and Industrial Fuels Use Act A new natural gas-fired combined-cycle facility will be subject to the provisions of the Power Plant and Industrial Fuels Use Act of 1978 (FUA). Pursuant to Section 201 of the FUA, natural gas may not be used as a primary energy source in a new electric power plant unless special permission is 6.6 obtained. Such permission is granted by the Economic Regulatory Administra- tion (ERA) within the Department of Energy (DOE) in the form of an exemption from the FUA prohibition of the use of natural gas. Thirteen conditions are set forth in the FUA, any one of which is a potential basis for an exemption. The conditions are as follows (10 CFR 503 .30-503.43): 503.31 - An alternative fuel supply to natural gas or petroleum would not be available within the first 10 years of plant life. 503.32 - An alternative fuel supply is available only at a cost that substantially exceeds the cost of using imported petroleum. 503.33 - Site limitations are present that would impede the use of alternative fuels to natural gas or petroleum. Qualifying site limi- tations include: a) physical inaccessibility of alternate fuels; b) unavailability of transportation facilities for alternate fuels; c) unavailability of land or facilities for storing or handling alternate fuels; and d) unavailability of land for controlling and disposing of wastes resulting from use of alternate fuels. 503.34 - Inability to comply with applicable environmental require- ments except by use of petroleum or natural gas. 503.35 - Inability to obtain adequate capital for plant construction except by use of petroleum or natural gas. 503.36 - State or local requirements (except for building codes, nui- sance or zoning laws) rendering use of alternate fuels infeasible. 503.37 - Use of cogeneration, where electricity would constitute more than 10 percent and less than 90 percent of the useful energy output of the facility. 503.38 - Use of mixtures of natural gas or petroleum and alternate fuels. 503.39 - Use of the plant for emergency purposes only. 6.7 503.40 - Need for the plant to maintain reliability of service due to timing considerations. 503.41 - Use of the plant for peakload purposes (not greater than 1500 equivalent full-power hours per year). 503.42 - Use of the plant for intermediate-load purposes (not greater than 3500 equivalent full-power hours at a heat rate of 9500 Btu/kWh or less). This exemption applicable to petroleum-fired units only. 503.43 - Use of the plant to meet scheduled outages (less than or equal to 28 days per year on average over 3-year periods). It appears unlikely that an exemption for the proposed facility could presently be justified on any of the conditions cited above. However, two approaches to obtaining exemptions for the proposed plant appear to exist. One would be to construct the proposed plant as a cogeneration facility. To meet the requirements of a cogeneration facility, as defined in the PUA, would require more than 10 percent of the energy production of the plant be usefully applied in nonelectrical form. One possibility would be a district heating application. Use of plant heat for district heating would likely qualify the plant for cogeneration exemption under the provision, allowing such an exemption to be obtained for “technically innovative" applications (10 CFR Part 503.37(a)(2)). A plant site much closer to a population center such as Anchorage would be required to develop a cost-effective district heating system. A second possibility for obtaining an exemption to the FUA would be for the State to find it in the public interest to generate electricity by use of natural gas and to establish statutory provisions encouraging the use of this fuel. Such legislation may allow exemptions to be obtained for natural gas- fired power plants under the provisions of 10 CFR Part 503.36. 6.1.5 Other Federal Requirements In reviewing federal environmental requirements to which a natural gas- fired combined-cycle power plant may be subject, it is necessary to consider 6.8 certain additional regulatory programs. Although these programs may not include permitting requirements, they contain certain requirements that can affect location and/or construction of a power plant. These requirements are summarized in Table 6.1; a discussion of each is presented in Ebasco Services Incorporated (1982). 6.2 STATE REQUIREMENTS To a large degree, the state requirements parallel and complement the federal requirements. They are summarized in Table 6.2. 6.3 LOCAL REQUIREMENTS The Cook Inlet Region is controlled by some of the most sophisticated local requirements in the entire state of Alaska. This is largely due to its proximity to Anchorage, one of the major population centers in the state. As a result, the proposed plant will most likely be subject to rather detailed requirements on a local level. The plant will likely be sited in either the Matanuska-Susitna Borough or the Kenai Peninsula Borough. The Matanuska-Susitna Borough is a second-class borough with powers of land use planning, platting and zoning with which devel- opment can be controlled. The Borough has acquired areawide powers for the regulation of ports and ambulances, and also controls education and the assess- ment and collection of taxes within its borders. The Kenai Peninsula Borough has areawide powers of platting and zoning and can control local land use. Plans to develop land in the Borough must be approved by the local zoning board which can regulate land use, building location and size, the size of open spaces and population distribution. In addition, the Kenai Peninsula Borough has a solid waste disposal program and an air pollution control program with which the proposed power plant may be required to comply. Those programs do not have permit provisions, but they do require that the plans for a proposed facility be approved by the Borough prior to construction. 6.9 6.4 LICENSING SCHEDULE It is expected that the licensing of the proposed plant would be com pleted in approximately 36 months from the time a specific site is chosen. However, two items of special concern should be recognized in reviewing the licensing schedule. First, the exemption to the Fuels Use Act granted by the DOE for the use of natural gas as a fuel in a new electric power plant requires submission of a complete application, and approval of that application. Completion of the application could take as long as 2 years, after which approval can be expected in up to 6 months. Accordingly, this exemption may be obtained within the 36-month schedule. Second, receipt of a permit to operate a hazardous waste treatment, stor- age or disposal facility as required by RCRA section 3005 may be slightly more complicated for a natural gas-burning facility than it is for coal-fired plant. The EPA has determined in a letter dated January 13, 1981, that, at least tem porarily, hazardous wastes produced in conjunction with the combustion of coal can be treated or disposed of in combination with high-volume coal combustion wastes without complying with the requirements of EPA's hazardous waste manage- ment program, (2) The exemption from compliance with the hazardous waste Management program was not extended by EPA to wastes produced in conjunction with a natural gas-fired combined-cycle power plant. The owners and operators of this type of facility should recognize, therefore, that they are more likely to be subject to the RCRA hazardous waste management program than the owners and operators of a coal-fired plant, who may treat and dispose of low- volume hazardous wastes in combination with high-volume coal combustion wastes and thereby avoid EPA's hazardous waste management program. Receipt of a RCRA permit was, however, included in the 36-month estimated schedule for a natural gas-fired plant. For a detailed discussion of the probable licensing sched- ule, consult Section 6, Institutional Considerations, of the Ebasco Services Incorporated (1982). (a) Letter from Gary N. Dietrich, Associate Deputy Administrator for Solid Waste, to Paul Emler, Jr. Chairman, Utility Solid Waste Activities Group. 6.10 In Table 6.1, the requirement that an EIS be prepared as per the require- ments of the National Environmental Policy Act of 1969 (NEPA) has been listed as a responsibility of the Army Corps of Engineers (Corps), even though more than one federal agency will impose regulatory requirements upon the project. As discussed in Ebasco Services Incorporated (1982), the lead agency is ulti- mately determined through negotiation between eligible agencies and the proj- ect owner. The final determination is usually based upon an examination of the following criteria: magnitude of agency's involvement, project approval/ disapproval authority; expertise concerning the action's environmental effects; duration of the agency's involvement; and timing of the agency's involvement. Due to its involvement in the issuance of the dredge and fill permit and the permit for construction in navigable waterways, the Corps is generally selected as the lead agency for an EIS regarding a steam-electric power plant. 6.11 7.0 REFERENCES Alaska 011 and Gas Conservation Commission, 1980. Stastical Report. State of Alaska, Alaska 011 and Gas Conservation Commission, Anchorage, Alaska. Battelle, Pacific Northwest Laboratories. 1982. Railbelt Electric Power Alternatives Study: Fossil Fuel Availability and Price Forecasts. Battelle, Pacific Northwest Laboratories, Richland, Washington. Commonwealth Associates, Inc. 1981. Feasibility Study of Electrical Intercon- nection Between Anchorage and Fairbanks. Engineering Report R-2274, Alaska Power Authority, Anchorage, aska. Ebasco Services Incorporated. 1982. Coal-Fired SteamElectric Power Plant Alternative for the Railbelt Region. Office of the Governor, State of Alaska, Anchorage, Alaska. Electric Power Research Institute. 1979. Technical Assessment of Guide EPRI-PS-1201-SR. Electric Power Research Institute, Palo Alto, California. deal