HomeMy WebLinkAboutAPA567Candidate Electric Energy
Technologies for Future
Application in the Railbelt
Region of Alaska
Volume IV
October 1982
Prepared for the Office of the Governor
State of Alaska
Division of Policy Developm~nt and Planning
and the Governor's Policy Review Committee
under Contract 2311204417
()Battelle
Pacific Northwest Laboratories
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CANDIDATE ELECTRIC ENERGY TECHNOLOGIES
FOR FUTURE APPLICATION IN THE RAILBELT
REGION OF ALASKA
Volume IV
J. c. King R. A. Zylman( a) w. H. Swift J. A. Barkshire(b)
R. L. Aaberg R. D. Eggemeyer(b)
R. s. Schnorr (a) J. R. Rich a)d son (b) s. 0. Simmons(a) c. R. Roy(b
J. E. Butts(a) c. H. Kerr(c)
E. s. Cunning~a~(a) M. A. Newe 11 (d)
R. A. Koelsch a
October 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
(a) Ebasco Services, Incorporated, Bellevue, WA.
(b) Alaska Renewable Energy Associates, Anchorage, AK.
(c) Reid, Call ins, Inc., Vancouver, B.C.
(d) Wind Systems Engineering, Inc., Anchorage, AK.
LTBRARY
1.0 INTRODUCTION
2.0 BACKGROUND.
CONTENTS
2.1 OVERVIEW OF RAILBELT GEOGRAPHIC AND
SOCIOECONOMIC CHARACTERISTICS .
2.2 ELECTRIC GENERATING CAPACITY
2.3 LOAD CHARACTERISTICS OF THE RAILBELT REGION
2.3.1 Seasonal Peak Load
2.3.2 Load Duration Curve
2.3.3 Projected Load Growth
3.0 SELECTION OF CANDIDATE ELECTRIC ENERGY TECHNOLOGIES
4.0 BASELOAD TECHNOLOGIES
4.1 COAL-FIRED STEAM-ELECTRIC GENERATION
4.1.1 Technical Characteristics
4.1.2 Siting and Fuel Requirements
4.1.3 Costs
4.1.4 Environmental Considerations
4.1.5 Socioeconomic Considerations
4.1.6 Potential Applications in the Railbelt Region
1.1
2.1
2.1
2.7
2.7
2.12
2.14
2.14
3.1
4.1
4.7
4.7
4.15
4.16
4.17
4.19
4.20
4.2 NATURAL GAS AND DISTILLATE-FIRED STEAM-ELECTRIC GENERATION 4.22
4.2.1 Technical Characteristics
4.2.2 Siting and Fuel Requirements
4.2.3 Costs
4.2.4 Environmental Considerations
4.2.5 Socioeconomic Considerations
4.2.6 Potential Applications in the Railbelt Region
i i i
4.22
4.24
4.25
4.25
4.26
4.28
4.3 BIOMASS-FIRED STEAM-ELECTRIC GENERATION .
4.3.1 Technical Characteristics
4.3.2 Siting and Fuel Requirements
4.3.3 Costs
4.3.4 Environmental Considerations
4.3.5 Socioeconomic Considerations
4.3.6 Potential Applications in the Railbelt Region
4.4 NUCLEAR LIGHT WATER REACTORS
4.4.1 Technical Characteristics
4.4.2 Siting and Fuel Requirements
4.4.3 Costs
4.4.4 Environmental Considerations
4.4.5 Socioeconomic Considerations
4.4.6 Potential Applications in the Railbelt Region
4.5 GEOTHERMAL GENERATION
4.5.1 Technical Characteristics
4.5.2 Siting Requirements
4.5.3 Costs
4.5.4 Environmental Considerations
4.5.5 Socioeconomic Considerations
4.5.6 Potential Applications in the Railbelt Region
4.6 PEAT-BASED STEAM-ELECTRIC GENERATION
4.6.1 Technical Performance
4.6.2 Siting and Fuel Requirements
4.6.3 Costs
4.6.4 Environmental Considerations
iv
4.31
4.31
4.33
4.35
4.35
4.37
4. 37
4.42
4.42
4.45
4.49
4.49
4.51
4.52
4.53
4.53
4. 59
4.60
4.60
4.62
4.63
4.65
4.65
4.73
4.74
4.75
4.6.5 Socioeconomic Considerations
4.6.6 Potential Applications in the Railbelt Region
5.0 CYCLING TECHNOLOGIES
5.1 COMBUSTION TURBINES
5.1.1 Technical Characteristics
5.1.2 Siting and Fuel Requirements
5.1.3 Costs
5.1.4 Environmental Considerations
5.1.5 Socioeconomic Considerations
5.1.6 Potential Application in Railbelt Region
5.2 COMBINED-CYCLE POWER PLANTS
5.2.1 Technical Characteristics
5.2.2 Siting and Fuel Requirements
5.2 .3 Costs
5.2.4 Environmental Considerations
5.2.5 Socioeconomic Considerations
5.2.6 Potential Application in the Railbelt Region
5.3 DIESEL GENERATION
5.3.1 Technical Characteristics
5.3.2 Siting and Fuel Requirements
5.3.3 Costs
5.3.4 Environmental Considerations
5.3.5 Socioeconomic Considerations
5.3.6 Potential Application in the Railbelt Region
5.4 INTERMEDIATE-AND LARGE-SCALE HYDROELECTRIC PLANTS
5.4.1 Technical Characteristics
v
4. 77
4.78
5.1
5.4
5.4
5.6
5.8
5.9
5.11
5.11
5.13
5.13
5.16
5.16
5.17
5.19
5.19
5.21
5.21
5.23
5.23
5.24
5. 25
5.25
5.26
5.26
5o4o2 Siting Requirements 5o33
5 o4 0 3 Costs 5 o34
5o4o4 Environmental Considerations 5o34
5o4o5 Socioeconomic Considerations 5 o38
5o4o6 Potentia 1 Application in the Railbelt Region 5o38
5o5 FUEL CELLS 5o44
5o5o1 Technical Characteristics 5o44
5o5o2 Siting and Fue 1 Requirements 5o49
5o5o3 Costs 5o 50
5o5o4 Env ironmenta 1 Considerations 5o 51
5o5o5 Socioeconomic Considerations 5o 54
5o5o6 Potentia 1 App 1 i cation to the Rail belt Reg ion 5.55
6o0 STORAGE TECHNOLOGIES 6o1
6o1 HYDROELECTRIC PUMPED STORAGE 6o3
6 ol.1 Technical Characteristics 6o3
6 ol.2 Siting and Fuel Requirements 6o6
6 ol.3 Costs 6o8
6ol.4 Env ironmenta 1 Considerations 6o8
6 ol.5 Socioeconomic Considerations 6 o11
6 ol.6 Potential Application to the Railbelt Region 6o11
6o2 STORAGE BATTERIES 6 o15
6o2o1 Technical Characteristics 6o15
6o2o2 Siting and Fue 1 Requirements 6o18
6o2o3 Costs 6o18
6o2o4 Env ironmenta 1 Considerations 6 0 20
6o2o5 Socioeconomic Effects 6o22
vi
6.2.6 Potential Application to the Railbelt Region 6.22
6.3 COMPRESSED AIR ENERGY STORAGE . 6.24
6.3.1 Technical Characteristics 6. 25
6.3.2 Siting and Fuel Requirements 6.28
6.3.3 Costs 6.29
6.3.4 Environmental Considerations 6.30
6.3.5 Socioeconomic Considerations 6.32
6.3.6 Potential Application to the Railbelt Region 6.32
6.4 OTHER ENERGY STORAGE TECHNOLOGIES 6 .34
7.0 FUEL-SAVER TECHNOLOGIES 7.1
7.1 COGENERATION 7.4
7 .1.1 Technical Characteristics 7.4
7 .1.2 Siting and Fuel Requirements 7 .10
7.1.3 Costs 7.10
7 .1.4 Environmental Considerations 7.11
7 .1. 5 Socioeconomic Considerations 7.13
7 .1. 6 Potential Application in the Railbelt Region 7.14
7.2 TIDAL POWER 7.17
7 . 2 .1 Technical Characteristics 7.18
7.2.2 Siting Requirements 7.21
7 .2.3 Costs 7. 21
7.2.4 Environmental Considerations 7.22
7.2.5 Socioeconomic Considerations 7. 26
7.2.6 Potential Application in the Railbelt Region 7.27
7.3 LARGE WIND ENERGY CONVERSION SYSTEMS 7.30
7.3.1 Technical Characteristics 7.30
vii
7.3.2 Siting Requirements 7.35
7 .3.3 Costs 7. 35
7.3.4 Environmental Considerations 7.36
7.3.5 Socioeconomic Considerations 7.38
7.3.6 Potential Application in the Rail belt Region 7.39
7.4 SMALL HIND ENERGY CONVERSION SYSTEMS 7.44
7.4.1 Technical Characteristics 7.44
7 .4.2 Siting Requirements 7.48
7.4 .3 Costs 7.49
7.4.4 Env i ronmenta 1 Considerations 7.50
7.4. 5 Socioeconomic Considerations 7.50
7.4.6 Potential Application in the Rail belt Region 7.51
7.5 SOLAR PHOTOVOLTAIC SYSTEMS 7.56
7.5.1 Techn i ca 1 Characteristics 7.56
7.5.2 Siting Requirements 7.59
7.5.3 Costs 7.59
7.5.4 Env ironmen ta 1 Considerations 7.60
7.5.5 Socioeconomic Considerations 7.61
7.5.6 Potential Application in the Railbelt Region 7.61
7.6 SOLAR THERMAL ELECTRIC SYSTEMS 7.64
7.6.1 Technical Characteristics 7.64
7.6.2 Siting Requirements 7. 66
7.6.3 Costs 7.66
7.6.4 E nv i ronmen ta 1 Considerations 7.67
7.6.5 Socioeconomic Considerations 7.68
7.6.6 Potential Application in the Ra i lbe lt Region 7.68
viii
7.7 SMALL-SCALE HYDROELECTRIC AND MICROHYDROELECTRIC POWER PLANTS 7.70
7.7.1 Technical Characteristics 7.70
7.7.2 Siting Requirements 7.74
7.7.3 Costs 7.75
7.7.4 Environmental Considerations 7.76
7.7.5 Socioeconomic Considerations 7.77
7.7.6 Potential Application in the Railbelt Region 7.78
8.0 LOAD MANAGEMENT 8.1
8.1 LOAD MANAGEMENT TECHNIQUES 8.1
8.1.1 Direct Load Control 8.1
8.1.2 Passive Controls
8.1.3 Incentive Pricing of Electricity
8.1.4 Education and Public Participation
8.1.5 Thermal Storage
8.2 LOAD MANAGEMENT APPLICATIONS .
8.3 COST EFFECTIVENESS OF LOAD MANAGEMENT ALTERNATIVES
8.3.1 Costs
8.3.2 Benefits
8.5
8.6
8.8
8.9
8.12
8.12
8.12
8.13
8.3.3 Timing 8.13
8.4 INSTITUTIONAL, REGULATORY, AND ENVIRONMENTAL CONSIDERATIONS 8.13
8.5 POTENTIAL APPLICATION IN THE RAILBELT REGION 8.17
9.0 ELECTRIC ENERGY CONSERVATION IN BUILDINGS 9.1
9.1 CONSERVATION MEASURES 9.1
9.1.1 Insulation 9.2
9.1.2 Sealing . 9.7
9.1.3 Vapor Barriers 9.8
ix
9.1.4 Space Heating and Hot Water System Efficiency 9.9
9.1.5 Retrofitting 9.10
9.2 PERFORMANCE CHARACTERISTICS
9.2.1 Efficiency
9.2.2 Coincidence to Load .
9.2.3 Adaptability to Growth
9.2.4 Type of Load Serviced
9 .3 COSTS
9.4 ENVIRONMENTAL IMPACTS .
9.5 SOCIOECONOMIC IMPACTS .
9.6 POTENTIAL APPLICATION IN THE RAILBELT REGION
10.0 ELECTRIC ENERGY SUBSTITUTES .
10.1 PASSIVE SOLAR SPACE HEATING .
10.2
10.1.1 Passive Types of Solar Systems
10.1.2 Technical Characteristics
10.1.3 Siting Considerations
10.1.4 Costs
10.1.5 Environmental Impacts
10.1.6 Socioeconomic Impacts
10.1.7 Potential Application to the Railbelt Region
ACTIVE SOLAR SPACE AND HOT WATER HEATING
10.2.1 Types of Active Solar Systems
10.2.2 Technical Characteristics
10.2.3 Siting Considerations
10.2.4 Costs
10.2.5 Env ironmen ta 1 Impacts
10.2.6 Socioeconomic Imp acts
X
9.11
9.11
9.13
9.13
9.13
9.14
9.15
9.15
9.16
10.1
10.1
10.3
10.7
10.14
10.18
10.21
10.23
10.25
10.28
10.29
10.33
10.35
10.36
10.37
10.38
10.2.7 Application to Railbelt Energy Demand
10.3 WOOD FUEL FOR SPACE HEATING .
10.3.1 Technical Characteristics
10.3.2 Fuel Requirements
10.3.3 Costs
10.3.4 Environmental Considerations
10.3.5 Socioeconomic Considerations
10.3.6 Potential Application to the Railbelt Region
REFERENCES .
APPENDIX A -ELECTRIC ENERGY TECHNOLOGIES NOT SHOWING PROMISE
FOR APPLICATION TO THE RAILBELT REGION
APPENDIX B -FUEL AVAILABILITY AND PRICES
APPENDIX C -COST ESTIMATING METHODOLOGY
APPENDIX D -WATER RESOURCE IMPACTS FROM STEAM-CYCLE POWER PLANTS
APPENDIX E -AIR EMISSIONS FROM FUEL COMBUSTION POWER PLANTS
APPENDIX F -AQUATIC ECOLOGY IMPACTS FROM STEAM-CYCLE POWER PLANTS
APPENDIX G -TERRESTRIAL ECOLOGY IMPACTS FROM STEAM-CYCLE
POWER PLANTS
APPENDIX H -SOCIOECONOMIC IMPACTS FROM ENERGY DEVELOPMENT
IN THE RAILBELT REGION
APPENDIX I -WASTE HEAT REJECTION SYSTEMS
APPENDIX J -AESTHETIC CONSIDERATIONS
APPENDIX K -SYNTHETIC FUEL TECHNOLOGIES
APPENDIX L -PERFORMANCE OF PASSIVE SOLAR OPTIONS
APPENDIX M -PERFORMANCE OF ACTIVE SOLAR WATER HEATING SYSTEMS
IN FAIRBANKS
APPENDIX N -POWERPLANT AND INDUSTRIAL FUELS USE ACT
APPENDICES REFERENCES
xi
10.39
10.41
10.41
10.45
10.47
10.49
10.51
10.56
R.1
A .1
B.1
C.1
D.1
E.1
F.1
G.1
H.1
1.1
J.1
K.1
L.1
M.1
N.1
Ref. A.1
FIGURES
2.1 Alaska Railbelt Region
2.2 Alaska National Interest Lands
2.3 Existing and Proposed Transmission Systems,
2.4 AML&P Load Duration Curve -1975
4.1 Typical, Combustion-Fired, Steam-Electric System
4.2 Coal Resources, Alaska Railbelt Region
4.3 Coal-Fired Power Plant Components .
4.4 Natural Gas and Petroleum Supplies in the Railbelt Region
4.5 Major Concentrations and Capacities of Sawmills in the
Railbelt Region
4.6 PWR Steam-Electric Plant
4.7 Faults and Seismic Areas in the Railbelt Region
4.8 Geothermal Resources in the Railbelt Region .
4.9 Binary Cycle Geothermal Power Plant
4.10 Peat Resources of the Railbelt Area
4.11 Power Production Alternatives Using Peat
4.12 Fuel System of a Peat-Fired Boiler
4.13 Peat Gasification Flow Sheet .
5.1 Simple-Cycle Combustion Turbine
5.2 Combined-Cycle Power Plant
5.3 A Typical Hydropower Installation .
5.4 Potential Hydroelectric Resources .
5.5 Typical Fuel Cell Plant .
6.1 Schematic of a Pumped Storage Hydro Plant
6.2 100-MWh, Zinc-Chloride, Load-Leveling Battery Plant
xiii
2.3
2.5
2.9
2.15
4.2
4.4
4.9
4.29
4.39
4.43
4.47
4.54
4.57
4.66
4.68
4.71
4.73
5.5
5.14
5.30
5.42
5.45
6.4
6.16
6.3 Schematic for the Turbomachinery in a Conventional CAES Plant 6.26
6.4 Component Plan for a Hard-Rock CAES Plant 6.28
7.1 Simplified Schematic of Steam Turbine Topping Cycle 7.6
7.2 Simplified Schematic of Combustion Turbine Topping Cycle
Producing Process Steam 7.7
7.3 Simplified Schematic of a Bottoming Cycle 7.9
7.4 Petroleum Refining in the Railbelt Area 7.15
7.5 A Typical Tidal Power Plant 7.19
7.6 Types of Turbine/Generator Sets for a Tidal Power Plant 7.22
7.7 Tidal Sites Selected for Further Study. 7.29
7.8 MOD-2 Wind Turbine Generator . 7.32
7.9 Vertical Axis Wind Turbine 7.33
7.10 Power Profile of the MOD-2 Wind Machine
7.11 Wind Power Density of the Railbelt Region
7.12 Alternative SWECS Configurations
7.13 A Typical Horizontal Axis Small Wind Machine
7.14 The Effect of Local Terrain on Wind Machine Performance
7.34
7.40
7.45
7.46
7.48
7.15 Example of Increase in Energy Available with Increased Tower Height 7.49
7.16 Potential Wind Resources for SWECS Development in the Railbelt Area 7.52
7.17 Solar Insolation for Selected Railbelt Locations
7.18 Turbine Operating Range .
7.62
7.72
7.19 Turbine Cross Sections 7.73
9.1 Energy-Conserving Wall Systems 9.4
9.2 Energy-Conserving Roof 9.6
10.1 Passive Solar Systems Appropriate for Alaska 10.4
10.2 Solar Gain Versus Heat Loss with Various Levels of Window Glazing
and Directional Orientation in Anchorage, Alaska . 10.9
xiv
10.3 Solar Shading Effects in the Railbelt
10.4 An Example Building Incorporating Passive Solar Design
10.5 A Typical, Liquid-Based, Flat-Plate Collector
10.6 Typical Active Solar Space Heating System
10.7 A Typical Active Solar Domestic Hot Water Heating System
10.8 A Typical Air Solar Collector
A.l Open-Cycle MHO/Steam Power Plant
A.2 Seawater Power Plant Using Ocean Thermal Difference
A.4 A Water Column/Turbine System
B.1 Projected Fuel Prices to Railbelt Utilities,
1982 $/MMBtu, 1980-2010 .
B.2 Natural Gas and Petroleum Resources in the Railbelt Region
B.3 Coal Resources of the Railbelt Region
B.4 Peat Resources in the Railbelt Region
!.1 Typical Recirculating Waste Heat Rejection System
!.2 A Natural Draft Cooling Tower
!.3 Mechanical-Draft Wet Cooling Tower
!.4 Mechanical Draft Wet-Dry Cooling Tower.
K.1 Flowsheet of Medium Btu Gas Plant
K.2 Methanol Production Flowsheet .
K.3 Fischer-Tropsch Synthesis Flowsheet
K.4 Solvent Extraction Process Flowsheet
K.5 Catalytic Hydrogenation Flowsheet .
XV
10.17
10.22
10.29
10.30
10.32
10.33
A.3
A .10
A.12
B.3
B.4
B.6
B.9
!.2
!.5
!.7
!.10
K.5
K.7
K.7
K.8
K.9
TABLES
2.1 Total Generating Capacity: Railbelt Utilities
2.2 Generating Capacity: Nonutility Railbelt Installations
2.11
2.12
2.3 Monthly Residential Electricity Consumption for 1979 2.13
2.4 Yearly Estimated Load Growth for the Railbelt Region 2.16
3.1 Candidate Electric Energy Alternatives . 3.3
4.1 Comparison of Baseload Technologies on Selected Characteristics 4.5
4.2 Typical Land Requirements for Coal-Fired
Steam-Electric Power Plants 4.16
4.3 Fuel Consumption for Coal-Fired Steam-Electric Plants 4.16
4.4 Estimated Costs of Coal-Fired Steam-Electric Plants 4.17
4.5 Typical Full-Load Fuel Consumption for Natural Gas and
Distillate Steam-Electric Plants 4.24
4.6 Estimated Cost for Gas-and Distillate-Fired
Steam-Electric Plants 4.25
4.7 Wood Waste Requirements by Plant Size 4.34
4.8 Estimated Costs for Biomass-Fired Steam-Electric Plants 4.35
4.9 Fuel Availability for Wood 4.38
4.10 Estimated Refuse-Derived Fuel Production 4.41
4.11 Estimated Costs for Nuclear Power Plants 4.49
4.12 Estimated Costs for Hot Dry Rock Geothermal Developments 4.60
4.13 Estimated Costs for Peat-Fired Steam-Electric Power Plants . 4.74
5.1 Comparison of Cycling Technologies on Selected Characteristics 5.2
5.2 Heat Rates of Combustion Turbines . 5.6
5.3 Estimated Costs for Combustion Turbine Power Plants 5.9
5.4 Heat Rates of Combined-Cycle Plants 5.15
5.5 Estimated Costs for Combined-Cycle Facility. 5.17
XV i i
5.6 Fuel Consumption Rates and Equivalent Heat Rates for a
Diesel Generator Operating at Various Loads . 5.22
5.7 Estimated Costs for Diesel Electric Generation 5.24
5.8 Technically Feasible Hydroelectric Sites in the Railbelt Region 5.28
5.9 Summary of More Favorable Potential Intermediate and Large-
Scale Hydroelectric Sites in the Railbelt Region . 5.40
5.10 Estimated Heat Rates of Fuel Cell Plants 5.48
5.11 Estimated Costs for Fuel Cell Plants 5.52
6.1 Comparison of Storage Technologies on Selected Characteristics 6.2
6.2 Estimated Costs of Hydroelectric Pumped-Storage Plants 6.9
6.3 Performance of Advanced Electrochemical Storage Batteries 6.19
6.4 Estimated Costs of Advanced Battery Storage Systems,
10-MWe Storage with 5 Hours of Capacity 6.21
6.5 Estimated Costs of a Hard Rock CAES Plant 6.30
7.1 Comparison of Fuel-Saver Technologies on S~lected Characteristics 7.2
7.2 Representative Capital Costs for Selected Cogeneration Cycles 7.11
7.3 Estimated Costs of a Representative, Natural Gas-Fired
Steam Turbine Topping Cogeneration Cycle 7.12
7.4 Representative Cost Estimates for Tidal Power Plants . 7.23
7.5 Estimated Costs for Large Wind Energy Conversion Systems 7.36
7.6 Wind Power Density Classes 7.41
7.7 Estimated Costs of SWECS 7.49
7.8 Estimated Small Wind Energy Conversion Systems
Development Potential, by Load Center 7.55
7.9 Estimated Costs for Solar Photovoltaic Systems 7.60
7.10 Estimated Costs for Solar Thermal Systems 7.67
7.11 Cost Summary for Grid-Connected Small Hydro and Microhydro Plants 7.75
7.12 Technically Feasible Small-Scale Hydroelectric Sites in the
Railbelt Region 7.79
xviii
7.13 Summary of More Favorable Small-Scale Hydroelectric Sites in the
Railbelt Region 7.80
7.14 Estimated Microhydroelectric Development Potential, by Load Center 7.82
8.1 Electrical Loads Most Frequently Selected for Direct Load
8.2 Regional Market Penetration for Major Electric Appliances
8.3 Average Daily Electric Consumption by Appliance Per Month
8.4 Load Control Cost Summary
8.5 Thermal Energy Storage Systems Summary of Payback
Period Calculations
9.1 Comparison of Heat Losses for Three Design Variations on a
Representative House
9.2 Comparative Annual Heating Loads and Costs: Retrofit of
Representative House and Alaska-Specific Design
10.1 Comparison of Electric Energy Substitutes on
Selected Characteristics
10.2 Usable Solar Heat for the Main Structure from an Attached
Greenhouse at Anchorage, Alaska
10.3 Simulated Comparative Heating Needs of Home Built to
ASHRAE 90-75 Versus Passive Solar Design
Control 8.2
8.3
8.4
8.14
8.15
9.12
9.12
10.2
10.11
10.12
10.4 Percentage of Radiation Striking a Surface at Given Incident Angles 10.16
10.5 Solar Heating Fractions for Various Railbelt Applications
10.6 Active Solar Cost Analysis for Fairbanks, Alaska .
10.7 Conversion Efficiencies for Wood-Fired Units
10.8 Railbelt Wood Characteristics
10.9 Survey of Railbelt Wood Suppliers .
10.10 Fuel Wood Costs for the Railbelt Area
10.11 Representative Wood Space Heating Costs
10.12 Wood Heat Fire Hazards
10.13 Summary of State Firewood Permits .
10.14 Wood Energy Summary/Railbelt Area
xix
10.26
10.37
10.44
10.45
10.47
10.48
10.49
10.50
10.54
w.~
B.l Fossil Fuel Availability and Price B.2
C.l Alaskan Cost Adjustment Factors C.2
C.2 Premises for Cost Assessment C.8
D.l Estimated Water Requirements Associated with Various
Steam-Cycle Facilities D.3
D.2 Possible Power Plant Water Sources in the Railbelt D.4
D.3 Stream Flow Data for Selected Railbelt Locations . D.5
D.4 Water-Quality Data for Selected Alaskan Rivers D.9
E.l Controlled Sulfur Dioxide Emissions for Various Technologies E.6
E.2 Controlled Particulate Matter Emissions for Various Technologies E.7
E.3 Controlled NOx Emissions for Various Technologies E.S
E.4 National Ambient Air-Quality Standards and Prevention of Signifi-
cant Deterioration Increments for Selected Air Pollutants E.9
F.l Some Commercially and Recreationally Important Aquatic
Species in the Alaska Railbelt Region F.2
G.l Approximate Land Requirements of Steam-Cycle Power Plants G.l
G.2 Possible Watersheds Associated with the Development of
Steam-Cycle Power Plants in the Railbelt Region and
Prominent Wildlife Found at These Locations • G.3
H.l Population of the Railbelt's Incorporated Areas H.3
H.2 Magnitude of Impacts from Power Plant Construction as a
Ratio of Population Increase to Community Size H.5
H.3 Flow of Capital Expenditures . H.7
J.l Visual Considerations for Assessment of Power Plant Impacts J.3
J.2 Magnitude of Off-Site Aesthetic Impacts from Power Plant
Construction J.5
K.l Typical Sizes of Coal Conversion Facilities . K.3
K.2 Water Requirements for Coal Conversion Processes . K.4
K.3 Product Gas Composition and Higher Heating Values from
Various Coal Gasifiers K.5
XX
K.4 Major Coal Liquefaction Pilot Plants in the United States K.9
K.S Estimated Capital Costs for Coal Conversion F ac i 1 it i es K .10
K.6 Range of Controlled Air Emissions from Coal Conversion Facilities K.12
M.l Solar Hot Water Heating System Perf orma nee: Hou seho 1 d of Four M.2
M.2 Solar Hot Water Heating System Performance: Hou seho 1 d of Six M.3
xxi
1.0 INTRODUCTION
The Railbelt region of Alaska, as defined for this study, includes
Anchorage, Fairbanks, the Kenai Peninsula and the Valdez-Glennallen area.
Together, these areas account for about two thirds of Alaska's population.
This region is presently served by nine major utility systems. Three are
municipally owned and operated, one is a federal wholesaler, and five are
rural electric cooperatives. Another entity, the Alaska Power Authority, is
empowered to own and operate power generating facilities and to sell power in
the region but does not presently do so.
To date several organizations, including the Corps of Engineers, the
Alaska Power Administration, the Alaska Power Authority, the Institute of
Social and Economic Research, and the existing Railbelt utilities, all have
engaged in various aspects of electric power planning. However, none to date
has prepared a comprehensive electric power plan that considers the overall
electric energy needs for the Railbelt region and the full set of supply and
conservation alternatives available for meeting future needs.
The State of Alaska, Office of the Governor, has contracted with Battelle,
Pacific Northwest Laboratories (Battelle-Northwest) to perform a Railbelt
Electric Power Alternatives Study. The primary objective of this study is to
develop and analyze long-range plans for electrical energy development for the
Railbelt region. These plans will contribute to recommendations being prepared
for the Governor and the legislature regarding future Railbelt electric power
development. These recommendations include whether the State should concen-
trate its efforts on developing the hydroelectric potential of the Susitna
River or if it should pursue other electric power alternatives.
A major task of the Railbelt Electric Power Alternatives Study is to
examine available electric energy supply and conservation technologies for
their potential viability in the Railbelt region. Technologies found to be
technically and etonomically viable and environmentally acceptable will be
considered in the development of electric energy plans for the Railbelt Region.
1.1
The purpose of this report is to provide an overview of several candidate
electric energy supply and conservation alternatives for Railbelt electric
power planning. This information will be used to help select technologies for
subsequent in-depth consideration. In general, the following information is
presented on each candidate:
• technical characteristics
• siting and fuel requirements
• costs
• environmental considerations
• socioeconomic considerations
• potential Railbelt applications.
This report, Volume IV in a series of seventeen reports, contains 10
chapters and 13 appendices. The following breakdown summarizes the contents
of each section. A list of the seventeen reports comprising the study follows
the content breakdown.
Section
Chapter 2.0
Chapter 3.0
Chapter 4.0
Chapter 5.0
Chapter 6.0
Chapter 7.0
Contents
-overview of the socioeconomic and geographic charac-
teristics of the Railbelt
-descriptions of the existing Railbelt electric energy
systems
-the selection of electric power generation and con-
servation alternatives for consideration in this
report
-general supporting information relative to the tech-
nology profiles
profiles of technologies typically used to supply
baseload power
-profiles of technologies that may be used in either
baseload or load-following applications
profiles of technologies typically operated in a
fuel-saver mode
profiles of energy storage technologies used for
supply management
1.2
Section
Chapter 8.0
Chapter 9.0
Chapter 10.0
Appendix A
Appendix B
Appendix C
Appendix D
Appendix E
Appendix F
Appendix G
Appendix H
Appendix I
Contents
-profiles of load-shaping technologies used for load
management
-profiles of electric energy substitutes
profiles of building energy conservation techniques
-discussion of electric energy technologies not likely
to achieve commercial availability and technical
feasibility
-discussion of the availability and price of fossil
fuels over the forecast period 1980-2010 for the
Railbelt region
-description of the common assumptions and procedures
used to estimate capital and O&M costs, fuel costs,
and energy costs cited in this report
-description of the water resource impacts associated
with each type of steam-cycle facility and their
mitigating alternatives
-discussion of the general nature of air pollution
that arises from fuel combustion, the broad regula-
tory framework that has been implemented to control
air pollution, and the regulatory considerations that
apply to the Railbelt region
-comparison of the different fuel combustion technolo-
gies used in electric power generation
-discussion of the general nature of siting require-
ments affecting the construction of combustion-fired
generating facilities in the Railbelt
-discussion of the aquatic ecology impacts associated
with steam-cycle power plants
-discussion of the terrestrial ecology impacts asso-
ciated with steam-cycle power plants
-discussion of the socioeconomic impacts associated
with energy development in the Railbelt
-discussion of the estimates of the cooling water
requirements required by each of the technologies
discussed in this report
1.3
Volume
Volume
Volume
Volume
Volume
Volume
Volume
Section Contents
Appendix J discussion of the methodologies for assessing aes-
thetic considerations, specifically visual, noise and
odor impacts
Appendix K -discussion of the processes that synthesize liquid or
gaseous hydrocarbons from fuel
Appendix L discussion of the performance of several passive
solar options using a representative house
Appendix M -discussion of the performance of active solar water
heating systems in Fairbanks
Appendix N discussion of the Fuel Use Act's prov1s1ons and con-
ditions under which exemptions can be obtained
I
II
III
IV
v
VI
VII
RAILBELT ELECTRIC POWER ALTERNATIVES STUDY
-Railbelt Electric Power Alternatives Study: Evaluation of
Railbelt Electric Energy Plans
-Selection of Electric Energy Generation Alternatives for
Consideration in Railbelt Electric Energy Plans
-Executive Summary -Candidate Electric Energy Technologies for
Future Application in the Railbelt Region of Alaska
-Candidate Electric Energy Technologies for Future Application
in the Railbelt Region of Alaska
-Preliminary Railbelt Electric Energy Plans
-Existing Generating Facilities and Planned Additions for the
Railbelt Region of Alaska
-Fossil Fuel Availability and Price Forecasts for the Railbelt
Region of Alaska
Volume VIII -Railbelt Electricity Demand (RED) Model Specifications
Volume VIII -Appendix -Red Model User's Manual
Volume IX -Alaska Economic Projections for Estimating Electricity
Requirements for the Railbelt
Volume X -Community Meeting Public Input for the Railbelt Electric Power
Alternatives Study
1.4
Volume XI -Over/Under (AREEP Version) Model User's Manual
Volume XII -Coal-Fired Steam-Electric Power Plant Alternatives for the
Railbelt Region of Alaska
Volume XIII - Natural Gas-Fired Combined-Cycle Power Plant Alternative for
the Railbelt Region of Alaska
Volume XIV -Chakachamna Hydroelectric Alternative for the Railbelt Region
of Alaska
Volume XV -Browne Hydroelectric Alternative for the Railbelt Region of
Alaska
Volume XVI -Wind Energy Alternative for the Railbelt Region of Alaska
Volume XVII -Coal-Gasification Combined-Cycle Power Plant Alternative for
the Railbelt Region of Alaska
1.5
2.0 BACKGROUND
This chapter provides an overview of the geography of the Railbelt region,
a discussion of current eiectric generating capacity in the Railbelt, and a
discussion of the electric load characteristics of the region.
2.1 OVERVIEW OF RAILBELT GEOGRAPHIC AND SOCIOECONOMIC CHARACTERISTICS
The Railbelt region, as shown in Figure 2.1, includes Anchorage,
Fairbanks, the Kenai Peninsula, and the Valdez-Glennallen area. Approximately
260,000 people reside in this geographic region, which extends approximately
450 miles from the southern end of the Kenai Peninsula north to Fairbanks.
Geographically, the area is characterized by three major lowland areas
separated by three mountain ranges. The lowland areas include the Tanana -
Kuskokwim lowland, the Susitna lowland, and the Copper River lowland. The
Alaska Range, Chugach and the Talkeetna Mountains form boundaries to the three
major lowland areas. As shown on Figure 2.2, much of this land has recently
been designated national inter~st land by the Alaska National Interest Lands
Conservation Act of 1980.
Major industries in the Railbelt include fisheries, petroleum, timber,
agriculture, construction, tourism, government, transportation, and financial
services. The federal government provides employment in both the military and
civilian sectors, although these sectors are declining. Current and potential
economic activity is generally directly related to development of Alaska•s
natural resources (Alaska Department of Commerce and Economic Development
1978).
Current estimates indicate that over 20% of U.S. energy resources are
located in Alaska. Coal deposits represent from 39 to 63% of the United
States• totals; oil, natural gas, and hydroelectric potentials are greater in
Alaska than in any other single state (Alaska Department of Commerce and
Economic Development 1978). Proper development of these resources is impor-
tant to Alaska•s future economic condition. Energy resource consumption
within the State of Alaska is currently as follows: petroleum liquids, 69%;
2.1
," ~ :Js
l
I
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'-! ..... ,
I
/' .• -:."'1 row ~~-~··r
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(J)
:A
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.. r.,.UAI"A.'
:NJ5
SCALE 1:2 500 000
0 50 100
MILES
NATIONAL GEODETIC VERTICAL DATUM OF 1929
ALASKA RAILBELT
REGION
USGS ~LASKA MAP E
FIGURE 2 .1.
2.3
Alaska Railbelt Region
'.-:;· )
',J.,,. ·-1
(·~:::.
0
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.~7'5].
~,,~ s--
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,, It
VfJ..tllv.<;
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50
ALASKA NATIONAL INTEREST LANDS
CONSERVATION ACT
SOURCE: U.S. Geolog,cal Survey.
1. Alaska Maritime National Wildlife Refuge
2. Kenai National Wildlife Rduge
3. Tetlin National Wildlife Refuge
4. Denali National Park and Preserve
5. Kenai Fjords National Park
6. lake Clark National Park and Preserve
7. Wrangell-Saint Elias National Park and
Preserve
8. r::::?--:::1 National Wild and Scenic
L:::.2J Rivers System
9. Chugach National Forest
10. Yukon-Charley Rivers National Preserve
11. Nowitna National Wildlife Refuge
12. Steese National Conservation Areas
SCALE 1:2 500 000
0 50 100
MILES
NATIONAL GEODETIC VERTICAL DATUM OF 1929
ALASKA RAILBELT
REGION
FIGURE 2.2.
2.5
Alaska National
Interest Lands
natural gas, 23%; coal, 6%; and hydropower, 2%. Note that most of the energy
consumed in the State of Alaska is petroleum based. Only 2% of the energy
currently consumed comes from renewable resources.
2.2 ELECTRIC GENERATING CAPACITY
Eight utilities presently serve the region, as shown in Figure 2.3. The
City of Anchorage is served by Chugach Electric Association and Anchorage
Municipal Light and Power (AML&P). Most of the Kenai Peninsula is served by
the Homer Electric Association, whereas the area near Palmer and Talkeetna is
served by Matanuska Electric Association. Each of these systems is intercon-
nected. Seward Electric System serves Seward. Fairbanks is served by Golden
Valley and Fairbanks Municipal, which are interconnected. Copper Valley serves
Glennallen and Valdez through a transmission line connecting the two towns.
Power is also generated by the Alaska Power Administration, military installa-
tions, the University of Alaska, and self-supplied industries. The existing
transmission system and the proposed route of the Anchorage-Fairbanks intertie
are shown on Figure 2.3.
Existing electric generating capacity by major utility and type is shown
in Table 2.1. Nonutility generating capacity is summarized in Table 2.2. In
addition to the central generating systems, several smaller installations
operated by individuals or small communities are found in the region.
Planned expansions of utility system generating capacity are limited.
The only system currently considering expansion is AML&P, which plans to add a
74-MW combustion turbine in 1982.
2.3 LOAD CHARACTERISTICS OF THE RAILBELT REGION
The demand for electrical energy in the Railbelt, as well as for most
regions in the United States, varies over time. Thus, loads or instantaneous
demands on an electric utility's system will change each hour of the day and
from season to season during the year. Because electric utilities are required
to satisfy the electrical demands imposed by its customers at all times,
utilities have to provide sufficient generation, transmission, and distribution
2.7
,._, ,,,.
'~bdJ
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is,~~TN.t ,,,.
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llii'.J
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l.loll.l """' IJIC
•.. , .
EXISTING AND PROPOSED
TRANSMISSION SYSTEMS
SOURCE: Alaska Power Administration.
........ _ ....
Existing
• • • -Proposed
SCALE 1: 2 500 000
100
MILES
NATIONAL GEODETIC VERTICAL DATUM OF 1929
ALASKA RAILBELT
REGION
USJS ALASKA MAP E
FIGURE 2.3.
2.9
Existing and Proposed
Transmission Systems
TABLE 2 .1. Total Generating Capacity (MW)(a): Railbelt Utilities (1980)
Regenerative Simple-Cycle
Combined Diesel Hydro-Combustion Combustion Steam
C~cle Electric electric Turbine Turbine Electric Total
Anchorage-Cook Inlet Area
Alaska Power Administration 0 0 30 0 0 0 30
Anchorage Municipal Light and Power 139 0 0 0 75 0 214
Chugach Electric Association 0 0 16 111 244 0 371
Homer Electric Association 0 2 0 0 0 0 2
Matanuska Electric Association 0 0, 0 0 0 0 0
Seward Electric System 0 6 0 0 0 0 6
Subtotal 139 8 46 111 319 0 622
N Fairbanks-Tenana Valle~ Area
Fairbanks Municipal Utility System 0 8 0 0 28 29 66
Golden Valley Electric Association 0 24 0 0 171 25 220
University of Alaska -Fairbanks 0 6 0 0 0 13 19
Subtotal 0 38 0 0 119 67 304
Glennallen-Valdez Area
Copper Valley Electric Association 0 16 0 0 3 0 19
TOTAL, ALL AREAS 139 62 46 111 520 67 944
(a) Entries rounded to the nearest MW; therefore, rounding errors may be
present.
TABLE 2.2. Generating Capacity (MW)(a): Nonutility Railbelt
Installations (1980)
Anchorage-Cook Inlet Area
Elmendorf AFB (Anchorage) 2 32
Fort Richardson (Anchorage) 7 18
Subtotal 9 50
Fairbanks-Tenana Valley Area
Eielson AFB (Fairbanks) 4 15
Fort Greeley (Big Delta) 6 0
Fort Wainwright (Fairbanks) 0 22
Subtotal 10 37
Tot a 1, All Areas 19 87
(a) Entries rounded to the nearest MW; therefore, rounding errors may be
present.
34
25
59
19
6
22
47
105
facilities to meet the largest (peak) hourly load. Therefore, the time-of-use
characteristics of system loads have important implications for an electric
utility system.
2.3.1 Seasonal Peak Load
In the Railbelt region the consumption of electricity is much greater
during the winter season than during other seasons. The major reason for the
higher consumption is the need for energy for space heating. Monthly (1979)
residential electricity consumption is shown, by utility, in Table 2.3. The
table shows that the 1979 winter-summer ratio varied from 1.48 to 2.30 for the
various utilities. The seasonal electricity consumption fluctuations are
determined mainly by the change in heating degree days.
2.12
TABLE 2.3. Monthly Residential Electricity Consumption For 1979(a)
(kWh/customer)
CVEA(b) CEA AML&P HEA MEA GVEA
January
February
March
Apri 1
May
June
July
August
September
October
November
December
Monthly Average
Winter-Summer Ratio(c)
TOTAL kWh/customer
Nonspace Heating Load(d)
Total Minus Nonspace Heat
Estimated Electri~ Space
Heating Customerst%)
620
646
562
525
466
432
371
426
432
434
571
549
491
1.48
5' 892
5,892
0
0
1,179
1,324
1,127
856
779
741
726
583
779
783
953
1,279
871
1.84
10,452
9,828
624
14
1,131
762
1,062
783
678
568
563
482
611
410
666
917
716
1. 74
8' 592
7 '726
866
15
1,418
1' 501
1,407
1,183
1,004
909
740
737
720
849
1,002
1,216
1,054
1. 73
12,648
11,429
1,219
2,017
1,936
1,691
1,396
1,079
903
850
771
834
962
1,245
1' 590
1,270
2.20
15,240
12,090
3,150
33
1,308
1,495
969
803
637
613
562
592
671
743
887
1,258
877
2.30
10,524
8,464
2,060
6
Space Heating Average
Consumption, kWh/customer
4,457 5,907
30
4,063 9,545 34,333
(a) Fairbanks Municipal Utility System data were not available.
(b) Utilities: CVEA -Copper Valley Electric Association; CEA -Chugach
Electric Association; AML&P-Anchorage Municipal Light and Power; HEA-
Homer Electric Association; MEA-Matanuska Electric Association; GVEA -
Golden Valley Electric Association.
(c) (December+ January+ February)/(June +July+ August).
(d) Based upon the CVEA ratio of total annual sales to sales in the summer
months of June, July, and August (4.79).
Source: Institute of Social and Economic Research (ISER) (1980).
2.13
2.3.2 Load· Duration Curve
Figure 2.4 illustrates the load duration curve for AML&P for 1975. (a)
The curve portrays the number of hours of annual generation that were a given
percentage of peak load. The curve indicates that for almost all hours, actual
loads were at least 30% of the peak. About 250 hours of the year had loads
exceeding 80% of the peak.
The 11 load factor 11 of a utility system is the ratio of actual energy
supplied during a period to the energy that would be supplied if peak load
occurred throughout the period. Low load factors indicate a 11 peaky 11 load,
whereas high load factors are characteristic of a flatter load profile. The
1975 load factor of AML&P was about 0.55. Nationwide, load factors range from
about 0.55 to 0.70, indicating that the AML&P load is rather peaky.
2.3.3 Projected Load Growth
Table 2.4 contains the yearly estimated peak loads for the total Railbelt
region as well as the total annual electric generation and associated load
factor. The 30-year forecast indicates increases in peak demand of approxi-
mately 3.5% annually with the load factor remaining essentially constant at
about 62%. Overall peak load is forecasted to grow from approximately 690 MW
in 1980 to 1800 MW by 2010. This computation, based on the ISER forecast
(1980), assumed that the Railbelt utilities were interconnected.
(a) Because 1975 was the most recent normal year in terms of AML&P weather,
AML&P developed the load duration curve for that year. Load duration
curves were not available for the other utilities in the Railbelt region.
2.14
LOAD
(Percent of Peak)
100
90
80
70
60
50
40
30
20
10
2 3 5 6 7 8
8760
HOURS X100
FIGURE 2.4. AML&P Load Duration Curve -1975
2.15
TABLE 2.4. Yearly Estimated Load Growth for the Railbelt Region
(ISER Medium Load Growth Scenario)
Total Generation Peak Load Load Factor
Year (MWh x 1,000) (MW) (Percent)
1978(a) 3,323 606 62.6
198o(a) 3,522 643 62.5
1981 3,703 676 62.5
1982 3,885 709 62.5
1983 4,066 742 62.6
1984 4,248 775 62.6
1985(a) 4,429 808 62.6
1986 4,528 826 62.6
1987 4,626 844 62.6
1988 4, 725 862 62.6
1989 4,823 880 62.6
1990 (a) 4,922 898 62.6
1991 5,148 939 62.6
1992 5,373 981 62.6
1993 5,599 1,022 62.5
1994 5,824 1,064 62.5
1995 (a) 6,050 1,105 62.5
1996 6,305 1,152 62.5
1997 6,561 1,199 62.5
1998 6,816 1,247 62.4
1999 7,072 1, 294 62.4
2000 (a) 7,327 1,341 62.4
2001 7' 556 1,383 62.4
2002 7,785 1,425 62.4
2003 8,013 1,467 62.3
2004 8,242 1' 509 62.3
2005(a) 8,471 1,551 62.3
2006 8, 744 1,601 62.3
2007 9,018 1,651 62.3
2008 9,291 1,700 62.4
2009 9,565 1,750 62.4
201o(a) 9,838 1,800 62.4
(a) Computed value. All others interpolated.
Source: Woodward-Clyde Consultants (1980).
2.16
3.0 SELECTION OF CANDIDATE ELECTRIC ENERGY TECHNOLOGIES
Potential candidate electric energy technologies for developing Railbelt
electric energy plans were identified by first considering the classes of
technologies that would either help offset future electric demand or that
would help meet future electric demand in the region. Seven classes were
identified:
• baseload generating technologies
• baseload/cycling load-following generating technologies
• energy-storage technologies
• fuel-saver (intermittent) generation technologies
• load-shaping technologies
• electric energy conservation technologies
• electric energy substitutes.
Baseloaded power plants operate 65 to 85% of the time and are designed to
supply the continuous (base) portion of electric load at low cost. Baseload/
load-following plants have more flexible operational characteristics and may
be used to meet intermediate and peak loads operating approximately 10 to 50%
of the time. Energy-storage alternatives convert the electric energy produc-
tion of baseload power plants to a storable form of energy. The stored energy
is reconv~rted to electricity during periods of peak demand. Fuel-saver
alternatives include those generating devices that are available only on an
intermittent basis. Fuel-saver alternatives displace baseload generation by
contributing energy to the electric power system, thus reducing overall fuel
requirements. Unless provided with storage devices, these technologies nor-
mally are not credited as generating capacity since their availability is not
assured on a continuous basis. Load-shaping alternatives reduce the need for
peaking capacity by shifting the use of electrical energy not dependent on a
specific time of day to off-peak times. Electric energy conservation alterna-
tives reduce the demand for electric energy by reducing the consumption of
electric power at the end-use stage. Electric energy substitutes substitute
an alternative energy resource (solar, wood, etc.) for end uses that often use
electric power.
3.1
In conformance with the scope of the study, only technologies directly
related to electric energy production and conservation were considered.
Transmission technologies were not considered because transmission intertie
alternatives will be explicitly considered in the development of alternative
electric energy plans. Technologies related to the production of fuel for
electric energy generating devices were not directly considered because fuel
availability and price are considered in a parallel task of this study. Tech-
nologies that were considered were limited to those normally operated in con-
junction with an electric utility grid; off-grid applications are outside the
scope of the study.
To meet the study•s objectives, a broad spectrum of currently commercial,
emerging, and advanced technologies meeting the criteria established above was
identified as potential candidate technologies. These are listed in the left-
hand column of Table 3.1. Only the technologies having a reasonable probabil-
ity of significantly contributing to the generation or conservation of electric
energy in the Railbelt region during the study•s planning period (1980-2010)
were selected for study. Selection of these "candidate" electric energy tech-
nologies was based on two screening criteria: commercial availability and
technical feasibility.
To meet the criterion of commercial availability, a candidate technology
should be currently commercial or should be projected to be commercially avail-
able by the year 2000. Such technology would have the potential to signifi-
cantly contribute to the electric energy needs of the Railbelt before the end
of the planning period of this study (2010). Projections of future commercial
availability of emerging and advanced technologies are based on current devel-
opmental progress (i.e., they do not assume unanticipated acceleration in the
rate of development).
Several of the technologies that initially were considered do not appear
likely to achieve commercial maturity by the year 2000. These technologies
are indicated in Table 3.1 and include magnetohydrodynamic generation, fast
breeder reactors, fusion reactors, ocean current energy systems, salinity
gradient energy systems, ocean thermal energy conversion systems, and space
power satellites.
3.2
TABLE 3.1. Candidate Electric Energy Alternatives
Baseload Generating Alternatives
Coal-Fired Steam-Electric
Natural-Gas/Distillate-Fired Steam-Electric
Biomass-Fired Steam-Electric
Peat-Fired Steam-Electric
Combined-Cycle Plants
Magnetohydrodynamic Generators
Fission Reactors
Fast ,Breeder Fission Reactors
Geothermal Electric
Fusion Reactors
Ocean Current Energy Systems
Salinity Gradient Energy Systems
Ocean Thermal Energy Conversion Systems
Space Power Satellites
Candidate
Electric
Energy
Alternative
Yes
Yes
Yes
Yes
Yes
No
Yes
No
Yes
No
No
No
No
No
Baseload/Load-Following Generating Alternatives
Combustion Turbines Yes
Yes
Yes
Yes
Yes
Diesel Generation
Conventional Hydroelectric
Small-Scale Hydroelectric
Fuel Cells
Fuel-Saver (Intermittent) Generating Alternatives
Ocean Wave Energy Systems No
Tidal Electric Yes
Large Wind Energy Conversion Systems Yes
Small Wind Energy Conversion Systems Yes
Solar Photovoltaic Systems Yes
Solar Central Receiver Systems Yes
Cogeneration Yes
Energy Storaqe Alternatives
Pumped Hydroelectric
Storage Batteries
Compressed Air Energy Storage
Load-Shaping Alternatives
Direct Load Control
Passive Load Control
Incentive Pricing
Education and Public Involvement
Dispersed Thermal Energy Storage
Electric Energy Conservation
Building Conservation
Electric Energy Substitutes
Passive Solar Space Heating
Active Solar Space and
Hot Water Heating
Wood-Fired Space Heating
3.3
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
Selection Criteria
Commercial Technical
Availability Feasibility
Available
Avail able
Available
Available
Available
2000-2005
Available
2005-2025
Available
2025
Beyond 2000
Beyond 2000
2000
Beyond 2000
Available
Available
Available
Available
Available
1990s
Available
Available
Available
Available
Available
Available
Available
Available
Available
Available
Available
Available
Available
Available
Available
Ava i 1 ab 1 e
Available
Available
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No (Resource Limited)
No (Resource Limited)
No (Resource Limited)
No (Resource Limited)
Yes
Yes
Yes
Yes
Yes
No (Resource Limited)
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
To meet the second criterion, technical feasibility, candidate technolo-
gies should demonstrate reasonable potential to operate successfully in the
Railbelt environment. As noted in Table 3.1, five technologies do not at this
time appear to have this potential. Four are resource limited in the sense
that the energy source required for their operation is not available in ade-
quate concentrations in or near the Railbelt region. These technologies
include ocean current energy systems, ocean thermal energy systems, salinity
gradient energy systems and wave energy conversion systems. One technology,
space power satellites, does not appear to be technically feasible at the
latitude of the Railbelt because of the large antenna area required to receive
microwave power transmitted from space power satellites in geosynchronous
equatorial orbit.
The remaining technologies qualified as candidate electric energy tech-
nologies are indicated in the second column of Table 3.1. A profile has been
prepared for each of these technologies and is included in the following chap-
ters. Brief overviews of the rejected technologies are provided in Appendix A.
3.4
4.0 !3Jl.5ELOAO T.ECJiNOL.OGIES.
in!"~ funi:l"-men t.J 1 bg.se 1-~~d g,e.n e:r-p t i-ng t'~l:.hno1'tl!;J i e-s. are ·ctlns 1der.ed in this
an ;tl u$i ~; Gomtru-st ton "f] re.d ~'t;E1ai\)'~e .]~ctr i c g.~nera 1L itm; •flUe lt':!ar s tea:m ~e lf?t: tr i c;
~eneril ~i'on~ 4tld getle ·roat.lan ba\?>ed ·of\ ·gedtherma 1 errergl', El'lce,Jt t-gr gf,:qthet-mli'•1,
an of t h:!i!!.l! a ll:.etflati've·s deJ)'end pt\ the b~111 •hrg ( iis's ion in nu c lear p ld.l!ts:) of
a fuel tQ. vaporj,ze a wurid n ~ f 1ui d\ 1,1SUa11y water>, Wn lCJ\ is -etp.and .ed tilrou~ll -a
turbjrte· to p'I'Muce e 1~'i;f.l~·.~cal powe:r i:ll' a, ·g,ene11 atpr, ». li l;hema t ic re~rt!.~nta
t ·i oli a if tl).e r;tream eye 1e af' t!QIIiDil :f.1i:'i.Dn-fired b!ll>e.]n a:cl . 't-~l!llrtil lulj i.e.s 1s. pre s ei)ted
1'11 Figure. 4 ,l t. i>e ci!Uie t[le fue 1 c hili'a c t~!"l s t i .q~ differ siJ!nHic~n nt amtiri!l
lll;lm.tiu~'tju!J .-iffred s.1;~!1m-ele~tr·i;;· _gener?~t 1 og i,.etthno log fl.)';;, th~~t tNscti.Ss ·1on i's
presented· ir1 three ser;ti:ons: Gh a1 ·-fi'N>i'l &t.e..am-e 1 e.~ri·t ~ (!tstlllti'l;e ~nd na t ·u -
ra~~sp,s-fired steaiJH!•l~GtHc ; and btpmJ~.s-s:-fi ·red stea:m·-e1ect.n c.
A11 of t he ba:;e1 o.ad techAo.iog i es ·r.e~tjfl\'e the M 11owinQ •: a fue·J 8 11 Mel:gy
.sourte; ~He ~ranstJ.Qr~j:ton :a:e:c~s$c i'acilrti.e.~; .e.l ~c.ti•i·cal t ransmisSion Hn e
a<:ce.-5 3<·; ph.)!sica1 s 'ite cil /i!l'a.cter1 s<t~c.s; to support. p l'a.nt oper a:t,;o.n (.e.9-., c.~~1"
in~ watE!-r f\.Od s;t;ah 1 ~ r gu.nt;l.a lt ion); ~nv tronmefit..a 1 e apat ;ty to atH'.orti p.i a)1·t
effluen fs; fnst itutiqna 1 ra(ll) .sm: 1a1 ilrfr·o.~tr,·IJI;fiure to su,ppqrt cofi s.trl:lcif i:on and
op~r11tion pf ~11e· fa\'.. i li~ty~ a nd a ~m1r ce of .c-ap i ta T an~ QPe r a t:h \ti f•t.tngs to· con-
st rutt and maint:a..in t he fac tHli.Y>. Each a:f th~:;e r(!q~i r·eroents is ~Qns j'tl ~r ed in
the ·d lsclfSS 1'91:1 o.f ea ch base 1 o;;d 9enfW<1M ~. le-c linology.
ln i:tl!! 1.olv,E!.f" '4& statecs-~. base load insta 1l at ion s hi!Ve t.ypic-~Jly l:lel!.rt large,
1aoo. t'lW .:~•' mQre.J Q11-, ,ga<>-. c.oa1-, or il\Jtlt'al'->fueled steam -.e •ie d ri e plants.
Because of tha R.ai'lael.t r-e:gitrn 's uniqQ e d.evg1opn11m t anti anvironrnental JSharac-
lier"r.s ttcs., H: h~s flO ~ fo lltlwed ~h.e har:J 'ttton'i) 1 ·tybwer-lill'ki dudog. p!J:tt~ns . Jn
lihe ·Rq.~ 1ibe-l;t , lill'9e . bash Toa:d:e:d· Unit$ h"av e _genera 11y not oeen ·edllilll!li'c·a 11 .Y
fe-asible 'b~~Ll~e of $·par ·se i?OP.'I.\Tal.iqn ..;,flii ]:ack: of t l'-a.nsmi~$,iifn i.ntei'~O'Jl iTI?C •
t i on·s . 'Ttie· re<1at:·;.,;.e ease u:f 'OliTl~b·lic;tion •. gr e.<J fr.er op i!tdf iflg 'fl!;!.:dtl~1~ty ,
stu:tr.~ ~titrsl.l:'uczt'i Dil l ~qQ 1; im~., and 1'o~1er t~p lta1 c<:rs'ts o f ft't(!.sel ~)11;1. ga.s
r!lr flipe f!l.C:il •i t;i~s ·h.:a~e l 'ed :to tlre.ir 1!-Se Ht t ile liaHI:!e.lt r:e.q.ibrt 'f i1P bas~ l o ~d
cap.adty., 'trapat·n y h.as be:en -atldetl ifl ~Jlla11 1ntrements., vdtl\' t he 1 .a;r~e;st
c10lltat in~ unit b:-e irtg 41!P rJO*iiilpt'e'1:Y !i i.l 'Mtll ·., Of:: the appr.tJR ima.tezy il.dOO •HW ef
11 .r
.
N
FUEL
AND
AIR
STACK
HEATED FEEDWATER
BOILER
STEAM
FLUE GAS
CLEANUP
EQUIPMENT
SUPERHEATED
STEAM
FEEDWATER
PUMP
ELECTRIC
GENERATOR
COOLING
WATER OUT
COOLING
WATER IN
CONDENSER
FIGURE 4.1. Typical, Combustion-Fired, Steam-Electric System (without reheat)
nonmilitary capacity installed, only 86 MW is steam electric; 20 MW of this
capacity is used as peaking capacity. The largest steam-electric unit cur-
rently found in the region is the 25-MW, coal-fired Healy plant (Figure 4.2).
The Railbelt region•s projected load growth of approximately 3.5% per
year indicates that individual generating units of approximately 10 to 25 MW .
may continue to be used for the next decade or more if the Railbelt system is
not interconnected (Woodward-Clyde 1980). Plant retirements and the advent of
the Anchorage-Fairbanks intertie could make the use of generating plants with
unit sizes of 100 to 200 MW attractive in the mid-1990s.
Selected characteristics of the baseload technologies considered in this
chapter are compared in Table 4.1.
4.3
IJ13RARlJ
COAL RESOURCES
-FIELDS HAVING SUPERIOR POTENTIAL
~OTHER FIELDS r
0
FIGURE 4.2. Coal Resources, Alaska Railbelt Region
(USGS 1961 and Joint Federal-State Land
Use Planning Commission 1975)
4.4
Aesthelli_l_~trus~nes.~
Visual Impacts
Noise
Door
~~L11g1acts
Gross Water Use (gpm)(b)
Land Use (acres) (c)
Costs
Capital Cost (S/kW/yr)
O&H Cost
Cost or Energy (mills/kWh)
Adap tab II !!Y__!Q.J!rQ.W_!h_
Unit Sizes Available
Construction Lead Time
Availability of Sites
TABLE 4.1. Comparison of Baseload Technologies on Selected Characteristics
Significant
Morlera te
Minor
!BOO
225
2100
30
Be lug a -57
Nenana -60
No direct safety
problems. Possible
air-quality degrada-
tion.
UtI 1 tty opera terl.
I0-1300 fill
3-5 years
Limlterl to coal
regions and sites
near ra 11 road or
water transport.
Oil & Natural Gas
120_0.~~ 2\.e•!!! . .EJ_e_cJr:.hl
Significant
Morlerate
Minor
I BOO
13-20
900-1330
20-22
Oil -120
Natural gas:
Cook -60
North Slope -143
No direct safety
problems. Possible
air-quality deg•·ada-
tlon with high sulfur
dlstl II ale.
llllllty operaterl.
10-000 fill
3. 5-5 years
Limited to s ltes
with pipeline access,
or (for distillate)
harge or rat 1 access.
Refuse-Uerlved Fuel
ill.:!!U.t_~'!!!! .. .!.~-~r.Js_l
Marler ate
Minor
Sign If lcant
325
25
2160
60
67
No direct safety
problems. Possible
air-quality degrarla-
tlon.
Hue lear
{t(){Ml-!!(LI!RJ ..
Sign II I cant
Minor
Hinnr
II ,ooo
125
1050
13
31
No direct safety
prob I ems. Pass lb le
ace I dental rad to-
nuc II de dIs charge.
Gr>nthenni11 read a)
. l~--~ llo~ Dry Rock) . PQ31W s_team-.E 1 oc tr tcJ
Sign If lean!. l~lrlP1·at.e
Hoclerate to Si~niflcllflt Minor
Sign if ic,lnt Hhuw
750 362
5 (E•cluding ll!dlfielrl) "-50
2550
175
57
Ho direct safety
problems. Possible
ah'-~uallty and water-
quality degradation
In ''lclnlty of plant.
1166
20~
R0-96
No direct safety
prob I ems. Pass lb 1 e
air -qua I I t.y dograda-
t.irm.
Utility or municipally Utility operated. 111.1 llty ope•·• tP<I. Ut.l 1 lty operated.
opera teet.
5-60 fill
1.5-3 years
Llmlt.ed to "-SO ml of
rue 1 source.
000-1200 1-14 < I 111 -50 111
7-10 years 7 years(•l)
Limited to sites adjacent
to port facilities or
rail cor-ridor; se ismlc
Influenced.
20-300
I. 5-3
50-100 miles lron1
rue 1 source
TABLE 4.1. (Contd)
!l_e llab llJ.!x
Availab lllty
Expenditures Within Alaska
Cap I tal
O&H
Fue 1
~oom/Bust Effects
Construction Personnel
Ope rat lng Personne 1
Rat lo
Hagn I tude of Impacts
Consumer Contro 1
Technical Development
Comnerclal Availability
Ra ilbe 1t E xperl ence
Coal
@0-HW ~team.J.!ectr_id
85%
40%
90%
100%
600
85
1:1
Severe
Contro 1 through regula-
tory a gene les.
Currently available.
Small scale ( < 25 t\1)
plants.
Oil & Natural Gas
LZ~0_-)'!11_ -~!".~"'..I! e.E_tr __ l£t
05-90%
25%
91%
100%
580
10
8:1
Sign if I cant in very
small comnunltles.
Hlnor to moderate In
all other locations.
Control through regula-
tory a gene ies.
Currently available.
Small sc.1le (<25 1-11)
phnt.s.
Refuse-Derived Fuel
QS---~--~te am J_l ec !!:.~t
85%
40%
90%
100%
65
25
3:1
Significant In very
small comnun It les.
Hlnor to moderate in
all other locations.
Control through regu-
latory agencies.
Currently avallab le.
Hone
(a) Characteristics cited are fm· power plant only. Peat. harvest chat·acteristlcs are not included.
(b) Recirculating cooling water systems.
(c) All facilities.
(d) 4-7 years for wellfleld proving. Three years for plant construct.lon.
Nuc le<1r
______ (_~OOO~f!'I __ I,_W_R) __
60%
40%
89%
0%
1300
100
1:1
Severe with the exceptions
of Fairbanks and Anchorage.
Con tro 1 through t·egu la tory
ogene les.
Currentl.Y available.
None
Genthcnna 1
150_-rw_ llot _ory_ Rock_L_
65%
45%
00%
N/A
90
30
3: I
Severe
Control through regu-
l?ltnry ag~nc ies.
Exper !mental. lifO
unknown. Limited to
resource areac;.
Hone
Peat.
l3():_11o/ S_t.eam-_Eie.ctrlc)
00%
40%
90%
100%
65
7.5
3: I
S lgn Hi cant. In very
sma ll comnun I tl es.
Hlnor to moderate In
all other locations.
Con tro l through r~qu
latory agencies.
Currently av,,llah le In
Europe. No IJ.S.
e xper I ence.
Nnne
4.1 COAL-FIRED STEAM-ELECTRIC GENERATION
Coal-fired steam-electric generation is a mature, reliable technology
that supplies more electric power in the United States than any other single
generating technology. Uncertainties in petroleum supply and rising petroleum
prices are leading the electric utility industry to return to coal-based plants
from oil and natural gas use, which became popular in the 1945-1975 period.
Small users converted much of their steam-generating capacity to oil or natu-
ral gas during this period because of two factors: 1) costs of storing and
handling coal, and 2) social pressures for cleaner air, as reflected in the
Clean Air Act, which required installation of flue gas cleanup equipment for
new coal units. Renewed interest in coal for new installations is due to the
large quantities of coal available in the United States, including significant
deposits located in the western states and Alaska. Coal deposits in the
Railbelt region of Alaska are shown in Figure 4.2.
Recent coal-fired power generation installations in the United States
have been large units (greater than 200 MW). However, smaller users and pro-
ducers of steam are expected to look to coal as a fuel in the forseeable future
because of its relatively abundant supply and lower cost when compared to com-
peting fuels. In addition to economic factors promoting coal use, the Power-
plant and Industrial Fuel Use Act of 1978 essentially prohibits the use of
natural gas and oil for units firing over 100 million Btu/hr (approximately
10 MW or 100,000 lb/hr of steam), unless exemptions can be obtained.
Contemporary coal-fired installations differ from older units in the
important area of flue gas cleanup. The Clean Air Act and subsequent amend-
ments require control of particulates, oxides of sulfur (SOx) and oxides of
nitrogen (NOx). Equipment is installed in the flue gas discharge path to
remove SOx and particulates befo.re the gaseous emissions enter the
atmosphere. NOx emissions are controlled by using modified combustion
technologies.
4.1.1 Technical Characteristics
Coal-fired, steam-electric plants have been installed in unit sizes up to
1300 MW, although most utility plants are between 200 and 800 MW. The lower
4.7
end is limited only by costs; 10 MW appears to be a practical low-end limit
based upon conditions existing in the lower 48 states. The projected load
growth and characteristics of the Railbelt electrical system appear to favor
units from 10 to 25 MW if the Anchorage and Fairbanks systems are not inter-
connected. Units of 100 to 200 MW may be practical in an interconnected
Railbelt system.
Design Features
The principal components of a coal-fired, steam-electric generating
facility include the boiler plant, the turbine system, the electric plant, the
air pollution control system, and the condenser cooling system (Figure 4.3).
The turbine system, electric plant, and condenser cooling system of coal-fired
installations are similar to those of steam-electric plants fired by other
fuels. The boiler plant and air pollution control system of coal-fired plants
differ substantially from those of noncoal-fired, steam-electric facilities.
The unique components of a coal-fired plant in comparison with gas-or oil-
fired units include th coal handling system, the air pollution control system,
and ash handling facilities. These facilities will be described in additional
detail. Coal handling and preparation facilities include facilities for
receiving, handling and storing raw coal and equipment for preparing the coal
for firing.
The design of the unloading station depends on the mode of coal trans-
portation. For transportation by rail, which is the most common mode, the
unloading station includes a rail spur (often a loop to facilitate continuous
unloading of unit trains), a thaw shed to thaw coal frozen in the railcar, anc
car unloading equipment. Car unloading equipment is of two general types,
trestles or dumping pits for bottom dump hopper cars, and rotary dumping
machines for gondola (fixed bottom) cars.
Long-term and live coal storage areas are generally provided. The long-
term storage area is usually sized for 60 to 90 days' supply; it may even be
sized to hold up to 6 months' supply if the normal source of coal delivery is
not reliable because of labor availability or weather conditions. The live
storage area, from which the coal is fed to the plant, is usually designed for
4.8
UOILER RUE
rJ~,5ES ,..,.~---~~
'HIGH PRES~URf
fl I GH "I'£M P£~1\TUIIE
STEAM
BOJ I$R: F£ED WA1ER
?liMP
a 7-day supply. Depending on the plant size, large crane-like stacker-
reclaimers or dozers are required for placing the unloaded coal into the
appropriate storage area and for retrieving it for use in the plant. In cold
climates, frozen coal crushers may be required at the reclaim area.
Most coal-fired plants use a conveyor system to move the coal from the
reclaiming area to the plant bunkers. Cold weather regions will require
climate protection equipment in addition to dust suppression systems.
Inplant storage bunkers are usually sized for 8 hours of capacity. The
bunkers are situated above the mills for gravity feed and require some form of
a fire protection system.
The mills are generally located below the bunkers and serve to pulverize
and to dry the coal for burning. The mills are extremely large, heavy-duty,
slow-speed, high energy-consuming pieces of equipment. The air pollution
control system is used to remove environmentally harmful pollutants from the
flue gas stream. These pollutants include particulate matter, oxides of
sulfur (SO) and oxides of nitrogen (NO ). Each of these pollutants X X
requires control under the provision of the Clean Air Act of 1971 and subse-
quent amendments.
Particles are removed from the flue gas by electrostatic precipitation or
fabric filters (baghouses). The most widely used system has been precipita-
tors, which are capable of 99.9% removal efficiencies. The performance of
precipitators is affected by the sulfur content of the fly ash; higher levels
of sulfur in fly ash result in enhanced removal efficiencies. This has led to
increased use of baghouses for plants burning low sulfur coal.
The most common method of removing sulfur from the flue gas is by lime or
limestone slurry scrubbing. In these processes a slurry containing calcium
carbonate, prepared from lime or limestone, is used to scrub the flue gas.
Sulfur reacts with the slurry to form insoluble calcium sulfites and sulfates
that are disposed of as solid waste. Removal efficiencies are about 90% for
single units. Either wet or dry systems are available. The wet system results
in a sludge requiring dewatering; dry systems are designed such that drying of
4.10
the sludge occurs in the flue-gas stream, resulting in a product requiring no
additional dewatering. The dry system reduces the freezing problems in a cold
climate. Several other SOx removal processes are currently under develop-
ment, many of which are regenerative processes, producing marketable sulfur
byproducts and reducing the need for scrubber feedstock.
NOx are formed during the combustion process by the combination of
atmospheric oxygen with atmospheric nitrogen at elevated firing temperatures.
Currently, NOx are controlled by special firing techniques.
Since coal combustion creates large quantities of ash from both the fur-
nace and the particulate removal equipment, a location for final disposal of
the ash must be provided. If a dry ash removal system is used, then only a
small, onsite storage area is required because dewatering is not necessary.
Wet ash removal systems require impoundments for dewatering. Ash may be mar-
keted as a by-product; otherwise, a permanent disposal site is required.
Permanent disposal may be in landfills, although occasionally ash is returned
to the mine for disposal.
Performance Characteristics
Plant heat rates are a function of unit size, design, auxiliary equip-
ment, heat sink temperatures, operating mode and operator attention. Typical
heat rates for various sizes of coal-fired steam-electric plants are as
follows:
Heat Rate
Rated CaQacit~ (~) {Btu/kWh}
20 10,600-13,000
200 10,200-13,000
400 9,800-12,200
600 9,500-10,600
The most recent data available from the National Electrical Reliability
Council (NERC) indicate that coal-fired unit availability varies with unit
size as indicated below:
4.11
Unit Size
100-199 MW
200-299 MW
300-399 MW
400-599 MW
Availability
(10-Year Average)
86.1%
84.8%
77.6%
74.1%
Additional information from the NERC survey indicates that in recent years
the units• availability has decreased in every size range. The added complex-
ity of flue-gas cleanup equipment being installed or retrofitted in those years
is undoubtedly a major contributor to those decreases. The higher availability
of smaller units may be somewhat misleading considering that these units are
usually less efficient than the larger units and are therefore held on standby
more often than the larger plants. (Being on standby enhances the availability
figure by reducing the frequency of equipment failure.)
Coal-fired steam-electric plants have lengthy startup times and low ramp
rates and are generally not suitable for load following. Thus, they are typi-
cally operated as baseload or intermediate load units. Capacity factors for
units in the above sizes range from 45 to 86%; however, for any particular
unit the capacity factor will depend on its heat rate, system size and mix,
availability, system demand, and the utility•s operating procedures. A new
base-loaded unit with a good heat rate will have a higher load factor than an
older, less efficient plant used for peaking purposes.
Economic lifetimes of coal-fired steam-electric power plants are typi-
cally 30 to 35 years. Actual physical lifetimes may be much longer, although
the older units generally serve as intermediate or peaking duty units.
New Developments
Fluidized bed combustion (FBC) is under development as an alternative to
pulverized coal combustion methods. A fluidized bed consists of a mass of
noncombustible particles lying on a perforated plate. As air is forced up
through the plate, the bed material starts to exhibit the motion and some of
the characteristics of a fluid. If fuel (coal particles about 1" x 1/4") is
4.12
added and the temperature is raised to about 1100°F by external means, the
coal ignites. The bed temperature then increases to about 1500°F and combus-
tion is self-sustaining. If limestone is added to the bed (such that a mole
ratio of 3 or 4. parts of calcium to 1 part of sulfur (in coal) is maintained),
then sulfur dioxide (S0 2) formation is minimized.
With the exception of the bed and the heat exchange tubes in the bed, the
basic boiler components are similar to a conventional unit. The heat transfer
coefficient of an in-bed heat exchanger is approximately five times as great
as the convection tubes in a conventional boiler. Although corrosion may be a
problem with the in-bed tubes, erosion has proven to be minimal (actually less
than that of tubes in the gas path of a conventional coal-fired unit). Minimal
erosion has been explained by the fact that the fluid motion causes the bed
particles to become 11 rounded 11 and the bed velocity is low, about 8 ft/sec as
compared to 50ft/sec for the gas path of a pulverized or stoker-fired boiler
at the superheater tubes.
Because each bed is limited in physical size (100 ft2) for practical
purposes, large boilers will consist of multiple beds. Each bed produces
approximately 50,000 lb/hr of steam. Dead cold beds can be started in about
6 to 8 hours; however, because they retain heat well they can be restarted in
about one hour after a two-day shutdown. Bed turndown is limited; however, in
a multiple bed design, overall unit turndown is improved by taking individual
beds out of service.
Utility application of FBC is currently limited. Although commercial
operations (Monongahela Power Co.) exist, the majority of the installations
are demonstration plants. The utility industry•s interest in FBC has signifi-
cantly increased in recent years for several reasons:
• Coal can be used as the fuel; therefore, dependence on expensive and
sometimes unreliable oil supplies is reduced.
• Coal is burned in intimate contact with limestone; thereby, so 2
emissions are reduced greatly. Under some circumstances New Source
Performance Standards could be achieved without using flue-gas
desulfurization systems.
4.13
• Combustion occurs between 1500 and 1750°F, which is well below the
temperature at which NOx formation is a problem. The relatively
low combustion temperature also limits slag formation and therefore
eliminates or at worst greatly reduces the need for a soot blowing
system.
• Particulate carryover in the flue gas can be reduced below that of
conventional coal-fired boilers. Dust collection equipment (usually
baghouses), however, is still needed to meet New Source Performance
Standard requirements.
• Carbon loss can be held to less than 0.01%, primarily by reinjection
of fly ash into the bed.
• A wide variety of coals (and other solid combustibles) can be burned by
FBC with the proper adjustments to fuel size, air velocity and feed rate.
• The bottom ash is powdery rather than hard slag or clinkers, which
are characteristic of conventionally fired coal units, therefore,
removal and disposal is made easier.
• Coal is not pulverized, thereby eliminating a significant portion of
the fuel preparation capital cost and maintenance expense.
FBC does not appear to show any advantage over conventional firing in the
areas of thermal efficiency, operating manpower or chemical cost for so 2
removal. Some advantage is expected in capital cost due to the elimination or
downsizing of such equipment as pulverizers, scrubbers, dust collectors and
ash handling equipment.
Presently, FBC exhibits the following disadvantages:
• Operating and design experience in utility sizes and applications is
lacking, although some industries, such as wood processors, have had
many years of actual operating experience.
• Possible corrosion problems may develop in the bed region over a
period of time.
4.14
• More square footage of boiler plant area is required for equal power
output than for conventional firing; however, air-quality control
equipment will be smaller or eliminated.
4.1.2 Siting and Fuel Requirements
A complex decision process that considers environmental aspects, econo-
mics of transportation, construction and transmission, natural resources,
aesthetics, public opinion, and growth patterns is used to site coal plants
in the United States. As the siting process has grown more complex, new plant
sites tend to be more distant from load centers. The location of the fuel
source, the available transportation facilities, and the size of the plant
weigh more heavily in the siting of a coal-fired unit than with oilor gas-
fired units because coal characteristics vary so widely compared to oil or gas.
Coal-fired steam-electric plants require water for condenser cooling,
emission control, ash handling, boiler makeup, general cleaning, and domestic
purposes. Typically, water requirements for boiler makeup, emission control,
domestic and other noncooling uses amount to approximately 5% of the boiler
throughput. Cooling water requirements vary according to the ultimate heat
sink employed. Once-through cooling requires water resources approximately 50
times the boiler flow. With the use of evaporative cooling (cooling towers)
the makeup required to the cooling system is approximately 65 to 75% of the
boiler throughput. Use of dry cooling (air condensers) reduces makeup to a
negligible amount. Dry cooling also prevents the formation of water vapor
plumes and resulting ice fogging. Dry systems have been used primarily at
sites with scarce water; however, the low, ambient air temperatures in the
Railbelt region make this a technology worthy of evaluation (see Appendix I).
The acreage of sites required for coal-fired power plants of varying
capacities is given in Table 4.2. These estimates account for the siting of
plant facilities (including coal storage and handling facilities, power plant
systems, cooling systems and solid waste disposal areas) and also onsite hous-
ing facilities that would be necessitated by remote siting.
4.15
Rated
TABLE 4.2. Typical Land Requirements for Coal-Fired
Steam-Electric Power Plants
Ash and Total Land
P 1 ant Scrubber Sludge Area Required
CaQac it.z:: ( MW} Island (Acres} DisQosa 1 {Acres} (Acres}
20 5 3 8
200 25 200 225
400 75 400 475
600 120 500 670
Fuel consumption (quantity) for coal-fired steam-electric plants varies
with heat rate and with fuel quality. The hourly consumption of coal and
limestone for potential power installations requires, in all but the smallest
installations, a railroad or waterborne transportation system to deliver coal
and limestone for flue-gas desulfurization. Siting coal-fired steam-electric
plants at mine mouth eliminates the need for fuel delivery systems. Coal and
limestone consumption is shown in Table 4.3 for four plant sizes.
4.1.3 Costs
Capital costs for coal-fired steam-electric generation vary from project
to project and depend on the construction schedule, unit size, scope of work,
and degree of standardization. O&M costs are difficult to estimate because of
the wide variations in utility practice. The cost per kilowatt decreases
substantially as unit size increases because larger units require relatively
TABLE 4.3. Fuel Consumption for Coal-Fired Stearn-E 1 ec tr i c Plants
Rated Capacity Coal Consumption Limestone
( MW} ( tons/hr} ( lb/hr}
20 16 150
200 145 1,400
400 275 2,750
600 400 4,000
4.16
fewer personnel than smaller units. Estimated capital and O&M costs vary with
plant size, as shown in Table 4.4. The basis for these cost estimates are
further discussed in Appendix C.
TABLE 4.4. Estimated Costs of Coal-Fired Steam-Electric Plants (1980 dollars)
Cost of Energ~(a)
Rated Capacity Capital O&M Costs Beluga Coal Nenana Coal
{MW} {$/kW} {$/kW/~r) {mills/kWh} (mills/kWh}
20 2560 68 68 71
200 2100 38 57 60
400 1730 27 49 52
600 1500 19 43 46
(a) Levelized lifetime costs assuming a 1990 first year of commercial
operation. Fuel costs are provided in Appendix B.
4.1.4 Environmental Considerations
Coal-fired power plants generate large quantities of solid waste derived
from both the combustion process (fly ash and bottom ash) and from atmospheric
emissions (flue gas desulfurization wastes). These wastes require more exten-
sive environmental monitoring and waste characterization studies, and generally
more sophisticated treatment technologies than other steam-cycle technologies.
Water resource impacts associated with these solid wastes are generally miti-
gated through appropriate plant siting and a water, wastewater, and solid waste
management program (refer to Appendix D).
The combustion of large amounts of coal leads to a potentially signifi-
cant deterioration of the surrounding air quality. The atmospheric emissions
from a coal facility would require an in-depth review by Alaska and Environ-
mental Protection Agency (EPA) authorities. The expected emissions from a
coal-fired power plant and the regulatory framework are presented in detail in
Appendix E, where emissions are compared to those of alternative technologies.
Note that although impacts from coal combustion are generally greater than
those of other fuels, a judicious siting analysis and strict environmental
4.17
controls will generally allow the operation of a coal-fired power plant near
the major Alaskan coal fields. The use of coal is also facilitated by the use
of low-sulfur coals common to most of Alaska's reserves. Plants located in
the resource areas would have to be designed to mitigate effects on these
resources.
Other significant effects from coal-fired steam plants are associated
with water supply and wastewater discharge requirements. Many potentially
suitable development areas for coal-fired plants border important aquatic
resource areas (salmon in streams like the Copper and Susitna Rivers and other
marine fish and shellfish in Cook Inlet). Water withdrawal may result in
impingement and entrainment of aquatic organisms. Chemical and thermal
discharges may produce acute or chronic effects to organisms living in the
discharge plume area. Thermal discharges can also cause lethal thermal shock
in the Railbelt region. These effects are discussed in greater detail in
Appendix F. Plants located in the resource areas would have to be designed to
mitigate effects on these resources.
Coal-fired plants will use the same or less water per megawatt than other
steam-cycle plants, except a combined-cycle facility. A suitable plant size
for the Railbelt region (200 MW) however, would be second only to nuclear
plants in total water use and would require approximately 90,000 gpm and
1,800 gpm for a once-through and a recirculating cooling water system, respec-
tively. In addition, water from coal-fired steam plants, particularly from
ash or flue-gas desulfurization wastes, generally requires more sophisticated
treatment than most other steam plants to reduce its toxic loading.
The greatest impact on the terrestrial biota is the loss or alteration of
habitat due to the large amounts of land required for both construction and
operation. These land requirements (Table 4.2) are generally greater than
those for other types of fossil-fueled power plants. Other impacts could
result from gaseous and particulate air emissions, fuel or waste storage
discharges, human disturbance, and the power plant facilities themselves; e.g.
bird collisions with cooling towers. These effects are discussed in Appen-
dix G. Biological impacts are best mitigated by siting plants away from
4.18
\nipQl'i>dnt ~1nd life ar ei!$ ~Jid by il(ip1.eme(ltinll a~~rt;JP.r iatt= P911Ut:ibfl Ccmtrl'l,l
prnt>.ett~J;re~, Although certa i'n imPntts 't>t.~n b.e tor1tro1laa. land los~es are
itrep 1 qC,.eilb, 1 e ,
4 ,1.$". Sor;:i.oecon1lmi c C<ms·!·d.er.i!tiofls
The ·C!Jn~tructi 9 1i arrd 'RW!11".at'i o11 .Df ·a cQa 1-f·i ~'~'"~ P'l<lnt tt~'!.l the. ,ji(lt!!Jlilj ~ 1 to·
ii er ious 1}' 5·rrej:t sm,a.11~r t>Q(I11JUrtil:.i .es a11d M · callS!! a b.t>Pm l·b~~t G:XcJe.. The ;;e
effe&.t $ .w·e dtle t'o {h~ remo.t.e.n~s·S of p l>os~et:t. ive ~ '[tes-. Th¢ i!)agn i t.,ud:e lllf
these imp'.dt't> t s a. funet t eo of tne con~tr uct i en trer 'i od, the .s j t,e p f the con -
$'tr'IJG,t:1on war~ f·ot c·e· aM ·J:he 'i:'at'io 'Of. c!lrrs.t"-r uc:t'i'on t:o operating 1/.er-;oone'L
CollS'tr'Uct'iol'J fAme,s, e)l.t.lu:~.iVJI. of Hc.en>s .. lng ahtl pe:rm a t1n .9, ~«i i1 lifa.r'Y :atturd ·1(1.g
t o thl~ H?e,. t _yp.e Q'f e.Q'u ipm~n·t,, ~nd axt;erll:a.l factors. ~uc:p a~ '~<?4 th-et a'rrd: 1-;l'.lqr
for bfl . Con-s:trvc t ie!l .::g;hedu les for .C9 .a.l-f f red illants tn .the-B.a•11tle l,t vi11 1 v.ary
de,pentHug up.an •../tret:f\er th~ boiler 1:s f~eld-el"l!eted. fl. smaii ·:W-M'il· unH c·Ou1 1;1
be .cG.tJst rutt.el:! lll &ppr.eM'mate1y -20 mo/lths H Ure boiler. is -a wacJI,.age ile<s t~o
a11d t r. t hl'f au,x4 i'iar.y eqtiipmenl is . .sud mu!mted . L.a.r<ge r tl ~i.t ~ (iibtJVe :50 'MW)
that are f'ie l:d. c,b'nS>truc-ted' \ofi 11 tak..e. frqiJl 3 t b t1 years, The cdr:tsM•uM ;~,
fo r cec f.qr o. ~PQ-M~ J))a:nt 'j{. !ls'timat~;g ii(.J be SOO penoiln~l. An oper·a·tilig wo1•11.
f. ore~ o:f E5 .woy ld .qe r.equ ii r~(l.
lJ!iP,act;s. WQIJ ltl' l!.e rn.os t: sev ere at· tlte Be 11J9a coal fi ~14s s.it~.G·e 't~e ~ut'rQyng
if1~ qommO!litie'$ 4re sm a ll :a nd tr~lis.P Q.r t·'!·ti o.fl h c:n]-t'ies are poor1y lfeye:lpped.
Puwer pl ant C/Jmlwnen f.s: >Ja~ lrl mQ -st 1iJcie 1 ~ b.e s·li ·ip~~a !J;y tlar~e ~rrd thert tr<Hl-s-~
ppr ted overland to t;f!e sft:e •. .SecDfl'd~ry imp&c t~ \¥Ould be c au;sed by· the CDfl-
~tr uc-tion .of hau ·] roads. The: ia i'~ c.trmmutdr.y i'IJ t1H~ al'ea Is Tyorre k,; afl
illiiSk';4 n rtatj.V.e ~ ~ 11 ag,e ·W'i th a perni l off i on flf 2:39. Th~ 1!1·fTU ~ of a. consttucMon
111?17R f.O r c e, -,..P.Jfa r.d l~S's q-t plant $l ··~e.. \'ltl.lf l<d l;l.i.s,r~~~t ti:Je stx ·l a 1 sl rU,e.till'e' Qf a
t:ofllll gn:;;ty. a.'f t 111:s ~ f'Z~ ..
~lfipg.t;;t;o; frd!)l 'pl .;n;t Q:e'(e ·)o}!me tfit i!1o!ig 'ehtl r,; llt~~ ·cprr'l.dor wou.ld. -depenf.l
Dll t Jie pl3n ~ sc;ale, Exhtin'g· .c·on11Junit,i~s maY .be .. ~I;Lg f9' af;c6!1flloda~~ t:Qr\S.tr uc-
ti~!l of ·~ !\1-t .O 30-M!)l •P l'ant imt ~<DU ld be lie:Ve'fe l-y. aff.~J;eq : by-~ lat'~e -s·c o.Jp.
pi\;nt . Mld -t ti.o.na 1 dis cussion off llo,tentta..1 impae.t~ i~ ]n ·.oviil!ld 'in Ap'p ·11'ndil\ H ..
1'1\e flow qf ~ap ita 1 expand it.ur~s ~otil outs1 ~e <~lid Wi!.hin ~he Rii<tl heilt ~re
·exP,ected ~q ~'I larrc e fo~ a 20.0-MW fi.e 1 ~ ... irre,c.t-ea Prliject an d to. b'li: P'I'Q~el"t ion-
ate iy h fgflel" IJ~ ls 1 tie .t~e r.eg 1 o1i f l'lr a 20 -(lill./ pa~k a918ll uni t.. .F ar a 1 «Yye un 1t ,
~"0%. Of ~~e tg)(p:en ~itlll"e s \ioli 'ld f1e\~ qu,ts:i9e t he Ra111;ie;l't' alld 'f ,Qf' i\ ~~1 1er
w'J I t , tlli~ro >;imitt:ety GO% of .the Q.fojec.t itw:estniM t W(l~l.d be made 01J tS'ide t~e
Railbe\1 . Hte perceptag·e I'J f '=apltal investmen t fol' (!. fh!hl-el:ected pl ant is
i arge r oompared to O<t~~J<-!Useloud techl\01 .og fes bec.au s.e Qf the l ill'ge coQ -~trur.~
ti Qn .wor k force a11d extensi~e He1q llre pi!rq·t1on r.el.lU 4r.emeiJU < Th e tlPI"' of 0&./4
expeRe'itiJres 1s e&pected t o t.e 10% spent au -hide t he r egfOr\ and the balaJ1oe
-sperl't 111 til"' l"eg l on,
A-.1 .• 5: Pot~nHal Applica t:1 on f r:~ t h·e Ra-llbe1t Re!JiOri
S orne d evelallment of" .c ·o~i-fi.red ste<~m-electri,r: gMeratlon ka~ occurrecl 111
til&-Rajl b ~;H: 'llith t:Qa 1 ftom tlhi! Nenana 4o~l field , A. .2~·MW, po a l -t ir~.d p.lat't
loc ated at HealV. i ~ o~erated 1>.¥ ~he Golden V·alley Elecb·i4 Assor:i &t~(;>n . ]fl
addition, t!H? Pai i'~anks Muni.e ip a1 Ut i1lties S:,Yst ·em opP-r <lte!> ft;~ur urlit s, at:
Qhena, qnq til ~ UI'IWel:'sitY of Alaska has th r ~ sm&ll ~nits . Tfle Be,lJga field s
have no:t treen devs1oped, iil~ho ugh ;tud 1e s are und !!rway t o define t he coal
rl!sou\"ee ch&l"&e::~E!I'istit;s ~Jld "1 ~rket~ (Bat t e 11e 198da ),
r.oal-fi~·e!J s t ea.m-e i~c:tl'i c gene!tation si'\D\'IS promise as a po~entiall,Y lnaJ'ol'
smu t ce a~ bi!SE! lo;'\cl' power i n tl\e' Ra i 1bel t l'eg,iort. The h !<lhna1ogy i s mat,wre and
co 1d-c atna~~ -~~p -j i c.~t.i ons 'I) aVe!' been we 11-cl:emons tl"at.e~ e 1se wherl'!,; C'i~ i ;costs
<~ra fewecas:tacJ to b:e r.el-a:tiV!'!lY law a'rid t he res ultil19 cost Pf PO I(e r IIIO!it:
li Kel.y-\oii'l1 be· CDIJ111Hitive WH h .either :gen.era-l::iqg al'ten14tives . lilniss,ion Of
atm'Qspliede po.lHrtant..-;;; ·pro bab ly tile. p\i 1ni!l'pa T eiWironmentai imP t~tl: t o be
GQrl~i dere ~; h:Owever, ~tll ntro1 ~ch nol O'~Y 1:> we ll 'lshblistu=~ fCit-par t i()ul ate
a nd su 1fu r emh',~ipns. MoJ!!!lV.er, the !!X't~em~l,v l ow slll•f ul· co o t~nt of Alask-al'l
Q'oa i :ea ses. s ~ lf.r.w C:ll n tro l re ql.dr-emen ~s . Ir.e fog f Qt'ma i;i 011 i> a-ll otet1t i i'\1
f!l.'Pl>,lenr, but most likelY c all' be ~ont ro\1ed \~ith we~j d i'Y• m ec.h "n i e~l' tlpaft , h~U
rejet:Ho.n eQll 1Jl'illl'!rl'!:.. NO x eml s-stttns: can b!E conttoll~d Within Ql!rrent st.s.n-
dar-d.S. by ~r ope \" furn aae M,>igrl a rrd f i rif•g pr acedUI'es.. ThR! l'Qi'l'IJ-i"errn effect Qr
col" tlfll iss ]ons on glnba1 t elliper.atur•es is oif l f1Ct>i11lf>i~!i Mnc-ern . Conitnd. H
.r eQ\.l ·i·red 1 cau1d be ac;zo mp l ~!ih eq by l"l39U)atin_g gJobal r•.ates o,f coa~ "omhu sttan,
an iSS·Ue. t~at !fJ US't b!' ~d d r es-sed <I t t~e i l'!1 e ·rn<i.ClO na l leve~.
Both the Beluga coal field and the Nenana coal field would be potential
sources of coal for coal-fired steam-electric plants. Plants using Beluga
coal would likely be located at or near the mine mouth to minimize coal trans-
portation requirements. Electrical transmission would be to the Anchorage
load center or to a future Anchorage-Fairbanks intertie.
Future plants using Nenana coal could be located at mine mouth but more
likely would be located along the Alaska Railroad some distance to the north
or south to avoid impacting the Denali National Park Class 1 Prevention of
Significant Deterioration Area. Prospective locations would include near
Nenana to the north and in the lower Susitna or lower Matanuska Valleys to the
south.
4.21
4.2 NATURAL GAS AND DISTILLATE-FIRED STEAM-ELECTRIC GENERATION
The natural gas and distillate (oil)-fired steam-electric generating
technologies are well known and widely used in the utility industry. However,
future application of these technologies is in question because of the world-
wide oil supply and pricing disruptions caused by the OPEC nations, and the
resultant passage of the Powerplant and Industrial Fuel Use Act of 1978
(PIFUA). The PIFUA essentially prohibits the use of oil or natural gas for
power generation in unit sizes exceeding approximately 10 MW. While exemp-
tions are available to utilities that can prove that no reasonable alternative
exists, these exemptions are difficult to obtain. Development of a synthetic
fuels industry based on coal or other primary resources may, in the future,
provide fuel for larger plants. However, the superior efficiency of combined-
cycle plants compared to steam-electric plants would likely result in use of
the former alternative in conjunction with synthetic fuel production.-
4.2.1 Technical Characteristics
Principal components of a distillate-or natural-gas-fired power plant
include the boiler plant, the turbine system, the electric plant and the
condenser cooling system. Depending upon environmental regulations and the
sulfur content of the fuel, flue-gas desulfurization equipment may be required.
Units have been constructed in sizes ranging from less than 10 MW to
800 MW. Units of 10-MW and 200-MW rated capacity are evaluated in this
profile. Units in the 10-MW range are used primarily in heavy industrial
applications; however, the purpose, operating procedures, and operating con-
ditions of such applications are usually different from those of a utility and
therefore only can give an indication of what can be expected for electrical
generation.
Design Features
Distillate-fired boilers require no special or unusual equipment. The
plant will require a large, fuel storage facility unless a reliable pipeline
is available. The size, type, and number of tanks will depend on fuel reserve
4.22
requirements. A one-week supply is a common criterion for plants with a reli-
able source; additional storage for Railbelt sites may be required if the plant
is supplied by tank truck or rail. A way to heat the oil may be required,
depending on oil type and ambient temperatures.
No special fuel storage or handling provisions are required for gas
firing because the fuel is delivered by pipeline at pressure. During periods
of extreme cold, when transmission line pressure drops, natural-gas-fired
units may have to be shut down or switched to oil, thus decreasing system
reliability.
Performance Characteristics
Typical heat rates for various sizes of natural gas and distillate-fired
steam-electric plants are shown below:
Rated Heat
Capacity Rate
Fuel (~l (Btu/kWh)
Natural Gas 10 12,000
200 11,400
Distillate 10 11,000
200 10,600
Industrial users frequently obtain plant availabilities of approximately
90%. This high percentage is possible because industrial boilers can be oper-
ated at a continuous load, and very often the end product is steam, thereby
eliminating downtime due to electrical generating equipment failures. For
utility purposes, a well-maintained base-loaded plant is estimated to be
available approximately 85 to 90% of the time for 10-MW units. These figures
are based on industrial data and data from NERC on the smallest reported units
(100 MW). Similar availability is expected with 200-MW units.
Natural gas and oil-fired steam-electric plants, like most steam-electric
plants, typically require lengthy startup periods and are characterized by
relatively slow response time. Thus, they are commonly operated as baseload
4.23
units. Older units may see intermediate duty. The typical economic life of a
plant is 30 to 35 years, although the physical life of a plant may be much
longer. Older plants are often used as intermediate or seasonal peaking units.
4.2.2 Siting and Fuel Requirements
The water resources and air-quality limitations in the siting decision
process for small gas-or distillate-fired steam-electric plants are similar
to those for coal units. (Flue gas constituents will differ but the regula-
tions, studies, and permits are similar.) Natural gas and usually distillate
fuels are environmentally preferable to coal, and thus environmental con-
straints on siting these facilities should be less rigid than those expected
for a comparably sized coal unit. The major siting parameters are related to
fuel source and fuel handling considerations and the land area requirements
for the power plant site.
A 10-MW distillate plant will require approximately 4 acres of land,
whereas a gas-fired plant of comparable capacity would require about 3 acres.
The difference is accounted for by tank storage facilities required by the
distillate-fired units. Land area allowances are made for boiler, turbine,
auxiliaries, oil storage, and electrical switchyard and waste disposal facili-
ties. For a 200-MW plant, land requirements are approximately 13 acres for
gas firing and 20 acres for oil firing. These estimates do not include an
allowance for employee housing, if such is required. Estimated full-load fuel
consumption for various sizes of natural-gas and distillate-fired plants are
shown in Table 4.5.
TABLE 4.5. Typical Full-Load Fuel Consumption for Natural Gas and
Distillate Steam-Electric Plants
Fuel
Rated Capacity
{ MW} Fuel Consum~tion
Natura 1 Gas 10 2.9 x 10 6 SCF/day
200 55 x 10 6 SCF/day
D i st i 11 ate 10 480 bb 1 /day
200 9170 bbl/day
4.24
4.2.3 Costs
The estimated costs to construct, operate, and maintain a facility in the
Railbelt region, with construction starting in 1982, are shown in Table 4.6.
TABLE 4.6. Estimated Cost for Gas-and Distillate-Fired
Steam-Electric Plants (1980 dollars)
Fuel Type Cost of Energy(a)
and Rated Capital O&M Distillate Cook Inlet Gas North Slope Gas
Capacit~ {MW) {$/kW) {$/kW/~r} {mills/kWh) {mills/kWh) {mills/kWh)
Distillate -10 1,920
200 1,330
Natural Gas -10 1,360
200 900
60
22
56
20
136
120
73
60
(a) Levelized lifetime costs, assuming a 1990 first year of commercial
operation. Fuel costs are provided in Appendix B.
4.2.4 Environmental Considerations
161
143
Water resource impacts of constructing and operating a natural-gas-fired
or oil-fired power plant are generally mitigated through appropriate plant
siting and a water, wastewater, and solid waste management program (refer to
Appendix D). These steam-cycle facilities present the least adverse impacts
of the combustion technologies. Significant or difficult to mitigate water
resource impacts are not anticipated.
The burning of oil or natural gas in steam-electric generators generally
presents the least adverse atmospheric impacts of the combustion technolo-
gies. The expected emissions from a natural gas or oil-fired power plant and
the associated regulatory framework are presented in detail in Appendix E.
so 2 emissions from the burning of residual fuels will be significant and
will require conventional scrubbers for large systems. In addition, NOx
emissions resulting from high-temperature combustion may be significant enough
to require the application of control techniques such as two-stage combustion.
4.25
The most significant and difficult to mitigate impacts from oil or
natural gas steam-cycle plants are associated with intake and discharge of
water (refer to Appendix D). These plants could be located near many major
aquatic resources on Cook Inlet and Prince William Sound or along major salmon
rivers in the Railbelt such as the Susitna or Copper Rivers. These plants use
the same amount or less water per megawatt than any other steam-cycle design
except the combined cycle. A 10-MW plant would use approximately 4,500 gpm
for once-through cooling systems and 80 gpm for recirculating cooling systems
(see Appendix I). Therefore, if the plants are properly sited and con-
structed, resulting impacts should be less than other steam-cycle plants
(except for combined-cycle units).
The greatest impact on the terrestrial biota resulting from natural gas
or distillate-fired steam-electric plants would be loss or alteration of habi-
tat. Land requirements for plant development should be approximately 6 acres
for a 10-MW facility and 20 acres for a 200-MW facility. Thus, these plants
require considerably less land area than other steam-cycle plants and impacts
are not expected to be significant. Also, natural gas and, in general,
distillate-fired power plants would probably be placed near existing developed
areas, thus avoiding environmental problems of plants sited in remote areas.
4.2.5 Socioeconomic Considerations
Socioeconomic impacts of siting a gas-or oil-fired steam-electric plant
will vary with both location and plant scale. The most likely sites for
oil-fired plants are near existing refineries or along distribution pipe-
lines. Other possible sites are along the railroad and major highway corri-
dors. Possible sites for gas-fired plants would be adjacent to the Cook Inlet
gas fields or near the gas transmission line that links Soldotna to Anchorage.
Completion of the North Slope natural gas pipeline would permit siting near
Fairbanks and along the Tanana Valley.
The flexibility of siting oil or gas-fired power plants, particularly an
oil-fired plant, results in numerous potential sites. If the access were
good, a 10-MW unit could be constructed in 20 working months. This estimate
4.26
is based 011 a p,a t k.qgetl l'le:l l.el' and skf,j-mot.m.t® awd 11 ary. ~u il;li11M t. A 2tl\!-'t•Wf
untt t-s. fi~l~ c.on~tr·yc1;ed 1 Vlhicfr ~JUt f'eq ;ui·re .qppr{l*'.ima:t.elt ~.5 to 5 Y~llOrs,
cje-pen<l i!J{L gn su~t1 v.~ri,qnle& a.;;. softe acc:essib fli~:y ~ .av<dlabil'l:t,y t}f wotk_ for'!:!',
-site ta;ndi·tiOf\h and \veather. 'T'aflk 'Ctlrlstr-UCtl,QJ1 for 9i1 f'·tt\ng \11~ atld to lt,fle
eol'ts:lru.c.tio!} V{ork far'!;!'!; .trut. the. ov'E!ra11 oonst rur;tiafi p:e..-tod shou l d ae tfua
si!me i!.S fo.r {I 9-<l-S-fi re!i j:j;l,a/lt .be~aus.e t ar* V~ofk can t:~):"oceecl s tmu. h.aneou~ ],)(
·w,itli na1ler nrrd. lUlrb,i n¢ if'ls't;a Hat, ron. Tli,e. edl'l stro.tt1 on WG):"·k· foY'c~s are ·es'tt ~
itr{l'tet;t tp J:~ea.k ~t 6~ Jteri$0~. fpr .an oil-fired un ~t a,ng SO f.qr a 11\\P'a:'ged .!:l as
l;lli ft:,. 'rhe d iff e r~en te il d~~ tQ. th,e ta:o~ a'!ld u'[i,) 0'~ i (lJ! fo,_C il ~ ~ i'es. (e~d~a for
.<J"n·fired t,jl'lits. 1'1ie .:wo.-N~· unlts ~re estli1)ated t.P ''e<i~if"g a Qe'ak wo rk 'fqt·r,e
~;f '$BO. QJI.f!r;ation~ 1 roctoRQJI(e i· is-e>St'imatetl at ·ao wor~ers (l;)'t tliE! fO -M~r plan,f:
a n.d 70 hr. the ~(10 -Mil ~n i b.
\~he1•eas 'lvery Slna li 11 C'Oiflll.Un it i es· ·\la.U id be 5 t /ll'l \fl'calJ.t"J y .aff ected by ti;Ie
influx of oot\~rlrtrdtoil wQr.k:e""• 0 srnai 1 ~ t~urm1.mitfas she.u 1d not. b~ <1 ftec:ted if
temp.&ra r;y hDU~intJ. 1$ pL"o.vfoeo for the wqrker~ (,see Append 1~ t\). L:btat;.~6t)s
thfit .m e~:t ttJ~s ~sma·ll" cd ·teri'.oY! and t na.t. are· near a d~S:tl"'i.b!.J.J;l.o n ;pi~e1~·11E
inc lude AllCl'!bl'.age., S.O 1 dotna·, and · fa i.Oo;;·nJ(~. 'Sec.ond.-a r y' l (J{a-.t:i.pn~ }nc lt.tde-Re.!'lff1',
Seward, ·Wa~~na, arid P,a·lmer. ftr.e: imP!l>Ct -9-f -,;ftirtg a Z:~O-~ pla!t't 'VIbu1il 'be
mi'nor i'n Anct~ora.!le , .;m(l rnod~r<ate in Fa itlra'*?· f'or a l1 9ther l pga:tJo os,
l rtC.ll.fdtn·g l<ema1,, Sew:a:rtf:-. Wa-silh and P.~llil~-r~ imP<!t.ts •.toi.dd r-a.119e from ~ignifi
c.ant to severe, ~timari1y due :li.o !:~1: ina.b:iHtJt of tl\o.se cottrnunit ieS> to "'bsar<b
dem<>nds on 1nfra ~tr u du ·t<a and vtib iic. ser~1t:~.s t h·at ac.c;:orni)&~Y J:h e· 1ar~ co11-·
struct-1o fl wor'k forcr;e ,,
£~pua 1 ap)f ·o~M· e-:<peflditul'les ~r!at would Ho1f oJJt Of-lipe re.gtdi) :dtre tc· tne
de~.elopmenf:. .or t)'le~e typ.~s of f~i Htie~ y~oul.d 1nc 1v\'te tJilvestme'n.t ln eqU1Jifllent
a]li:l ewPToyrre)'it. af ·spet:i.1.1 11'ted· ~LIPe~"Vl-st>rY 'J}etsonr\E 1· QYe · to the lllOd'el"ate-
s U':~~ col'l'$trw;:·t.i ·oJ1 wotk 'fqr:t;'e: an.d ~ 1 aUvely s~r!. itl$i:a:ll at1tm· ·per'hrd, Z&%' cyf
tl'je projef t .':s c:<1pit~ 1 ·~x.p.elli'liture ~ Ci!li b~ e!(pec~~ w fi.e rna@!! w·i:t.h in t'tre
J'e_g'ib!'f ~n d ~% w.siuld be sp¢)'1t, o:utsi l'le l\1.asJ¢a. l'liine uerce'nt Of 'tllle Q81M .el(P.en-
ditur.es wo.u ld most Ti'kel..Y •oe: spent ouhtc:le Ala:S~·a.
4.2.6 Potential Application in the Railbelt Region
The sources of distillate fuel in the Railbelt are presently confined to
the refineries at Kenai and at North Pole (Figure 4.4). Petroleum pipelines
carry refined products from the port of Whittier to Anchorage. These areas
are prime sites since fuel refining or pipeline transmission systems are
already in place.
Areas served by good transportation facilities connecting to the refiner-
ies can also be considered for distillate-fired generation. These areas would
include the Kenai Peninsula, locations adjacent to the Alaska Railroad, and
major highway corridors. Highway transport would likely be feasible only for
smaller plant sizes. For example, a 10-MW distillate-fired plant would
require two to three tank truck deliveries per day.
The only practical method for transporting natural gas in quantity is by
pipeline. Potential sites are limited to locations where existing service is
available or where it can be easily provided. The Anchorage, Cook Inlet, and
Kenai regions are well suited because of their proximity to refinery capacity,
wells, and gas transmission systems. The proposed North Slope gas pipeline
would provide natural gas to the Fairbanks area.
Natural-gas-or distillate-fired steam-electric plant could potentially
be used to provide baseload power to the Railbelt region. Of the two fuels,
distillate most likely would not be used in the Anchorage area because natural
gas is available at a substntially lower cost. Although natural gas is not
presently available in the Fairbanks area, the present excess of installed
capacity would make constructing a distillate-fired steam-electric units in
the near term impractical. In the longer term, the construction of the
Anchorage-Fairbanks intertie may obviate the need for new baseload capacity in
the Fairbanks area. If new capacity were required in Fairbanks, future avail-
ability of North Slope natural gas via the proposed North Slope natural gas
pipeline would probably make natural gas the fuel choice between oil and
natural gas.
4.28
NATURAL GAS &
PETROLEUM
J:-,::-··.:4NATURAL GAS FIELDS.
-OIL FIELDS·
······PROPOSED NORTH SLOPE
NATURAL GAS PIPELINE
-·-NATURAL GAS PIPELINES
-PETROLEUM PRODUCTS PIPELINE
--NORTH SLOPE CRUDE PIPELINE
SCALE
0 50 iOOMiln
FIGURE 4.4. Natural Gas and Petroleum Supplies in the Railbelt Region
4.29
Currently, the Fuels Use Act effectively constrains development of natu-
ral gas or distillate-fired steam-electric plants from all but minor applica-
tions. The Fuels Use Act prohibits use of natural gas or distillate for
baseload electric generating facilities exceeding 10 MW in capacity. Because
natural-gas-or distillate-fired steam-electric plants are primarily baseload
units, this technology is effectively excluded from future development except
under limited situations in which exemptions to the Fuels Use Act may be
obtained. Provisions of the Fuels Use Act, including conditions under which
exemptions may be obtained, are discussed in Appendix N.
4.30
4.3 BIOMASS-FIRED STEAM-ELECTRIC GENERATION
Biomass fuels available in the Railbelt region for power generation
include sawmill residue (wood waste) and fuel derived from municipal waste
(refuse-derived fuels). Limited quantities of waste oil are also available.
Wood waste has been used for industrial power and process steam generation for
many years, especially in the timber industry. Use of refuse-derived fuel is
a more recent concept and is less well developed in the United States.
4.3.1 Technical Characteristics
Conversion technologies suitable for using biomass fuels include direct-
fired steam-electric plants and several thermochemical conversion and/or chem-
ical-based processes for synthetic gas and liquid fuels production. Various
gasifiers presently are being developed that could be used for process heat
and retrofits of oil-and natural-gas-fired boilers. Suitable gasifiers may
be commercially available in less than 5 years if adequate development support
occurs (Office of Technology Assessment (OTA) 1980). Methanol synthesis is
the near-term option for liquid fuels production. Whereas wood-to-methanol
plants are commercially available, herbage-to-methanol processes remain to be
demonstrated. Various other thermochemical conversion processes also are
being developed with considerable promise for future new and improved fuels
and chemicals syntheses.
Another biomass conversion operation that may prove suitable for produc-
ing gas for the retrofit of natural-gas-fixed systems is anaerobic digestion.
This biological process produces a gas containing methane and carbon dioxide.
Appropriate feedstocks include many wet forms of biomass, such as animal
manure and some aquatic plants. Digesters for onfarm production of gas from
animal manure appear to be the most likely near-to-midterm applications.
Various digesters using different feedstocks need to be demonstrated before
they can be considered commercially available.
Biomass-fired power plants are distinct from fossil-fired units in that
maximum plant capacities are relatively small and specialized fuel handling
equipment is required. The generally accepted capacity range for biomass-
4.31
fired power plants is approximately 5 to 60 MW (Bethel et al. 1979; Jamison
1979). Smaller plant sizes are generally used because of the expense of
transporting low-energy-density biomass fuels appreciable distances.
Design Features
The core of a biomass-fired steam-electric power plant is the boiler and
the turbine generator. Auxiliary systems are provided for fuel receiving,
storage and processing, stack gas cleanup, bottom and fly-ash handling, and
condenser cooling.
Because biomass fuels have relatively low heat values and bulk densities
in the 10 to 20 lb/ft 3 range, and because they are variable in particle
size, moisture content, and contamination, fuel handling systems are of criti-
cal importance. Particle sizes are reduced by "hogging•• or grinding rather
than by pulverizing. Materials handling equipment also must be larger than
that used for a coal plant of equivalent capacity to handle the increased
volumes of material. Finally, systems for fuel classification, contaminant
removal, and possibly drying must be provided.
Preferably, municipal waste will be shredded and classified, and sorted
to minimize contamination by metals and glass objects. Metallic and other
noncombustible objects must be removed, usually magnetically. Mass burning
(firing of unsorted refuse), while practical in some cases, results in less
efficient operation of equipment.
Fuel handling systems in the Railbelt region will have to be designed to
accommodate cold conditions and frozen fuel. Such systems are routinely
installed in northern climates. Since the supply of any one biomass fuel may
be insufficient to support a power plant, provisions may have to be made for
dual-fuel firing. For example, plants constructed to burn refuse-derived fuel
may be supplemented by coal. Research in fuel preparation and fuel gasifica-
tion is under way to improve upon and to overcome limitations in the efficiency
of biomass power plant systems caused by moisture content, low bulk densities,
and modest heating values.
4.32
Performance Characteristics
The typically high moisture content of biomass fuels~ as well as small
scales of operation~ introduces thermal inefficiencies into the power plant
system. However~ biomass plant efficiencies improve rapidly as plant scale
increases. Heat rates as a function of plant size are shown below (Tillman
1981).
Rated Capacity
(megawatts)
5
15
25
35
50
Heat
Rate
(Btu/kWh)
20~000
15~100
14 ~200
14~100
14~000
Biomass facilities~ which
demonstrated high reliability.
of 80 to 90% can be achieved.
would be operated as base-loaded units~ have
Industrial experience shows that load factors
High load factors are attained by constant
attention to maintenance and by proper design. Unit life is forecasted to be
20 years.(a)
4.3.2 Siting and Fuel Requirements
Biomass fuels are generally inexpensive but are characterized by modest
heating values. Typical net heating values of biomass fuels are compared to
coal below (Metcalf and Eddy Engineers 1979):
Fuel
Refuse-derived fuel
Waste Oil
Wood
Coal
Heat Value
Btu/lb
6~700
19~250
4~500
9~000
(a) Electric Power Research Institute. 1982 (Draft). 1981 Technical
Assessment Guide. Electric Power Research Institute~ Palo Alto~
California.
4.33
The rate of fuel consumption is a function of plant efficiency and
capacity. Fuel consumption as a function of plant capacity is presented
in Table 4.7 for a wood waste-fired plant (Tillman 1981).
TABLE 4.7. Wood Waste Requirements by Plant Size
Truck Rail
Daily Loads Cars
Rated Capacity Requirements Per Day Per Day
{ MW) {tons) {Aeeroximate) {Aeeroximate)
5 260 10 7
15 600 25 15
25 960 40 25
35 1300 50 35
50 1900 75 50
Siting requirements for biomass-fired power plants are dictated by the
fuel quality, fuel source location,, and cooling water requirements. Because
biomass fuels are high in moisture content and low in bulk density, economical
transport distances are unlikely to exceed 50 miles (Tillman 1978). Biomass
power plants are thus typically sited close to the fuel source. Sites must be
accessible to all-weather highways or rail lines since biomass fuels are usu-
ally transported by truck or rail car.
Proximity to the fuel source may be the most limiting factor, although
sites also must be accessible to water for process and cooling. Land area
requirements are a function of scale, extent of fuel storage, and other design
parameters. Typically, a 5-MW, stand-alone power plant will require 10 acres;
a 50-MW, stand-alone plant will require 50 acres. These areas are quite large
relative to plant capacity because they must accommodate fuel receiving facil-
ities, fuel storage piles, materials handling and preparation systems, boilers,
feedwater treatment systems, turbine generators, stack gas cleaning and ash
disposal facilities. Substantial buffer zones may be required for a plant
using refuse-derived fuel for odor and vermin control requirements. A one-to
three-month fuel supply should be provided to ensure fuel availability during
prolonged periods of inclement weather. For plants cofired with coal, coal
4.34
preferably might be used for long-term storage because of its greater energy
and the difficulties of storing refuse-derived fuel for long periods of time.
4.3.3 Costs
Biomass-fired power plants, particularly small-scale plants, are expen-
sive to construct. Capital and O&M costs for relevant-scale biomass facili-
ties in Alaska are presented in Table 4.8. Capital and O&M costs were derived
from SRI (1980) and are based on a direct-fired, electric generating plant
using wood waste as fuel. The cost of power estimates in the table are based
on use of dual fuel firing of coal and refuse-derived fuel with the proportion
of refuse increasing over the life of the facility. Estimated coal and refuse-
derived fuel prices are provided in Appendix B.
TABLE 4.8. Estimated Costs for Biomass-Fired Steam-Electric Plants
(1980 dollars)
Rated
Cost of Energy(a) Capacity Capital O&M
{ MW} { $/kW} {$/kWhr} { m i 11 s /kWh}
25 (Anchorage) 2590 200 67
20 (Fairbanks) 2900 200 78
50 (Anchorage) 2450 200 74
(a) Levelized lifetime costs, assuming a 1990 first year of commercial
operation. Fuel costs are provided in Appendix B.
4.3.4 Environmental Considerations
Water resource impacts associated with the construction and operation of
a biomass-fired power plant are not expected to be significant or difficult to
mitigate because of the small plant capacities that are considered likely.
The burning of biomass could lead to significant impacts on ambient air
quality. The expected emissions from a biomass facility and the regulatory
framework are presented in detail in Appendix E. Impacts arise largely from
emissions of particulate matter and NOx. Particulate emissions can be
controlled with electrostatic precipitators or baghouses. The tradeoff
between emission controls and additional project costs must be assessed at
4.35
each facility, but wood-or coal-burning facilities larger than about 5 MW
will require air pollution control systems to meet federal New Source
Performance Standards.
Potentially significant impacts to aquatic systems from biomass plants
are similar to other steam-cycle plants and result from water withdrawal and
effluent discharge (refer to Appendix F). Although these plants are second
only to geothermal facilities in rate of water use per unit of capacity
(730 gpm/MW), the total use for a typical plant would only exceed that of
small (10-MW) oil and natural-gas-fired plants because of the small size of
prospective plants. Approximately 18,250 gpm and 362 gpm of cooling water
would be required for once-through and recirculating cooling water systems,
respectively. Proper siting and design of intake and discharge structures
could reduce potential impacts.
The major impact on the terrestrial biota is the loss or modification of
habitat. Land requirements for biomass-fired plants, approximately 50 acres
for a 50-MW plant, are similar to those of coal-fired plants of equivalent
capacity and are generally greater than those of nuclear and the other steam
cycle power plants on an acres-per-MW basis (see Appendix G).
Potential locations of biomass-fired power plants in the Railbelt region
include Fairbanks, Soldotna, Anchorage, and Nenana. All four areas contain
seasonal ranges of moose. Waterfowl also inhabit these areas with high use
occurring along the Matanuska and Susitna River deltas near Anchorage, and the
areas around Nenana. The Soldotna region also contains populations of black
bear, and caribou calving areas, migration corridors, and seasonal ranges.
Populations of mountain goats, caribou, and Dall sheep occupy habitats in the
Susitna and Matanuska River drainages near Anchorage. Impacts on these animal
populations will depend on the characteristics of the specific site and the
densities of the wildlife populations in the site area. Due to the relatively
small plant capacities involved, however, impact~ should be minimized through
the plant siting process.
4.36
4.3.5 Socioeconomic Considerations
To construct and operate biomass-fired facilities, relatively small labor
forces are required. For 15-to 30-MW plants, a construction work force of 65
would be required, whereas operating and maintenance would require approxi-
mately 25 people. Construction periods would range from 18 months to 3 years
(excluding the licensing process). Possible locations for biomass-fired
plants include Anchorage, Fairbanks, Soldotna and Nenana. Impacts of bio-
mass-fired plants, as well as plant size, will vary among these locations.
Anchorage, Fairbanks, and Soldotna should be able to accommodate the construc-
tion of a 5-to 50-MW plant with minimal impacts to the social and economic
structure of these communities.
Nenana, an Alaskan native village, has a population of 471, and the sur-
rounding area has an aggregate population of approximately 1,000. Because of
Nenana•s small population size and undeveloped infrastructure, the impacts of
plant construction on Nenana may be significant and will increase with plant
size. The transfer of workers and their families for a period of 1 to 3 years
may cause a strain on the social fabric of Nenana and may create demands for
infrastructure in the nearby community of Anderson (pop. 390). These impacts
can be mitigated by limiting the scale of the plant.
The breakdown of capital expenditures is expected to be 60% outside the
Railbelt and 40% within the region. Expenditures due to a large capital
investment will be offset by employment of an Alaskan labor force. Approxi-
mately 10% of the O&M expenditures would be spent outside the region.
4.3.6 Potential Applications in the Railbelt Region
Potential sources of biomass fuels in the Railbelt region include mill
residue from small sawmills at Soldotna, Anchorage, Nenana, and Fairbanks
(Figure 4.5), and municipal waste from the cities of Fairbanks and Anchorage.
Fuel availability for wood residue in the Railbelt region is shown in
Table 4.9 (U.S. Department of Agriculture 1978).
Only broad ranges of wood residue availability have been developed
because little information is available on lumber production as a function of
markets, lumber recovery, and internal fuel markets. The residues considered
4.37
TABLE 4.9. Fuel Availability for Wood
Area
Greater Anchorage
Kenai Peninsula
Fairbanks
Nenana
Wood Fuel
(tons/day)
200-600
60-180
10-30
40-140
here include bark from debarkers, chips, slabs, sawdust, and planer shavings.
Some of these residues could be used as fuel since by-product markets (e.g.,
pulp mills, particle board plants) for such materials appear to be absent.
Harvesting of trees solely to fire electric power plants does not appear to be
desirable due to the slow regeneration of forests and the availability of coal
at competitive prices.
Estimated future availabilities of refuse-derived fuel for the Anchorage
and Fairbanks areas are shown in Table 4.10. Forecasts for Anchorage through
2000 are taken from Metcalf and Eddy Engineers (1979); years 2005 and 2010 are
extrapolated using linear regression. Fairbank's estimates are based on
ratios between Anchorage and Fairbanks municipal waste production taken from
Nebesky (1980). Quantities given are average daily tons of refuse-derived
fuel product, processed using ferrous metal magnetic separation followed by
air classification. Estimated heat value of the product is 6714 Btu/lb.
In the Railbelt region biomass power plants using municipal refuse sup-
plemented with wood residue and coal may potentially contribute up to 5% of
future power needs. With that potential, the biomass-fired units would be
central station installations capable of serving individual community load
centers or interconnection to a Railbelt power grid.
Since the biomass-fired systems are relatively small, they are particu-
larly adaptable to the modest incremental capacity needs that are forecast for
the Railbelt region. The most probable application of the technology appears
to be a small plant at Anchorage, which is fired by refuse-derived fuel, waste
oil, and such wood residue as may be available and is supplemented by coal
4.38
""'tJ.J
4'1,1-t~d/j
;'S,~~~,..~ •n,..
~~)~"~
t·
., JDfi ;;p'-l•t'liiC 'p;~{,<,Oif!tol:l t"Os~i
-·...'!.!!!tilt. ,"4't.Ja
,.
MAJOR CONCENTRATIONS AND
CAPACITIES OF SAWMILLS
in Thousand Board Feet per Day
(MBF/D)
SOURCE: Alaska Sawmill Directory.
"""-·-......
SCALE 1: 2 500 000
NATIONAL GEODETIC VERTICAL DATUM OF 1929
ALASKA RAILBELT
REGION
FIGURE 4.5.
USGS ALASKA MAP E
FIGURE 4.5.
4.39
Major Concentrations and
Capacities of Sawmills in
the Railbelt Region
TABLE 4.10. Estimated Refuse-Derived Fuel Production
(average tons/day)
Year Anchorage Fairbanks
1985 396 150
1990 502 190
1995 640 240
2000 777 290
2005 890 330
2010 1010 380
firing as necessary. A smaller plant at Fairbanks may also be feasible, fired
by refuse-derived fuel, waste oil and wood residue from Nenana and Fairbanks
and supplemented by coal.
4.41
4.4 NUCLEAR LIGHT WATER REACTORS
Nuclear steam-electric generation is a mature, commercially available
technology. At present, some 73 units with a total installed capacity of
54,000 MW are operable in the United States. An additional 104 units repre-
senting approximately 116,000 MW of capacity have either been ordered or are
in some phase of the licensing or construction process. Canada, France,
Germany, Japan, Sweden, and the United Kingdom also have a large nuclear
steam-electric capacity based either on U.S. developed technology or on tech-
nologies developed within those respective countries. In spite of this exper-
ience, nuclear power is experiencing social and political problems that might
seriously affect its viability. These problems manifest themselves in licens-
ing and permit delays and therefore are important to the Alaskan electrical
supply situation, given their cost and schedule impacts.
Diminished load-growth rates, concerns over nuclear weapons prolifera-
tion, adverse public opinion fueled by the Three-Mile Island (TMI) accident,
expanding regulatory activity (also fueled by TMI), and lack of overt politi-
cal support have resulted in no new domestic orders for nuclear units since
1977. The industry currently is maintaining its viability by completing
backlog work on domestic units and by pursuing new foreign orders. Although
the current administration has indicated support for nuclear power, not enough
time has passed to observe tangible results.
4.4.1 Technical Characteristics
The principal commercial power reactor designs used in the United States
are based on the use of natural water (11 light water 11
) as the reactor coolant.
Light water reactors (LWRs) produce electricity using a steam cycle similar to
that of fossil-fuel-fired power plants. However, in a nuclear power plant the
heat used to raise steam is obtained by fissioning uranium fuel in a nuclear
reactor.
The economics and design trends since the introduction of commercial
nuclear power have evolved to the point that almost all plants being con-
structed are in the 800-to 1,200-MW range. Because of these plant sizes and
the resulting costs, nuclear power is a viable option only for utilities hav-
ing a large electrical baseload. (Nuclear units with generating capacities
4.42
ranging from 50 to 700 MW are operating in the lower 48 states. However,
these are demonstration and first and second generation nuclear facilities and
represent unit designs not currently available from domestic vendors.) Smal-
ler plant designs could be obtained from various vendors but are not currently
commercially available. Smaller designs could incur licensing difficulties
and increased costs because of the lack of standardization. Smaller plants
(about 500 MW) are available from foreign suppliers but, again, could incur
licensing difficulties.
Two LWR designs, boiling water reactors (BWR) and pressurized water reac-
tors (PWR), are in common use. In BWR designs, coolant water circulates
through the core and is heated to form steam at about 1,100 psi for direct use
in the turbine. PWR designs include primary and secondary coolant loops
(Figure 4.6). The primary loop is operated at high pressure (about 1700 psi)
to maintain the primary cooling water in liquid form at all times. The hot
primary water is circulated from the reactor to a heat exchanger (steam
generator) where steam is formed in the secondary loop for use in the turbine.
Reactor designs using other heat exchange systems exist but are not common in
the United States.
REACTOR
WATER
REACTOR
COOLANT
PUMP
FIGURE 4.6.
STEAM
STEAM
STEAM
GENERATOR
WATER
TURBINE
PWR Steam-Electric Plant
4.43
COOLING
WATER OUT
_COOLING
WATER IN
Performance Characteristics
Nuclear power generating plants are typically designed for operation as
baseload units because of their characteristically high capital costs and low
fuel and operating costs. The more power produced from the plant, the lower
cost per unit of electricity delivered. Therefore, nuclear power plant capa-
city functions are typically close to plant availability factors.
Plant availability is determined by scheduled and unscheduled outages.
Scheduled outages for nuclear facilities are based on periodic maintenance
requiring plant shutdown and refueling requirements. Typically, refuelings
are scheduled annually, and approximately one third of the fuel assemblies are
replaced. Because the plants must be shut down for refueling, refueling is
normally done during periods of low electrical demand. Typical planned
(scheduled) outage rates for LWR plants are about 13%.(a)
Unscheduled outages are due to equipment malfunction. Much of the elec-
trical, heat rejection, and in the case of PWRs, steam system equipment of a
nuclear reactor is not fundamentally different than similar components of a
conventional steam-electric plant, and similar reliability is experienced.
However, the equipment and controls of the primary (reactor) systems are far
more complex and sophisticated than in a conventional steam-electric plant.
Unscheduled outages due to malfunction of these systems have generally been
higher than anticipated, leading to higher unscheduled outage rates overall
for nuclear plants than for fossil-fired steam-electric plants. A particu-
larly significant problem in PWR plants has been corrosion and leakage of
steam generator heat exchange tubing. Typical, equivalent unplanned outage
rates for LWRs are currently estimated to be approximately 22%.(a)
The typical equivalent availability including both planned and equivalent
unscheduled outages of LWR plants is estimated to be approximately 68%.(a)
The design life of LWRs is generally 40 years; an economic life of 30 years is
typically used.
(a) Electric Power Research Institute. 1982 (Draft). 1981 Technical
Assessment Guide. Electric Power Research Institute, Palo Alto,
California.
4.44
4.4.2 Siting and Fuel Requirements
Nuclear plant siting has more constraints than other technologies because
of stringent regulatory requirements. These requirements result from the
potential consequences of accidents involving the release of radioactive
materials. These requirements, however, would not be expected to bar nuclear
power development in Alaska.
Under the siting criteria of the U.S. Nuclear Regulatory Commission (NRC)
(10 CFR 100), nuclear facilities must be isolated to the degree that proper
exclusion areas and low population zones may be maintained around the facil-
ity. Nominal distances ranging from 2,000 to 5,000 ft to the nearest site
boundary (encompassing areas of 250 to 2,000 acres) usually are sufficient to
meet the first criterion for almost any size nuclear facility. Additionally,
a physical separation of 3 to 5 miles from areas of moderate population den-
sity allows compliance with the second criterion. Because of the Railbelt's
generally low population densities, these requirements are of little conse-
quence in the region. Land required for the construction force campsite could
serve as the plant exclusion area when the plant is completed.
Seismic characteristics of a·potential site are a major factor in plant
siting because the nuclear plant must be designed to accommodate forces that
result from earthquake activity. Seismic zones and major faults of the
Railbelt region are shown on Figure 4.7. Constructing a nuclear plant in
Zone 3 would very likely require expensive plant designs and a lengthy licens-
ing process. Siting a plant in Zone 2 would be less difficult. In either
case, extensive preapproval geotechnical investigations would be required.
Nuclear plants most likely would not be excluded from the Railbelt on a
seismic basis since nuclear plants have been designed and constructed on a
worldwide basis in each of the types of seismic zones found in the Railbelt
region.
In addition to meeting the specific nuclear safety requirements of the
NRC, a nuclear plant site must meet the more typical criteria required of any
large, steam-electric generation technology. A 1,000-MW nuclear project rep-
resents a major, long-term construction effort, involving the transportation
4.45
of bulky and heavy equipment and large quantities of construction materials.
Transportation capable of handling these items limits the potential Railbelt
sites to the corridor along the Alaska Railroad and port areas of Cook Inlet
and Prince William Sound. The requirement for remote siting must be balanced
against the cost of transmission facilities required to deliver power to load
centers.
Substantial heat is rejected by a 1,000-MW plant. Therefore, a potential
site must have enough cooling water to remove the heat according to environ-
mental criteria for thermal discharges. Once-through cooling of a 1000-MW
facility requires a water flow of approximately 3,000 cfs and would almost
certainly require coastal siting. Because closed-cycle systems require less
water than once-through systems (probably less than 100 cfs), siting options
can include some of the rivers of the region (Appendix I).
Reactor fuel, a highly refined form of enriched uranium fabricated into
complex fuel elements, is not produced in Alaska and would have to be obtained
from fuel fabrication facilities located in the western portion of the lower
48 states. The proximity of the nuclear plant to the fuel source is rela-
tively unimportant because uranium is a high-energy density fuel, and refuel-
ing is accomplished on a batch rather than a continual basis. Refueling is
required about once a year and is usually scheduled during summer months in
cold climates to prevent weather-induced delays and to coincide with periods
of low electrical demand.
Recent estimates of U.S. uranium supply show that ample low-cost uranium
resources exist to support about ten times the number of reactors now in ser-
vice or under construction (Piepel et al. 1981). When all low-cost uranium is
committed, the fast breeder reactor (FBR), which produces a surplus of fuel-
grade plutonium, will become commercially feasible. Because fuel-grade plu-
tonium can be used to fuel LWRs, long-term fuel supply should not be a limiting
factor. Although Alaska has identified uranium deposits, the economic forces
for developing the resource are tied to the world market conditions rather
than to the use of uranium as fuel for nuclear plants located in Alaska.
4.46
.,,
I
I llA~HIJt .. IN
lltll CASll( UIN. N•rli..; J·HO
l lwtl~ttrnla
Hous.aO
FAULTS AND SEISMIC AREAS
SOURCE: Compiled in 1971 by the Federal Field
Committee for Development Planning in Alaska.
-Seismic Zones Richter Scale
1-Minor Structural Damage (3.o-4.5)
2-Moderate Structural (4.5-6.0)
Damage
3-Major Structural Damage (6.Q-B.B)
---Major Faults
SCALE 1: 2 500 000
0 50 100
MILES
NATIONAL GEODETIC VERTICAL DATUM OF 1929
ALASKA RAILBELT
REGION
FIGURE 4.7.
USGS ALASKA MAP E
FIGURE 4. 7.
4.47
Faults and Seismic Areas
in the Railbelt Region
4.4.3 Costs
The capital cost of a nuclear plant is high relative to other baseload
technologies. No overall major cost distinction can be made between the two
types (BWR and PWR) of reactors. Each project must be evaluated to determine
the most economical type for installation. The cost of the nuclear steam
supply system (reactor steam generators and auxiliaries) is higher for a PWR
because of the added complexity of the secondary fluid loop; however, this
cost is offset by the higher costs of the BWR's containment building and
shielding. Conceptual level estimated costs for construction and operation of
nuclear power plants in the Railbelt are shown in Table 4.11.
TABLE 4.11. Estimated Costs for Nuclear Power Plants (1980 dollars)
Plant Type and
Cost of Energy(a) Rated Capacity Capital O&M Fuel
(~) ($/kW) ($/kW/Yr) (mills/kWh) (mills/kWh}
PWR -1000 1850 24 7 31
BWR -1000 1850 24 7 31
(a) Levelized lifetime costs, assuming a 1990 first year of commercial
operation.
The capital costs of Table 4.11 are overnight construction costs and do
not include escalation or interest during construction. The capital cost
estimate is based on observed capital costs of $975 per installed kilowatt for
the lower 48, adjusted to Alaska conditions using an adjustment factor of 1.9.
O&M costs are based on estimated Lower 48 O&M costs of 16 $/kWh/yr,
adjusted to Alaskan conditions using a factor of 1.5. Fuel costs are
discussed in Appendix B.
4.4.4 Environmental Considerations
Water resource impacts associated with constructing and operating a
nuclear power plant are generally mitigated through appropriate plant siting
and a water and wastewater management program (Appendix 0). Note, however,
that due to the generally large sizes of nuclear power stations, the magnitude
of water withdrawal impacts for a given site may be greater than those for
4.49
other baseload technologies. Magnitude, however, does not necessarily imply
significance. A favorable attribute of nuclear power is the lack of waste-
water and solid waste associated with fuel handling, combustion, and flue-gas
treatment and experienced with combustion-based technologies.
The generally large unit size for a nuclear facility indicates that these
plants would be the largest water users of any steam-cycle plants; approxi-
mately 310,000 gpm would be used for a once-through cooling system and
6,200 gpm would be used for a recirculating cooling water system. Their rate
of use (gpm/MW) is also higher than many other technologies (Appendix D)
because of somewhat lower plant efficiencies. Potential impingement and
entrainment impacts would therefore be somewhat higher than for other baseload
technologies of comparable size. Detrimental effects of discharge may also be
high because of the large quantity of water used.
In addition to the effects on aquatic and marine ecosystems resulting
from cooling water withdrawal and thermal discharges, common to other steam-
cycle plants, nuclear facilities have the potential for routine low level, and
possibly accidental higher level discharge of radionuclides into the aquatic
environment. However, under normal operation the discharge water contains
fewer hazardous compounds than may be found in other steam-cycle wastewaters.
Nuclear power plants cause no deterioration in air quality other than the
routine or accidental releases of radionuclides. A complex meteorological
monitoring program is required to assess the potential dosages of these radio-
active materials. The wind speeds and dispersive power of the atmosphere play
a crucial role in diluting the effluent. Generally, sites in sheltered val-
leys and near population or agricultural centers are not meteorologically
optimal. Large amounts of heat are also emitted by nuclear power plants.
Some modification of microclimatic conditions onsite will be noted, but
offsite these modifications will be imperceptible. The NRC will ensure that
the ambient meteorological conditions are properly measured and considered in
the siting of a nuclear power plant. These constraints will not preclude the
construction of such a facility in the Railbelt region.
The predominant impact on terrestrial biota is habitat loss. Nuclear
power plants require land areas (100 to 150 acres for a 1000-MW plant) second
4.50
in size to those of coal-and biomass-fired plants (on a per-MW basis). Fur-
thermore, lands surrounding the plant island are at least temporarily modified
by auxiliary construction activities (i.e., laydown areas, roads, etc.).
These lands possibly could be partially recovered through revegetation. Most
of the exclusion area would remain undisturbed.
Other impacts difficult to mitigate could be accidental releases of
radionuclides. The effects of such accidents on soils, vegetation, and ani-
mals could be substantial. However, releases resulting in substantial impacts
are regarded as highly unlikely. The TMI incident, for example, caused no
contamination of the surrounding area. Proper plant design and construction
should prevent these releases under normal operating conditions.
4.4.5 Socioeconomic Considerations
A construction work force with a peak of 1,300 workers is typically
required for a 1,000-MW nuclear plant. In comparison to other baseload tech-
nologies, a nuclear power plant has the greatest potential to adversely affect
communities. The construction of a nuclear facility could severely strain
nearby communities• abilities to provide housing, public services and facili-
ties, and commercial goods and services. Highly sk~lled workers would be
required during both the construction and operation phases, resulting in the
migration of much of the work force. The in-migration of construction workers
would be augmented by spouses and dependents. The long duration of the con-
struction period (7 to 10 years) would cause a permanent expansion of the
existing infrastructure.
Only within the vicinity of Anchorage, where the infrastructure could
support a large population influx, could a nuclear facility be constructed
without major socioeconomic impact. The siting of a nuclear plant 25 to 50
niles from Anchorage could induce further urban sprawl. Communities with
1opulations of 5,000 or less would experience severe impacts.
Depending on location of the site, a new town could be built to accommo-
lte workers and their families. When construction was finished, most of the
)nstruction work force and their families would leave the area, leaving an
4.51
operating and maintenance crew of approximately 180. The large out-migration
would leave the community with abandoned housing and facilities and would
drastically alter the social fabric and local economy.
Approximately 60% of the project capital expenditures would be spent out-
side the Railbelt since all equipment and most of the labor would be imported
from the lower 48 states. Approximately 11% of O&M expenditures would be spent
outside the region.
4.4.6 Potential Application in the Railbelt Region
As discussed in Section 4.4.2, fuel availability and siting constraints
would probably not significantly impair construction of commercial nuclear
power plants in Alaska. Potential sites, however, would have to be near
existing or potential port facilities or along the Alaska Railroad because
large amounts of construction material and very large and heavy components
would have to be delivered to the site. Interior sites would present more
favorable seismic conditions.
More constraining than site availability is the rated capacity of avail-
able nuclear units in comparison with forecasted electrical demand in the
region. The forecasted interconnected load of 1,800 MW in 2010 (see Chap-
ter 2.0), will probably be too small to accommodate even the smaller nuclear
power plants, primarily from the point of view of system reliability effects
and surplus capacity likely to result from introducing such a large facility.
Incorporating a nuclear power plant into the Railbelt system would require
significant reserve capacity to provide generating capacity during scheduled
and unscheduled outages.
In addition to the technical/economic considerations impacting the use of
nuclear power in Alaska, current State statutes specifically exclude nuclear
energy production from the definition of power projects that can be funded
through the Power Development Fund [see Power Authority Act as amended
4483.230(4)].
4.52
4.5 GEOTHERMAL GENERATION
Potential high-temperature geothermal resources have been identified in
the Wrangell Mountains, east of Glennallen, and in the Chigmit Mountains, west
of Cook Inlet. Several low-temperature geothermal sites are found in the
Railbelt (Figure 4.8). Geothermal energy may be used for electricity genera-
tion, which usually requires temperatures of at least 280°F, or for direct
applications, which require temperatures less than 280°F. Direct heating
applications include space heating for homes and businesses, applications in
agriculture and aquaculture, industrial process heating, and recreational or
therapeutic use in pools.
Three types of geothermal resources hold potential for development:
hydrothermal, geopressured brine, and hot dry rock. Although hot dry rock
resources represent over half the U.S. geothermal potential, satisfactory
technologies have not yet been developed for extracting heat from this
resource. Hydrothermal systems are in commercial operation today. Hydrother-
mal geothermal resources are classified as vapor-dominated or liquid-dominated
systems. A typical vapor-dominated system produces saturated to slightly
superheated steam at pressures of 435 to 500 psi and temperatures of approxi-
mately 450°F. Liquid-dominated systems may be subdivided into two types,
those producing high enthalpy fluids greater than 200 calories/gram (360
Btu/lb), and those producing low enthalpy fluids less than 200 calories/gram.
Wells drilled into high enthalpy, liquid-dominated systems produce a mixture
of steam and water. The steam may be separated for turbine operation to pro-
duce electricity. Lower enthalpy fluids may be useful for direct heating
applications (Considine 1976).
4.5.1 Technical Characteristics
Fundamentally, a geothermal-electric plant uses geothermal heat to form a
vapor (either steam or a low boiling point organic material), which is used to
drive a turbine generator. Several different geothermal plant designs are
available, or have been proposed, as discussed below.
The two basic components of a geothermal electric plant are the well
field and the power plant. The well field includes production wells, piping
4.53
GEOTHERMAL RESOURCES~ r-t
• HOT DRY ROCK RESOURCES
• LOW TEMPERATURE LIQUID
SCALE
100Miln
FIGURE 4.8. Geothermal Resources in the Railbelt Region
4.54
for conveying fluid to the power plant, piping for returning fluid to the well
field for reinjection and the reinjection wells. The power plant includes the
turbine, switchyard, and heat rejection equipment. Other equipment, including
pumps, steam-flashing drums, and heat exchangers may be located either in the
well field or at the power plant, depending upon the type of system used.
Based on the economic tradeoff between the economics of scale inherent in
larger power plant sizes and the costs associated with collecting and return-
ing fluid to larger well fields, the optimal geothermal-electric plant size
has been determined to be approximately 50 MW. Geothermal resources having
greater potential would likely be developed using multiple plants of 50-MW
capacity. Wellhead units of less than 1 MW capacity are also available.
Design Features
The specific type of plant that could be selected to develop Alaskan
geothermal resources will depend on the temperature, pressure, and quality of
the geothermal fluid. Five principal geothermal plant designs have or are
being developed: 1) dry steam, 2) flashed steam, 3) binary plants, 4) a
combination of flashed steam and binary fluids, and 5) hybrid plants. Dry
steam and flashed steam plants are currently commercially available. Binary
plants are in the early stages of commercial demonstration with availability
for commercial orders anticipated about 1986.(a) The hybrid plant type is
not yet commercially available.
In a dry steam plant, steam is brought to the surface via extraction
wells and piped directly through manifolds into turbines, which in turn drive
the generators. On exiting from the turbine, the steam is condensed in a
cooling tower or by direct contact with cooling water and is injected back
into the reservoir.
Flashed steam plants operate on steam flashed from depressurized hot
water brought to the surface. Utilization efficiency can often be increased
by flashing at decreasingly lower pressures (multiple flashing) to obtain as
(a) Electric Power Research Institute. 1982 (Draft). 1981 Technical
Assessment Guide. Electric Power Research Institute, Palo Alto,
California.
4.55
much steam as possible from a given volume of water. Once the steam is sepa-
rated from the water, it is supplied to turbines as in a dry steam plant. The
remaining water fraction and turbine condensate are both reinjected.
The development of flashed steam power plants is more technically demand-
ing for sites having liquid-dominated systems than for vapor-dominated sys-
tems. Development of liquid-dominated systems would require larger masses of
fluids to be produced to generate a given amount of electrical energy. In
addition, corrosion of well casing and piping may be severe, precipitation of
minerals from the brines may be considerable, and large pore pressure drops in
the reservoir rock may result in subsidence of ground surface.
Binary plants, as depicted in Figure 4.9, use secondary working fluids
such as freon, isobutane, or isopentane to drive turbines. Using a binary
cycle plant allows electricity to be generated with geothermal fluids that are
below the flashing temperature of water. Binary plants may also use geother-
mal fluids whose direct use would be undesirable because of corrosion or scal-
ing problems. In binary cycle plants, such as that at Raft River, Idaho, the
geothermal fluid is pumped from the production well through a heat exchanger,
where the secondary fluid is vaporized. The cooled, geothermal fluids are
reinjected into the reservoir. The vaporized, secondary working fluid is used
to driv~ turbogenerators and is condensed for reuse. Because the geothermal
fluid is reinjected, the reservoir pressure of the geothermal fluid is main-
tained and gas release is eliminated, thus reducing some scaling or corrosion
problems as well as eliminating the potential for major air pollution from
gases often encountered in geothermal reservoirs. In addition, scaling and
corrosion can be limited to the primary side of the heat exchanger, minimizing
replacement and repair requirements.
Binary cycle plants can also be used in conjunction with flashed steam
plants. In this arrangement, the water that remains after flashing is passed
through a binary cycle unit. Additional energy thus is extracted and the
resource is used more efficiently.
The hybrid plant type uses geothermal resources in conjunction with fos-
sil fuels, solar energy, or biomass for power generation. Hybrid plants would
supplement geothermal resources with auxiliary energy sources such as coal,
4.56
HEAT EXCHANGER
FIGURE 4.9. Binary Cycle Geothermal Power Plant
biomass, or solar energy. One approach is to use geothermal energy to preheat
feed water for a boiler fired by the auxiliary fuel. In some cases, such as
with the use of biomass, the geothermal resource can also be used to dry the
organic fuel, which increases its burning efficiency. The hybrid plant can
use geothermal resources that are below the temperature required to produce
usable amounts of steam.
Present evidence indicates that the Alaskan geothermal resources are of
the hot dry rock type. Hot dry rock resources would be used by injecting a
working fluid, probably water, into the hot rock through injection wells. The
heated water would then be brought to the surface through production wells,
where it would be flashed to steam and used to drive turbogenerators. Hot dry
rock technology, however, is not yet demonstrated.
The low thermal conductivity of rock controls the rate of heat transfer
to the circulating fluid. Large surface areas are thus required for hot dry
rock geothermal development. Los Alamos Scientific Laboratory (LASL) is field
testing a rock-fracturing method based on conventional hydraulic fracturing.
When high-pressure water is pumped into a well drilled to a predetermined
depth, existing fractures are widened and new fractures are created through
rock displacement. The working fluid, generally water, is pumped into wells
that penetrate to the bottom of a hydraulically fractured zone. The fluid
passes through the fractures and into an extraction well, where the heated
working fluid is drawn.
Performance Characteristics
The appropriate measure of a geothermal plant•s thermodynamic performance
is the .. geothermal resource utilization efficiency ... Well-designed, dry steam
geothermal power plants with condensing turbines operate with utilization
efficiencies between 50 and 60%. Plants receiving lower quality geothermal
fluid, i.e., lower temperature, will exhibit lower efficiencies because a por-
tion of the geofluid has to be sacrificed to raise the energy of the remaining
portion to a usable level.
Steam in a geothermal electric generating plant is of moderate pressure
at only a few degrees of superheat. Due to the high specific volume of the
steam, the heat rate of the turbine is about 22,000 Btu/kWh. This rate is
4. 58
equivalent to a thermodynamic efficiency of 16%, requiring approximately twice
the heat rejection as a conventional fossil-fired unit of comparable rated
capacity.
The availability of a geothermal plant will vary widely, depending on
such factors as technology type, corrosive matter in the fluid, and mainte-
nance and source reliability. A geothermal plant in the Railbelt region is
estimated to be available approximately 65% of the time.
The lifetime of a geothermal power plant is forecast to be 30 years.
Well life varies widely but averages 15 years. Additional wells are developed
during the life of the plant to support continued plant operation.
4.5.2 Siting Requirements
Geothermal plants are always located at the site of the geothermal
resource. The four most important siting criteria used to evaluate geothermal
resources for application to electric power production are as follows:
1. fluid temperatures in excess of approximately 140gC (280°F)
2. heat sources at depths less than 10,000 ft, with a temperature
gradient at 25°F per 1,000 ft
3. good rock permeability to allow heat exchange fluid to flow readily
4. water recharge capability to maintain production.
Individual geothermal wells should have a capacity to supply 2 MW of
electricity.
The site must have access available for
maintenance personnel, and a source of water
(and injection in the hot rock technology).
construction, operation, and
available for condenser cooling
The land area required for the
geothermal power plant will be similar to that required for an oil-fired unit;
however, the total land area will be vastly larger because of the diffuse
location of the wells. A 10-MW plant, excluding wells, can be situated on
approximately 5 acres of land. After exploratory wells are sunk to determine
the most productive locations (both for production and injection wells), the
plant would be located based on minimum cost of pipelines and other siting
factors. A network of piping would then be established to complete the
installation.
4.59
4.5.3 Costs
Identified Railbelt geothermal resources that are potentially suitable
for electricity production are limited to the hot dry igneous type. Hot dry
rock technology would be required to exploit this resource. Estimated capital
and O&M costs of hot dry rock geothermal development, including well field
development, are shown in Table 4.12 (DOE 1978 and DiPippo 1980). These costs
are highly speculative because of the current early stage of technical
development of hot dry rock technology.
TABLE 4.12. Estimated Costs for Hot Dry Rock Geothermal Developments(a)
(1980 dollars)
Rated Capacity
(MW)
50
Capital
($/kW)
2550
(a) DOE 1978; DiPippo 1980.
O&M
($/kW/yr)
175
Cost of Energy(b)
(mi 11 s /kWh)
57
(b) Levelized lifetime costs, assuming a 1990 first year of
commercial operation.
4.5.4 Environmental Considerations
A problem unique to geothermal steam cycles involves disposing of the
geothermal fluid. This fluid is generally saline, and therefore most geother-
mal plants in the United States practice reinjection into the geothermal
zone. If the geothermal zone is highly pressurized, however, not all of the
brine may be reinjected, and alternative treatment and disposal methods must
be considered. For geothermal fields located in the Chigmit Mountains, brine
disposal in Cook Inlet should not be too difficult. The interior fields,
however, could require extensive wastewater treatment facilities to properly
mitigate water-quality impacts to freshwater resources and to comply with
relevant water-quality regulations. Depending upon a specific field's water
characteristics, the costs associated with these treatment facilities could
preclude development.
4.60
Geothermal water is often high in salts and trace metal concentrations
and is often caustic. The caustic nature of the solution often corrodes
pipes, which can add to the brine's toxicity. Current regulations require
reinjection of spent geothermal fluid; however, entry of these brine solutions
into the aquatic environment by discharge, accidental spills, or groundwater
seepage could cause acute and chronic water-quality degradation.
Geothermal plants have the highest water-per-megawatt use of any steam-
cycle plant (845 gpm/MW). A 50-MW plant would use 42,200 gpm for once-through
and 750 gpm for recirculating cooling water systems, respectively.
Atmospheric emissions from the development of geothermal resources will
consist primarily of co 2 and hydrogen sulfide (H 2S). Other emissions may
consist of ammonia, methane, boron, mercury, arsenic compounds, fine rock
particles, and radioactive elements. The nature and amount of these emissions
can vary considerably. This uncertainty can be removed only by test wells in
the proposed project area. Emissions are also a function of operational tech-
niques. If reinjection of geothermal fluids is used, emissions into the atmo-
sphere may be reduced to nearly zero. Alternatively, H2S emissions can be
controlled by oxidizing this compound to so 2 and using conventional scrubber
technology on the product gases. Emissions may also be controlled in the
water stream by an "iron catalyst" system or a Stretford, sulfur recovery
unit. Efficiencies of these systems have ranged as high as 90% H2S removal.
At the Geysers generating area in California, H2s concentrations average
220 ppm by weight. The power plants emit about 3 lb/hr of H2S per megawatt of
generating capacity. Regulation of emissions of other toxic compounds can be
controlled by various techniques, as stipulated by the regulations governing
the specific hazardous air pollutants. Control of hazardous pollutants will
probably not preclude the development of geothermal resources in the Railbelt
region.
One of the major geothermal potential areas in the Railbelt is located in
the Wrangell Mountains near Glennallen. This area drains into the Copper
River, which is a major salmonid stream. The result of accidental discharge
of untreated geothermal fluids into this system may have significant impacts
on these fish and other aquatic organisms, depending on the size and location
of the release.
4.61
Other large geothermal areas are in the Chigmit Mountains on the west
side of Cook Inlet. Much of this area is close to the marine environment. In
general, geothermal waters would have less detrimental effects on marine
organisms (because of their natural tolerance to high salt concentrations)
than on fresh water organisms.
Land requirements for the geothermal power plant, on a per-kW basis, are
low relative to biomass, coal, and nuclear plants and are comparable to those
for oil and natural gas plants. The well field, however, would require a much
larger area. The primary impact resulting from geothermal plants on the ter-
restrial biota is habitat loss. The Chigmit Mountain area is remote and is
inhabited by populations of moose and black bear. The Wrangell Mountain area
is generally more accessible and includes populations of moose, Dall sheep,
caribou, and possibly mountain goats. However, geothermal lands are more
likely to be located in remote areas than other steam-cycle power plants.
Impacts will be greatest in remote areas since an extensive road network would
have to be built to service the well field. Roads would cause the direct
destruction of habitat and also would impose additional disturbances to wild-
life and vegetation because of increased human intrusion. Disturbances to
these areas could be extensive, depending on the land requirements of the
geothermal well field.
The major geothermal pollutants acting on the terrestrial environment are
H2s, toxic trace elements, and particulates. The impacts of these pollu-
tants can generally be minimized through installation of pollution control
devices.
4.5.5 Socioeconomic Considerations
The construction of a 50-MW, geothermal plant would require approximately
90 workers over a 7-year period. Although the construction work force would
be moderate in size, the remoteness of the geothermal resources would affect
the magnitude of the impacts. To develop the geothermal resources in the
Chigmit Mountains, the power plant components would be shipped by barge and
then hauled overland. Semipermanent construction camps would be required to
house the workers. Impacts to the coastal communities may therefore be con-
4.62
fined to the disturbance caused from transporting equipment. An operational
work force of 30 will be required because of the technology•s relatively high
maintenance requirements.
Impacts to communities from development of the Wrangell Mountain resource
could be expected to be more severe since Glennallen (pop. 360) is a large
enough community to attract workers and their families. The in-migration of
the work force to Glennallen would place a strain on community•s infra-
structure. Haul roads would have to be built from the Glennallen-Gakona-
Gulkana area. Secondary impacts to the communities would result from the
transportation of equipment to the site.
Project capital expenditures are estimated to be 55% outside the region
and 45% within the Railbelt. The large investment in production and reinjec-
tion wells and equipment would be offset partially by the moderate-sized con-
struction work force and long construction period. Approximately 12% of O&M
expenditures would be spent outside the region because of the high percentage
of expenditures on supplies.
4.5.6 Potential Application in the Railbelt Region
Only hot dry rock (hot igneous) and low-temperature, liquid-dominated
hydrothermal convection systems have been identified in or near the Railbelt
region (Figure 4.8). Hot dry rock geothermal resources with temperatures that
may be high enough to generate electricity have been discovered in the Wrangell
and Chigmit Mountains. The Wrangell system (Mt. Sanford, Mt. Drum, and Mt.
Wrangell), located approximately 200 miles from Anchorage, has subsurface
temperatures exceeding 1200°F. The Chigmit system (Mt. Spar, Black Peak,
Double Peak, Redoubt Volcano and Iliamna Volcano), to the west of Cook Inlet,
is isolated from the load centers by 200 miles of rugged terrain. Little is
known about the geothermal properties of either system.
The geothermal areas (with the exception of Mt. Spurr) of both the
Wrangell and Chigmit Mountains are located in lands designated as National
Parks (Figure 4.2). The federal Geothermal Steam Act prohibits leasing and
developing National Park lands. Development could be possible, however, if
townships within these areas are selected by a Native corporation under the
Alaskan Native Claims Settlement Act, and if the surface and subsurface
4.63
estates are conveyed to private ownership. The Alaska National Interest Lands
Conservation Act of 1980 allows the granting of right-of-ways for pipelines,
transmission lines and other facilities across National Interest Lands for
access to resources surrounded by National Interest Lands.
Some low-temperature geothermal resources in the Fairbanks area are used
for heating swimming pools and for space heating. In southwest Alaska some
use is made of geothermal resources for heating greenhouses as well as for
space heating. A low-temperature hydrothermal resource in granite rock has
been identified in the Willow area. A deep exploration well was discovered to
have a bottom hole temperature of 170°F. Exploration data to date indicate
that while this resource may prove useful for low-temperature applications,
its relatively low temperature makes it an unlikely source for electric
generation.
Based on current knowledge of Railbelt geothermal resources, little near
or mid-term potential for geothermal-electric development is foreseen for the
Railbelt. Presently identified resources of sufficient temperature to support
electrical generation are of the hot dry rock type for which the technology
for development is yet in the experimenta·l stage. Because of the widespread
presence of active igneous systems in the Railbelt region, further exploration
for geothermal resources suitable for electrical development appears to be
warranted. Some potential appears to be available for development of low-
temperature hydrothermal resources for direct applications. For example, for
the proposed state capital at Willow might be explored.
4.64
4.6 PEAT-BASED STEAM-ELECTRIC GENERATION
Peat consists of partially decomposed plant matter and inorganic minerals
that, over time, have accumulated in a water-saturated environment. In
Northern Europe and the Soviet Union, peat has been extensively used as a fuel
resource. The Soviet Union has more than 6500 MW of peat-fired, electric
generation capacity in operation or under construction. The largest unit now
under construction is rated at 1000 MW (Tibbetts and Ismail 1980). In Ireland,
440 MW is produced from several peat-fired units ranging from 25 to 40 MW
(O'Donnel 1974). Peat provides some 399 MW of electric power and 600 MW
equivalent of district heating in Finland. Other countries, including Canada,
the United States, Sweden, and West Germany, have active peat-fuel research
programs.
Significant peat reserves are found in Europe and North America and
account for over 95% of the estimated worldwide resources. In the United
States peat lands are estimated to cover 52.6 million acres, making the United
States second only to the Soviet Union (200 million acres) in total peat-land
area (Punwani 1980). Almost 51% of the domestic peat resources are located in
Alaska. An estimated 27 million acres is outside the permafrost zones. Peat
within the permafrost zones is not included since overwhelming problems are
associated with its extraction.
Primarily because of the availability of other lower cost fuels, little
peat has been used in the United States as a fuel resource. Studies are
currently assessing the resource potential and fuel applicability of peat in
several areas of the country, including Maine, Michigan, Minnesota, North and
South Carolina, and Alaska. The potential Alaskan peat resource areas are
shown in Figure 4.10.
4.6.1 Technical Performance
Peat can be used to generate electricity either by burning it directly to
fire a steam-electric plant or by converting it to a gas and using the gas to
fire a combustion turbine unit. Boilers ranging from 20 to 300 MW of thermal
output and designed to handle peat are commercially available from European
manufacturers. Peat has traditionally been burned directly in steam-electric
4.65
PEAT RESOURCES
1(07/21 PEAT DEPOSITS
SCALE
0 50 iOOMiles
FIGURE 4.10. Peat Resources of the Railbelt Area
4.66
plants to generate electricity. Peat gasifiers, however, are currently in the
advanced research and development stage. Laboratory and process development
unit-scale gasifiers have been produced in the United States, Sweden, and
Finland. In the United States, Rockwell International and the Institute of
Gas Technology have been involved in gasifier and gasification system configu-
ration design and development (Punwani 1980).
Design Features
A diagram of various peat fuel utilization systems is presented in Fig-
ure 4.11. The two principal methods for extracting peat in quantity are sod-
peat harvesting and milled-peat harvesting. Both are dry harvesting methods
and require drainage of the bog prior to peat extraction. The steps of bog
preparation for such harvesting include clearing surface vegetation, dredging,
rerouting surface streams, and developing a network of ditches and waterways
to collect and to route the bog waters away from the harvest area. As the bog
dries, it can be leveled and cleared of debris. This preparation typically
takes several years.
Sod harvesting of peat, the oldest mechanical method of peat harvesting,
is used extensively in Ireland, Finland, and Germany. The peat is dredged or
excavated from the bog and compressed and cut into bricks or cylinders about
14 inches long. The bricks (sods) are left on the bog surface to dry. This
drying can limit the harvests to only two per season, as occurs in Ireland
(DOE 1979c). Sod harvesting is very labor intensive.
Milled harvesting is much more mechanized than sod harvesting. Once the
bog is dried, the surface is scraped to a depth of half an inch or less and
the scrapings are milled over a spiked drum. The shreds are then left on the
field to dry, possibly in ridges, if the weather and drainage warrant. After
about 2 to 3 days of drying, the peat is harvested either by vacuum harvesters
or by mechanical picking equipment. A problem with this method, however, is
the potential environmental pollution of suspended particle matter. This
material is defined as 11 Criterion pollutant .. by the Clean Air Act and could
limit the viability of this harvesting method in the United States. Also,
milled harvesting creates a significant potential for bog fires, which can
burn out of control for several months.
4.67
HARVEST
MILLED
HARVEST
SOD
HARVEST
PREPARATION
FLUE GAS/
HOT AIR
DRY
BRIQUETTING
HYDRAULIC(a) WET (a)_r
HARVEST ------1111-... CARBONIZATION
(a) UNDER DEVELOPMENT
FIRING
PULVERIZED
FIRING
FLUIDIZED
BED
GRATE
FIRING
FLUIDIZED
BED
PLANT TYPE
(a) ..._COMBINED CYCLE WITH OR
PEAT GASIFIER ---.. -• WITHOUT COGENERATION
FIGURE 4.11. Power Production Alternatives Using Peat
A harvesting procedure currently in the developmental stage is slurry
peat harvesting (a hydraulic or wet harvesting technique). Once the bog is
cleared, but not drained, a dredge or backhoe can be used to extract the peat
onto a moving screen. It is then washed by water jets to form a slurry of
water and peat. The slurry is pumped by pipes to a dewatering operation. The
success of this type of harvesting will depend on the development of the
dewatering operation and the environmental impacts. Further development of
hydraulic peat harvesting techniques is considered necessary before it is
commercially successful (DOE 1979c).
Peat-fired steam-electric power plants are physically similar to coal-
fired units. The primary components of a peat-fired plant are the fuel
receiving, storage and processing systems, the boiler, the turbine generator,
the stack gas cleanup equipment, and the condenser cooling system.
Although most components are similar to those used in coal facilities,
the unique properties of peat require certain modifications to several plant
systems. The high moisture content, low energy density, the content of
volatile matter, and general bulkiness of peat require larger fuel storage
areas and fuel handling systems and a furnace volume greater than that required
for a coal-fired plant producing the equivalent amount of electric power.
The peat received at power plants has a moisture content of no greater
than 60 to 65%. Natural peat is approximately 90% water. The currently used
harvesting methods, both milled and sod, rely on solar and convective drying
to produce a fuel at a moisture content of 30 to 55%. At 50% moisture con-
tent, Alaskan Railbelt peat samples have an average heating value of about
6500 Btu/pound (EKONO 1980). The actual combustion process requires a further
reduction, depending on the combustion process used, to 10 to 25% moisture
content.
Direct combustion of peat can be accomplished using pulverized firing,
grate firing, or fluidized combustion. Most pulverized-fired facilities today
use recirculated flue gases or hot air to dry the milled or sod peat prior to
feeding it into the boilers.
4.69
To use peat in grate-fired boilers, however, the peat must be pressed
into suitable pellets or briquettes. Fluidized-bed combustion systems and
peat gasification units also generally require that peat be prepared to a
specific size and shape. Sod-harvested peat generally does not require
compaction. Milled peat (the primary method of peat harvesting today),
however, is regularly compacted for grate-fired operations in Northern Europe
and the Soviet Union. To be pressed into suitable briquettes the peat's
moisture content, density, and fiber content must be homogeneous. Preparation
involves blending, crushing, and screening prior to drying to about 10%
moisture content and final compaction. The dryer heat may be generated from
combustion of rejected fibers. Such prepared peat is estimated to have a
heating value of 10,000 Btu/pound (Rohrer 1979). A diagram of a peat-fired
boiler system is presented in Figure 4.12.
Another process, wet carbonization, has the advantage of overcoming·the
time-consuming and uncertain air drying of peat on the bog. Wet carboniza-
tion, currently in the pilot plant stage, uses hydraulically harvested peat
fed into the plant as a peat slurry (Rohrer and Bertel 1980). The slurry
passes through pulping, screening, and preheater stages to a steam-heated
reactor. In the reactor, the peat is heated under pressure to produce some
carbon loss (carbonization) and dewatering of the peat. It is then filtered,
flash dried, and pelletized. For gasifier feed and other onsite applications,
the final thermal drying and/or pelletizing are often not necessary.
Peat gasification plants are currently being developed that would take
advantage of peat's inherent high chemical reactivity to produce a clean burn-
ing substitute gas to fire combustion-turbine power plants. Hydraulically
harvested peat would be sent in a peat slurry to the facility, where it would
pass through the wet carbonization dewatering process. The resulting peat
material would be fed into a gasifier. Different basic types of gasifiers
could be used, including entrained flow and fluidized bed gasifiers. By con-
trolling the gasification temperatures and pressures, the gaseous and liquid
product mix can be significantly varied. Peat gasification could yield lowor
medium-Btu fuel gas, substitute natural gas, fuel liquids, and ammonia
4.70
AIR INTAKE STACK
STEAM BOlLE~-:;'
SILO 2 (
·~ ...
F.D. FAN
•;:·.·.:·,:·.\
':\ ·, ·. \ '.
!~ : ·,I'\ ·I ·'• I I :1 ! : o•,, .u i! ;l·~
t
PULVERIZER
FIGURE 4.12. Fuel System of a Peat-Fired Boiler
and sulfur by-products. Peat, typically higher in nitrogen and lower in sul-
fur than coal, will yield relatively more ammonia and less sulfur by-products
than coal gasification under less severe operating conditions. Available data
on peat gasification currently are limited to laboratory-scale operations (DOE
1979c).
Downstream units, in addition to the combustion turbine or combined cycle
unit and gas fuel storage facility, would include equipment for heat recovery,
gas quench, acid gas removal, water gas shift, and methanation, depending on
the desired gasification products. A conceptual flow diagram of the peat
gasification system is shown in Figure 4.13.
Performance Characteristics
Peat, because of its inherent high moisture content, introduces thermal
inefficiencies into the combustion process. Efficiencies increase with the
size of the plant, as shown below (Tillman 1980):
Heat
Rated Capacity Rate
(megawatts} (Btu/kWh}
5 20,000
15 15,100
25 14,200
35 14,100
50 14,000
Condensing cycle plants of 100 MW or larger can achieve a 35% overall effi-
ciency rating (EKONO 1980). If the steam from the turbine exhaust can be used
for industrial processes or for district heating, the overall thermal effi-
ciency of the plant can be increased significantly.
Because peat-fired power plants are capital-intensive units, they gener-
ally are operated as baseload units. The achievable load factor of such
direct-fired peat units is similar to that of other biomass-fired plants
(about 80%). These high load factors are attained by proper design and main-
tenance. The reliability of a power plant is a function of the individual
reliability of numerous system components, including the fuel receiving,
4.72
... STORAGE AND -DRYING AND ~-DUAL LOCKHOPPER . GASIFIER '--
PEAT AT -PREPARATION GRINDING -FEED SYSTEM -
SO% MOISTURE
'~
OXYGEN
PLANT
LIQUIDS -ACID GAS ... CO SHIFT .. METHANATION ... SNG -RECOVERY -REMOVAL --AND COMPRESSION -
FIGURE 4.13. Peat Gasification Flow Sheet
preparation and handling systems, the boiler, the steam turbine generator and
the associated steam equipment, and the pollution control equipment. Increas-
ing the complexity of any system tends to diminish the reliability. The
lifetime of peat-fired steam-electric generating plants is estimated to be
30 years.
4.6.2 Siting and Fuel Requirements
The siting of a peat-fired power plant depends on several factors, many
of which are location specific. General siting factors, however, include the
location of the fuel source, the condition of the fuel, transportation and
transmission line access, and cooling water availability (for steam-electric
generation facilities). Another siting consideration may be the location of
potential cogeneration steam users.
Peat is a transportation-intensive material. Because of its high mois-
ture content and low energy density, the practical transportation of milled-
or sod-harvested peat is limited to about 50 miles by truck and 100 miles by
rail (EKONO 1980). Although similar limitations have been established for
peat slurry lines, rough indications of the cost can be seen in coal-slurry,
pipeline cost estimates. To avoid excessive transportation costs, peat-fired
units are generally being proposed for bog-side operation.
4.73
Peat-fired power plants 1 fuel requirements are a function of the plants 1
thermal conversion efficiency and plant scale. Representative fuel require-
ments for various sizes of peat-fired plants are presented below:
Daily Requirements Rated Capacity
(MW) @ 50% Moisture Content (tons)
5
15
25
35
50
260
600
960
1300
1900
Land requirements for peat-fired plants are similar to those of coal-
fired plants and are generally greater than those of other steam-cycle power
plants on an acres-per-MW basis. A 5-MW stand-alone plant could require about
10 acres, whereas a 40-MW plant is estimated to require 60 acres, largely due
to the ash disposal and the fuel storage areas (Tibbetts and Ismail 1980).
The 40-MW, peat-fired, steam-electric generation plant being examined for
New Brunswick, Canada, is anticipated to require 1400 tons of peat each day
(Ismail 1980).
4.6.3 Costs
The economies of scale for peat-fired electric power generation are
rather steep, as shown in Table 4.13. The information in this table was pro-
duced in a recent study of Alaskan peat utilization potential (EKONO 1980).
TABLE 4.13. Estimated Costs for Peat-Fired Steam-Electric
Power Plants (1980 dollars) (EKONO 1980)
Rated Capacity (MW)
1
30
Capital ($/kW)
2600
1166
O&M
($/kW/yr)
1000
204
Cost of Energy(a)
(mills/kWh)
246-269
80-96
(a) Levelized lifetime costs, assuming a 1990 first year of commercial
operation. The ranges reflect potential fuel costs (Appendix B).
4.74
These cost estimates compare favorably with those made for the 40-MW,
peat-fired power plant scheduled to be built in New Brunswick (Ismail 1980).
Over its 30-year lifetime, the cost of power was estimated to be $0.05/kWh
(54.8 mills/kWh). This estimate, in constant 1979 dollars, was based on $1.90
levelized delivered cost of peat.
4.6.4 Environmental Considerations
The use of peat as an energy resource will have an impact on the quality
of the region's air, water, and land resources. The nature and degree of
these impacts will depend on the particular harvesting, fuel preparation and
energy conversion technologies selected.
The peat harvesting operation is one of the major potential sources of
airborne pollutants. The amount of fugitive dust produced during harvesting,
handling, and storage depends on the harvesting techniques used. The milled-
peat method, in which the bog is drained and the peat is milled and ploughed
into ridges for air drying, generates the greatest amount of dust. This dust
also creates a serious explosion problem during storage and handling activi-
ties. Another difficulty is the prevention and control of bog fires. These
problems of dust, explosion potential, and bog fires are essentially elimi-
nated if the peat is harvested in its wet state by hydraulic means.
If the peat is used to fire a direct combustion boiler of greater than
about 5 MW, the required air-pollution control equipment will minimize the
emissions to their legal limits. The expected emissions from a peat facility
and the regulatory framework are presented in Appendix E. The impacts of air
pollutants on the terrestrial environment are presented in Appendix G.
The air emissions from peat gasification operations will be controlled by
air pollution equipment developed for coal gasification and oil refining
facilities to levels below those required by New Source Performance Standards.
Combustion-turbine operation using peat-based synthetic gas would produce
minimal air emissions.
Potentially significant impacts to the aquatic systems could result from
harvesting, processing, and/or the conversion process. Conventional harvest-
ing operations producing milled peat or sod peat remove only a small portion
4.75
of the total peat deposit in one year and cut to a depth of about 5 to 8 inches
each year (DOE 1979c). Therefore, a large area must be cleared and drained to
provide an adequate volume of peat and a sufficient drying area. (Assuming a
heat rate of about 6700 Btu per pound, 7500 cubic feet of peat harvested per
acre per year and 22 pounds per cubic foot, a 30-MW plant would require, using
a mill harvesting operation, some 2300 acres of peat to be harvested annually.)
The draining of the bog can have significant impacts on the aquatic system.
The pH of the drainage water differs from normal surface water and the ditch-
ing of the bog could possibly have an impact on surrounding lakes, rivers, and
streams. Bog waters may also contain such chemicals as phosphorous and nitro-
gen compounds, which may contribute to the eutrophication of the receiving
waters. Heavy metals in the bog water may be introduced into the local water-
shed along with possible detrimental organic waste products such as polyphe-
nolic humic acids. These impacts are currently under investigation. Possible
mitigation requirements being considered include the separation of drained bog
waters from the local natural surface waters.
Hydraulic harvesting does not require bog drainage and as a result avoids
many of the problems associated with sodor milled-peat operations. After the
bog area to be harvested is cleared, all the peat is removed by backhoe or by
other mechanical systems. The methods for control of hydrology and water
quality in and around hydraulic, peat-harvesting operation will depend on the
specific harvesting plan that is used and the land reclamation option that is
selected. Potential water-quality control methods include buffer zones, pH
control operations and permeability control systems. The selection of one or
more methods strongly depends on the interactions among peat harvesting tech-
niques, local hydrology and water quality, and land reclamation options.
Proposed land reclamation of harvested bog areas has included agricultural
developments, forest plantations, and recreational water areas.
Condenser cooling water requirements for peat-fired power plants would be
similar to other steam-cycle plants (see Appendix I). The rate of water
required would be about 750 gallons per minute per megawatt (gpm/MW) passing
through the condenser. For a once-through cooling system, this translates to
18,250 gpm for a 25-MW facility. If a recirculating cooling system is
4.76
employed, the makeup water requirements would be reduced to about 362 gpm.
Onsite water treatment facilities and the proper siting and design of intake
and discharge structures will contribute to reducing the aquatic impacts from
the power plants. Similar equipment, procedures, and proper siting will be
necessary to minimize the aquatic impacts of peat gasification units.
Proposed activities include onsite biochemical treatment of contaminated
water, and the concentration of inorganic salts into salt form for disposal.
4.6.5 Socioeconomic Considerations
To construct and to operate peat-fired power plants, relatively small
labor forces are required. For 15-to 30-MW plants, a construction force
of 65 would be required. An operating staff of up to about 25 could be neces-
sary for such size plants, depending on the specific peat processing and com-
bustion processes employed. A peat-gasification -combustion-turbine facility
of similar power output would require a slightly larger operating force.
Construction periods for the power plants would range between 18 months to
3 years (excluding the licensing process) (EKONO 1980). If the plants are
developed and operated in association with the peat harvesting operations
("at bog-side••), the personnel requirements and construction period would be
increased. Therefore, for conventional harvesting, the operations staff could
double and between 3 to 6 years could be needed to prepare the bog. If
hydraulic harvesting is employed, the preparation time could be as little as
6 months.
A preliminary assessment of peat resources in the Railbelt identified
bogs in the Matanuska-Susitna Valley as potential sources of fuel peat (EKONO
1980). Prime locations for bog-side plants include the Willow, Houston, and
Knik areas. The socioeconomic impacts of harvesting and plant operations may
be significant on Houston and Knik and to a lesser degree on Willow. These
impacts will increase as the size of the facility increases. Houston has a
population of 69, Knik has about 40 residents, and Willow has 38 people. The
influx of some 65 construction workers and their families for up to 3 years
and the permanent residence of between 15 and 50 operations staff families
(depending on plant size and harvesting operations) could put a severe strain
on the social and economic structure of these communities. These impacts may
be mitigated by limiting the scale of the plants.
4.77
The breakdown of capital expenditures is expected to be 60% outside the
Railbelt and 40% within the region. Expenditures due to a large capital
investment will be offset by employment of an Alaskan labor force. Approxi-
mately 10% of O&M expenditures would be spent outside the region.
4.6.6 Potential Applications in the Railbelt Region
The Matanuska-Susitna Valley and Kenai Peninsula appear to have peat bogs
that could possibly be suitable for energy production (EKONO 1980). Six
sites, all located in the Susitna Valley, were selected for detailed consider-
ation. The selection was based on a consideration of a variety of factors,
including organic soils information, population centers and transportation
systems locations, vegetation and ecosystem distribution, surficial geology
data and ownership plats. These six bogs also met other criteria including
transportation distance to major users, bog area limits (greater than
80 acres), and continuity of the bog. The six areas examined were Mile 55
Kettles, 12 miles west of Wasilla and 2 miles south of the Parks Highway;
Nancy Lake West, bordering the west edge of the Parks Highway northwest of
Houston; Stephen Lake, 5 miles northwest of Knik; Nancy Lake East, same vicin-
ity as its western namesake; Miles 196 West, alongside the Parks Highway north
of Kashwitna; and Rogers Creek, located off the Parks highway, about 3 miles
north of Willow. Of these sites, Nancy Lake East appears to be one of the
more suitable, based on the preliminary resource study. If the entire bog,
with an estimated average depth of 7 feet, contained fuel-quality peat, it
would provide fuel for a 30-MW cogeneration plant for about 15 years (EKONO
1980).
The.quality of the Alaskan peat resources is its limiting factor as an
energy resource. Using existing data, the EKONO study (1980) found that the
ash content seems to be the prevailing problem. Only 36% of the peat samples
analyzed for ash had less than a 25% ash content, the limit for peat fuel as
specified by the U.S. Department of Energy. Another problem is the lack of
continuous, high-quality peat resources.
Although the quantity of peat resources is not yet well defined, present
data are sufficient to indicate that Alaska has significant fuel peat
resources. Current resource information is not sufficient to allow a firm
4.78
estimate of potential power production from peat to be made. Further site-
specific investigations are necessary to identify suitable peat resources and
potential power plant sites. In addition, developmental work needs to be done
on several advanced technologies proposed for use in Alaska (including the
hydraulic-harvesting, wet carbonization system and the peat gasification
units). The time necessary to complete these resource assessment and technol-
ogy development activities will preclude this resource as a power generation
alternative for the Railbelt at this time. Depending on the results of these
activities, and the economic, environmental and socioeconomic factors associ-
ated with its use, peat could be a possible power generation resource in the
Railbelt in the next decade.
4.79
5.0 CYCLING TECHNOLOGIES
The primary characteristic of cycling technologies is the capability to
adjust the output of generating units on an hourly or even more frequent basis
according to system demand. The cycling technologies would satisfy intermedi-
ate load and peaking service electrical requirements in the Railbelt region.
The lack of a regional grid system and the unique pattern of growth of
the Alaska Railbelt have resulted in technologies traditionally considered
cycling (certain combustion turbine and combined-cycle units) being used for
baseload service. This practice can be expected to change as the area grows,
as natural gas and oil prices increase, and as an interconnected transmission
system is developed.
Four currently available technologies and one emerging technology have
been identified as candidate cycling technologies for the Railbelt:
• combustion turbines
• combined eye 1 e
• d i ese 1 e 1 ectr i c
• conventional hydroelectric (intermediate and large scale)
• f ue 1 ce 11 s •
The first four technologies are already in use in the Railbelt region. Fuel
cells represent an emerging technology and are undergoing a demonstration in
New York City. A comparison of selected characteristics of the cycling tech-
nologies considered in this study is provided in Table 5.1.
5.1
U1
N
TABLE 5.1. Comparison of Cycling Technologies on Selected Characteristics
~t~i~ \-c _ l!l~_u_~.! !~'le ~s
No t~e
OtJor
Ecolo!J..Ical .!!5>acts
·-Gross waTer ·use (<JJml
UuH.I Use (acres)
Costs
-e.-pnal U/kW)
O&H (S/kW/yt·
Cost or F.nergy (S/kW)
Adi!J!. tab II H.r to G•·owth
--un it .. ~izos 7iva iTafiie
Construct ion Le;,d 1 imc
Availability or Sites
R~m:~m,ty
~J!!!.''LI!.~.~~.l!!t)lLn ~l_a.~t~
Cap Ita I
O&H
Fue I
Boom/Dust Effects -·ransrn;crronversonne1
OperiJllng Personne I
Rat to
Hagn itude nr Impacts
! eg~~~~~a~~Wv-lr~~~~?·~, ty
Railhelt Exprrtenc:e
Comhuo;tlon Turbines
V.~-~_. .. ll_~scF.Ir~_<!) __
Hi nor
Horlerate
Htnnr
0
560
40
58 (136j(•)(h)
No direct. sarety
prob I ems. Poss lb Je
long~term a lr
qtMIIt.v degradation.
Utility operated.
05-80 ""
I yr
Limited hy access to
rue I supp Jy and air-
qu;,lHy control ;,reas
0!1%
20%
81%
100%
30
17
2.5: I
Minor to moderate
in all l01:atlnns.
Contra 1 through regu-
1 a tor v a gene ies
Currently Avi!lhhle
Fxtens lve
Cormlnecl Cycle
_(.?..I!O._f!4 .. G_a~.:l'.lred -··-·
Hoderate
HCli'terate
Minor
600
960
35
49(•)
llo direct safety
prob I ems. Posslb Je
long~term atr-
quall ty degradation.
Utility operated.
90-250 HW
2-4 yr
Limited by access to
fuel s11pply, avalla-
blllty or cooling
water and air-quality
contra 1 areas.
85%
30%
84%
100%
45
15
3: I
Hlnor t.o moderate
In all locations.
Cootrol through regu-
latory ageor. tes
Currently Available
Llmltecl (7. plants)
Ole so I
____ (l?.f:'l)__ ____ _
Hlrn>r
Hod"! rate
l.oca lly rnorfrrate
700
35
100 (17Jj(h)
llyrtnu~ )N;It·lc:
.J4-Jfifi Jt./)
Holier<1h~ to <;lqniflr..lnt
Hinnr
Hnne
Bulk or strriJmrlow flit<>c;.rd
through turh lnr>s
'lih!·SJtPrlrtr:, lllOr. tn HKlOc:;
tsqo-11,775
30-225
23-73"
lfo direct sarety Safe
prob )P~. Poss 1b h~
local •lr-qu•llty
degrclrlilt ton
Uti 1 Hy, corrmun tty targeT rae lilt ie~
or consumer operatPd. utility operi1l~rl.
tntermerll<1te f;,cll H l~o;
could be r.nrnnunltv
operated.
.03-15 HW
I yr
LIMited by CO non-
attainment areas
90%
20%
92%
100%
25
2
12: I
HI nor In • II
1oc at Inns.
Potent tal ror consu-
mer r.ontro 1
Currently Avallahle
Ex trn-.lve
15-400 ""
5-10 yr
stt~s ltrnltetJ ln c;t.n•amc:;
hitvlng ravm·ahle dlscharq,.,
tnpoqnphy ,,nd Q(?n lnqy.
300
5
60:1
Severe In sm;,l1 con•nunlt il•<>
Moderate to sign If lcilnt in
F;,lrhank.s '-intennr>rti.ltr•-<>iTed
corrmunlttes. Minor In vlt iult.y
or Anchnr.,qe.
Conlro 1 through rc9u 1a hn y
agenc les rm· ullllty-nprr .1f.rtl
raciltliP.s. CniTTnuntt.v (nnlrol
ror rnun lc lp;,l pt·n.1Pct<>.
Currently AvaiJ;,hiP
l.lmltPrl (3 pt·n.l~><l•)
(j]
w
Acsthcl ics Intrusiveness -vlsiia i----------
tto lse
Odor
~!!.!~j~~L.!mpocts
Gross Wtr
land
Costs -Tap Hal
01.11
Cosl of Energy ( $/kW)
~!!l!.t!£ !l£<t!.lli!. ~afe!)'
~!'!!! !..•.!! iJ !!l' . .!!!_Growth
Unll >lzes Ava1lable
Construct ion lead I lme
Av•llabillly of Sites
~~~~~kl!~~-~ith!n_!l~!!
O&H
Fue I
Duom/Uust Etrects -·-construc.:tTon·-
Operat ing
Rallo
Hagn itude of hllfJacls
l t!~,H~.! !!~~ l}~V!: ~~!£!!!1g~t
Cunmt~l'c ia I 1\v.t ilabi llty
ltJ. i I be It E "1.11!1" i ence
Fuel Cell Slallon
____ WU:!! .• _ Phospl!!!£.!f..Ac ldL_ ___ _
Hi nor
Negligible
Hi nor
20
2
750
!~ (14Jj(o)(b)
No direct safely probletHS
Ulll ity or rnun lc lpa lly
opet·ated. Very sma 11-
sca le cogenerat ton
plants could be operated
by bu lld lng owners.
< 1-25 ""
I yr
All areas with potential
access to natura 1 gas or
fuel oiL
91%
20%
90%
100~
90
5
18:1
Significant in very srRall
collliiUn It les. Minor to
n1odera te in a 1 I u ther-
Iac at ions.
Contra t uf ul i 1 ity-operalcd
u11its through regulatory
ll9CIKics. Consumer control
of small (bu lid lng-scale)
units.
fonmerc 1.:~ 1 tk!niOI)S\rat ion
Sldye, AFO I91J4(C
Hone
U~ 111~ tuuk lnld gd.S cas tuc I.
TABLE 5.1. (Contd)
Fuel Cell Statlon(c)
___ j!J!. ltoi,J:!!!_lten Carbona_\£.) ______ _
Coal Gaslfier(d)-Fuel (ell
._l_"'!!!!.l.!!!'!i £1£ !g (!OIXJ ~).
HI nor
Hegllglb le
Minor
Hol Available
<10
810
B (142)(a)(b)
No direct safety problems
Utility or municipally
operated. Very SMa 11-
sca 1e cogeneration
plants cou 1d be operated
by bu lid lng owners.
<1-25 ""
I yr
All areas with potent tal
access to natura 1 gas or
fuel oil.
91%
20%
90%
100%
90
5
18:1
S lgn if I cant In very sma 11
comnun It ies. Minor to
moderate in a 11 other
local ions.
Contra 1 of ut t1 ity -opera ted
units through regulatory
agencies. Consumer control
of small (building-scale)
unIts.
Ocvc loJllnenla 1 Stage
AFO 1990
Hone
Significant
Hodera te
Moderate
Hot available
"-IOU
22)(]
]9
4J(f)
No direct safety problems.
Possible minor air-quality
degradation in viclnlly of
p lanl.
Utility operated.
100-1000 ""
J yr
Beluga area. ARR line
83%
Unknown
Unk no\rn\
IOU%
Several hundred
"-50-100
Unknown
Severe in a II locations
ucept Anc:h01·age or
Fair-banks.
Contr·u I lhrOllgh reyu Ia lory
agencies.
UeYe lup1neola 1 Stage
AFO 1990
Hone
(•)
(L) Cust:.. cxtCI'IIdllu pan:nlhe~c:, ..1r·~ tur bJsclu11d up~ratlun (65'-' capacity factor). Costs in pareuth~::.cs ar~ fur peaking St!rvice
( IOl '"I'"" ily lac lur).
(L)
(•I)
(c)
(I)
(~)
P1'l!~1!Ul CIJ idf!llt~ indicdlc:, llh1l moHcn 1.dl'bOfiJlt: fuel cells &Day be unsuit~d for luaJ-followlny service. Oue to low J.llalll l.diJi-
Lul l.UlLS. howcy~r. fuel cell ~tdtiuus uswg dlOltL'fl C:drbonate fuel cells may be suitable for nun-loaJ-fullowing peal-ing duty.
Pr1!!>t:ill I:!V iJI!n~e lnt.ilt~ates lhtll Uh.)llt.!O Cdt'hat1ate fut:l cells way be unsuiled for lodd-fu11uwlng s~rvice. ludd following
LJpuldlil.Y ~.:.oult.t bt: achi~.:vctJ u~Hl!J sup1Jienh!I1Utf)' (duct-burnl!r) ste.w p1anl firing.
f\yu i IJU le for order.
l.i.IS~Jll Ull Ul!)ugd COd.).
Hl) •Xt.uumjc evahJa.liou~ of Lh1~ ted111uluyy ~rl:! )ucatt:t.t; thus. no reltdblc t...ost ddla ar~ availahl~.
Natural Gas(e) fuel <:ell
~~!!>_!~~ C_y~_k_ ~~~ ~!'!J.
fol(uleratc
Hnd1~ra tc
Hlnm·
Uot AvaIlable
't.lO
Uo direct safely problems
Ut tJ lty oper'ated.
'-25-1000 ~
J yr
All ar·ea~ with natural g.Js
supply.
80-90%
lll1known
Unknown
100%
Severa 1 humlred
"-50-100
Unknown
Severe In a 11 locations
except Anchorage or
fa lrbanks.
Conlro l throuyh regu )a tory
agenc les.
Oeve lupn1cnta 1 St a~Je
AFO 1990
None
5.1 COMBUSTION TURBINES
Combustion turbines have been used for nearly two decades in the utility
industry, primarily to provide peaking and emergency power generation. Com-
bustion turbines are readily suited to cyclic duty operation, and they can be
brought on-line quickly from a cold start. Their simplicity makes them ideally
suited for operation in remote locations, and they can be operated unattended
if necessary.
The main disadvantages of combustion turbines are two-fold. They are
relatively inefficient compared to large, conventional, fossil fuel plants.
Secondly, the petroleum-based fuels, which they most readily use, are in short
supply. The relative inefficiency of these units can be overcome by incorpo-
ration of gas turbines into more efficient cycles (such as combined cycle,
cogeneration, or regenerative cycle) in which increased thermodynamic efficien-
cies stem from the use of rejected heat. The fuel availability problem may be
overcome by development of synthetic fuel production (Appendix K).
5.1.1 Technical Characteristics
A combustion turbine power plant essentially consists of a gas turbine
that drives a generator. Plant designs are highly standardized and available
in unit sizes ranging from 0.5 to 80 MW.
Design Features
The combustion turbine power plant uses a gas turbine engine as the prime
mover. This engine, which is similar to an aircraft jet engine, can burn
either liquid or gaseous fuel. The fuel is burned continuously in the pre-
sence of compressed air, and the hot exhaust is allowed to expand through a
gas power turbine. The power turbine drives the inlet air compressor and the
electric power generator, as shown in Figure 5.1.
Most of the energy entering a combustion turbine as fuel is lost in the
form of exhaust gas heat. Only minor mechanical losses are encountered in the
turbine/generator machinery itself. Alternative cycles, including the regen-
erative cycles, the combined cycle and cogeneration cycles, have been devel-
oped, which use part of this exhaust gas heat to improve efficiency. The
combined cycle and cogeneration cycles are discussed in separate technology
5.4
GENERATOR
EXHAUST
GAS
fr
POWER TURBINE
'(\~
FUEL
FIGURE 5.1. Simple-Cycle Combustion Turbine
profiles. In the regenerative cycle, combustion air leaving the compressor
section is channeled through an air-to-air heat exchanger located in the tur-
bine exhaust. The energy thus absorbed by the combustion air decreases the
requirement for fuel and thus increases the combustion turbine efficiency.
This cycle is used in several installations in the Railbelt. Other complex
cycles using interstage cooling and gas reheat have been proposed but are not
currently used in commercial power plants.
Combustion turbine power plants are not complex to build since most of
the equipment arrives at the site assembled, and installation requirements are
minima 1.
Performance Characteristics
Combustion turbine power plants typically have been less efficient than
fossil-fired, steam-electric generating stations. However, recent advances in
combustion turbine technology, particularly improvements in blade metallurgy
and cooling and in combustor efficiency, have significantly increased combus-
tion turbine output and efficiency. Heat rates and conversion efficiencies of
combustion turbines are presented in Table 5.2 for different plant sizes.
5.5
TABLE 5.2. Heat Rates of Combustion Turbines
Rated
Capacity
(MW)
20 -100
0.5 -20
Heat Rate
(Btu/kWh)
10,000 -11,000 (LHV)(a)
12,000 -14,000 (LHV)(a)
(a) Lower heating value. For natural gas the
LHV is 910 Btu/ft3 and the higher heat-
ing value is 1024 Btu/ft3.
Combustion turbines are reliable and are available to meet demand approx-
imately 88% of the time. Typical plant life is 20 years.
5.1.2 Siting and Fuel Requirements
The simple-cycle, combustion turbine power plant has fewer siting con-
straints than conventional fossil fuel or nuclear plants. Only limited space
is required, no cooling water is required, and no operating personnel are
necessary. The primary siting constraints relate to atmospheric emissions and
fuel supply.
The exhaust from combustion turbines typically contains SOx when resid-
ual fuels are used, as well as NOx. These constituents comprise the
pollutants of greatest regulatory concern. Carbon monoxide (CO), unburned
hydrocarbons, and particulate matter can also be present. The quantity of
each particular contaminant emitted is a function of the size of the machine,
the manufacturer, the type of fuel burned, and the extent to which emission
control techniques are used. The suitability of a particular site will depend
upon the degree to which these contaminants can be controlled.
The technology also requires a location to which fuel can be easily
delivered. Combustion turbines need to be located adjacent to a distribution
pipeline or railroad to permit transportation of large volumes of fuel. A
plant with fuel storage would require a 6-acre site; without fuel storage, it
would require 3 acres.
5.6
Future power plants using synthetic fuels derived from coal will have to
be located adjacent or close to the coal gasification plant if medium or low
Btu gas is used, since these fuels cannot economically be moved by pipeline
over long distances. If synthetic liquid fuels are used, the same fuel trans-
portation constraints that exist for liquid petroleum fuels would apply.
Combustion turbines can use a wide variety of natural and synthetic
liquid and gaseous fuels, ranging from heavy residual oils to medium Btu syn-
thesis gases. Combustion turbines operating in tne Railbelt use natural gas
or distillate oil. The performance of the turbine varies slightly with each
fuel, and whereas the basic design of the combustion turbine is the same
regardless of the fuel type, some modifications in design are required.
Natural gas is perhaps the best combustion turbine fuel for performance
and operating simplicity. Heat rates are generally better and exhaust emis-
sions, especially for sulfurous oxides and particulates, are almost nonexis-
tent. Less maintenance is required, since the combustion products of natural
gas are not nearly as corrosive as other liquid fuels. One drawback to using
natural gas is that it must be supplied at a moderate pressure, usually around
300 psig. If the supply pressure is not adequate, a gas compressor must be
used, which can offset the heat rate advantage of natural gas.
Distillate oil used in combined-cycle power plants is normally a light
distillate, Grade DF-2 or equal. Heavier grade distillates can be used if
appropriately treated. Distillate oil can contain sulfur, fuel ash, and trace
metals not generally present in natural gas. Sulfur and fuel ash contribute
to exhaust emissions, and trace metals can cause corrosion, which will reduce
the life of the combustion turbine. However, the amount of contaminants in
distillate oil is generally much lower than in heavier liquid fuels. A mini-
mal amount of treatment equipment, if any, is required to make distillate oil
an acceptable fuel. Because Alaska crude oils are in the medium to heavy
category, a greater proportion of locally produced distillates would be in
the heavier range.
Combustion turbines can burn a variety of synthetic fuels, although little
operating experience with synthetics has been gained to date. Experience is
5.7
lacking mainly because of the high cost and limited availability of synthetic
fuels. However, certain synthetic fuels, notably gas synthesized from coal,
are approaching economic viability. Potential application of synthetic fuels
to Railbelt power facilities is described in Appendix K.
Methanol is a liquid synthetic fuel that may be derived not only from
coal but also from tar sands, oil shale, and biomass. It is suitable as a
combustion turbine fuel and requires only a minimum of modifications to exist-
ing hardware. Methanol produces fewer emissions than petroleum-based fuels.
It contains virtually no nitrogen and no sulfur. Further, since methanol has
a theoretical flame temperature approximately 300°F below that of distillate
oil, thermally produced NOx emissions are substantially reduced. CO emis-
sions are increased slightly, but are still comparable to distillate CO emis-
sions, especially when water injection is required to reduce NOx emissions
in distillate oil.
To use any of these fuels, a fuel transportation system must be provided.
Natural gas will not require storage as long as an adequate gas supply is
readily available through local distribution. Distillate oil is normally
stored on site, and the amount of storage is generally a function of the reli-
ability of the source of supply. Both storage and transportation of low Btu
synthesis gas are impractical, and thus the combustion turbine power plant
must be located adjacent to the gasification plant. Medium Btu synthesis gas
can be transported economically via pipeline to distances up to approximately
100 miles. This capacity removes the limitation of locating the combustion
turbines at the gasification plant, and several power plants may be served by
a single gasification plant. Like other liquid fuels, methanol may be stored
on site. However, it is somewhat more volatile than distillate oil and
requires special handling.
5.1.3 Costs
Combustion turbine power plants are generally regarded as having the low-
est capital cost per kilowatt of any current technology. The brief construc-
tion times, often 1 year or less, contribute to low construction costs.
5.8
As with any other facility, some economy of scale is associated with a
combustion turbine power plant. Virtually all of the capital expenditures are
for package equipment. Unlike steam systems, field erection costs are minimal.
Estimated costs are presented in Table 5.3. O&M costs vary significantly and
published costs can be misleading. Even with identical combustion turbines,
many operators report significantly different O&M costs. One reason for this
difference is that maintenance costs are more directly associated with operat-
ing practices than with equipment. For example, cyclic duty is much more
demanding than continuous operation. Extended operation at peak load rating
and premature loading without a proper warm-up period can drastically reduce
machine life, as can improper fuel selection and inlet air contamination.
Also, maintenance practices differ significantly among utilities. Some utili-
ties rely heavily on preventative maintenance, whereas others only perform
necessary maintenance. In addition, the methods of recording O&M costs are
not uniform, and differences in reported costs may result purely from account-
ing practices.
TABLE 5.3. Estimated Costs for Combustion Turbine Power Plants (1980 dollars)
Cost of Energ~ (mills/kW)(a)
Rated Capacity Capital o&M Cook Inlet North Slope Distillate
(~ioj) (S/kW) (S/kW/~r) Natural Gas Natural Gas @ Fairb~~
50 720 40 60 ( 149) 146 (236) 127 (n7)
70 560 40 58 (136) 11\4 (223) 125 (204)
(a) Levelized lifetime production costs, based on 1990 first year of commercial
operation. Costs shown external to parenthesis are based on baseload operation
(65% capacity factor). Costs enclosed in parenthesis are based on peaking
service (10% capacity factor)
5.1.4 Environmental Considerations
Combustion turbines do not require cooling or other process feedwater for
their efficient operation. Small quantities of water will be required for
domestic use, equipment cleaning, and other miscellaneous uses. If standard
engineering practice is followed, water resource effects should be insignifi-
cant.
5.9
Combustion turbine generators are comparatively inoffensive sources of
air pollution when compared to alternative combustion technologies. This
comparison is provided in Appendix E along with a discussion of the regulatory
framework and various siting considerations. Sulfur emissons can be controlled
by using low-sulfur oils or natural gas. Emissions of NOx can be controlled
by using water or steam injection. These emissions will not preclude the
siting of combustion turbines anywhere in the Railbelt region, except that
their operation within the Fairbanks or Anchorage nonattainment areas may be
difficult to justify. Optimum siting would have to consider nonattainment
areas and Class 1 PSD proximity to natural gas pipelines, barge terminals,
railroads, or other sources of fuel and load centers.
Because cooling water is not required for combustion turbines, aquatic
biota would not be impacted. The only potential impacts would be from con-
struction runoff (refer to Appendix F). Proper construction techniques would
eliminate the potential for impacts on the aquatic environment.
Land losses and human disturbance resulting from combustion turbine power
plants represent the most significant impacts on the terrestrial biota. Land
losses, however, will generally be small (6 acres for 140-MW plant including
fuel storage). These losses will be increased if fuels requiring storage and
waste disposal facilities are used. The overall land requirements for combus-
tion turbine plants are usually much smaller than those for combined-cycle,
steam-electric, or other conventional power plants.
In addition to land losses, combustion turbine power plants fueled by
fossil or synfuels release gaseous and particulate matter that could affect
the terrestrial biota. so 2 and certain trace elements from distillate fuel
use could be the most ecologically offensive pollutants. The impact of toxic
air emissions as well as habitat loss and human disturbance on soils, vegeta-
tion, and wildlife is described in Appendix G. These impacts could be mini-
mized by siting plants away from sensitive ecological communities and by
installing effective pollutant control devices.
5.10
5.1.5 Socioeconomic Considerations
Due to the relatively small work force and acreage requirements for
combustion turbine development, socioeconomic impacts can be expected to vary
more with location than with plant scale. The absence of major siting con-
straints allows flexibility in locating a combustion turbine facility. Thirty
construction workers will be required for a 70-MW plant for a period of
9 months, and 12 workers will be needed to operate the plants. To minimize
impacts, combustion turbines should not be sited in very small towns, although
installing a construction workcamp would lessen the demand for housing and
public services.
A combustion turbine is a capital-intensive facility. Approximately 20%
of the project capital expenditures would be invested within the Railbelt,
whereas 80% would likely be spent outside the region. Approximately 19% of
operating expenditures would be spent outside Alaska because of the large
allocation of costs for outside maintenance.
5.1.6 Potential Application in Railbelt Region
Combustion turbine power plants currently operating in the Railbelt vary
from 3 to 80 MW, with the newer being the large-frame industrial machines in
the 60 to 80 MW range. They have been used in the Alaskan Railbelt since the
early 1960s and currently furnish approximately 64% of the total capacity in
the region. The main reasons for their wide use in the Railbelt have been
their low capital costs, short construction lead time, relatively small unit
size (suitable for small utility systems), and the availability of inexpensive
gas and distillate fuels.
A significant amount of additional combustion turbine capacity is not
expected to be installed in the Railbelt in the future. The prospect of
future cost increases in natural gas in the Cook Inlet area will require more
efficient units of natural gas to be used as an electrical generation fuel.
The need for more efficient units is likely to be met by natural gas combined-
cycle plants, described in the following section. Combined-cycle plants have
much greater efficiency than combustion turbine units and provide similar
operating flexibility.
5.11
In the Fairbanks area, substantial surplus combustion turbine capacity is
in place, making any need for additional units unlikely. When the Anchorage-
Fairbanks intertie is complete, low-cost energy most likely will be imported
from base-loaded Cook Inlet natural gas combined-cycle plants. Operation of
the existing Fairbanks combustion turbines then would be limited to reserve
and peaking purposes. New combustion turbine units most likely would not be
needed. If inexpensive North Slope natural gas were delivered to Fairbanks,
new gas-fired plants probably would be combined cycle or possibly fuel cells,
if the latter technology becomes commercial.
Possible future applications of combustion turbines in the Railbelt could
include 1) installations to meet unexpected load growth, 2) installations to
serve isolated loads and 3) black start reserve units. The short lead time
required for combustion turbine installation and their low capital cost makes
these units ideal for meeting unexpected demand for new capacity. Several
qual~ties of combustion turbines make them attractive for serving small iso-
lated loads. These qualities include the availability of units of modest
rated capacity and low capital cost, the capability of burning readily trans-
portable liquid fuels, simplicity of operation, and load-following capacity.
Combustion turbines can be started and brought on-line quickly. This capabil-
ity together with low capital cost makes these units valuable for reserve
service.
Future application of this technology is presently restricted by the Fuel
Use Act, which restricts petroleum fuel and natural gas use. The Fuels Use
Act generally limits use of petroleum or natural gas for electricity genera-
tion to peaking units operating 1500 hours per year or less. After 1990 the
use of natural gas is prohibited. However, combustion turbine power plants
that are integrated with a coal conversion plant or fueled by a product such
as low or medium Btu gas, methanol or distillate oil from such a plant could
be used. Some exemptions from the provisions of the Fuel Use Act are avail-
able, including units used for cogeneration. Further discussion of the pro-
vision of the Act is provided in Appendix N.
5.12
5.2 COMBINED-CYCLE POWER PLANTS
The combined-cycle power plant relies on two proven technologies, the
combustion turbine and conventional, steam-cycle power generation. Combined-
cycle plants are efficient and reliable generating resources that have been in
commercial operation over a decade. These plants are capable of closely fol-
lowing growth in demand since generating capacity can be added in relatively
small increments.
5.2.1 Technical Characteristics
The combined-cycle power plant is so named because two different thermo-
dynamic cycles are used simultaneously to produce electricity. (This differs
from cogeneration, which produces two forms of energy, electricity and process
heat.) A combustion turbine combined-cycle plant consists of a conventional,
combustion turbogenerator, as described in the combustion turbine profile
(Section 5.1) with an exhaust heat recovery boiler supplying a steam turbo-
generator.
The minimum economical size of a large-frame, combustion turbine, com-
bined-cycle plant is 90 MW. This is slightly larger than a large combustion
turbine plant (60 to 80 MW). Plant sizes up to about 250 MW are available.
Design Features
The heat recovery boiler of a combined-cycle plant uses the thermal energy
in the combustion turbine exhaust to produce superheated steam, which is then
used in the steam turbine to generate additional electricity. By recovering
energy that would otherwise be wasted, the combined cycle substantially
improves the efficiency of a simple-cycle, combustion turbine plant. The
process of generating electricity in a combined-cycle plant is depicted in
Figure 5.2.
The early combined-cycle plants resulted from 11 repowering 11 existing steam-
electric generating facilities. Combustion turbines with heat recovery boilers
were retrofitted to provide steam for existing steam turbine generators. When
fuel prices increased drastically during the mid 1970s, several utilities
5.13
HEAT
RECOVERY
BOILER
GENERATOR
EXHAUST
GAS
41
-)
t
POWER TURBINE
"(\~
COMBUSTORS
,--..,.......~--.--.---= COOL/ NG
WATER
0 d 4 d
FUEL
FIGURE 5.2. Combined-Cycle Power Plant
retrofitted simple-cycle, combustion turbine plants to combined-cycle opera-
tion, thus increasing generating capacity and markedly improving efficiency.
Converting a simple-cycle, combustion turbine plant to combined cycle
normally does not restrict the use of the facility as a simple-cycle plant.
Combustion turbine exhaust dampers allow the heat recovery boiler to be
bypassed entirely (Figure 5.2). The steam cycle can be started up when
5.14
necessary after the combustion turbines are on-line. Further, only one steam
turbine is normally furnished for several combustion turbine, heat-recovery
boilers. This steam turbine can operate at partial load if any of the combus-
tion turbines are out of service. This capability allows a combined-cycle
plant considerable flexibility in electrical output. Additional operating
flexibility can be provided by exhaust duct firing whereby the waste heat
boiler can be separately fired without operation of the combustion turbines.
Combined-cycle power plants can be erected more rapidly than conventional,
large power plants of equivalent capacity. Two to 4 years is a typical con-
struction time for a new plant. They are usually constructed in phases, with
the combustion turbine portion erected first. This process allows the combus-
tion turbines to generate power while the balance of the plant is still under
construction. Combined-cycle plants therefore traditionally have been used
where generation is needed to fill critical shortages.
Performance Characteristics
Combined-cycle plants are considerably more efficient than simple-cycle,
combustion turbine plants, since turbine exhaust heat is converted into useful
electrical energy. Average annual heat rates are provided in Table 5.4. Com-
pared to other conventional fossil generation technologies of comparable capa-
city, a combined-cycle plant would use less fuel and would reject less heat to
the environment.
TABLE 5.4. Heat Rates of Combined-Cycle Plants ( EPRI 1979a)
Rated Heat
Capacity Rate
Fuel { MW} {Btu/kWh}
Distillate 250 8600
Residual 250 8685
Combined-cycle plants are generally used for intermediate duty applica-
tions (2,000 to 4,000 hr/yr), but they are efficient enough for baseload oper-
ation. For example, the AML&P Anchorage 2 Plant is operated as a baseload
5 .15
plant. Since the combustion turbines can be operated independently of the
steam cycle, combined-cycle plants can also meet peaking duty requirements.
The reliability of combined cycle compares favorably with other combustion
technologies. On the average, combined-cycle power plants are available 85%
of the time, compared to 78% for nuclear steam electric and 92% for natural-
gas-fired steam electric. The response time to changes in load is very good,
making a combined cycle useful for load-following applications. Typical plant
life is 30 years (EPRI 1979a).
5.2.2 Siting and Fuel Requirements
Like the simple-cycle, combustion turbine plant, a combined-cycle plant
has siting constraints related to air emissions (see Section 5.1). In addi-
tion, the combined-cycle plant has further constraints imposed by the steam
cycle, which requires water for condenser cooling and boiler makeup. However,
because the combustion turbine portion of the total combined-cycle plant
(approximately two thirds) requires essentially no cooling water, water
requirements are much less than a similar sized, conventional steam-electric
plant.
Fuel storage and handling requirements for combined-cycle plants are the
same as those described in Section 5.1 for combustion turbines. A pipeline
source of gas is required for natural gas units. Distillate-fired units
require a pipeline or rail supply of fuel. Natural gas, distillates, and
synthetic fuels may be used. A typical 200-MW, combined-cycle plant composed
of two combustion turbines and one steam turbine would require 12 acres with
fuel storage and 6 acres without fuel storage. These estimates do not include
buffer areas, which may be required for noise suppression.
5.2.3 Costs
Capital costs in 1980 dollars for combined-cycle plants are obviously
higher than those for simple-cycle plants, but are still substantially less
than other fossil fuel or nuclear facilities. Typical costs for a combined-
cycle plant are presented in Table 5.5. Estimated capital costs of retrofit-
ting a steam turbine/generator and heat recovery boilers to convert a simple-
cycle combustion turbine into a combined cycle are also shown in the table.
5.16
TABLE 5.5. Estimated Costs for Combined-Cycle Facility (1980 dollars)
Cost of Energ~ {mills/kW)
Rated Capacity Capital O&M Cook Inlet North Slope 0 ist i llate
(MW} ($/kW} ($/kW/yr) Natural Gas Natural Gas @ Fairbanks
90 (New P 1 ant) 1000 35 50 111 96
200 (New Plant) 920 35 49 110 96
90 (Retrofit) 240 35 39 99 85
200 (Retrofit) 320 35 40 100 86
(a) Levelized lifetime production costs, based on 1990 first year of commercial
operation. 65% capacity factor is assumed.
Capital expenditures for combined-cycle plants are largely for equipment,
although some field erection is required, particularly for larger waste heat
boilers and associated steam-cycle equipment. Combined-cycle plants require
less labor for construction than do steam-electric plants.
O&M costs for combined-cycle plants are fairly constant over a large
range of plant sizes. O&M costs for combined-cycle plants seem to suffer the
same recording and reporting disparities as simple-cycle combustion turbines.
Reported O&M costs vary considerably as a result of different operating and
maintenance practices as well as accounting practices. Reported O&M costs for
combined-cycle plants are generally about 1 mill/kWh less than those for
simple-cycle, combustion turbine plants. This difference may result because
the baseload operation typical of combined-cycle plants is less demanding of
machine life than is the cyclic duty typical of combustion turbines.
5.2.4 Environmental Considerations
Water resource impacts associated with the construction and operation of
combined-cycle power plants are generally mitigated through appropriate plant
siting criteria and a water and wastewater management program (refer to Appen-
dix D). A favorable attribute of combined-cycle power plants is that, on a
per-megawatt basis, these facilities require much .less water for cooling than
any other conventional steam-cycle systems. They also produce little solid
waste and therefore minimize disposal and wastewater treatment requirements.
Significant, or difficult to mitigate, water resource impacts should not pose
restrictive constraints on the development of combined-cycle plants.
5 .17
Air-quality impacts of combined-cycle plants are similar to those of com-
bustion turbines (see Appendix E). Nox emissions can be controlled through
water or steam injection techniques. so 2 emissions are negligible with natu-
ral gas fuel, but for distillate fuels so 2 emissions can be reduced by using
low sulfur oils. Water vapor is discharged from the waste heat rejection
system of the boiler unit. The formation of plumes can be eliminated by using
a wet or wet/dry cooling tower system (Appendix I). No offsite meteorological
effects of system operation will be detectable.
Potentially significant water withdrawal and effluent discharge impacts
that are common to all steam-cycle plants would be the lowest on a per-megawatt
basis for combined-cycle plants. A typical water-use rate of thes~ facilities
is 150 gpm/MW or 3 gpm/MW for once-through or recirculating cooling water sys-
tems, respectively.
The greatest impact resulting from combined-cycle power plants on the
terrestrial biota is the loss of habitat. The amount of land required is
generally small (6 acres for a 200-MW plant) but can be larger (12 acres) if
plants are fueled by distillate oil or certain types of synfuels that require
onsite fuel storage. Distillate-fired plants may also require land for ash
and scrubber sludge disposal. Combined-cycle plants generally have greater
land demands than simple-cycle plants because of the need for condenser waste
heat rejection systems.
In addition to direct habitat loss, combined-cycle plants can affect ter-
restrial biota through gaseous and particulate emissions. so 2 and emissions
from certain trace elements probably have the highest potential for terrestrial
impacts. This potential, however, highly depends on the fuel type. Distillate
oil-fired plants produce the highest levels of so 2 emissions, whereas natural
gas-fired plants produce almost none. The specific impacts of these emissions
and those of land loss and human disturbance on the terrestrial biota are
described in Appendix G. The impacts on soils, vegetation, and wildlife can
be minimized by siting plants away from sensitive ecological areas and by
installing adequate pollution control devices.
5.18
5.2.5 Socioeconomic Considerations
Construction of a 200-MW combined-cycle plant will require approximately
45 persons for a period of 2 to 4 years. The operating and maintenance force
would consist of approximately 15 persons. Since the construction work force
is relatively small, impacts should vary more with site location than with
piant capacity. Severe construction-related impacts .. would likely only occur
in very small communities where the infrastructure is insufficient to meet new
demands. These impacts can be lessened by siting a combined-cycle plant in a
community with a population greater than 500.
Since combined cycle is a capital-intensive technology, the largest
portion of expenditures outside the region would be attributed to equipment.
Approximately 70% of the project's capital expenditures would be spent outside
Alaska, whereas 30% would be spent within the Railbelt. Approximately 16% of
O&M expenditures would be spent outside the region. Fuel (natural gas or
distillate) would likely be purchased in state.
5.2.6 Potential Application in the Railbelt Region
Widespread use of combined-cycle technology is relatively recent, dating
from the mid 60s. One plant, the 139-MW AML&P Anchorage 2 unit, is currently
operating in the Railbelt, and conversion of Chugach Electric Beluga Units 6
ana 7 to combined-cycle operation is underway.
Further application of natural gas combined-cycle units in the Railbelt
appear to be promising if Cook Inlet natural gas prices continue to remain at
their relatively low levels and if exemption to Fuel Use Act prohibition could
be obtained. The high efficiency and relatively low capital cost of combus-
tion turbine combined-cycle units would result in continued supply of low-cost
electricity. These units• operational flexibility, which allows them to be
operated in either baseload or load-following capacity, also adds to their
desirability in a relatively small utility system. The high efficiency of
these plants would also extend natural gas supplies as far as is possible with
currently available fossil-fuel technology. Questions remain, however, as to
the long-term availability of natural gas in the Cook Inlet region.
5.19
Construction of new, natural-gas-fired, combined-cycle plants may be
severely curtailed because of the provisions of the Powerplant and Industrial
Fuel Use Act (PIFUA) of 1978 (10 CFR 500). The PIFUA prohibits petroleum or
natural gas use as a primary energy source in new base-loaded electric power
plants. Exemptions are available, for example, for plants incorporating pro-
visions for cogeneration. Additional discussion of the provisions of the
Fuels Use Act is provided in Appendix N.
An alternative application of combined-cycle technology in the Railbelt
is conversion of existing combustion turbine units to combined-cycle configura-
tion. The conversion, which would likely be feasible for newer and larger
combustion turbine units only, would extend fuel supplies and allow economic
operation of the retrofitted plans as baseload units. Conversion candidates
are found in both the Fairbanks and Anchorage areas.
In the longer term, a promising application of combined-cycle technology
may be in integrated, coal gasifier combined-cycle plants. Coal gasification
technology, currently in the the developmental stage (Appendix I) may be used
to supply a low or medium Btu synthetic fuel gas that can be used to fire com-
bined-cycle plants. Physical integration of the gasifier and combined-cycle
plant reduces waste heat loss and increases overall plant efficiency. If coal
costs were low, such a plant appears capable of economically competing with
conventional, pulverized, coal-fired powerplants. Recent research (Fluor
Engineers and Constructors, Inc. 1980) indicates that gasifier-combined-cycle
units might be operated in load-following duty, an advantageous feature not
possessed by conventional coal-fired powerplants. Coal-gasifier, combined-
cycle plants would not be subject to provision of the PIFUA.
5.20
5.3 DIESEL GENERATION
Diesel generation accounts for approximately 5% of the Railbelt's elec-
tric generating capacity. Approximately 36 MW of utility capacity exists,
whereas institutional (e.g., military) power generators operate approximately
17 MW. These units are used as "black start" units (units that can be started
with batteries, compressed air or gasoline engines when a power outage occurs),
peaking units, and standby units. Diesel generators also are used as load-
following (cycling) units in remote locations and in small communities in the
Ra i lbe lt.
5.3.1 Technical Characteristics
A diesel generating plant consists of a diesel cycle, internal combustion
engine driving a standard electricity generator. Diesel installations in the
Railbelt region range in size from 1.5 to 7.2 MW, although a much larger range
of unit sizes is available. Stationary diesel generator sets have been built
in capacities ranging from 30 kW to 15 MW. Units ranging in size up to 20 MW,
using slow-speed, two-stroke diesels, are under constructi.on.
Design Features
The diesel engine was invented to simulate the idealized Carnot thermo-
dynamic cycle. In the diesel cycle, air is admitted and compressed with fuel
until ignition occurs. During combustion additional fuel is added to the
cylinder to maintain constant pressure. Expansion of the combustion products
performs the work (i.e., drives the generator).
The diesel cycle varies from the Otto (spark ignition) cycle in that the
compression of air provides sufficient heat for fuel ignition. Compression
ratios typically range from 12:1 to 15:1 and can reach 20:1, contrasted with
spark ignition ratios ranging from 6:1 to 10:1. These higher compression
ratios contribute to the relatively high thermal efficiencies of diesel units.
Performance Characteristics
The fuel consumption of diesels is largely a function of thermal effi-
ciency. Typical heat rates of relatively modern diesels in the Railbelt region
are about 10,500 Btu/kWh (a thermal efficiency of 33%). Very large, slow-speed
5. 21
units have achieved heat rates of 8,500 to 9,700 Btu/kWh, with efficiencies
ranging from 35 to 40%. Very small units may have heat rates that approach
11,400 Btu/kWh.
In contrast to combustion turbines, diesel power has the advantage of
being able to efficiently operate at less than full load. Fuel consumption
rates for a Caterpillar 900-kW generator demonstrate this characteristic
(Table 5.6).
TABLE 5.6. Fuel Consumption Rates and Equivalent Heat Rates
for a Diesel Generator Operating at Various Loads
Fuel Consumption Heat Rat~ )
Kilowatts {gallons /hr) {Btu/kWh~ a
900 70 11 '100
800 60 10,700
700 52 10 '600
600 45 10,700
500 39 11 '200
400 32 11 '400
(a) Assuming a heating value of 19,000 Btu/lb;
specific gravity of 0.9.
Diesel units are reliable. Experience in the Railbelt area indicates a
forced outage rate of only 10%. Life spans of 20 years are common, with life
spans reaching 30 years for well-maintained units. Units in remote locations
may have a much shorter life because of poor maintenance.
Diesel units are able to quickly respond to startup and shut down. These
units are used in the Railbelt and elsewhere as black start emergency units.
Diesels can also be used to augment fuel-saver technologies, such as wind or
tidal power when natural conditions preclude power generation from the fuel-
saver technologies.
5.22
5.3.2 Siting and Fuel Requirements
Diesels are well suited for generation throughout the Railbelt region.
The small, high-speed units are compact, usually are prefabricated, and require
little site preparation. An 850-kW machine, for example, is approximately
15 x 5 x 7 ft high and weighs 12 tons. Mediumand low-speed units are larger,
usually are site erected, and require more foundation work. Diesel units
require a noise-suppressing, weatherproof structure plus fuel storage facili-
ties. Sites for even the largest units seldom exceed 2 to 5 acres, and many
sites in remote Alaska villages are 1 acre or less.
Siting requirements are few. Closed cooling systems are generally
employed; thus, a constant supply of cooling water is not required. Units may
be remote controlled, allowing unattended operation. The principal site con-
straints for diesel units include access to fuel supply and site accessibility
via barge, rail, or truck for delivery of the unit. Air shipment of units has
been used in remote locations such as communities in the Alaska's interior.
Auxiliary systems associated with diesel units are minimal. Fuel storage
is required, particularly in remote locations where fuel deliveries may be
yearly. Waste heat boilers may be attached for cogeneration (see Section 7.1).
The small size of diesel units and the relatively clean fuels consumed gener-
ally eliminate the need for extensive pollution control systems, although sound
suppression systems are required.
Diesel units can be fueled by a variety of liquid and gaseous hydro-
carbons. Available data show that Alaska diesel units are fueled by distil-
late oils, although other fuels such as natural gas have been used. Synthetic
fuels, such as low and medium Btu gas from coal and biomass conversion and
methanol, also have been proposed for diesel units.
5.3.3 Costs
Diesel power is typically expensive. Most of the capital cost expendi-
ture is for the equipment, which is purchased outside Alaska, and the trans-
portation of that equipment to Alaska. Only small erection expenditures are
necessary. For smaller, high-speed units traditionally used in Alaska,
5.23
operating costs are largely incurred for purchase of fuels and lubricants.
Remote control of several systems by a single operator is possible in multiple
unit systems. Replacement of parts in remote villages is costly because of
transportation expenses for parts and possibly labor derived from Anchorage or
outside Alaska. In remote areas, consumers may play a role in diesel mainte-
nance and have a direct role in the decision to supply electricity.
Estimated capital, O&M, and levelized costs of power for diesel plants of
various capacities are provided in Table 5.7.
TABLE 5.7. Estimated Costs for D i e se 1 E 1 ec tr i c Generation (1980 dollars)
Rated Capita 1 O&M Levelized Cost (a)
Cae ac it,t ( MW} ($/kW} ($/kW/,tr} of Energ,t (mills/kWh)
3 850 55 105 (205)
6-9 800 45 103 (191)
12 700 35 100 (173)
(a) Levelized lifetime production costs based on 1990 first year of com-
mercial operation. Costs external to parentheses are for baseload
operation (65% capacity factor). Costs in parentheses are for
peaking service (10% capacity factor). Fuel is distillate at
Fairbanks.
5.3.4 Environmental Considerations
Diesel electric generating systems do not require cooling water or con-
tinuous process feedwater for operation. Also, they require extremely small
tracts of land for all plant facilities. Impacts to the water resources and
to aquatic and marine ecosystems from both construction and operation of these
plants will be insignificant.
Air-quality emissions from diesel engines will be confined mainly to CO
and particulates. High sulfur residual fuels are generally not used in these
engines. CO emissions can be controlled by using catalytic converters, and
particulate emissions can be controlled by optimizing engine operation. In
the Railbelt, these facilities may be sited almost anywhere, with the possible
exception of CO nonattainment areas (Anchorage and Fairbanks).
5.24
l~lpa.<.ts Dfl t he tt!tr~stria I bin ta. f1'.01\1 d iesel ~~·t:ems shou ld b·~ min'iroa l .
LMid t eq.u ir~metlts ~.ra s.ma11 ( les:; •t han '5 acre~5;) Mel. ah' p.o.11uU~n poten tial 1!.
lDw. AtEe<;;s re.ad l'equ l'rem e nts wou.ld also~ tllinimal si.nce pi a.t\ts wqu1.d !;le
s 1ted inar a.rH ~en -t ta devl':1.o!J,e;.l ore a.s , f'o~s \ble impqcts due to no·1s!!' a:nd
f uel ~.f;o r~g ~ c9rr gen>!r.;llY be rew .l Ved thrtHJgti no•1se-sup~l',ess1on dedces amt
tha i\V.oHl~nee 9f im~ol''lant Yli'1 •ilife il ~bit;;~~
'l'l're mipact s of sH.tnn ti i ese 1 g.ener.~tors in t he Ra<tl belt -are ·~y,pec ted t o
~'!! mir'l ima l due t o :t.he i nher'el\t 11mi't.ati!1n nf pl:ant st:a 1-a (!L O ~ t,o :20 MW'i l!rid
tl\e allsen r:e of nl aJ'ur s it i ng G!l h !fb•a 1 n t~~ A l-arge di.esei ,9,enel"iltO.l" wo ulcl
reqtd !·e a ,s ma l1 ~a n ·'&tt ud i x:!h crew n f 5 f a 125 WJllrk·.en f C!ll' l mon ::h to i I)' ear,
~epentli ng .upon .\.ll',i t si~e. Oiie o.r two people on a part -time: ll o$Sl'£ cou~d fu l-
fill t he O&N reqo f ~en~s,. Fll<! ·Work Por'ce coul.d ~e. comj3ost>i;l pr im ~'''il.l' of
res fdetlts., tnak i ng d l~se 1 powe l' oomP~·~'il'!l e with vet~ 11 -sma 11 ., ~m il.1 t, •md int.et·-
med1~te-si~!;d fXOmm j.jnit-1es.
Si·hcc diese "l e:'J edl"ic 9eneN'tl•PI1 i~ capitai i»J:;eil s i:Ve t a l a1"~e-p.ort.ion rrf
ttl~ c:ap1ta:l fUruis wsuld' b.e sent auts1 ci !l Alasl,:cl.. Apj:i'r0~·1rn~l.e l y 00% tYf ih~
C::t'i.~ i,~a l i nves t 111ent. ef tlu> P,l"b.jed 1'/0\lld be made .ov t:.s itl.e of t:h l> R"i 1 be ]t,
.l'iher~q.s cZ<i~ would be spen t 1ns1de the regj,on . Bect~use of the l>fllill1 ou .tsi~e
ttlii1nto;natJce requirellle nt5, 9 ~~ l.i f 08111' exP,erid 1tures are. expected t;Q r.emaftl
W fth1 'o the r.egi on , Fut;.l m!J5t. ii.kelY ~~ould . IJ e: pUrcha t ell i'r9m wit h ill t he re§•ion ,
~ .J .5 Po~e rnf.ta.l App 1i cat 1 ol\ ~/I the rl.a il h!i< 1 t Re.!} iOii
'EiecuiJSe sma 11 i ncr.ements of capac it,y are .;v~ ilall1~ and beca(!se oie;$el
gener.atort c.'!l n 15e in1;ta lled quic~ l y , t htay cart be JJs.ed to pro y icl~ b,ase luad
tapacit;.y '01' resi.'Y'ye 1!!'8P<~cit.Y F·ot srnall .cD!1li1~Mi :tl~'l ill t he R"iloel t 1"eg1on .
Tlteir efficiency , parti'cu lar l,V at part ia •l loacl s , plul! :hf 1ein rehatt'i·!lty,, m,:~lli e
'li~em po.rti cl,l .l<irly ~u1te!i w tll!i t•etno t e V·11 l <!ges .. r..a_s t of oper ation h th.e
lthntine f<~~:tor b.ecause pf t~1ei l" cl,ependen ee on l'i 'f!lh"~pr·t te'i'l, ref 1 ,~ed. l'etro leum
pl~oiluds.
Th-e mo £1. 1ike1y t"utu ~e use l)f 0 1e!ie T elet.tl"it Uliits. Wi th in the i\-a:i ,be lt
ur.ea t ha t is serv~ii b~ f.fle larg.er in 'te'rton n er;~er! lf ~il'iti:es 11rJU lil b-e f or' blsc ~
!'l.'\;ii rt )·eserve ~nit!>.
5.4 INTERMEDIATE-AND LARGE-SCALE HYDROELECTRIC PLANTS
Hydroelectric plants convert the energy of flowing water to electric
power. Generation of electricity from falling water is a mature technology
and the economics are well established. The viability of hydroelectric
developments depends on streamflow and site characteristics, project design,
proximity to load center, ability to meet estimated electrical demand, and
environmental and socioeconomic impacts.
The first hydroelectric plant in the United States was put into operation
at Appleton, Wisconsin, in 1882, a few days after the first thermal electric
plant began operation. Prior to 1919, development of hydroelectric plants was
slow because transmission of electricity over great distances was inefficient.
As transmission efficiencies were improved, hydroelectric developments pro-
gressed rapidly. For decades in many regions of the United States, thermal
plants served primarily as standby units in case of equipment failure or as
supplements to hydroelectric units during peak demand hours. Because the
growth in electric power demand has outstripped the supply of suitable hydro-
electric sites in the Lower 48, the more recent trend has been toward the use
of thermal power to carry baseload, with hydropower supplementing thermal
generation for peak loads.
Of the 610 GW of installed capacity for the United States (DOE 1979a),
about 11.5% (70.4 GW) is hydroelectric capacity. About 80% of the peak load
demand for the Pacific Northwest is provided by hydropower (Pacific Northwest
River Basins Commission 1980). In comparison, only 13% of all electric energy
consumed in the Railbelt is from hydroelectric resources.
5.4.1 Technical Characteristics
Two basic types of hydroelectric plants exist: conventional and low
head. By definition, conventional plants have heads greater than 20 meters
(66 ft), and low-head plants have heads less than or equal to 20 meters.
Low-head plants are usually small and have become more economically feasible
as energy prices have risen. Very few economical low-head sites have been
identified in Alaska. However, many conventional and small, high-head sites
exist.
5.26
Intermediate and large-scale hydroelectric projects are defined as sites
having an installed capacity greater than 15 MW. Significant differences in
operational capability are also inherent in this distinction, as small-scale
hydro projects are more likely to be "run-of-river" and not capable of produc-
ing scheduled peak power generation. Thus, small-scale projects often operate
in a fuel-saver mode in contrast to intermediate and large-scale projects,
which generally have storage and are thus capable of operating as load-
following units. Small-scale and microhydro units are discussed in
Section 7 .6.
An inventory of technically feasible hydroelectric sites in the Railbelt
region has identified sites having potential installed capacities ranging from
the 2 to 3600 MW (Table 5.8).
Design Features
The major components of a conventional hydroelectric development include
a dam or diversion structure, a spillway for excess flows, hydraulic turbines,
a conduit (penstock) to convey water from the reservoir to the turbines, gen-
erators, control and switching apparatus, a powerhouse for housing equipment,
transformers, and transmission lines (see Figure 5.3). Additional requirements
may include fish passage equipment, trash racks at the entrance to the pen-
stock, gates for penstock and spillway flow control, a forebay (small reservoir
that regulates flow into the penstock from the canal, if present), a surge
tank (to prevent pipe damage from forces created when flow in the penstock is
changed rapidly), and a tailrace (a channel into which water is discharged
after passing through the turbines). No two hydropower projects are exactly
alike. The type and arrangement of the plant best suited to a given site
depends on many factors, including head, available flow, and general topo-
graphy of the area.
Four types of dams exist, classified on the basis of configuration and
construction materials: gravity, arch, buttress, and earthfill. The first
three are usually constructed of concrete. More than one type of dam may be
included in a single development. For example, a concrete gravity dam that
contains spillway and low level outlets may be constructed across the main
river section with earth or rock-fill wing dams extending to either abutment.
5.27
TABLE 5.8. Technically Feasible Hydroelectric Sites in the Railbelt Region
Average
Annual
Site Stream
Firm Ener~y
( GWh) a)
Eneru;
(GWh) )
Insta 11 ed C~pac it}
(MW) (c,
* Allison Creek(d) Allison Creek 18 33 4 (8)
Big De 1 ta Tanana River 987 226
Brad l~y '-a~e Bradl~y Creek 410 (315)(e) 347(e) 94 (9Q)(e)
.;r Browne Nenana River 385 410 80 ( 100)
* 5ruskasna Nenana River (f) 140 40 (30)
* Cache Talkeetna River 220 220 50 (50)
Canyon Creek Canyon Creek 131 27
Car ioou Creek C<:r ibou Creek 90, 19
Carie Nenana River 84Qif) 30
Cathedral Bluffs Tanana River 693 158
* Cnakachamna Chakachatna River 1600 1925 366 (480)
Chu I·itna (East Fork) East Fork Chulitna River 59 12
Chulitna (West Fork) Chu 1 itna River 68 14
Coa 1 Creek Matanuska River 307 64
Coffee Beluga River 160 37
Crescent Lake I Crescent River 79 41
Crescent Lake II Crescent River 29 6
D~adman Creek Deadman Creek 165 34
Dev ~ 1 Canyon Susitna River (g) 738 (400)
Eagle River Eagle River 45 9
Fox Unknown Unknown Unknown
Gakona Copper River 727 150
Gerst 1e Tanana River 438 100
Granite Gorge Talkeetna River 345 i2,
Grant Lake Grant Creek 19(h) 27(h) 7\h)
Greene stan~ Talkeetna River 246 51
Gulkana River Gulkana River 164 34
Hanagita Lake Hanagita River 160 33
Healy Nenana River (f) 130
* Hicks Matanuska River 286 245 59 (60)
Hurricane Chulitna River 166 34
Jack River Jack River Unknown Unknown
* Johnson Tanana River 920 210
Junction Island Tanana River 2330 532
Kantishna River Kant is hna River 394 82
Ka~ilof River Kasilof River 193 40
* Keetna Talkeetna River 324 395 74 (100)
Kenai Lake Kenai River 552 115
Killey River Killey River 100 21
King Mountain Matanuska River 210 44
Klutina Klutina River 263 54
Kotsina Kotsina River 133 28
Lower Beluga Beluga River 72 15
* Lower Chulitna Chulitna River 394 90
Lower Lake Creek Lake Creek 105 22
Lower Kenai Kenai River 263 55
* Lane Susitna River 1052 240
Lowe Lowe River 254 55
Lucy Chulitna River 71 15
5.28
Site
~lcCl~ren River
McClure Bay
~lcKinley River
Million Dollar
Moose Horn
Nellie Juan
Ohio
Power Creek -I
Power Creel: -II
Unl: nown
Rampart
Salmon
Sanford
Sheep
Sheep Creek I
Sheep Creel: II
Unknown
* Silver Lake
Skwentna
* Snow
Solomon Gulch
South Fork
Ste 1 ters Ranch
* Strandline Lake
Summit Lake
Talachulitna
Talachulitna River
*Talkeetna -II
Tanana River
Tazlina
Tebay Lakes
Tel:lanil:a River
Tiel:el River
* Tol:ach itna
Totatl ani I: a
* Tustumena
Upper Be 1 uga
Upper Lake Creel:
Upper Nellie Juan
Vachon Island
Van Cleave
Watana
Wh isl:ers
Wood Canyon
Yanert -II (j)
Yentna
TABLE 5.8.
Stream
McClaren River
Unknown
McKinley River
Copper River
Kenai River
Nellie Juan River
Chulitna River
Power Creel:
Power Creel:
Unknown
Yukon
Bremmer River
Copper River
Talkeetna River
Sheep Creel:
Sheep Creek
Unknown
Duck River
Skwentna River
Snow River
Unnamed
South Fork Bremmer River
Kenai River
Beluga River
Gull:ana River
Sl:wetna River
Talachulitna River
Talkeetna River
Tanana River
Tazline River
Tebary River
Tel:lanil:a River
Tiel:el River
Chulitna River
Totatlanil:a River
Tustumena Glacier
Beluoa River
Lake-Creel:
Nellie Juan River
Tanana River
Unnamed
Susitna River
Susitna River
Copper River
Nenana River
Yentna River
Alaska Power Administration (1980) estimates shown.
Acres Pmerican (1981b) estimates, unless noted.
( Contd)
Firm Enerp
(GWh)lal
263
Unknown
201
1927
290
47
144
66
Unknown
34,200
86
385
149
94
Unknown
48
(i)
278
11
156
403
81
164
1390( i)
137
215
315
503
193
272
105
806
114
102
210
74
57
2050
10
552o(g)
368
21,900
298
(i)
Average
Annual
Enerp
(GWh) ,b)
220
85
215
6070
Installed C~pacity
(MW)(C;
55
Unknown
42
440
60
10
30
14
Unknown
5040
18
80
31
20
Unknown
10
98
63 (50)
2
32
84
17 (20)
34
75
28
50 (50)
65
104
40
57
22
184
24
21
48
15
12
426
2
478 (BOO)
84
3600
62
145
(a)
(b)
(c) Alaska Power Administration, installed capacity proposed by Acres Pmerican (1981b) shown in
parentheses.
(d)
(e)
(f)
(g)
(h)
(i)
( j)
Asterisks indicate the 17 sites that are potential altern~t~ves to the Upper Susitna Project.
Obtained from telephone conversation with John Denniger from the Alaska Power Administration,
Juneau, A 1 ask a.
Healy, Brusl: asna and Carlo operated as a system.
Devil Canyon and Watana operated as a system. Firm energy estimate based on preferred plan
(Watana/Devil Canyon) of Acres A~erican (198lb).
CH2M-Hi ll (1981).
Skwentna, Talachulitna and Yentna operated as a system.
Would inundate Carlo and Brusl:asna sites.
5.29
RESERVOIR
ELEVATION
CANAL
FOREBAY PENSTOCK
PLAN
SURGE
TANK
HEAD
TAILRACE
FIGURE 5.3. A Typical Hydropower Installation
5.30
The type of dam chosen for a particular site is a function of engineering
feasibility and cost. Feasibility is governed by topography (e.g., if the dam
site is located in a narrow canyon or in a flatter area), geology (foundation
characteristics, rock permeability), and climate. Cost depends on the design,
availability of construction materials near the site, and the accessibility to
transportation facilities.
A spillway is provided to discharge major floods without damaging the dam
and other project components. The spillway may be uncontrolled, or it may be
controlled with crest gates so that outflow rates can be adjusted. The
required discharge capacity depends on the design flood (the largest flood
that statistically might be expected), normal discharge capacity of outlet
works, and the available reservoir flood storage.
The powerhouse does not have to be located at the dam. Various combina-
tions of open canals and pressure conduits (pipes flowing full with water
under pressure) can be used to convey waters from the reservoir and intake
structure to the turbines in the powerhouse. Open canals can be used to
convey water over a relatively flat terrain. Penstocks are used for the
elevation drop between the reservoir and the powerhouse.
A hydraulic turbine transforms the kinetic energy of flowing water into
mechanical energy that performs useful work when harnessed to a generator.
Three basic types of hydraulic turbines exist: impulse (e.g., Pelton wheel),
which derives mechanical output from one or more jets that impinge on the
periphery of a wheel (the runner), and two reaction types (Francis and propel-
ler), which harness the combined actions of pressure and velocity of water
passing through the turbine runner and water passages. Impulse turbines are
inefficient at heads other than the design head, and they are usually used in
high head (650 to greater than 3,300 ft) installations. This type of unit is
suitable for small, high-head application in Alaska. The Francis-type reac-
tion turbine is widely used for high-unit capacity installations and with
hydraulic heads in the range of 100 to 2,400 ft (medium range). Propeller-type
reaction turbines are used for hydraulic heads less than 100ft.
5.31
The powerhouse that houses and protects hydraulic and electrical equip-
ment may be either a surface or an underground structure. The surface power-
house consists of a substructure to support the hydraulic and electrical
equipment and a superstructure to house and protect this equipment. An
alternative arrangement, which reduces the superstructure cost, provides only
individual housing for each generator. The disadvantage of this "outdoor
powerhouse" arrangement is that units cannot be disassembled during inclement
weather. This design most likely would not be used in Alaska. The second
type of powerhouse, the underground powerhouse, is constructed in a natural or
manmade cavern. This arrangement is used in certain topographic conditions,
particularly narrow canyons, which preclude the convenient siting of a surface
powerhouse.
Performance Characteristics
In its present state of technological development, the hydraulic turbine
is simple, efficient, easily controlled, and long lived. It has the ability
to serve as a baseload, a cycling, or a standby unit. Also, it is capable of
assuming full load in a matter of minutes, and of following load variations
with minimal attention. The turbine can drop load instantly without damage.
Because of its simplicity and flexibility, the hydraulic turbine can be
operated automatically with little attention.
Overall energy conversion efficiencies of a hydroelectric development are
about 80 to 85%. This estimate includes generator, turbine, and transformer
efficiencies and hydraulic friction losses, but not transmission losses. The
response time for hydroelectric generators is very good. When startup time is
not critical, a few minutes are adequate to provide full power. If response
time is critical, turbines can be kept on spinning reserve at full rotational
speed using reduced flow volumes. Full power is then available in a matter of
seconds.
Plant availability is typically about 90%. Full outages are rare for
piants having multiple generating units. Hydroelectric plant lives are often
forecasted to be 50 years for economic purposes, although 100-year plant lives
are frequently assumed for large federal projects.
5.32
5.4.2 Siting Requirements
The power potential of a hydroelectric development is a function of the
head and streamflow available at a given site. Higher head and greater stream-
flows increase the power generation potential of a site. If the head differ-
ential is available over a short horizontal distance, the length of water
conductors is reduced, resulting in lower total project costs. Dam, spillway,
water conductor, powerhouse, and switchyard structures must be located and
designed for specific topographical and geotechnical site conditions.
Dam height (a major contribution to cost) must be optimized to provide
storage and seasonal regulation without loss of water over the spillway.
Smaller or low-head hydroelectric projects generally have little reservoir
storage capacity and must be operated as run-of-river. Therefore, these
projects depend upon seasonal fluctuations of water supplies, which lead to
spilling of excess flows during the wet season and reduced generation during
the dry season. For conventional or low-head projects, basic information is
needed about the drainage area, runoff characteristics, and any major water
usage upstream and downstream of the project. If adequate records are not
available, the necessary data must be synthesized using correlations of nearby
streamflow data. Streamflow duration data (and head) are used to calculate
average annual energy and dependable (firm) capacity for the site.
Site geophysical conditions determine the availability and cost of con-
struction materials, type and height of dam, and required seepage treatment.
These conditions also strongly influence the general location of major civil
works (dam, penstock, canals) for the project. Fault lines, sedimentary
deposits, potential seismic activity, and great depth to hard rock can result
in excessive construction costs, thus eliminating otherwise suitable sites.
Rail or road access is required for transportation of material and
equipment.
The land area required for a hydro facility is largely a function of
reservoir size and may be significant. Because of variation in topography,
are requirements must be determined on an individual project basis.
5.33
5 .4.~ ·c.osts
)]_iip 1'Mr 1 cos·t .s fo r h.Yd~e'le: lec tt· w. dev.e: l ilpJilell ts -ire ·scjt-e spec i"fi r:: a11d liar){
a:cc:prdi n 9' ta tyPfl , si JE;, twa(!. iln!± Tey,ahon o:f th:e p.roa ·fl'ct, fhe amti J.!nt abd
t;'Q <;,t ·of-reqy l r:e,d )and ., ant;~ t'e1:l~h•e(:l re~ot at'i.on s, The ws~s of rfa'$el"vok~ af)d
w<~taf'way,-:. (pen d·~t~ck~ anct eana1~) vary crmsi de rat>i.y andln'~Y ·n-ave· 1 Ht 1e r e l a -
Hans~ ~)l. t o. t ire 1'fstall'e,d ,gene.rat t n'g a~P'at \t ,y. 1h£; cp~ts .Qf power'li.eu"$1ii'S v;;r y
1es.s , :aitno \l gh tYil'l ,plii,nJ;S' ~f' th!! :>aTIIe eap a~f'l:J ,SPflle.t i111.es h.IIVec $ .co~t rJ ]ffe re.n-
:t ]d:f ~f 5'0:~ .. Cili il tOniPQr'I'!\M$ (ll.ams, s p.i llwo.:n 1lll(l ot.fi.~·r no.rrmet ltMical o\'
·narr~1ec tt i 11i!l fen'J;,IJ ~·<S.) ctf low h~fltl and sm~ 11 hyd 'rll JJeve1 cO'Ilm!!fl~~ •1?u.'a 1h ~arr'Y
a -m~a11e r (le-l"·centage 43'f · t:h ·e to tia1 d.ev elup,.ment fi'.o~ts: t ·l'lan f eati:We.li f or t ol]v en -
t i ona1 l'l_ydro d:eve.l Gplilerft s ,
08iM ccrs ts ar.ec detefm.Hi eo p l"fmal"~]:y 'tw plant -si t(:!·. O't he r ht:t b r$ inc1.uc.l ec
bhe t Jp.e oJ _qMru.ll;iol.l (ba se load or pea)ci ng ), a,ni1U,3 T gep er:ati·on , fl tirribet: .o.nd
~i.ze at.. ),mit$', ov!!t ,o:ti nq ll!!a.d ·, a:ntl ·tJtner c·arrcl-il i011s P.~co.~<lt{lr tp in91V''iclil?~.l
PhilH ,.,
fi. 4 .-4 .£nv i ro nment:a 1 Collst de r ltit·l ons.
The 'fl ll_ysic.A1 ccirafig~:~,..~i i!ltr and .OJlel'.ation of a tfYdr,oe1et.tr h:: f'·ad Ht,y. q ;n
e..ailse s,eVeral hyam'ioqi c 'imuar;t ·s. The: llJ'ost> pO.v 1oJls i~ the c'!'~ii;t i .on· of an
'tmpvU.ndmefl,t;. The ctianqe i'rorri .a, ;flWil'!!j--yi.il:~e.r tci a' st.i ll~v1a tp~ emi'ir.onm.ent i&
a f )J tt~amerrta.1 •mg(fi f'i ~~J•t. i'ort Qf ttre hy~ro 1 o~ri.~:: s;y&t:e'l!l·· Dev~ 1·o!)'m e.r\t r;Jf th~
~>e rVq :ir .also· i rt_creil'·ses -e,'i ap()r;~·ldDn q'nd grou ·M.w<~ter s-e·ep,\lige. BD t h pfoe.Min.elia
i :o~;-r.e~se \'la tet' T QS'$e's to , t tle ·v(at.e n)w~.. rrr t)le. 1 0'11 1"\l f!Off t'E;gi(lji'S. Qf J;!he
!1o:v'f.(1ern, fr,lilb·e1t at<e.a, t h_e:s e lo~~s, 1.f !>ubst a (ttia l , tP\Iltl 12au~e s.i .gnffi~an±
i i11P~(';~s ·ll,11 re.dl:lCi n~ down -st:r.eam 1\tow..: ~.Pe.<:1a 11,y. iiud ng th.1! >WmJer mll.rfitl:J.s:.
I'll)portant h;):J:Jrl!l l og i.e ilnpa.c t.s a "e ai:sd ass.a c 1 aifle.t! with t he opero.t i ol'l o I ·a
tl,ycl r oel ec:tr i·c phmt. l.a.r'.ge ~Hucr-oa1 fhtcl;uat ,1~l'ls in t:tver H .Qw .carr t1e-su H wh!!n
h,l!tl ropower ls used f1ll' f>eaH n.g powe 1> br loa.Q fo 11 0\ilin:g . large a!'ld ra~id fluc-
t.uat i ol'ls a ari atl VI?'rst."iy ~ff:ec t aqua•Hc Biota and co.ul d be 1'\a-zar cl ou s t.i'J dowro-
$,t ream M.creattoj'iht-s . '011 4 ~a$Ma t .ti me s..-;.a1 ~t f t:r i!\ l'e;Sf;rVa h" ieve>1 ca'rl var y
q .. e<~t 'lll< t again f!d .Mm1;i ally i!H®t>1noa aqua t-1~ b.fo 'ta liYiq lllalti n~ tfte. reservo:ir
urt att::r .acti ve for re.cr~a;ti on ~espec.liallY ·"fhen the rese l"y!l:ir.·l§ low). Ifr
d ~s ~~tfed willtl o.l:leql;l a:t;g s :to-raa~ t:-C!):Il!C.: rW , '~"eser~tOi ·r~ can ;a.t"trenuate flpQ!J · f1ttws,
thereby helping prevent flood damage to property downstream. Conversely, low
river flows can be augmented to improve water quality and aquatic habitat.
Because many rivers in the Railbelt region exhibit wide natural flow varia-
tions, flow regulation can be a significant positive impact.
Reservoir operation affects four parameters of water quality: tempera-
ture, dissolved oxygen (DO), total dissolved gases, and suspended sediment.
Temperature and DO can be adversely affected during the summer months when the
reservoir is stratified. The large water surface area of the reservoir allows
the upper layer of water (epilimnion) to be heated to temperatures higher than
those experienced in the natural, free-flowing river. If all water released
from the reservoir is from the epilimnion, the temperatures of the river water
downstream can increase, causing adverse impacts on aquatic biota (especially
cold water fish). If all water released from the reservoir is from the lower
layer of water (hypolimnion), the DO in the river will be depressed until it
can be replenished by natural reaeration. Intake structures can be designed
to take water from different levels in the reservoir to help avoid some of
these impacts.
Water, as it falls over a spillway, is turbulent, and atmospheric gases
(nitrogen and oxygen) are entrained and readily dissolved, often to the-point
of supersaturation. This condition can result in fish mortality. The effects
are most pronounced in organisms that inhabit shallow areas or surface levels.
Supersaturation can be minimized by spillway design and operating measures.
As water flows into a reservoir, its velocity is reduced, and it deposits
much of its suspended sediment. Therefore, when the water is released from
the reservoir, it is relatively free of sediment load. A potential exists,
then, for this water to initiate scour downstream to re-establish the natural
equilibrium between the erosive energy of the flowing water and its sediment
loads. Because many of the Railbelt rivers are glacier fed with very high
suspended sediment loads, sediment deposition and downstream scouring will be
important siting considerations. Scour can also occur in the vicinity of the
outlet works and spillway of the hydropower plant if the water is discharged
with a high velocity. These scour problems can be mitigated by proper engi-
neering design.
5.35
The dam construction and reservoir development of at least several square
kilometers in size will cause some variation in meteorological conditions.
Conditions will generally be less extreme near an unfrozen reservoir, result-
ing in warmer nights and cooler days. No perceptible change in precipitation
patterns will occur. When reservoirs are frozen and snow covered, nighttime
temperatures will be less than those observed before the reservoir was con-
structed. These modifications will be small and generally will not be percep-
tible beyond a mile from the reservoir.
Hydroelectric projects alter the streamflow characteristics and water
quality of streams, which results in corresponding changes in the aquatic
biota. Although impacts occur on all levels of the food chain, the impacts on
fish (particularly anadromous salmonids) are usually of most concern. In the
Railbelt potential effects that will be most difficult to mitigate include the
following: 1) loss of spawning areas above and below the dam; 2) loss of
rearing habitat; 3) reduced or limited upstream access to migrating fish; and
4) increased mortalities and altered timing of downstream migrating fish. An
initial assessment of the potential hydropower sites in Alaska indicates that
these impacts could occur at many locations, especially for anadromous fish
DOE 1980b). Many of these potential sites are located on major anadromous
salmon streams such as the Tanana, Beluga, Skwentna, Susitna, and Copper
Rivers.
Construction can result in elevated stream turbidity levels and gravel
loss, and expanded fishing due to increased access. Other potentially signi-
ficant impacts could include altered nutrient movement, which could affect
primary production; flow pattern changes, which could modify species composi-
tion; and temperature regime alteration, which could affect the timing of fish
migration and spawning, and insect and fish emergence. Competition and preda-
tion among and within species may also be changed.
Mitigative procedures are possible for many impacts and are frequently
incorporated into the facility's design. Fish hatcheries are commonly used to
replace losses in spawning habitat. Screening or diversion structures are
used to direct fish away from hazardous areas. Depending on the height of dam
and the availability of spawning areas upstream of the reservoir, fish passage
5.36
facilities may be incorporated into the design. Controlled release of water
(including both flow and temperature regulation by discharging from various
depths in the reservoir) can be used to improve environmental conditions dur-
ing spawning, rearing, and migration.
With the exception of run-of-the-river projects, hydroelectric energy
projects require large amounts of land for water impoundment. Although the
amount of land required varies with the energy-producing capacity of a plant
and the characteristics of a river basin, they generally exceed those of other
energy technologies. Therefore, the greatest impact on the terrestrial biota
is the inundation of large areas of wildlife habitat. Inundation of flood
plains, marshes, and other important wildlife habitat can adversely affect big
game animals, aquatic furbearers, waterfowl, shorebirds, and raptors. Big
game animals could be affected by loss of seasonal ranges and interruption of
migratory routes. Winter ranges particularly are critical habitats for migra-
tory big game animals. Large reservoirs could also cause genetic isolation of
migratory big game animals and other wildlife. The flood control provided by
dams may significantly reduce the extent of wetland habitats because of the
elimination of seasonal inundation of large areas downstream of dam sites.
This feature may affect moose and other wetland species. Aquatic furbearers
could be adversely affected by the loss of riparian habitats. Correspondingly,
waterfowl and shorebird nesting, loafing, and feeding areas could be elimi-
nated by the flooding of these habitats. The re-establishment of riparian and
riverine habitats is generally prevented by the constantly fluctuating reser-
voir levels of plant operation. Fluctuating water levels could also destroy
trees and other natural structures used by raptors for perching, nesting, and
roosting sites. Fish-eating raptors and bears could be further affected by
the loss of anadromous fish if anadromous fish populations are reduced by the
project.
In addition to the losses of wildlife habitats resulting from inundation,
access roads to remote locations will cause extensive disturbance to wild-
life. Not only will habitat be replaced by roads, but isolated wildlife popu-
lations, such as grizzly bears, will be adversely affected by increased human
activity and numbers. Also, other wildlife could be affected from increased
5. 37
hunting pressure, poaching, and road kills. The magnitude of these and other
potential impacts will depend on the wildlife population densities at each
specific site.
Mitigative measures could be taken to relieve some wildlife impacts
resulting from dam developments. The habitats flooded by a reservoir would be
largely irreplaceable. However, other habitats, such as islands used by water-
fowl for nesting, could be created through placement of spoils or creation of
channels. Trees and other natural features used by raptors could be retained
instead of removed as is usually done prior to inundation. Whereas these
relief measures are somewhat specific, impacts on all wildlife could be mini-
mized by selecting only those sites where wildlife disturbances would be least.
5.4.5 Socioeconomic Considerations
The construction and operation of a large hydroelectric plant has a high
probability of causing a boom/bust cycle. A conventional hydroelectric pro-
ject of 100 MW installed capacity would likely require a construction work
force of 200 to 400 personnel for 5 to 10 years. The resident operating work
force could range from zero for unmanned facilities to 10 to 12 persons. The
primary reason large projects create adverse effects is the remoteness of the
larger sites. All sites identified in this study are located at or near
communities with a population of less than 500. An in-migration of the 250 to
1,000 workers required for a plant in the range of 100 to 1000 MW could more
than quadruple the population. Installing a construction camp would not
mitigate the impacts on the social and economic structure of a community.
The expenditures that flow out of the region account for investment in
equipment and supervisory personnel. For a large-scale project, a larger pro-
portion of the expenditures is attributed to civil costs. Approximately 35%
of an investment in a large project would be made outside the region, whereas
65% would be made within the Railbelt. Approximately 11% of O&M expenditures
would be spent outside the Railbelt and 89% would stay within the region.
5.4.6 Potential Application in the Railbelt Region
Alaska's history of hydropower development dates back to the 1840s when
water was used to power a sawmill at Sitka. In the period following World
5.38
War II, development of resources, and thus demand for electrical energy,
increased significantly. In 1956, the total electric generating capacity was
approximately 100 MIJ. Hydroelectric power comprised 52% of that capacity. By
1976, the State's electricity generating capacity had increased to 940 MW, but
hydro represented only 13% of that capacity. One intermediate-scale hydro
project is operational in the Railbelt, the Eklutna project (30 MW) near
Anchorage. The Solomon Gulch (19 MW) project near Valdez is under construc-
tion and will serve Valdez and Glennallen when finished.
Several studies of Alaskan hydropower potential have been undertaken
including those by the Federal Power Commission, the U.S. Army Corps of
Engineers, the U.S. Bureau of Reclamation, the U.S. Geological Survey, and
the State of Alaska. Over 700 potential sites throughout the state have been
identified in these surveys (Federal Power Commission 1976).
Following a review of these studies, Acres American (1981b) identified a
total of 91 technically feasible undeveloped large-, intermediate-and small-
scale sites in the Railbelt region (Acres American 1981b) (Table 5.8). Also
shown in Table 5.8 are the Devil Canyon and Watana sites comprising the Upper
Susitna Project.
Using a four-step site evaluation process based on economic, environ-
mental, and land use considerations, Acres American (1981b) identified a short
list of 17 sites as potential alternatives to the Upper Susitna Project. In
Table 5.8 these sites are indicated by asterisks preceding the project name.
Each of these sites was judged to be economically feasible and environmentally
acceptable, although four (Talkeetna-2, Lower Chulitna, Lane and Tokachitna)
ranked "poor" (although not "unacceptable") in the environmental evaluation.
Fourteen of the Upper Susitna alternative sites are intermediate or large
scale. These 15 sites, together with the Upper Susitna sites (Devil Canyon
and Watana), plus one additional large-scale Railbelt site (Bradley Lake)
being seriously considered for development are listed in Table 5.9 and located
as shown on Figure 5.4. Also provided in Table 5.9 are summaries of the
economic, environmental, and land-use characteristics of these sites.
As is evident from the capacity and firm energy characteristics of the
sites listed in Table 5.9, abundant potential for hydroelectric development
5.39
1Jk ___ .
Orad ley Lake
Hrowne
Bru ~k asna
Cache
Chak achamna
llev i I Canyon (f)
!licks
Johnson
TABLE 5.9. Summary of More Favorable Potential Intermediate and Large-
Scale Hydroelectric Sites in the Railbelt Region(a)
Black Bear
Grizzly Bear
Black Bear
Gr i zz ly Bear
Hoose
Cadbou {winter)
0 I ack Bear
Grizzly Bear
Moose
Caribou {winter)
Black Dear
Grizzly Bear
H<lose (winter)
Caribou (winter)
D lack Bear
Hoose
Black Bear
Drown Dear
Hoose
Car lbou
Black Bear
Gr tzz J y Bear
Car lbou
Hoose (winter)
8 lack Bear
GrIzzly Dear
waterfowl.
Rap tors
.!!!~~~~~~
Peregrine Fa leon
I. ow DensIty
of Waterfowl
Low Oenslty of
Waterfowl, Nest lng
and Halting
None
Identified
Waterfowl
Nesting and HolLing
low PopulatIon of
Waterfowl, Cliff Nest-
ing Areas for Ravens
and Raptm·s
Waterfow I
Nesting and Halting
Anadrornous
LW~~-
None
None
None
Spawn lng
Area
Present
Spawn lng
Ate as
Downstream
Present
Downstream
Low Density Waterfowl Spawning
Nesting and Ho 1L lng Area
Area
Ayrtcu llural
Potential
25-30~ Marginal So lis
lllgh-Quallty Forests
Hore than 50~
Marginal So11s
None
!dent I fled
Hone
!dent I fled
Spruce and
Hardwood Forest
Unknown
Hone
I dent I fled
25-50~ Suitable Salls
Spruce-Uardwood
Forest
Wilderness
---~g!!l!~L--
Gaod to lllyh
Qua llty Scenery
None
Good to lllgh
Qua llty Scenery
Good to lllyh
Quality Scenery
Pr lmlt lve Lands
Good to Ulgh Qua llty
Scenery, Primitive
and Natural Forest
WIlderness Quality
Lands
Average Quality
Scenery
None Identified
Cu )lin· a I, Recrcal iona I
.. ~ ~ -~~ t!!.!!!_ !L!.£ .f_~ ~~m:~~.~
Boating
Boating Potentia 1
Boating Potentia 1, Proposed
Ecological Reserve
Boating Potential
Boat lng
llunt lng,
Boating
llunt lng
lsl imated
Capital Cosdb)
U.LH!l.._. __ _
2,9oo(d)
6,245
7,933
11,275
2, 997
1,890
B,Bll
Boat lng Not Ava I hb le
E~t imal ed
O&H Cosl !M'!/~r) c)
58
125
160
225
60
38
180
llot Available
E!,l im.:~lt~d
Cost of Puwe1·
(If! I )1~/~HI•)
49
95
126
179
23(9)
141
12o!e)
01
.p.
Waterfowl,
Rap tors
__ _llk__ ~.!!L§ame.f~~~ _ _i~dan~!~-~~~-
l<eetna IJiack Bear Hone
GrIzzly Bear I dent If led
Cal'ibou (winter)
Hoose (Fall & Winter)
lane Black Dear Low Density Waterfow 1
Hoose He sting and Holt lng
Caribou Area
Lower Chu lltna 0 lack Bear Hedillll1 Dens lty Water-
Grizzly Oea•· fowl Hesting and
Car lbou Holt lng Area
Snow Black Bear Nesting and Molting
Dall Sheep Area
Hoose (winter)
Strand line Lake Black Dear Hest lng and HoI tlng
Gl'i zz ly Bear Area
Hoose
Talkeetna II Black Bear Hone
Grlzz ly Bear I dent Hied
Hoose (fall & winter)
Caribou (winter)
Takach itna 81 ack Bear Hed lum Density Water-
Hoose fowl Nesting and
Car lb!XI Ho 1 tlng A1·ea
lustun~ena Black Bear r~one
Da II Sheep I dent I fled
Watana (I) 0 lack Dear low Popu Jat ion
Drown Dear of Wat~rfowl
Hoose
Car ihou
---------
TABLE 5.9.
Anac.Jromous Agr leu ltural
_fisheries Po tent lal
Spawn log None
Area I dent If led
Spawning More than 50S
Area Su ltab le So lls
Spruce-Poplar Forest
Spawning Hare than 50S
In Vicinity Suitable Soils
None Hone
I dent If led
Hone 25-50S Marginal Soils
Spawning None
Area Identified
Spawning In 50S of Up land
VicInity Soils Suitable
None Hone
I dent If led (dent If led
Spawning Unknown
Areas
Oowostream
(contd)
Wilderness
___ Potent~L ____ _
Good to lligh Quality
Pr imit lve lands
Hone Identified
Selected for WIlder-
ness Cons iderat ton
Hone I dent If led
Good to lllgh Qua II t y
Scenery, Pr imH ive
Lands
Good to lllgh Quality
Scenery, Pr lnlit ive
Lands
Nea•·by Primitive
Area
Selected fur Wilder-
ness Consideration
Good to lllgh Quality
Scenery, Primitive
lands. Natura 1
Features
Wll derness Quail t y
Lands
Cu llura 1, Recreat iond I
~!!L~!~!Uf!f. f.~~.t~.r~s.
lligh
Boating Potential
Boating Potential
Boating Potential
Chugach fi.F. Proposed
Biological Reserve
None I dent If led
Boating Potential
Boating PotentIa I
Hone Identified
llunt ing
Boating
!~! Environmental and land-use characteristics and capital cost esthnates taken from Acres American (198lb) unless olherw1se noted.
Costs are overnight construction costs In .July 19!30 dollars.
(c)
(d)
(e)
(f)
(g)
2~ of capital costs used for all projects.
Preferred altertllJtiv~. Provided in a telephone conversation wtth John Oenntger from the Alaska Power Adtninistratton, ~Juneau, Alaska.
Pow~r costs were deter111ined using cost Indices provided in APA (1900) with Chakachamna estim~Jte as a base.
Oevil Canyon ami Wat~Jna datns comprise the Upper Susltna project. which Is planned to be coustructed In three stages 1 Watana I (600 ,..,). Wata11<1 II
(1020 HW), llevil Canyon \600 HW). Average cost of power following construction of all stages Is 56 mills/kWh.
Corps of Eng lneers ( I9UU •
Est imaled
Cat> ita I Cost (I>)
-~W~~)
4. 767
Hot Avallah le
Not Avallab le
5,092
6,300
9,993
Not Avallab le
llot Available
3,890 (I)
4,030 (II)
E:st imaled
OLH Cost
( S/kll/yrj{_cl __
95
Not Available
llot Available
100
130
200
Not Available
Not Avallab le
78 (I)
01 (II)
Est im<tled
Cost of Ener~JY
(•~i.!l ~(kJi~l
II
sq(e)
738
94
158
125(•)
50 (I j( r)
00 (ll)(rl
CANDIDATE
HYDROELECTRIC
SITES
1. SNOW
2. BROWNE
3. CHAKACHAMNA
4. ALLISON
5. WATANA
6. DEVIL CANYON
7. BRANDLEY LAKE
8. STRANDLINE LAKE
9. KEETNA
1 0. GRANT LAKE
1 ;CBRUSKASNA
12. CACHE ~
13. HICKS
14. JOHNSON ~~~~
15. LANE \
16. LOWER CHULITNA
17. SILVER LAKE
18. TALKEETNA II
19. TAKACHITNA
20. TUSTUMENA ( {
SCALE
0 50
FIGURE 5.4. Potential Hydroelectric Resources
5.42
lOOMiln
exists in the Railbelt region. Hydroelectric power offers the advantages of
flexibility of operation and minimal atmospheric environmental impacts. How-
ever, hydrologic, ecological, and socioeconomic impacts can be severe if sites
are not carefully selected and proper mitigative techniques are not imple-
mented. Although initial capital costs tend to be high, facility lifetimes
are long and variable operating costs are low, resulting in power costs that
are relatively secure from inflationary effects.
5.43
5.5 FUEL CELLS
The fuel cell is a solid state device for production of electricity by
electrochemical combination of hydrogen and oxygen. The hydrogen is supplied
by reforming a hydrocarbon fuel, and the oxygen is obtained from the atmos-
phere. Fuel cell technology is in the demonstration stage and several fuel
cell stations have been constructed for commercial testing.
5.5.1 Technical Characteristics
The basic fuel cell plant consists of a fuel processor, the fuel cell
section, and a power conditioner (Figure 5.5). The purpose of the fuel pro-
cessor is to reform the hydrocarbon fuel (usually a gaseous or liquid hydro-
carbon) to produce hydrogen feedstock for the fuel cells. The fuel cell
section includes the fuel cells, configured in series to achieve the desired
voltage and current capacity. The power conditioner includes inverters to
change the DC power output of the ce 11 s to AC, and transformers to match the
output of the fuel cell station with the grid.
Although the 11 stand-alone 11 fuel cell station is the only configuration
presently in commercial operation, other fuel cell configurations are being
studied. Coal gasifier fuel cell plants would use low or medium Btu coal-
derived synthetic gas as a source of hydrogen for fuel cell operation. Second
generation molten carbonate fuel cells, with much higher operating tempera-
tures than first generation phosphoric acid fuel cells, could be used either
in stand-alone fuel cell stations or in a combined-cycle mode of operation.
In combined-cycle operation fuel cell reject heat would be used in a waste
heat boiler, either to raise steam for a steam-driven turbine generator or for
district heating. A fuel cell -combined-cycle plant could be fueled by oil,
natural gas or coal-derived synthetic fuels.
Plant sizes will depend upon the plant configuration and operation.
Stand-alone fuel cell stations will be highly modular and likely constructed
in sizes of tens of megawatts. Larger sizes, although technically feasible,
will likely not be common due to the suitability of fuel cell stations for
dispersed siting. Coal gasification fuel cell plants and fuel cell -
combined-cycle plants will likely be more centralized, in sizes ranging to
hundreds of megawatts.
5.44
FUEL
6~T Fl' H
s TEAM •
REFORMER
I
GAS clEANUP L
AND tj DESULFURIZER
FUEL PROCESSOR
...
~ CARBON DIOXIDE
___ ___.d L..,
HYDROGEN _j
ANODE(-) DC CURRENT ...;.;;.; ...
ELECTROLYTE
CATHODE(+)
0 2 0R AIR -1.-
GAS-TIGHT n SEPARATIO.!iJ WATER
If · HYDROGEN -ANODE~-~
ELECTROLYTE
02 OR AIR -. CATHODE l+l
--,
1CwATEA
FUEL CELL STACK
(two cells shown)
-? ? ~
LOAD
(DC)
INVERTER
FIGURE 5.5. Typical Fuel Cell Plant
Design Features
A single fuel cell consists of positive and negative electrodes, immersed
in an electrolyte. The electrolyte may be an aqueous acid, an aqueous alka-
line, a molten salt or even a solid. Catalysts are provided to speed up the
reaction.
Cells currently being produced use phosphoric acid as the electrolyte,
and hydrogen-rich fuel and oxygen (or air) as the reactant gases (Marianowski
and Rosenberg 1972). Hydrogen reacts at the anode to form electrons and posi-
tive ions. The electrons pass through an external circuit to the cathode, and
the circuit is completed by ions, which pass through the electrolyte. At the
cathode, the electrons, ions, and oxygen combine to produce water. Direct
current is produced, which must be converted to alternating current for grid-
connected applications.
Second-generation fuel cells use molten carbonate electrolyte and operate
at higher temperature than the phosphoric acid cell. This design is more
efficient because of reduced polarization losses. The molten carbonate fuel
cells can tolerate several ppm of H2S in the fuels, unlike the phosphoric
acid fuel cells in which the catalysts are poisoned by sulfur compounds.
Therefore, the molten carbonate fuel cell is more suitable for using synthetic
fuels derived from coal. A further advantage of the molten carbonate cell is
that waste heat is available at temperatures sufficiently high (1200°F) for
making high-pressure steam. This steam can then be expanded through a turbine
to generate additional electricity. Combined-cycle efficiencies of 60% should
be attainable (Bowman et al. 1980). Cogeneration with molten carbonate fuel
cells is also a possibility for the utility interested in supplying district
heat or industrial process heat.
A third-generation fuel cell using a solid-oxide electrolyte is now in
the laboratory research phase, but many development problems are yet to be
solved. Optimum materials for electrodes have not yet been defined, but
experimental results with lanthanum cobalt oxides indicate that the solid
electrolyte fuel cell could be a promising candidate for commercial uses
during the 1990s.
5.46
An individual fuel cell produces an output of about 0.8 V under load.
Individual cells are connected in series to provide greater output voltage and
are connected in parallel to provide greater output current. For example, one
current design uses 456 cells stacked in a cell stack assembly to produce
300 VDC at a current of 500 amps (United Technologies Corp. 1978). The cell
stacks can be connected in series or parallel to produce megawatt quantities
of power at 2000 to 3000 V DC.
An entire fuel cell system, including fuel processor, power system, power
conditioner, and control system, can be designed in modular form, which can be
preassembled at the manufacturing plant to reduce the labor required at the
installation site. Using factory mass production, unit costs may be reduced.
Using the modular arrangement, modules conceivably could be added or shifted
to new locations, depending upon changes in local load conditions.
Performance Characteristics
Because they are not based on a thermodynamic cycle, efficiencies of the
fuel cell are typically better than conventional methods of converting thermal
energy to mechanical energy for power generation. Estimated heat rates of
fuel cell plants are provided in Table 5.10.
Phosphoric acid fuel cells can respond to load changes very quickly and
are thus suitable for use in a load-following (cycling) mode. The time con-
stant of the fuel processor is the control factor. For example, a demonstra-
tion plant that is designed to follow a load change between 35 and 100% of
full power within 2 seconds has been built. Moreover, the efficiency of fuel
cell plants is practically constant over wide ranges of loads. This constancy
means that they are suitable for partial load operation to meet 11 spinning
reserve 11 requirements of a utility grid.
Coal gasifier-fuel cell plants using molten carbonate cells may not be
as suitable for load-following operation. Although the carbonate cell has a
good turndown capability, coal gasifiers do not. Thus, if this type of fuel
cell plant is run as a load-following plant, an alternative use for coal-
derived gas should be provided when electrical demand decreases. As one
solution, this type of plant could shift to methanol production during low
load periods. The stored methanol could be converted back to hydrogen during
5.47
TABLE 5.10. Estimated Heat Rates of Fue 1 Ce 11 Plants
Type of
Plant Electro l,lte ~ (Btu/kWh)
Fue 1 Ce 11 Station P ho s ph or i c Ac i d 10 9000 (a)
Fue 1 Ce 11 Station Molten Carbonate 10 730o(b)
Coal Gasifier-Molten Carbonate 1000 7130(b)
-Fue 1 Ce 11-
-Combined Cycle
Natura 1 Gas-
"'57 00 (b) Fue 1 Ce 11-Molten Carbonate
Combined Cyc 1 e
(a) EPRI 1979. EPRI 1982 suggests that an annua 1 average
heat rate of 8300 Btu/kWh may be obtained if operating
under intermediate load conditions.
(b) EPRI 1979; Reconfirmed in EPRI 1982.
(c) Based on estimate of 60% thermodynamic efficiency by
Bowman et al. (1980). No specific design studies have
been performed on this type of plant.
high electrical load periods, thus reducing the required capacity of the gasi-
fication plant. A second problem with using the molten carbonate cell in
cycling service is the adverse effects of thermal cycling on this cell design.
Because of the high operating temperature, 1200°F, excessive thermal cycling
may lead to cracking in the electrolyte tile. For these reasons, the molten
carbonate cell is more suitable for baseload operation.
The reliability of a fuel cell plant depends to some extent on the type
of fuel that is used; plants are expected to be extremely reliable when a clean
fuel is used. An availability of approximately 91% is predicted for dispersed
fuel cell stations (EPRI 1979). Because of their greater complexity, the
availability of gasifier -fuel cell -combined-cycle plants is anticipated to
be somewhat lower than fuel cell stations, approximately 83% (EPRI 1979). The
reliability of fuel cell -combined-cycle plants fired by natural gas or
distillate could be expected to be intermediate between these two estimates.
Scheduled outages for maintenance will therefore be less than for the
conventional coal or gas-fired plants.
5.48
Presently, fuel cell manufacturers recommend a rework of the cells every
10,000 operating hours. Design goals are for a cell with 40,000-hour
operating life (EPRI 1980b).
Plant design lifetimes are anticipated to be 20 years for dispersed fuel
cell stations and 20 to 30 years for fuel cell -combined-cycle plants.
5.5.2 Siting and Fuel Requirements
Considerable flexibility in siting is possible because of the modular
design, compact size, and modest environmental effects of fuel cell stations.
Small fuel cell stations would create very little noise and very little visual
intrusion and could be sited in dispersed locations in the Railbelt, such as
small communities, electric substations, or even individual neighborhoods,
assuming adequate fuel distribution systems.
The principal siting constraint for such plants would be the source of
fuel. Plants operating on natural gas would require a gas pipeline. Liquid
fuels such as naphtha or distillate oil could be supplied by pipeline, tanker
truck, or rail. Fuel storage facilities would be required for plants supplied
by truck or rail.
Considerably more stringent siting requirements would apply to a gasi-
fier -fuel cell plant or a large natural gas -fuel cell -combined-cycle
plant. Siting requirements for these plants would be similar to those for
coal gasification plants and combined-cycle plants, respectively, as discussed
elsewhere in this report. A medium Btu gas fuel could economically be trans-
ported by pipeline for moderate distances (up to 100 miles), allowing remote
or dispersed siting of the fuel cell generation plants.
Current demonstration fuel cell plants are of the dispersed station size,
varying in size from 25 kW to 11 MW. Assuming no onsite fuel storage, a com-
plete 40-kW plant would require less than 1 acre, and a 5-MW plant would
require 1 to 2 acres. If 30-day fuel storage were required (considering use
of a liquid fuel such as naphtha), these area requirements would approximately
double. The larger proposed plants, such as a coal gasifier-molten carbo-
nate plant, will likely require less area than a coal plant of comparable
capacity because land for flue gas desulfurization waste disposal would not be
required of the fuel cell plant.
5.49
Little, if any, external water is required for a noncombined-cycle fuel
cell plant because water formed by the fuel cell process is usually sufficient
for cooling and heat recovery systems. The fuel cell stacks are normally
cooled by the process gases passing through the structure, although forced air
cooling has also been satisfactorily tested. Cooling water would be required
for the steam section of a fuel cell combined-cycle plant.
Fuel cells consume different types of fuel, depending upon the type of
electrolyte. Phosphoric acid fuel cells use hydrogen, generally produced by
reforming a hydrocarbon fuel in the presence of steam, to produce H2 and CO.
The resulting CO is passed over a catalyst to convert the CO to H2o and co 2 and
more H2 by the shift reaction. A fuel processor is typically used to convert
propane, methane, naphtha, or No. 2 fuel oil to hydrogen. At present, the most
fully developed process is for naphtha and methane as fuel for phosphoric acid fuel
cells. A demonstration fuel cell station in New York City will use either naphtha
or methane gas as its fuel supply.
In the molten carbonate and solid-oxide fuel cells, CO is the fuel, being
catalyzed on the electrode surface to form H2 and co 2 in the presence of
steam. The molten carbonate cell must have co 2 available at the cathode,
along with the oxidant such as oxygen or air, to provide the co 3 charge
carriers in the molten carbonate electrolyte.
The shortage of natural liquid and gaseous fossil fuels (required to
obtain hydrogen) has prompted research in developing fuel cells that would use
coal-derived gaseous fuels directly. Coal can supply H2 and CO as gaseous
fuels, but the CO cannot be directly used in H2-o 2 (phosphoric acid) fuel
cells. Both gases may work in a molten carbonate fuel cell, but reliable
operation of this design has not been demonstrated. Coal gas, synthetic gas,
and methyl-base fuels are also suitable for generating hydrogen, although use
of these fuels will require minor modifications to the fuel processor.
5.5.3 Costs
Capital costs for phosphoric acid fuel cell plants are not yet competi-
tive with comparable conventional power plants (combustion turbine or combined-
cycle plants) now being installed in the United States. In addition, the
typically high cost of suitable fuel contributes to costs of power currently
5.50
exceeding that of conventional coal plants. However, in the Railbelt, natural
gas is currently available at prices very competitive with coal. Furthermore,
mass production of phosphoric acid cells should result in a decrease in "rea,..
li.e., adjusted for inflation) capital cost. Estimated costs derived from
EPRI (1980b) for phosphoric acid fuel cell stations using naphtha as fuel are
given in Table 5.11 in 1980 dollars and adjusted for Alaska. Note that this
technology is not commercially available and therefore the costs represent a
de-escalation of values expected in the late 1980s.
Because of the early stage of technical development of molten carbonate
fuel cells, only preliminary estimates can be made of the costs of coal
gasifier -fuel cell -combined-cycle plants. EPRI has prepared an estimate
of the cost of constructing and operating a coal gasifier-fuel cell -
combined-cycle power plant using Texaco gasifier technology and molten
carbonate fuel cells (EPRI 1980). The EPRI estimate was used as the basis for
the cost estimate for this type of plant in Table 5.11, which is assumed to be
constructed at a rural Alaskan site.
No engineering-economic assessment of a natural gas -molten carbonate
fuel cell power plant was located for this study. Thus, reliable cost data
for this technology are not available. Most likely the capital costs of this
technology would be somewhat less than the capital costs of a coal gasifier -
fuel cell -combined-cycle plant.
5.5.4 Environmental Considerations
Fuel cells produce water at elevated temperatures during normal
operation. Characteristic cell operating temperatures for phosphoric acid
cells are 20 to 90°C. Molten carbonate cells operate at temperatures to
1200°C. A typical value given for waste heat disposal, to avoid electrolyte
decomposition, is about 30% of the heat of reaction. This will correspond to
about 260 Kcal/kW (66 Btu/kW) (Davis and Rozeau 1977; Adlhart 1976).
For a cell operating at the theoretical maximum efficiency of 100%, the
product water formed is approximately 421 grams/kWh. For a 10-MW plant, this
corresponds to a water production rate of approximately 27,000 gal/day (Davis
and Rozeau 1977). For phosphoric acid plants, operating at 20 to 90°C, this
5. 51
Type of Plant
Fuel Cell Station
(Phosphoric Acid)
TABLE 5.11. Estimated Costs for Fuel Cell Plants (1980 dollars)
Cost of Energia)
Rated Be 1 uga Cook Inlet North Slope
Capacity Capital O&M Coal Natural Gas Natural Gas
(MW} ($/kW} ($/kWJ:tr} {mi 11 s/kWh} {mills/kWh} (mills/kWh}
10 750 43 49 (143) 111 ( 206)
Distillate
@ Fairbanks
(mills/kWh)
97 (192)
en Fuel Cell Station 10 810 43 43 ( 142) 94 (193) 83 (182)
en (Molten Carbonate)
N
Coal Gasifier-Fuel
Cell-Combined Cycle
(Texaco/Molten Carbonate)
Fuel Cell -Combined
Cycle
(Molten Carbonate)
1000 2230 39 43
(No economic evaluations of this technology were located; thus no reliable cost data
are available)
(a) Levelized lifetime production costs, based on a 1990 first year of commercial operation. Costs shown external to parentheses
are based on baseload operation (65% capacity factor). Costs enclosed in parentheses are based on peaking service (10%
capac it y factor ) .
product water would likely be discharged from the plant or used for local
space heating. Waste water from a molten carbonate plant could be flashed to
steam and used to drive a conventional steam turbine in a bottoming cycle, or
used in the fuel processor to reform the hydrocarbon fuel. Additional cooling
water also may be used to maximize the usage of the reject heat in producing
steam. The quantity, however, would be very design specific. Regardless of
the specific facility application, an appropriate water and wastewater manage-
ment plan incorporating suitable waste heat rejection technologies would be
required to ensure that thermal discharges comply with pertinent receiving
stream standards.
Gaseous emissions from the operation of fuel cells are very low compared
to combustion-based power generation technologies. Sulfur, from fuels contain-
ing sulfur, will not be oxidized and can easily be recovered from process
streams. Fuels that are essentially free of sulfur and nitrogen, including
hydrogen or natural gas, will not produce oxides of nitrogen. Carbon dioxide
and water vapor will be formed in large quantities, similar to that associated
with combustion, but will cause no detectable environmental impacts. Because
of the high efficiencies of fuel cells and the ease of controlling potential
pollutants, fuel cells represent a dramatic improvement in air-quality effects
compared to combustion technologies.
The quantity of makeup water for cooling, if any is needed, will depend
on the operating characteristics of each plant. If cooling water is required,
its potential impacts on aquatic ecosystems will be similar to those of other
steam-cycle plants. Because water-use requirements vary with fuel cell plant
design, no direct per-megawatt comparison can be made with another plant. For
small dispersed plants, adverse effects on the aquatic environment can be
avoided by proper construction and siting.
The impacts of fuel cell energy systems on terrestrial biota are rela-
tively slight since the air pollution potential is very low and relatively
small land areas are required. Dispersed fuel cell stations would be sited
within or adjacent to developed areas where access road and transmission
corridor requirements would be minimal.
5.53
5.5.5 Socioeconomic Considerations
Sites for fuel cell power plants would be determined by the type of plant
and availability of fuel. Small-scale fuel cell stations using natural gas or
distillate as fuel would likely be located in or near load centers to minimize
transmission losses. Close in-siting of these plants will be feasible because
of the ready availability of suitable fuels in populated areas and the absence
of environmental effects. Because of their modularity and potentially small
size, such plants could service small communities and thus be located near
them. An estimated 90 persons would be required over a period of a year to
construct a 10-MW fuel cell station. An operating staff of approximately 5
would be required. Construction of this type of facility could cause a
significant socioeconomic impact in a small community but relatively little
impact in a larger community. A one-to two-year construction period should
be typical.
Natural gas -fuel cell -combined-cycle plants and coal gasifier-fuel
cell -combined-cycle plants would likely be developed as central stations in
locations proximate to a suitable fuel supply. A suitable location for
natural gas fired -fuel cell -combined-cycle plant would be the western Cook
Inlet area. However, because this type of plant will have relatively benign
environmental effects, siting closer to urban areas will be feasible. Thus,
the best location would be established by a trade-off analysis of natural gas
transport versus electricity transmission.
Coal gasifier -fuel cell -combined-cycle plants could be located either
in the Beluga area, supplied by Beluga coal, or along the Alaskan Railroad
supplied by Nanana coal. A 3-year construction period would be typical with a
construction work force numbering in the hundreds. The operating staff would
be on the order of 75 to 100 people for a plant of this type.
Capital expenditures that would flow out of the region due to development
of a fuel cell facility would include investment in high-technology equipment.
An expected 80% of the project expenditures would be made outside the region,
with 20% spent within the Railbelt. Approximately 90% of operating and
maintenance expenditures would be spent outside the Railbelt.
5.54
5.5.6 Potential Application to the Railbelt Region
Fuel cells represent an emerging technology. It is not yet commercially
available and has thus not been applied in Alaska. Present-day demonstration
fuel cells, which generally use phosphoric acid as the electrolyte, are
expected to be commercially available within the next few years. Satisfactory
operation of phosphoric acid fuel cells has been demonstrated in several small
plants (1 MW or less), which have operated for periods in excess of 100
hours. Single cells have been operated for periods approaching 100,000
hours. A plant with 4.8-MW output is under construction in New York City and
one with an output of 10 MW is under construction in Tokyo, Japan (Glasser
1980). Commercial production facilities are being built by a major electrical
equipment manufacturer, with 11-MW fuel cell modules to be commercially
available around 1985. Given a 2-year preconstruction lead time and a 1-year
construction period, phosphoric acid fuel cell stations could be available for
operation in the Railbelt as early as 1988.
The molten carbonate cell has been under development at a modest level
for about 25 years and is currently about 5 years behind the phosphoric acid
cell technology. Good progress and accelerated effort have characterized this
concept in past few years of its development; thus this second-generation fuel
cell could be generating multi-megawatt power on a demonstration basis within
3 to 4 years. DOE is funding a significant effort to achieve a molten
carbonate system demonstration in 1986 or 1987. Fabrication processes are
being developed with current funding from DOE and EPRI. However, commercial
availability is not anticipated until after 1990 (Mansour 1980).
Coal gasifier -fuel cell -combined-cycle power plants based on molten
carbonate cell technology are forecast to be available for commercial order by
1990 (EPRI 1982). Given a 4-year preconstruction lead time and a 3-year
construction period (EPRI 1982), these plants could see commercial service in
the Railbelt as early as 1996. However, because of foreshortened construction
seasons in the Railbelt, a 4-year construction period might be more realistic,
leading to a 1997 earliest commercial service date.
5.55
The commercial availability of natural gas-fired -fuel cell -
combined-cycle plants will likely parallel that of coal gasifier -fuel cell -
combined-cycle plants based on molten carbonate cell technology. Assuming
1990 commercial availability (EPRI 1982), a 2-year preconstruction lead time
and a 1-year construction period, fuel cell stations based on molten carbonate
cell technology could be available for commercial operation in the Railbelt by
1993.
Potential obstacles to commercialization of fuel cells for electric power
generation are threefold: technical development, insufficient orders, and
national fuel policy. The first factor, status and prospects of technical
development, has been discussed previously. Relative to the second factor,
enough orders must be generated to take advantage of the economies of scale
that are needed to produce fuel cells at competitive prices. No one utility
is currently in a financial position to sponsor the potentially high cost of
developing production facilities for fuel cells, so the development time table
is assumed to depend upon federal funding. The Tennessee Valley Authority
(TVA) is planning a pilot plant in Muscle Shoals, Alabama, to develop the use
of coal-derived gas as a fuel for phosphoric acid cells. The TVA will use a
portion of the flow of hydrogen, carbon monoxide, and carbon dioxide gases
from an ammonia-from-coal plant. Within 3 years, TVA also plans to construct
a 10-MW fuel cell plant that will use the full output of the coal gasifier at
this site. The Energy Research Corporation is currently experimenting with
the conversion of methanol to hydrogen for use in the phosphoric acid fuel
cell. Conversion of biomass is also a possible method to obtain hydrogen for
the fue 1 ce 11.
A third factor potentially impacting use of fuel cell plants is the Fuels
Use Act. Essentially the Fuels Use Act prohibits use of petroleum or natural
gas fuels for electric power generation, with several exceptions. The excep-
tions are more fully discussed in Appendix N; however, the general impacts of
the FUA on the four types of fuel cell plants discussed in this section are
summarized below:
5.56
• Phosphoric acid fuel cell stations, using distillate or natural gas
for fuel could be constructed and operated for peaking or
intermediate load duty, although generally they could not be used
for baseload duty under current FUA provisions unless mandated by
environmental considerations or state law.
• Molten carbonate fuel cell stations, using distillate or natural gas
for fuel, could be constructed and operated for peaking or
intermediate load duty. These stations could be used for baseload
applications if at least 10% of waste heat were used in cogeneration
applications, or if mandated by environmental considerations or
state law.
• Coal gasifier-fuel cell -combined-cycle plants would be exempt
from FUA provisions.
• Fuel cell -combined-cycle plants operating on natural gas could be
operated as intermediate or peaking plants, but could be operated in
a baseload application only if more than 10% of waste heat were used
for cogeneration, or if mandated by environmental considerations or
state law.
When commercially available, fuel cell based power plants could serve
useful roles in the Railbelt electric power system. Several applications
appear to be potentially feasible:
Peaking or Intermediate Load Duty in the Anchorage Area
• Given continued availability of reasonably low-cost natural gas in
the Anchorage area, fuel cell stations in the 10 to 25-MW size range
would serve well as peaking and intermediate load-following units.
Given some decrease in capital cost, the greatly superior heat rate
of fuel cell stations would make them preferable to simple-cycle
combustion turbines for this application. Earliest availability
would be 1988.
5.57
Base, Intermediate or Peaking Load Duty in the Fairbanks Area
• If the Fairbanks area continued to be electrically isolated from the
remainder of the Railbelt region, fuel cell stations in the 10 to
25-MW size range would be appealing successors to the combustion
turbine power plants currently in use in the Fairbanks area. The
superior heat rate and flexible scale of fuel cell stations
contribute to the feasibility of this application. Earliest
availability would be 1988.
Coal-Based Baseload Power
• Coal gasifier-fuel cell -combined-cycle plants in the 200 to
300 MW size range could eventually serve as the baseload component
of the Railbelt electric power system. The excellent heat rate and
potentially modest environmental effects of these plants would suit
them well for such applications in lieu of coal steam electric or
coal gasifier -combustion turbine -combined-cycle plants.
Earliest availability would be 1997.
Natural Gas-Based Baseload Power
• If natural gas continues to be the fuel of choice in the Anchorage
area, natural gas fired -fuel cell -combined-cycle plants could
eventually serve as the baseload component of the electric power
system. The excellent heat rates of these plants would maximize the
electric power generating potential of the natural gas supply and
would provide protection against rising natural gas prices. Such
plants may be able to be retrofitted to synthetic gas firing as
natural gas prices continue to rise. Earliest availability would be
1997.
Natural Gas-Based Baseload Power and District Heating
• Because of the likely modest environmental impacts of a natural gas
fired -fuel cell -combined-cycle plant, such a plant could likely be
sited in sufficient proximity to urban areas to allow the development of
a district space heating system based on fuel cell waste heat. Earliest
availability would be 1997.
5.58
6.0 STORAGE TECHNOLOGIES
Energy-storage technologies provide a way to use baseload electrical
generating capacity to meet peak demands. Energy from baseload plants is
stored during offpeak hours and is subsequently released during peak periods.
The net effect is to substitute relatively inexpensive baseload generating
capacity for peaking capacity. A second application of energy storage
technologies is for storage of energy from intermittent operating generating
facilities (e.g. wind, solar and tidal plants), increasing the availability of
energy from these types of generating facilities. A third application is to
provide an emergency standby power supply in case of power station or trans-
mission system failure.
Three types of energy-storage systems are described in this chapter:
hydroelectric pumped storage, battery-storage systems and compressed-air
energy storage (CAES) systems. Of these systems, the only one in widespread
commercial use is hydroelectric pumped storage. Battery-storage systems may
become commercially available in the next ten years. One commercial com-
pressed-air storage plant is in operation in West Germany. However, the
technology is in the preliminary design stage in the United States. No
technological breakthroughs are required to establish CAES commercially, and
its commercial development will likely depend substantially upon the compara-
tive economics of CAES and competing storage systems.
Selected characteristics of hydroelectric pumped storage, battery-storage
systems, and compressed-air energy storage systems are compared in Table 6.1.
6.1
TABLE 6.1. Comparison of Storage Technologies on Selected Characteristics
Aesthetic Intrusiveness
Visual :mpacts
Noise
Odor
Ecological Impacts
Gross Water Use (gpm)
Land Use (acres)
Costs
--capital Cost ($/kW)
O&M Cost ($/kW/yr)
Cost of Energy (mills/kWh)
w/ 20 mill electricity
40 mill electricity
80 mill electricity
Public Health & Safety
Consumer Effort
Adaptability to Growth
Unit Sizes Available
Construction Lead Time
Availability of Sites
Re 1 i ab i 1 i ty
Availability
Expenditures Within
A 1 ask a
----capT t a 1
O&M
Fuel
Boom/Bust Effects
Construction Personnel
Operating Personnel
Ratio
Magnitude of
Impacts
Consumer Control
Raiibelt Experience
Pumped Storage
(25 MW, Above Ground)
Significant
Minor
None
Site Specific
Site Specific
950
10.0
42
63
110
Safe
Utility operated.
1.5 -400 MW
5 - 7 yr
Limited to suitable
topography.
85%
45%
88%
100%
Battery Storage
(10 MW/5 hr (50 MWh)
Minor
Minor
Minor
None
0.5
110 -240
6.5
38 -44
65 -72
110 -130
Potential local
chemica 1 hazard.
Utility operated.
4 -40 MW (for 5 hr)
1 yr
Widely available.
>90%
15%
88%
100%
350 20-40
10 Not known
35 Not known
Minor in vicinity Minor
of Anchorage.
Moderate to severe
in all other locations.
Control through Control through
regulatory agencies. regulatory agencies.
Currently available. 1988-1992
None None
Compressed Air
Energy Storage
(1000 MW, Hard Rock)
Significant
Moderate
Minor
Moderate
"'100
690
10.7
54
67
94
Potential aquifer pollution.
Potential air pollution.
Utility operated.
200 -1000 MW
5 - 6 yr
Limited to suitable geology.
>90%
55%
45%
100%
150-300
(<100)
1.5-3:1
Major in all locations
except Anchorage & Fairbanks.
Contra 1 through
regulatory agencies.
Currently available.
None
(a) Costs are based on 100-MW installed capacity and may be higher for a 25-MW plant.
6.2
6.1 HYDROELECTRIC PUMPED STORAGE
A hydroelectric pumped-storage plant consists of an upper and a lower
reservoir, a reversing turbogenerator, and interconnecting piping. Water is
pumped from a lower reservoir to the upper reservoir during off-peak hours.
During peak demand periods, the water is allowed to flow from the upper
reservoir through turbines to the lower reservoir; power is generated in the
process. A net energy loss occurs with pumped-storage facilities because of
system pumping losses and generator inefficiencies. However, these losses are
more than compensated for by the difference in power production costs between
the baseload plants used to fill the pumped-storage reservoir and the peaking
plants that are displaced by operation of the pumped-storage plant.
Pumped-storage plants had their commercial origin in the United States in
1929. The first domestic installation was the 7-MW Rocky River Plant near New
Milford, Connecticut. This facility was followed by the 8.5-MW Flat Iron Plant
built by the Bureau of Reclamation in Colorado in 1954.
Pumped-storage generation has undergone several important changes as a
result of advancing technology and changing system needs. The most signifi-
cant, single technological advancement was the development of the single
runner, reversible pump/turbine with high-head pumping capacity. These units
currently have pumping capabilities as high as 600 meters (1800 ft).
6.1.1 Technical Characteristics
The major components of a pumped-storage project include upper and lower
reservoirs, water conductors, and the powerhouse, which contains pumping and
generating equipment. A typical pumped-storage arrangement is shown in
Figure 6.1.
Commercially operating pump/turbines have been built with capacities
ranging from 1.5 MW up to 400 MW (TVA•s Raccoon Mountain project) with larger
units anticipated for the future.
6.3
UPPER
RESERVOIR
UPPER
RESERVOIR
DAM
PENSTOCK
GENERATOR/MOTOR
PUMP/TURBINE
SURGE TANK
HEAD
LOWER
RESERVOIR
LOWER
RESERVOIR
SCHEMATIC OF A PUMPED
STORAGE HYDRO PLANT
FIGURE 6.1. Schematic of a Pumped Storage Hydro Plant
Design Features
Several hydroelectric pumped-storage arrangements are possible:
Natural Upper and/or Lower Reservoir. The natural reservoir may consist
of any large body of water of adequate volume, such as rivers or lakes.
A natural reservoir may also consist of a basin, surrounded by higher
topography or mountainous terrain, with dams constructed across the basin
valleys or low points.
6.4
Manmade Upper and/or Lower Reservoir. The manmade reservoir consists of
constructing the complete reservoir using perimeter dikes. This approach
is generally used on flat or nearly flat terrain where an upper reservoir
is to be built on a plateau or high, level bluff.
Underground Lower Reservoir. The underground reservoir would use under-
ground, natural rock caverns or an underground rock excavation and would
have an underground powerhouse. The upper reservoir may be either natural
or manmade, as described above, or it may use the storage reservoir of an
existing, conventional hydro plant.
Conversion of Existing Hydro Plant. In this approach an existing conven-
tional hydro plant would be converted entirely to pumped storage. The
existing reservoir would be used as the upper reservoir, and the lower
reservoir would be formed by constructing a lower dam downstream of the
existing dam.
Conventional Hydro with Pumped Storage. In this approach, a seasonal
pumped-storage facility would be built in conjunction with a conventional
hydro project. During periods of high river flow and during off-peak
hours, the excess water normally discharged over the spillway of the
existing structure could be used to run pump/turbines to pump water to an
offsite, upper reservoir. During the peak demand hours, this stored
water would be discharged back though the pump/turbines, operating in a
generating mode, to the river.
To form the reservoir, several dam types are used, generally depending on
the valley conditions, local geology, availability of construction materials,
and cost. Typical dams may include concrete gravity, concrete arch, or earth
or rockfill dams with an impervious central core. Perimeter dikes are typi-
cally constructed of earth and rockfill with an impervious central core or an
impervious liner.
Upper reservoirs are provided with an emergency spillway. The spillway
conveys excess water caused by accidental overpumping away from the reservoir
in a controlled manner. When formed by a dam structure, lower reservoirs also
include a spillway. The function of this spillway is similar to that for a
6.5
conventional hydro dam. Since a lower reservoir dam would normally be located
along an existing stream or river, the spillway would discharge flood flows
from the existing waterway. Water conductors between the reservoirs may be
rock tunnels or aboveground penstocks, depending on the project configuration,
site geology, topography, and cost.
The major powerhouse equipment consists of one or more reversible pump/
turbines coupled to motor/generators. During periods of low electrical demand
the pump/turbines, driven by the motor/generators, pump water from the lower
to the upper reservoir. During peak demand hours, the pump/turbine unit
transforms the kinetic energy of flowing water into mechanical energy to drive
the motor/generator as a generator.
The powerhouse may be either a surface or an underground structure. The
surface powerhouse consists of a substructure to support the hydraulic and
electrical equipment and a superstructure to house and to protect this equip-
ment. Underground powerhouses are constructed in natural or manmade caverns.
This scheme is used in certain topographic conditions, particularly narrow
canyons, for which no convenient site exists for a conventional powerhouse,
and for underground pumped-storage plants. Its feasibility depends on site
geology and cost.
Performance Characteristics
Overall conversion efficiency (kWh in/kWh out) of hydroelectric pumped
storage plants are about 72% (EPRI 1979b). Equivalent annual availability is
estimated to be 95.5% for an underground pumped-storage plant (EPRI 1979b),
availabilities for surface facilities should be similar.
Unit lifetime is estimated to be 45 years for underground pumped-storage
plants (EPRI l979b). Lifetimes for surface facilities should be similar to
the 50-year economic lifetime community accepted for conventional
hydroelectric facilities.
6.1.2 Siting and Fuel Requirements
The size and feasilibity of a pumped-storage project are strongly
influenced by site characteristics. Availability of water, land, transmission
lines, and access roads are important considerations in the site selection
6.6
process. In addition, potential sites are evaluated for topography, geology,
seismology, and availability of construction materials.
Site topography, specifically the effective head and reservoir storage
capacity, determines the power generating duration and rated capacity. Topo-
graphy also determines the extent of dam construction required to contain the
reservoir; maximum use of natural embankments is desirable. The length of the
water conductors largely depends on topography. Longer conductors will add to
construction costs and will result in larger generating losses and pumping
costs. The shortest possible horizontal distance between the upper and lower
reservoirs is desirable.
Geologic conditions can affect all plant structures. The presence of
unfavorable geologic conditions can result in seepage and stability problems
that can be costly to rectify. The competency of the rock will also determine
the type of water conductors used (tunnel~ versus aboveground penstocks) and
whether an underground powerhouse can be considered.
Sites characterized by high seismic activity should be avoided, although,
if necessary, a project could be designed to resist seismic loads at an over-
all cost increase. Embankment slopes would have to be flatter; additional
restrictions would have to be placed on fill materials; and structures would
have to be more massive.
Availability of construction materials also is an important consideration
in the site selection process. All concrete structures will require quanti-
ties of fine and coarse aggregate. Depending on the configuration of poten-
tial dam structures, a considerable amount of fill material also could be
required. This material could range from a large, rockfill-sized material
down to impervious soil fill. Potential borrow pits should be located as
close to the construction site as possible to minimize construction costs. No
single site is likely to ideally satisfy all requirements, and therefore the
relative technical and economic merits of several candidate sites will have to
be evaluated before selecting a single site.
The fuel requirements for a pumped-storage project consist of the elec-
tricity required to compensate for electrical and mechanical losses during
6.7
plant operation. This electricity is normally supplied from base-loaded oil,
gas, coal or nuclear plants. Water is, of course, required for system
operation.
6.1.3 Costs --
Capital investment costs for pumped-storage development are site specific
and vary according to type, size, head, location of the project, amount and
cost of required land, and required relocations. The costs of reservoirs,
power tunnels and penstocks vary considerably with site characteristics and
may have little relationship to the installed generating capacity. However,
an installed capacity cost of $950/kW (1981 dollars) is generally accepted for
low-capacity, pumped-storage projects (less than 100 MW). Unit investment
costs are a function of capacity and generally decrease as plant capacity
increases; however, for very large pumped-storage plants (greater than
100 MW), investment costs begin to rise.
Plant size, number of pump/turbine units, annual generation, operating
head, and site-specific conditions for individual plants are maor factors in
maintenance costs. Fuel costs include the cost of pumping water from the
lower to upper reservoir and transmission losses. The cost of pumping water
depends on the source of off-peak electric power used for pumping.
Table 6.2 shows the estimated costs of hydroelectric pumped-storage
plants. The costs were developed based on data from Ebasco, U.S. DOE (1979a)
U.S. Army Corps of Engineers (1979) and Electric Power Research Institute
(EPRI)(1979b). Note, however, that hydroelectric pumped-storage costs are
highly site specific and can vary significantly from the costs of Table 6.2.
6.1.4 Environmental Considerations
The impacts of a hydroelectric pumped-storage facility on the water
resources of both the upper and lower reservoirs can be similar to those
discussed in Section 5.4.4 for a conventional hydroelectric facility. The
major impacts occur from basin flooding and the alteration of the hydrologic
regime of the water body. In addition, a natural upper reservoir may exper-
ience adverse impacts due to possible modifications in the water-quality
regime if differences exist in the water-quality characteristics of the upper
and lower reservoirs (i.e., from introduction of lower quality water from the
6.8
TABLE 6.2. Estimated Costs of Hydroelectric Pumped-Storage Plants
(1980 dollars)
Electric Energy Cost
Rated Capacity Capital O&M (mills/kWh @ baselofd
{MW} {$/kWl {$/kW/trl energt costs shownl a)
20 40 80
100 950 10 56 77 120
400 600 7 46 67 110
500 500 6 43 64 110
>1000 500 4 47 63 110
(a) Assumes 1990 as first year of commercial operation and 50-year
economic life; incremental costs with 20, 40 and 80-mill baseload
power are shown.
lower reservoir). These impacts are site and facility specific, being a
function of reservoir volumes, mixing rates, reservoir water-quality, and many
other variables. These water-quality impacts also will affect the lower
reservoir, again depending upon site-specific characteristics and whether the
lower reservoir is a natural of manmade water body.
Both reservoirs could experience increased scouring and elevated tru-
bidity levels associated with the pumping process and hydroelectric facility
discharge design. Proper engineering and plant operation can minimize these
impacts.
Creation of a manmade reservoir, either upper or lower, may affect the
local hydrologic regime because of increased groundwater seepage and evapo-
ration. Also, underground caverns used for water storage, whether natural or
manmade, may impact groundwater quality due to the potential solvation or
reaction with the local rock media. Proper site selection criteria and design
should minimize these impacts.
No impacts on air quality would result from the use of pumped-storage
techniques. Development of an artificial reservior may produce some changes
in the microclimate. However, these changes will pertain mainly to tempera-
ture and humidity values near the reservoir and will not be perceptible
offsite.
6.9
Biological impacts of pumped storage are similar to those of conventional
hydroelectric plants. Depending on the size, pumped-storage projects typi-
cally alter the stream flow characteristics and water quality of streams,
which results in corresponding changes in the aquatic biota. Although impacts
occur on all levels of the food chain, the impacts on fish (particularly
salmonids) are usually of most concern. The following are the potential
effects most difficult to mitigate: 1) loss of shoreline spawning areas in
lower and upper reservoirs; 2) loss of rearing habitat; 3) increased mortali-
ties of fish passing through turbines; and 4) entrainment of fish due to
pumping and discharge from one reservoir to the other. Construction may
result in elevated turbidity, gravel removal from the stream, and expanded
public fishing in the area because of improved access. Plant operation may
result in altered nutrient movement, affecting primary production; water-flow
pattern changes, modifying species composition; and altered temperature
regimes, affecting migration timing. Also, depending upon spillway design and
location, a pumped-storage project may result in gas supersaturation in either
the lower reservoir or at downstream locations. This gas supersaturation
possibly may result in fish mortalities. Competition and predation among and
within species also may be changed.
Mitigative procedures are possible for many impacts and are frequently
incorporated into the facility design. Fish hatcheries are commonly used to
replace losses in spawning habitat. Screening or diversion structures are
used to direct fish away from critical areas. Controlled pumping and release
of water (including both flow and temperature regulation) can be used to
improve environmental conditions during spawning, rearing, and migration.
Potential pump-storage sites in the Railbelt region have not been identi-
fied. However, potential terrestrial impacts of pumped-storage facilities are
similar to those of conventional hydroelectric developments (see Section 5.4.4)
and include wildlife habitat loss from land inundation and wildlife disturbance
from increased human intrusion. Unlike conventional hydroelectric plants,
impacts may not be limited to riverine ecosystems. Lowland wildlife popula-
tions, particularly moose and caribou, would be impacted by inundation of
6.10
habitat. Pumped-storage reservoirs can be developed in basins lacking major
surface water systems, such as forested areas, using containment dikes. To
reduce terrestrial impacts, pumped-storage facilities should be sited in areas
of low wildlife value. Other mitigative actions could include enhancing the
value of a reservoir to certain wildlife (i.e., waterfowl).
6.1.5 Socioeconomic Considerations
Since pumped storage is a labor-intensive technology, impacts would vary
with both plant scale and location. The construction work force requirements
would range from 350 for a 100-MW plant to 1200 for a 1000-MW plant, for a
period of 4 to 5 years. Plant operation and maintenance requirements would
range from a staff of approximately 10 for a 100-MW plant to 30 for a 1000-MW
plant. The large differential in construction and operating personnel could
cause a boom/bust cycle in remote areas.
A 100-MW plant would have minor socioeconomic impacts if located near
Anchorage. The magnitude of the impacts on Fairbanks and intermediate-sized
communities would depend on the extent to which the local labor pool could
reduce the number of migrants. Small and very small communities would be
severely affected by a 100-MW plant because of the substantial population
increase.
A 1000-MW plant would affect all locations of the Railbelt, with the
exception of Anchorage and possibly Fairbanks. Construction camps would not
relieve the impacts to remote areas since the construction period is suffi-
ciently long (5 to 7 years) to result in semipermanent settlement by the work
force dependents and secondary inmigrants.
An estimated 55% of the project's capital expenditures would flow out of
the region, and 45% would remain within the Railbelt. Approximately 12% of
O&M expenditures would be spent outside the region.
6.1.6 Potential Application to the Railbelt Region
No hydroelectric pumped-storage projects have been developed in the
Railbelt region. However, under certain future conditions, the development of
energy-storage systems may become desirable in the Railbelt.
6.11
Electric energy storage systems may become desirable in systems having
one of two conditions:
1. A low diurnal load factor, high-cost peaking capacity and low-cost
baseload capacity.
2. A low-cost source of intermittent power, large in capacity compared
with system loads.
The Railbelt system is currently characterized by a fairly low load
factor (Chapter 2) and surplus capacity. In the Anchorage area, the variable
operating costs of baseload plants (primarily gas-fired combined-cycle plants)
are low; variable costs of peaking units (primarily gas-fired combustion
turbines) are slightly higher, but still reasonably inexpensive. In the
Fairbanks area, variable costs of baseload capacity (coal steam-electric and
oil-fired combustion turbines) range from moderate to high; variable costs of
peaking capacity (oil-fired combustion turbines) are high.
Given these conditions, energy-storage systems could find application in
the Railbelt under several circumstances.
1. Natural gas continues to be used as the primary electric-energy
resource in the Anchoraqe area, and natural qas prices rise over
time. Energy storage in used to provide peak power from high effi-
ciency combined-cycle plants. Currently, simple-cycle combustion
turbines (or the combustion turbine sections of combined-cycle
plants) are used for peaking purposes in the Anchorage area.
Although the heat rate of combustion turbines is substantially
higher than that of combined-cycle plants, the combustion turbines
continue to be used for peaking duty because of the sunk costs of
the existing combustion turbines and the low cost of gas. Use of
energy storage plants, operating with electricity generated by
combined-cycle plants, might be desirable if gas costs increase
substantially. Use of energy-storage systems might be even more
attractive if increasing baseload demand resulted in conversion of
existing combustion turbines to combined-cycle plants, thereby
forcing a choice between new combustion turbine plants or
energy-storage plants for capability.
6.12
2. Coal is developed as a major regional electric energy resource.
Energy storage is used to provide peaking capability using coal-
fired baseload plants as sources of energy. Contemporary coal-fired
power plants are highly efficient generating devices but are not
readily suited to load-following application. Energy storage
facilities could provide a way to obtain load-following capability
in a coal-based system. Alternatives to use of energy storage
facilities for this application in the Railbelt would include con-
struction of hydro capacity for peaking application or continued use
of gas-fired combustion turbines for peaking.
3. Cook Inlet tidal power is developed for electric energy production.
Energy storage is used for leveling plant output. The proposed Cook
Inlet tidal power project would produce a large quantity of energy,
cycling with the tides. The potential output of the proposed
project would be so large that only a portion of the tidal plant
output, if untimed, could be absorbed by the Railbelt electric power
system. An energy storage facility could provide a way to use a
larger fraction of tidal plant output.
4. A large block of intermittent dispersed wind or solar capacity is
developed. Energy storage is used in conjunction with these units to
provide firm capacity. This application is not unlike the previously
described (Cook Inlet tidal) application, except the energy storage
capacity required would likely be greater relative to the installed
solar or wind capacity because of the intermittent nature of the wind
or solar resource (as compared with the cyclic nature of the tidal
resource). Storage capacities equivalent to several days output most
likely would be required to firm up the capacity of solar or wind
generation.
5. Lengthy transmission interties and large central generating plants
are constructed. Dispersed energy storage plants are used to
enhance system reliability.
Hydroelectric pumped-storage plants represent only one of several
possible ways to store electric energy for the applications described above.
6.13
However, it is the one technology that is fully proven in commercial service
and would likely receive most serious consideration for near-term applica-
tion. Of the potential applications described above, hydroelectric pumped
storage would be suitable for all except number 5. Dispersed, smaller scale
energy storage facilities (such as battery storage plants) would be more
suitable for enhancing the reliabiity of a highly centralized system. The
principal disadvantages of a hydroelectric-pumped storage facility include the
need to locate a suitable site and the potentially significant environmental
impacts.
6.14
6.2 STORAGE BATTERIES
Utility-scale use of storage batteries is an emerging technology that may
find applications for load leveling and for energy storage with intermittent
(fuel-saver) generating alternatives. In a load-leveling capacity, electri-
city would be converted from high-voltage AC into lower voltage DC and would
be stored in the batteries in hours of low demand. During peak hours the
process would be reversed to carry part of the utility's load. The economic
use of storage batteries for load-leveling applications thus requires the
availability of low-cost baseload power to offset high-cost peaking sources.
Storage batteries also may be potentially useful with "fuel-saver"
generating options; e.g., wind turbines, solar devices and tidal hydroelectric
devices. Coupled with storage batteries, the fuel-saver options could be
granted capacity credit.
EPRI and DOE have funded the development of batteries for utility load
leveling. Battery prototypes are to be tested in the Battery Energy Storage
Test Facility (BEST), sponsored jointly by DOE and EPRI. To provide actual
operating experience with battery storage coupled to a power grid, the DOE is
initiating a Storage Battery for Electric Energy Demonstration project
(SBEED). Plans call for completion, in 1984, of a facility consisting of a
30 MWh, lead-acid battery coupled to a 10 MWh, AC-DC converter (Kalhammer
1979).
6.2.1 Technical Characteristics
A 100-MWh (20-MW capacity for 5 hours) zinc-chloride, load-leveling
battery plant is shown in Figure 6.2. Storage-battery systems include
batteries, equipment for power conditioning and for utility interface. Power
conditioning equipment consists of an inverter/converter module, which con-
verts DC to AC or AC to DC. The utility interface includes a transformer
filter, controls, and associated switch gear. Other items included in the
plant are the cell handling equipment, cooling system, and instrumentation.
Commercial battery-storage systems are expected to be sized in the 20 to
200 MWh capacity range.
6.15
44-MODULE
STACK
COOLING TOWERS POWER
CONDITIONING
FIGURE 6.2. 100-MWh, Zinc-Chloride, Load-Leveling Battery Plant(a)
(a) The battery subsystem consists of 1584 modules on 36 44-module racks, one of which is shown
inset (Energy Development Associates (EDA) 1979).
Design Features
Several new types of storage batteries are under development for utility
application. Among these are the advanced lead-acid battery, the sodium-
sulfur battery, the iron-chromium Redox fluid battery, the zinc-chloride bat-
tery, the lithium metal-iron sulfide battery, the zinc-bromine battery, and
the hydrogen-chlorine battery. The most promising battery types for utility
applications include Redox (Lewis Research Center), zinc-bromine (Exxon),
sodium-sulfur (Ford and Dow) and zinc chlorine (Energy Development Associates)
(Krauthamer and Frank 1980).
The Redox flow cell uses chromium-chloride and iron-chloride solutions,
which are pumped through a 11 stack 11 of flow cells. In each flow cell, the
fluids are separated by an ionic-permeable membrane. The fluids transfer
electrical charge through the membrane as each fluid reacts at a separate
inert-electrode surface, but chromium and iron remain in solution, barred from
passing through the membrane. One concern is that the maximum stack voltage
is limited to 100 volts. Another concern is the ultimate life of the mem-
brane. A 1-MW unit is planned for installation in the BEST facility in FY96.
Zinc-bromine batteries have been developed by Exxon, Gould, and General
Elecric. The Exxon design, which apparently has the economic advantage,
employs a cation exchange membrane and inexpensive·, conductive plastic
composite electrodes. The Gould design uses titanium electrodes. Areas of
concern in the Exxon design are limited stack voltage and life of the cation
selective membrane.
Sodium-sulfur batteries have been developed by Ford, Dow, and General
Electric. The batteries operate at 300 to 350°C, with molten sodium and
sulfur as reactants. The Ford and General Electric designs are similar.
Areas of concern with the cells include cracking of seals, corrosion by
polysulfides, and long-term stability of the beta alumina separator, which
separates the molten sodium from the molten sulfur.
The major difference in the Dow sodium-sulfur battery is that the ion-
conducting glass fibers are used as a separator instead of beta alumina. Major
areas of concern are breakage of the tiny, hollow glass fibers, and complex
6.17
manufacturing. Also, the ability of the cell to withstand the thermal cycling
of startup and shutdown is unknown. These problems are reflected in the low
probability of availability (20%) cited in Table 6.3.
The zinc-chlorine battery is being developed by EDA. The cell consists
of a zinc electrode, a chlorine electrode, and an aqueous, zinc-chloride
electrolyte. Important safety and environmental impact considerations revolve
around accidental release and dispersion of toxic amounts of chlorine (EDA
1979). Other areas of concern include hydrogen evolution from the anode,
removal of zinc from the anode, requirement of special charging equipment, and
maximum stack voltage of 21 volts. A 5-MWh, zinc-chloride system was to be
installed in the BEST Facility in 1981.
Performance Characteristics
Table 6.3 presents a summary of performance parameters of eleven advanced
battery systems. Station equivalent annual availability is estimated to
exceed 90% (EPRI 1979b). A 30-year economic lifetime with several interim
replacements of batteries is estimated.
6.2.2 Siting and Fuel Requirements
One of the EPRI criteria established for utility battery plants is mini-
mum siting restrictions. Designs should allow unlimited siting in urban,
suburban, and rural areas (EDA 1979).
Battery plants in the 20 to 200 MWh range could be located at substations
in the utility subtransmission or distribution network (EDA 1979). Covering
an area of 8 kWh/ft 2, a 100-MWh plant can be located on a half-acre site at
a utility substation (EDA 1979). 11 Fuel 11 requirements for a battery-storage
plant could be either electricity from baseload plants or electricity from
intermittent generating plants.
6.2.3 Costs
A summary of cost estimates for advanced battery-storage systems is given
in Table 6.4. Results are based on a facility with a 10-MW power rating with
5 hours of storage capacity (50 MWh) and a 30-year life. Costs for a facility
6.18
TABLE 6.3. Performance of Advanced Electrochemical Storage
Batteries (Krauthamer and Frank 1980)
Throughput
Battery Efficiency Projected
Battery Cycles (t Efficiency (Battery + Power Avai labil1t1 Probability of
T~Ee 80% DOD a) at 80% DOD Conditioner} for Order b Availabilit~
Advanced
Lead-Acid 4000 80-85% 70-78% 1985 0.95
Sod i urn Sulfur
(General 2500 76% 70% 1985 0.95
Electric)
Sodium Sulfur
(Ford) 2500-5000 75% 69% 1985 0.80
Sod i urn Sulfur
(DOW) 3000 90% 83% 1990 0.20
Iron-Chromium
Redox
(NASA 10000 75% 69% 1990 0.80
Lewis
Research
Center)
Zinc Ch 1 or ide
(Energy 2500-3500 71-74% 65-68% 1985 0.95
Development
Associates)
Lithium Metal-Iron
Sulfide (Argonne) 3000 85% 78% 1990 0.70
Zinc-Bromine
(Gould) 2500 70% 65% 1990 0.70
Zinc-Bromine
(Exxon) 2500-5000 80% 74% 1990 0.70
Zinc-Bromine
(General 2000 75% 69% Unknown Unknown
Electric)
Hydrogen-Chlorine
(Brookhaven Unknown 65% 60% Unknown Unknown
National Laboratory)
(a) Depth of discharge.
(b) Quantities of 1000 MWh/yr.
6.19-
rated at 100 MWh would likely be similar due to the modularity of a battery
storage facility. Levelized costs are greatly influenced by initial invest-
ment and battery replacement costs.
Estimated capital costs for advanced battery-storage systems that appear
most promising for utility application are given in Table 6.4. These costs
were computed on the same basis, but they are only tentative estimates. The
batteries• actual manufacturing costs, O&M costs, and lifetimes are not well
known. In addition, balance-of-plant costs shown are only rough estimates.
For example, updated costs for a zinc-chlorine battery system show balance-of-
system costs of $175/kWh (EDA 1979) as compared with $30.7/kWh estimated in
Table 6.4.
O&M costs were estimated at 19 mills/kWh (EDA 1979), compared with
0.6 mills (1981 dollars) in the source from which the estimates of Table 6.4
are taken (Krauthamer and Frank 1980). EPRI estimates that advanced storage-
battery's fixed O&M costs to be 0.3 $/kW/yr and variable O&M costs to be
2.0 mills per kWh (EPRI 1979b). The EPRI estimates, escalated to 1980 and
regionally adjusted, are shown in Table 6.4.
Estimated incremental power costs for a variety of advanced storage
battery systems for 20, 40, and 80 mill baseload power costs are shown in
Table 6.4. Costs will be kept to a minimum by component modularization and by
reduction in building requirements, although Alaskan installations most likely
will require weather protection. Modules will be factory assembled, which
reduces site construction labor and construction time.
6.2.4 Environmental Considerations
Advanced battery facilities are to be designed to have minimum impact on
their surroundings. The land area required for a 100-MWh station would be
about one-half acre; this could be at an existing substation. Airborne
emissions are expected to be minimal and heat releases to the surroundings
should be low. An unavoidable short-term impact on air quality, including
dust and equipment emissions, plus noise and some solid waste would occur
during construction. As discussed previously, the materials used in certain
battery designs may present a potential chemical hazard.
6.20
Q) .
N
fo.,.:l
TABLE 6.4. Estimated Costs of Adyanced Battery Storage Systems, 10-MWe Storage with
5 Hours of Capacity(aJ
Present Electric(Elergy
Value of Total Battery Cost f
Number of Battery Balance Battery System Replace-(mills/kWh l
Battery Replacements Initial of System Replacement Initial ment O&M @ Baseload Energy
Efficiency Over 30-Year Cost Cost Cost Cost Cost Cosd e l Costs Shown
Battery T.i'}!e (%) Life ($/kWh) ($/kWh) ($/kWh) (c) HJkWh)(d) ($/kWh) J1L!<..\!LY.!:l 20 40 80
Iron-Chromium Redox 69 0 74 37 0 (110) 111 (g) 6.0 40 69 130
(Lewis Research Center)
Zinc-Bromine 74 49 37 21 (110) 107 32 6.0 38 65 120
(Exxon)
Sodium-Sulfur 69 66 42 28 (140) 136 43 6.0 43 72 130
(Ford)
Sodium Sulfur 90 3 50 39 155 (240) 244 79 6.0 43 65 llO
(Dow)
Z inc Ch 1 or ide 74 2 59 40 75 ( 190) 194 73 6.0 44 71 130
(EDA)
(a) Capital costs, battery efficiency and number of replacements based on Krauthamer and Frank (1980); capital costs are adjusted to
Alaska using 1.3 adjustment factor.
(b) 10-MW Storage with 5 hours of capacity (1980 dollars).
(c) Present value at time of commercial operation, discounted at 3%.
(d) Battery initial cost plus balance of system cost plus present value of battery replacement cost.
(e) O&M costs are from EPRI (1979b), escalated to 1980, adjusted to Alaska using a 1.3 adjustment factor and assuming full cycling on a
daily basis (equivalent of 21% capacity factor). Plant rating taken at 10 MW for purpose of O&M costing.
(f) Assumes 1990 startup date; 30-year economic life.
(g) A small salvage value was allowed in Krauthamer and Frank (1980); no salvage was assumed for this analysis.
6.2.5 Socioeconomic Effects
The maximum construction work force for a battery-storage facility would
be 20 to 40 persons. Factory assembled modules will reduce the work force
required for onsite construction. Battery stations will be unattended.
Construction of a battery-storage facility of 100 MWh capacity is estimated to
require one year (EPRI 1979b). The Alaskan construction season is typically
shorter than that estimated by EPRI for lower 48 conditions. However,
battery-storage systems would likely be enclosed, allowing construction to be
completed during cold seasons. The logical location of a battery plant would
be near a load center where peaking power is required. Because a load center
would be near an existing population center, the impact of construction would
be sma 11.
Most of the money spent on such a project would be for purchase of equip-
ment manufactured outside Alaska. Out-of-state capital spending is estimated
to be 85%.
6.2.6 Potential Application to the Railbelt Region
Considerations that govern the application of battery energy-storage sys-
tems to the Railbelt include 1) commercial availability of the technology,
2) potential need for energy storage facilities, and 3) the technical charac-
teristics of battery-storage systems.
Utility-scale battery-storage systems are expected to become available
for commercial order in the 1988-1992 time period. Given the anticipated one-
year construction period, these systems could be available for commercial
operation in the period 1989-1993. Thus, any Railbelt application will be in
the mid-to long-term.
Circumstances under which development of energy-storage projects might be
attractive in the Railbelt region are discussed in Section 6.1.6 of this chap-
ter. These include 1) use of energy storage projects in conjunction with
natural-gas-fired combined-cycle baseload plants to meet peak loads, 2) use of
energy storage projects in conjunction with coal-fired baseload plants to meet
peaks loads, 3) use of energy storage projects to retime output of the pro-
posed Cook Inlet tidal power project, 4) use of energy storage projects in
6.22
conjunction with dispersed smaller scale intermittent power projects (solar or
wind) to provide firm power, and 5) use of energy storage projects to enhance
system reliability.
Battery-storage units, when commercially available, will have the
advantages of 1) few siting restrictions, 2) modest environmental impacts,
3) modularity in size, and 4) short lead times. The principal disadvantages
will likely be few economics of scale with larger plants sizes and high
interim capital replacement costs. In view of these characteristics, the most
promising future applications of battery-storage systems appear to be in
conjunction with dispersed wind or solar generating units to provide firm
capacity, and in conjunction with a highly centralized system to enhance
system reliability. Technically, storage batteries could provide energy
storage for the other potential applications discussed above. However, the
plant size required would be substantial, and hydroelectric pumped storage or
CAES facilities with their potential for economics of scale with larger plant
sizes would be preferred for such applications.
6.23
6.3 COMPRESSED AIR ENERGY STORAGE (CAES)
CAES is a relatively new technology for large-scale, centralized storage
of electricity. During off-peak hours surplus energy from the utility grid is
used to compress air that is cooled and stored underground in an excavated
hardrock cavern, a solution-mined salt cavern, or an aquifer. Then, during
peak-demand hours, the air is released from the cavern and is expanded in
turbines to generate electricity. The primary objective of CAES is to use
relatively inexpensive baseload power more effectively and thereby reduce the
need for peaking devices fired by expensive oil and natural gas.
After the air is compressed in a CAES plant, it is cooled before it is
stored underground. Then, when the air is recovered for power generation it
must be reheated to permit efficient expansion in the turbine. Reheating is
accomplished by burning fuel oil, as in a conventional gas turbine. The
energy contributed by the fuel is significant, and therefore a CAES plant is a
net generator of electrical energy as well as a storage device. The ratio of
input electrical energy to output electrical energy for an oil-fired CAES
plant is about .75.
The first (and only) CAES plant started operation in Huntorf, West Germany
in 1978 and has proved to be highly successful, surpassing predictions for
reliability and operational flexibility. It is a 290-MW unit that employs two
solution-mined salt caverns for air storage.
In the United States, CAES is being investigated by EPRI, DOE, and
individual electric utilities. EPRI and DOE have sponsored three preliminary
CAES engineering design studies, led by three electric utilities: Middle
South Services, Inc. (MSS); Potomac Electric Power Co. (PEPCO); and Public
Service Indiana (PSI). These studies addressed design, economic, environ-
mental, safety, and siting considerations. Each focused on one storage
medium: MSS on salt, PEPCO on hardrock, and PSI on aquifers. In general, the
results of these studies indicate that CAES would be cost effective and would
reduce system consumption of petroleum fuels. The decision to build a CAES
plant is still pending for these utilities.
6.24
6.3.1 Technical Characteristics
The major components of a CAES plant are the turbomachinery and the air
storage reservoir. The turbomachinery consists of a large-volume, high-
temperature compressor train coupled to a reversible motor/generator through a
clutch assembly. The motor/generator in turn, is coupled to a high-volume
turbine train through another clutch assembly. The motor/generator powers the
compressor during the charging cycle and generates electricity during the
recovery cycle. A CAES turbomachinery schematic that is standard for most
CAES designs is depicted in Figure 6.3. However, for the air storage reser-
voir and for the air reheat equipment several options exist that radically
affect the construction and operation of the CAES plant. Plant sizes are
expected to range from 200 to 1000 MW.
Design Features
Three major storage options exist: hard-rock-mined caverns, solution-
mined salt domes, and aquifers. Each has advantages and disadvantages.
Salt domes are the least expensive to develop. The solution-mining tech-
nique entails drilling a well into a salt dome and continuously pumping in
fresh water. Over a period of time the salt dissolves. (The two Huntorf
caverns took 12 and 16 months to mine.) While water is being pumped in, the
resultant brine is pumped to the surface for disposal. An advantage of salt
is that contact with the water during the solution-mining process heals small
fissures and helps to prevent air leakage.
Salt also has disadvantages. One is the tendency to flow, or creep, when
exposed to high pressures over a period of time. The tendency is accelerated
by elevated temperatures and could cause a gradual reduction in cavern volume.
Salt creep is not entirely destructive, however, because it tends to heal
cavern fissures. Another potential drawback of these reservoirs is salt
carryover to the plant•s turbines, where it could result in system corrosion.
The Huntorf system is designed so that air velocities near cavern walls are
never high enough to carry brine droplets up into the turbines.
6.25
Key:
AIR RESERVOIR
~..,.....,......,..-.,-'""<"""'l"....,.-.:~~
C -Compressor
I -Intercoder
T -Turbine
M -Motor
R -Regenerative Heat Exchanger
CC -Combustor
T -Gas Turbine
M/G -Motor/Generator
FIGURE 6.3. Schematic for the Turbomachinery in a Conventional CAES Plant
The advantages of hard rock as a compressed-air storage medium include
the widespread availability of potential sites and a well-established excava-
tion technology. The major problem is the difficulty of knowing before
excavation whether the deep rock is suitable for caverns. Rock may be highly
fractured, requiring expensive shoring or site abandonment. Fissures in the
rock could also permit air to escape, and grouting the entire cavern may be
required. (Natural caverns are generally not considered for compressed-air
storage because of the difficulty of exploring, reinforcing, and sealing them
properly.) A hard-rock reservoir is more expensive to develop than a salt
cavern; mining is labor and equipment intensive, and large, expensive shafts
are required for excavation.
6.26
Sand, gravel, or sandstone aquifers, as with rock beds, are widely avail-
able in the United States and can be developed into compressed air reservoirs
without excavation. A series of wells is drilled into the aquifer, and air is
slowly injected, forcing the groundwater away from the well casing. During
air discharge, water pressure drives the air out of the well. High porosity
and permeability are necessary for rapid charging and discharging of the CAES
system through a reasonable number of wells. The aquifer must also have an
impermeable, dome-shaped caprock to prevent air from migrating upward and
escaping laterally.
The aquifer storage medium is not yet proven. Natural gas is commonly
stored in aquifers, but these aquifers are not subject to the daily cycling
that would be experienced with a CAES plant. Weakening of the aquifer matrix
may be a problem with CAES cycling and elevated temperatures. Aquifer
plugging may also prove to be a difficult problem with extended use.
The turbines generate electricity most efficiently when the incoming air
is maintained within a small range of pressures. Therefore, the air in the
cavern should be maintained at a constant pressure rather than at a constant
volume. In a hard-rock system, constant pressure is achieved by use of a
surface water reservoir connected to the bottom of the air storage cavern
through a J-tube (see Figure 6.4). The water column over the compressed air
is maintained at a constant height, exerting a constant pressure on the
compressed air. The compensating reservoir is unsuited to a salt cavern
because of dissolution problems. The reservoir is unnecessary for an aquifer
storage system because the displaced groundwater in the aquifer fulfills the
same purpose.
A conventional CAES plant reheats the air in an oil combustion unit
before it is expanded in the turbine. Advanced CAES configurations that would
eliminate this dependence upon petroleum fuels have been investigated. One
particularly promising technology is thermal energy storage. The heat of
compression is stored (rather than discarded in cooling towers) and recaptured
by the compressed air before expansion in the turbine. The heat recaptured
then reduces or entirely eliminates dependence upon fuels. The CAES plant is
no longer a net generator in this latter case, with an electrical input-to-
output ratio of about 1.5:1.0.
6.27
1
----------------------------,--,
! I ,
I I
i
,...-
I
COMF'EH:S~T I t1G I ! F:ESEPVO I P i
TUPBOr1~CH I t,lEPY 0 ,r\ I -~
\ l
'~ ,•
RIP SH~FT
I Cot·1PPESSED ~IR
-'
IJJ~TEF.: SHRFT
l .. '·, ~ ·.,..... ...~-~ .....
"'-. ... '·,,
W~TER
-
FIGURE 6.4. Component Plan for a Hard-Rock CAES Plant
Coal combustion technologies are also under investigation as an alter-
native to oil firing. However, coal gasification or pressurized fluidized bed
combustors would be required, and these technologies are not yet ready for
commercialization.
Performance Characteristics
The electrical input/output ratio of a conventional (reheat) CAES plant
is about .75:1.0. The reheat heat rate is generally about 4000 Btu (of reheat
fuel) per kWh out. CAES plants using regenerative heating arrangements are
expected to have an electrical input/output ratio of about 1.5:1.0. The
equivalent annual availability of CAES plants is estimated to be approximatly
90% (EPRI 1979b). A 30-year plant life is anticipated.
6.3.2 Siting and Fuel Requirements
Siting a CAES plant is a major task, with most of the effort expended in
the search for a suitable geologic structure. Hard-rock masses, salt domes,
6.28
!
'
--
and aquifers are abundant, but many geologic structures may be unsuited to
compressed air storage. Extensive literature searches and field investiga-
tions are necessary to identify and confirm prime sites. Construction of a
CAES plant in an unfavorable geologic setting can result in stability or
leakage problems, which are costly to correct. Availability of water, land,
transmission lines and transportation access are also important factors in the
site selection process. The CAES plant can be located anywhere on a trans-
mission line and need not be close to the generation source nor the load
centers.
The surface portion of a CAES plant is similar to that of more conven-
tional power plants, and the same topographic requirements exist. In addition,
a hard-rock CAES plant will require about 30 acres for a pressure-compensating
reservoir. An aquifer CAES plant will require many interconnected wells, and
the topography must be suited to the economic construction of a complex piping
system. A salt cavern CAES has no specialized surface requirements.
Water will be required for several purposes, including construction,
sanitary needs, cooling, and pressure compensation (hard-rock plant only).
Where feasible, a CAES plant will generally employ wet cooling for cooling the
compressed air (before storage) and the turbomachinery. Water will also be
required for solution mining of the cavity in a salt cavern CAES plant.
Transportation access (road, rail, or water) will be required during
construction, and during operation for fuel delivery.
6.3.3 Costs
Capital investment costs for CAES plants are site specific and depend
upon plant size, reheat technology, and the type of storage medium employed.
Significant economies of scale can be realized by increasing plant size from
200 MW (generally the smallest plant considered) to 1000 MW. Only minimal
scale advantages are foreseen for larger plants.
The cost of the aboveground equipment is highly dependent upon the
technology selected for reheating the air. Oil-or gas-fired units are the
6.29
least expensive. Other technologies, such as thermal energy storage and coal
combustion, will have considerably higher construction cost, but may result in
a lower busbar cost of power.
The cost of the air storage facility will depend upon the type of storage
facility developed and the storage duration required. In general, a hard-rock
cavern is more expensive than a salt cavern, and aquifer storage lies some-
where in between. Designs typically call for 8 to 11 hours of storage at full
plant output. However, weekly storage cycle may be selected, which would
require 20 to 30 hours of storage, and correspondingly higher capital cost.
No CAES plants have been constructed in the United States, so actual U.S.
construction costs are not available. The PEPCO plant (924 MW, hard-rock
cavern) has been estimated to cost about $550/kW in 1981 dollars. O&M costs
are expected to be about $8.50/kW/year (at a 20% capacity factor).
Adjusting these estimates to 1980 dollars and Alaskan conditions gives
the cost provided in Table 6.5.
TABLE 6.5. Estimated Costs of a Hard Rock CAES Plant (1980 dollars)
Electric Energy Cost
Rated Capacity Capital O&M (mills/kWh@ basel?ad
( MW) ($/kW) {$/kW/,tr} (a) energ,t costs shown} b,c)
20 40 80
924 690 10.70 54 67 94
(a) At 21% capacity factor.
(b) Assuming 1990 startup date; 30-year economic life; Cook Inlet Natural Gas;
incremental costs with 20 mill, 40 mill and 80 mill baseload power are
shown.
(c) Based on the use of Cook Inlet natural gas for reheat (Appendix B).
6.3.4 Environmental Considerations
The environmental impacts of a CAES plant depend upon the type of storage
medium employed. The most serious impacts may result from the construction
activities.
6.30
For a salt plant, the principal environmental impact and also the most
likely area of regulatory concern is with the disposal of the brine resulting
from the solution-mining operation. Each cubic meter of cavern will result in
7 to 10 cubic meters of brine. Brine disposal options include underground
injection, ocean disposal, and ponding/evaporation. Underground injection
generally is the most environmentally benign and the least expensive option.
Construction of a mined, hard-rock cavern poses the problem of disposal
and long-term care of the rubble excavated from the cavern. The amount of
material is significant; a 1000-MW plant would produce waste rock covering
40 acres to a depth of 17 feet. A continuing environmental problem of the
surface wastes most likely will be control of sediment in runoff. A sedimen-
tation pond may be required.
During operation, the major environmental impact would be air pollution
from the combustion of natural gas or oil for reheating the compressed air
before power generation. The impact should be similar to a gas turbine, but
on a lesser scale, since fuel consumption per unit of power output is about
one third that for a peaking oil-fired combustion turbine. Oil handling and
storage, although commonplace activities, also pose some threat to the
environment.
Alteration of groundwater quality is a potential environmental problem.
Aquifer CAES systems pose the greatest danger, but air escaping from hard-rock
or salt CAES storage caverns can potentially affect groundwater quality. Con-
taminants can be released from the rock matrix through the introduction of
oxygen and carbon dioxide or heat of compression. In aquifer systems, improper
casing or inadequate chlorination can pollute groundwater through the intro-
duction of micro-organisms. These potential effects are site specific and can
be minimized by proper site selection and design.
Impacts on wildlife habitat would be limited to the actual plant area,
and the vicinity. The turbomachinery is noisy, but any adverse impact can be
minimized by site selection and enclosure design. If the plant is located in
a remote area, increased traffic and dwellings could have a significant impact
on the terrestrial environment.
6.31
6.3.5 Socioeconomic Considerations
Construction of a large CAES plant is labor intensive, entailing from
150 to 300 men over a five-year period (depending upon the air-storage medium
and stage of construction). Subsequent operation of the plant is not labor
intensive and would involve only a few men. (The Huntorf plant is operated on
an unmanned basis.) The large differential in size of construction and ope-
rating crews may cause a boom/bust cycle in remote areas. A small plant would
have only minor socioeconomic impact near Anchorage, but decidedly greater
impact on intermediate and smaller sized communities.
A 1000-MW plant would affect all locations of the Railbelt with the
exception of Anchorage, and possibly Fairbanks. Construction camps would not
relieve the impacts to remote areas since the construction period (5 to
6 years) is long enough to create semipermanent settlement by the work force
dependents and secondary inmigrants.
An estimated 55% of the project expenditures would flow out of the region
and 45% would remain within the Railbelt.
6.3.6 Potential Application to the Railbelt Region
The key requirement for CAES is an adequate supply of low-cost, excess
baseload capacity that can be stored for peaking and intermediate load
generation. The outlook for CAES is good for many parts of the United States
with excess baseload capacity in a well-integrated system, and distinct
peaking power requirements. Presently, the Railbelt region does not have a
suitable baseload generating capacity to warrant consideration of CAES.
Several circumstances under which use of energy storage systems may
become feasible in the Railbelt region have been described in Section 6.1.6.
CAES could potentially provide energy storage capability for the first four
circumstances discussed (although storage would be central, not dispersed for
application in conjunction with dispersed wind, or solar units and therefore
would require a well-integrated transmission network). CAES would be less
suitable for providing dispensed system backup capacity. Key considerations
influencing the selection of CAES over competing energy-storage options
6.32
include 1) economics, 2) lack of suitable sites for pumped hydroelectric
storage and 3) availability of liquid or gas fuels for supplemental firing of
CAES combustion turbines. Development of a CAES facility depends upon the
availability of suitable geology.
6.33
6.4 OTHER ENERGY STORAGE TECHNOLOGIES
Several energy storage technologies have been conceptualized, and
recently, many of these have been the object of significant research and
development efforts. Those energy storage technologies that are currently
commercially available or show promise of near-term commercial application
have been discussed in the preceding section. Other, less developed storage
technologies include the following:
Hydrogen -Hydrogen can be produced by using off-peak electricity from base-
load plants to electrolyze or to decompose water. This hydrogen would be
stored and subsequently reconverted to electricity in a fuel cell or burned in
a gas turbine. Significant development is still required to improve the cost
and efficiency of hydrogen storage.
Flywheels -Electric energy can be converted into rotational energy stored by
a flywheel. This stored energy would then be used to generate electricity
during the peak demand hours. This method presently has limitations in its
energy storage capacity and efficiency, which preclude it from being
economically competitive.
Magnetic Energy Storage -Some conceptual designs have been developed for
magnetic storage units capable of storing the entire 10 hour output of a
1000-MW thermal plant. However, most of the work done in this area is
exploratory and conceptual. The main engineering problem foreseen in this
area is the design of superstructures capable of containing the mechanical
forces generated by the large magnetic fields. Also, this type of system is
expected to be economical only in large sizes.
6.34
7.0 FUEL-SAVER TECHNOLOGIES
11 Fuel-Saver 11 technologies supply energy to the power grid but typically
cannot be assigned capacity credit because of the intermittent or cyclic
availability of the energy source. Candidate fuel-saver technologies for
potential Railbelt application include the following:
• cogeneration(a)
• tidal power projects
• large wind energy conversion systems
• small wind energy conversion systems
• solar photovoltaic systems
• solar thermal-electric plants
• small-scale hydroelectric and microhydroelectric plants.
Capacity credit can be assigned to these technologies if energy storage
devices are provided, or, in some instances, if the level of penetration
permits assignment of capacity credit on the basis of statistical analysis of
energy availability.
A comparison of selected characteristics of the fuel-saver technologies
discussed in this chapter is provided in Table 7.1.
7.1
N
TABLE 7. 1. Comparison of Fuel-Saver Technologies on Selected Characteristics
Acsthel ic _ !!!!!~t'U~!!~~ vrsuar
Ho lse
Odm·
~acts on Hlota
-~:;:o·;;-WateTOSe ( \JPIR)
land Use(dJ (acres)
~!!-~.L!!L~nergt
Cap ita 1\1/kW)
O&H ( S/kW/yr)
Cost of f.ner9y
(mi lis/kWh)
~~'!1!\~~~!H.t ~-~ru•~t!
Un1t >izes 11Vailahle (i'!.j)
Cons Lruc t ion l.ead lime
(years)
Availability of Sites
~!i.~~j !.1\1.
Avail•hillty
Cogeneration
(20-HW, Natural{•)
-~-~team __ ~ys_I~_L __ _
Hlnor to Moderate
Hi nor
Hi nor to Sign if icantlcl
lBO
8
850
25
34 (typical)
Safe. Possible
long-term air
quality degradation.
lyp lea lly consurner
opera ted maybe by a
25-100
1-3
Oil Refineries
Hll itary Bases
lust itut ions
large Buildings
H5X
large Wind Energy
Convers ton Systems
.J!Q:I:.~ HW _tt~sh.l nes ) _
Moderate to Significant
Hi nor
Hi nor
Site-Spec if lc
Site-Spec lflc
2800-3600
50-70
50-80
Safe
Utilily operated.
46-2o,IOO
1
16 potentia 1,
3 prefen·ed sites
In Cook Inlet.
40X
Sign if I cant
Hlnor to Moderate
Hnne
0
1225
1500
13-22
54-72
Safe
Uti I Hy or· co!nuun lty
operated.
0.1-2.5
3
limited to few rnoun-
ta In and coasta 1
s ltes having
favorable wind
res(J
81%
Small Wind Energy
Convers ton Systems
t!!.J!!.:!!!. Stand:_A.l!!.!~ .. l!!U!J
Moderate
Hi nor
Hone
0
l/4
2000
20
46-91
Safe
Co!llnun ity or consumer
operated.
0.0001-0.031
1-2
Sites limited to acres
of favorable wind
resources.
Kat available.
Solar
Phutovo Ha ic
! !!!.:.~. ~~~!. i'!•!L
Significant
Hi nor
Hi nor
0
50
11 ,ooo(d)
30-1o(d)
620(d)
Sale
Various size lnstdllatinns
could range from conswoe.--
operated rooftop arrays to
ut 11 tty-operated contro I
systems.
<0.001-10
1-2
Wide availability of poten-
tial sites. No specific
sites identified.
40X
Solar
lhenua I
(IQ ~~l.
S lyn If icant
Minor
flinor
150
?00
1500
40
91
Safe
5ma 11-Sc.lle
llydnH!lectr lc: Project
_mMI!l
Hot1Hrt1 te
Hi nor
Hone
Hulk of stredmf low
passed throuqh turll ine.
SHe spPciflc,
to's to IOO's.
800-20,000
16-~00
10-760
Utility operated. IJLillty, cuntnunity or
COI\Sumer operated.
10-)0()
5
Nn specific sites
Identified.
<().! -15
2-4
Sites I imiled to
stn~iJms having favorahle
dis charge, topography
aru1 qeo logy.
Not ava i )dble.
TABLE 7 .1. (Contd)
Large Wind Energy Small Wind Energy Solar Cnyenerat ton
(20-HW, Natural
_ _!!!~ ~~~'!!!-~!&~~~ ____ Tid<t!(_b_l ___ _
Conversion SystelllS Conversion Systems Photovo I talc
{10-2.5 MW_Hachln!!l_ tJ!~ Stand:~~\!1 _______ l!Q.:_~_j_t_~~!!!!!l.
E_!l!end I lures Within Alaska -ciiPITiil ___________ _
O&M
fuel
Bomn/Bust Effects ·-·conStructrOOPersonne 1
Operat lng Personne I
Ratio
Magnitude of Impacts
JJX
BJX
IOOX
30
15
2: I
Hin<r to moderate
In all locations.
Consumer Contra 1 led.
Contnercially available.
Widespread district
heating •PP Heat Ions.
67X sgs
300
30
10:1
Minor In vicinity of
Anchorage. Significant
to severe In all other
locations.
Contro 1 through
regulatory agencies.
20X
S5X
12
0
Ml nor to moderate
In all locations.
Contro 1 through
regu Ia tory ogene les.
Conmerclally available Commerical demon-
but not mature. stratton stage.
Hone Limited (two small
wind farms).
Hot available.
Hot available.
4
0
Minor In all locations.
Customer contro lied.
Conmerc Ia lly avail-
able.
Limited (two small
wind farms pIus
scattered Individual
Installations).
1gs
SIX
100
10
10:1
Utility-scale Installations:
Minor In vicinity of
Anchorage & fairbanks;
moderate to severe In all
other local tons. Dispersed
Installations: oninor.
Range of poss lb le ownersh lp-
utillty to lnd tv ldual.
Cononerclally available hut
not fully mature.
No utility-scale installa-
tions.
(a)
(b)
(c)
(d)
Cogeneration Is treated as a fuel saver bec•use operation of a cogeneration facility depends upon the operation of the associated Industrial pl•nt
or district heating facility.
Allr lbutes generally do nut depend on s lze.
If municipal waste is usetJ as fuel.
1980 techno logy.
Solar
Therma 1
_ ___ l!Q !!!L --
19X
SIX
60
25
2.5:1
Utility-scale
lnst alia tions:
oninor In vicinity
of Anchorage &
fairbanks; mod-
erate to severe
In all other
lor. at Ions.
Regu Ia tory
agenc 1es.
Research and
developmental
stage.
Hone.
Small-Scale
Hydroe lee tr ic Pro.Joc I.
____ l!L"!Wl ..
40X
90S
20
4
5:1
Minor In all locations
e<eepl smallest
communities.
Contra 1 through regu-
latory agencies for
utlllty-oper•led facil-
Ities. Comoounlty or
customer contra I for
municipal or Individually
owned plants.
Commercially available.
l.imlted (one small-scale
hydro faclllt_y).
7.1 COGENERATION
Cogeneration is the simultaneous production of electricity and useful
heat. The heat can be distributed as steam or hot water to commercial and
residential users in district heating systems or can be used for industrial
process heating applications. Opportunities for cogeneration occur when
large, stable demands for heat and electricity occur simultaneously. Typi-
cally, the demand for heat becomes the driving variable. Cogeneration oppor-
tunities exist only with industrial or commercial development. Cogeneration
capacity can be expanded simultaneously with increases in industrial capacity.
A major barrier to the development of cogeneration was removed with the pas-
sage of the Public Utility Regulatory Policies Act of 1978. The Act essen-
tially allows industries and other nonutility generators to sell power to a
utility at a fair market value.
Cogeneration systems generally range from 25 to 100 MW, although high
electricity costs prevail in locations where the 5 to 25 MW range is becoming
economical. Cogeneration systems are generally smaller than condensing
steam-electric power plants because of their tie to manufacturing facilities,
although systems in the 100 to 400 MW range have been designed and built for
large manufacturing complexes.
7.1.1 Technical Characteristics
Cogeneration facilities are classified as those using 11 topping 11 cycles
and those using 11 bottoming 11 cogeneration cycles. Both exist commercially,
although the topping cycles predominate. Topping cycles capture available
energy at temperatures above those required for process or space heat applica-
tions and are used at installations whose primary purpose is to produce low-
quality heat for process or space heating applications. Three topping cycles
are available: 1) steam turbine topping, 2) combustion turbine topping, and
3) diesel generator topping. Cycle selection is usually determined by rela-
ti ve power and
system design.
level heat and
steam demand, fuel availability and cost, and process heat
Bottoming cycles are used to capture otherwise rejected low-
to convert this heat into electric power. Bottoming cycles can
7 .4
use waste heat from high-temperature process heating systems or waste heat
rejected from thermal generating plants. Bottoming cycles generally use
large, low-pressure condensing turbines.
Cogeneration systems exhibit high thermodynamic efficiencies in compari-
son to condensing power cycles. Heat rates in cogeneration typically range
from 4,200 to 6,500 Btu/kWh. Comparable heat rates for condensing power
plants are typically 9,000 to 11,000 Btu/kWh. The higher efficiencies result
from the ability to capture heat otherwise rejected. The high efficiencies of
cogeneration systems, other than diesel, depend upon operating at full loads.
Turbines are quite inefficient when operated at less than 70 to 80% of
capacity.
Steam Turbine Topping Cycle
In the steam turbine topping cycle, as depicted in Figure 7.1, high-
pressure/high-temp.erature steam is raised in the boiler, is passed through a
noncondensing turbine, and is exhausted at or near process conditions to the
process steam header. The exhaust steam is then used for process purposes.
Power production comes from the differences in energy content of the steam
between turbine inlet (throttle) and exhaust. As throttle pressure is
increased and exhaust pressure is decreased, the power generation/steam pro-
duction ratio is increased.
System capacity is generally determined by manufacturing or space heating
steam needs. Manufacturers with requirements for only one steam quality(a)
use simple, back-pressure turbines. Where more than one type of steam is
needed, multiple-point, automatic extraction turbines are used.
The overall efficiency of electrical cogeneration is determined by boiler
efficiency plus turbine-generator heat rates. For example, a typical small-
scale, wood-fired cogeneration system as used in a sawmill has a heat rate of
6000 Btu/kWh and an overall efficiency of 65%. A comparable coal-fired unit
would have a heat rate of 4200 to 4500 Btu/kWh, and an overall efficiency of
about 85%.
(a) Steam quality refers to the pressure and temperature characteristics of a
given steam supply.
7.5
STACK GAS
I
AIR BOILER
HIGH
PRESSURE
STEAM
~ BOILER FEEDWATER
1--~1/JooASH
ELECTRICITY
GENERATOR
PROCESS
STEAM
FIGURE 7.1. Simplified Schematic of Steam Turbine Topping Cycle
The primary advantage of the steam cycle is its ability to use virtually
any fuel directly. Solid fuels such as coal, peat, biomass, and organics can
be employed as well as liquid and gaseous hydrocarbons. A second advantage is
the manufacturing community•s familiarity with boilers and their operation.
This cycle is employed at the University of Alaska.
Combustion Turbine Topping Cycle
Combustion turbine topping cycles, as shown in Figure 7.2, integrate a
combustion turbine and a heat recovery boiler to simultaneously produce elec-
tricity and steam. Combustion turbine topping cycles may also be used to pro-
duce warm process air, such as for drying operations, by passing the turbine
exhaust through an air/air heat exchanger.
Combustion turbine technology is described in Section 5.1. The second
major component of the system is the heat recovery boiler. These components
are typically finned watertube boilers accepting turbine exhaust gases at
about 900°F and exhausting them at 350-450°F, depending on the quantity of
so 2 in the exhaust stream. An economizer for feedwater heating is typically
added to remove additional heat from the stack gas (Figure 7 .2).
7.6
t
LIQUID OR
GASEOUS FUEL
AIR ELECTRICITY
GENERATOR
TURBINE STEAM TO
EXHAUST HEAT PROCESS
'-------~~ RECOVERY 1-----t-.
BOILER
~--~~--~STACK
GAS
ECONOMIZER f-------4 ...
FIGURE 7.2. Simplified Schematic of Combustion Turbine Topping Cycle
Producing Process Steam
The primary advantage of a combustion turbine cycle is the high elec-
trical power/steam ratio. The power/steam ratio for combustion turbines may
be up to four times that of steam topping cycle turbines. It is also less
costly because of the possibility for constructing boilers without expensive
feedwater treatment systems, pressure parts, and extensive superheaters. The
overall efficiency of combustion turbine topping cycles also is about the same
as that of steam turbine topping cycles. Typical heat rates (i.e., that por-
tion of the heat rate used to produce electric power) range from 5000 to 6000
Btu/kWh.
A potential drawback of combustion turbine topping cycles is the petro-
leum-based or natural gas fuel requirements of combustion turbines. Natural
gas and distillate oil are the preferred fuels, although heavier oils have
been used, and such synthetic fuels as medium Btu gas (e.g., 350 Btu/ft 3 )
and methanol have been proposed. However, solid fuels such as coal, peat,
7.7
biomass, and municipal waste cannot be used unless gasified.
from solid fuels must be upgraded to optimize the power cycle.
The gas produced
Development of
low Btu gas turbines is proceeding, however, to take advantage of low Btu
synthesis gas.
Diesel Generator Topping Cycle
Diesel topping cycles are similar to combustion turbine topping cycles.
Diesel generator sets are used to generate electricity with exhaust gases
being used to raise steam or to produce hot water in waste heat boilers.
Diesel generator topping cycles may be used in institutional and high-density
residential installations ("total energy systems") where the electricity is
used for the house load with surplus sold to the utility and the stream or hot
water is used for space heating. These cycles also may be appropriate for
smaller manufacturing establishments such as seafood processing plants.
Diesel generation, which has been described in Section 5.3, has three
potential advantages over combustion turbine-based systems: 1) the higher
power/steam ratios, typically twice those of combustion turbines; 2) the abil-
ity to be used at small (e.g., <1 MW) scale; and 3) the ability to operate
efficiently on partial loads. These advantages may be particularly signifi-
cant in smaller communities within the Railbelt particularly those communities
amenable to a hot water district heating system.
Diesel generation requires the premium gaseous fuels or oil required by
combustion turbine systems. Low Btu synthesis gas from coal and biomass has
been used successfully in diesel equipment; however, this use results in
substantial derating of the equipment.
Bottoming Cycles
Currently available bottoming cycle technology converts reject steam into
electricity by using large, specially designed condensing turbines that can
handle saturated steam. The cogeneration concept is illustrated in Fig-
ure 7.3. Water rates(a) for these turbines are high. For example, a
(a) Water rate refers to the amount of water required to be circulated through
the turbine (as steam) to produce a given amount of electrical energy.
7.8
STACK GAS
-~
BOILER
PROCESS
STEAM
---f' f-----. I
PROCESS
ELECTRICITY
STEAM
BOILER " ~
1 .. ~----· F;..;E;.;;;E;;;;.D..;.;W..;..:.4.;..TE;;..R_-i:J CONDENSATE ~~-~----
~~----~~-~~ASH CONDENSER
FIGURE 7 .3. Simplified Schematic of a Bottoming Cycle
turbine accepting 65 psig steam and condensing at 3 inches of mercury has a
water rate of approximately 25 pounds of steam per kWh. With a lower vacuum,
water rates increase.
Performance Characteristics
The electrical heat rates of cogeneration installation depends upon the
basic combustion technology used and the quality of steam or hot water drawn
off for process or district heating use. Typical heat rates are discussed
under the specific cogeneration technology headings above.
Cogeneration plant availability is similar to the availability of the
combustion technology upon which it is based. Actual capacity factors, how-
ever, are frequently dependent upon the demand for process or district heating
energy.
Plant lifetimes are similar to those of the basic combustion technology;
however, shorter lifetimes could be anticipated for retrofit of an existing,
older manufacturing facility.
7.9
7.1.2 Siting and Fuel Requirements
All cogeneration systems must be located at or near steam or process heat
users. Typically, the cogeneration system will be located on the manufac-
turer's premises, although some have been located up to 1 mile away. Systems
producing heat for district heating must be located close to heating loads,
although hot water generally can be transported over longer distances than
steam. Since cogeneration systems are usually located at or near manufactur-
ing or high-density, commercial-residential heat loads, they are also located
near electrical load centers. Proximity to fuel sources is not required
unless the fuel can not readily transported over long distances, which would
apply more to biomass fuels than to fossil fuels.
Fuel requirements for cogeneration systems are determined largely by
cycle type, as discussed in Section 7 .1.1. Steam turbine topping and bottom-
ing cycles can be fueled by virtually any combustible energy source. Combus-
tion turbine and diesel topping cycles, however, require premium liquid or
gaseous fuels (e.g., distillate oil, methanol, natural gas).
Quantities of fuel required for electricity generation are determined by
the heat rate (Btu/kWh) for given plants. Heat rates are determined by sev-
eral site-specific variables. Typical values for cogeneration facilities are
normally in the 4500 to 6500 Btu/kWh range depending on cycle, power/steam
ratio, process steam conditions, and other parameters.
7.1.3 Costs
Cogeneration project costs are site specific. Costs vary substantially
as a function of manufacturing requirement, the cycle employed, and conditions
at the site. Representative capital costs for a range of sizes are shown in
Table 7.2.
O&M costs depend on cycle, capacity, and degree of system complexity. An
additional variable is the availability, at the site, of operators having the
necessary operation and maintenance skills. For example, at refineries main-
tenance can be accomplished by existing plant crews. For many applications,
however, a special maintenance crew must be hired. Labor and maintenance
costs are somewhat higher for steam turbine systems than for combustion
7.10
TABLE 7.2. Representative Capital Costs for Selected
Cogeneration Cycles (1980 dollars)
Steam Combustion Diesel
Turbine Turbine Generator
Topping Topping Topping
Rated Cycle( a) Cycle Cycle
Ca~acit~ {MW} {$/kW} {$/kW} ($/kW)
3 1,470 760 800
5 1' 180
10 850
20 850 550
75 400
(a) Assumes natural gas-fired boiler.
turbine systems, primarily because of the complex water circuit. However, if
synthetic fuel systems (e.g., low Btu gasifiers) are tied to combustion tur-
bines, this differential may disappear. Representative values for O&M costs
would be about $25.00/kW/yr. Estimated costs for a typical, natural-gas-fired,
steam turbine topping cycle are provided in Table 7.3.
Despite the complexities and costs of cogeneration, the price of power
from such systems is generally lower than that of condensing power stations.
The power price is lower mainly because cogeneration is more efficient in the
generation of electricity, and thus the quantity of fuel consumed/kWh is less.
Much of the capital investment can be charged against the process steam pro-
duction, and the power generation cycle can be treated as an incremental
investment; therefore, many of the operating costs can be treated in incre-
mental fashion. Cogenerated power costs are generally less sensitive to ris-
ing fuel prices than condensing power cycles because of the highly favorable
heat rates associated with cogeneration systems.
7.1.4 Environmental Considerations
Conversion of an existing industrial facility to cogeneration would
generally produce minimal incremental impacts on an area's water resources
because most makeup water requirements, effluent discharges, and appropriate
treatment facilities would be accounted for in the existing facility.
7.11
TABLE 7 .3. Estimated Costs of a Representative, Natural Gas-Fired
Steam Turbine Topping Cogeneration Cycle
Rated
Capacity
(~)
20
Capital(a)
($/kW)
850
O&M(a)
($/kW)
25
Cost of Electric
Energy( b)
(mills/kWh)
34
(a) Incremental costs for electric plant equipment.
(b) Levelized lifetime cost, assuming 1990 first year of
commercial operation. 65% capacity factor, Cook Inlet
natural gas (prices given in Appendix B).
With a steam topping cycle, a small increase in boiler feedwater and
boiler blowdown requirements could be expected. In addition, a slight
increase in ash handling requirements could possibly add to water require-
ments, depending upon the ash handling system design. However, a slight
decrease in overall plant-makeup water requirements could result because of
increased condensate recovery.
A bottoming cycle will increase the steam requirement as much as three to
four times per kWh compared to a conventional condensing plant. Cooling water
requirements would increase correspondingly. Boiler feedwater and blowdown
would remain essentially unchanged from the original facility.
Potentially adverse water resource impacts of constructing and operating
a cogeneration facility are generally minimized through appropriate plant
siting and water, wastewater, and solid waste management programs (refer to
Appendix D). Water resource impacts that are difficult to mitigate are not
anticipated with the development of cogeneration facilities, especially in
light of small power plant capacities that are considered.
Any of several possible atmospheric impacts may be associated with the
development of cogeneration facilites. These impacts occur because many dif-
ferent fuels, processing systems, facility sizes, and combustion techniques
may be used. For existing facilities, the incremental air-quality impacts
resulting from cogeneration systems are probably negligible unless a great
deal of additional fuel is consumed. These systems use heat or power that has
7.12
already been generated for other purposes, and they extract a portion of the
available energy for electric power generation. Cogeneration typically may be
characterized as having a very low atmospheric impact when compared to other
combustion systems.
New cogeneration facilities will require an extensive review of air-
quality impacts, especially for the larger (>25 MW), more economically viable
systems. Emissions from coal and biomass combustion facilities will be greater
than those of oil and gas combustion facilities. Incremental impacts attri-
butable to electricity production may be considered minimal because the emis-
sions basically are associated with the industrial process or system to which
the cogeneration facility is attached.
Converting an existing steam production facility to a cogeneration system
is not expected to result in significant incremental impacts on aquatic or
marine ecosystems. Additional water requirements are minimal. Moreover,
steam bottoming cycles reduce waste heat rejection to the aquatic environment
compared with noncogeneration facilities. The aquatic ecosystem impacts of
constructing and operating a complete cogeneration facility would depend upon
fuel and process type and would be similar to those experienced with compar-
able, steam-cycle facilities (refer to Appendix F).
Incremental terrestrial ecosystem impacts associated with adding elec-
trical generating facilities to an existing steam plant will be minimal.
Generally, few additional acres are required. Although slightly greater
amounts of air pollutants may be produced when compared with the processing
plant alone, impacts on the terrestrial biota should generally be negligible.
Impacts of constructing and operating a complete cogeneration facility would
depend upon fuel and process type, but would be similar to those experienced
with comparable, steam-cycle facilties (refer to Appendix G).
7.1.5 Socioeconomic Considerations
Several potential sites for cogeneration have been identified in the
Railbelt. The refineries located in Kenai and Fairbanks are prime potential
sites for cogeneration as well as the proposed refinery at Valdez. Other
7.13
potential sites are located primarily in Anchorage and Fairbanks and includes
industries, military installations, universities, hospitals, and large apart-
ment complexes.
The size of the construction work force will vary from 25 to 250, depend-
ing on plant scale. Assuming that a maximum plant size of 100 MW requires a
labor force of 250, the impacts of construction should be minor in the
Anchorage area and moderate in the Fairbanks area. Although both Valdez and
Kenai have experienced the influx of large work forces from the construction
of a pipeline terminus and oil refineries,' both communities have relatively
small populations (3173 and 4326, respectively). A boom/bust cycle can be
avoided in these communities by installing construction camps.
Capital expenditures of a cogeneration facility would flow primarily out
of Alaska because of the amount of equipment compared to the moderate-sized
work force and relatively short construction time. The estimated percentage
breakdown of project investment is approximately 67% outside of Alaska and 33%
within the state. Due to the relatively large outside maintenance require-
ments, 17% of the O&M expenditures would be spent outside the Railbelt.
7.1.6 Potential Application in the Railbelt Region
Significant potential exists in the Railbelt for cogeneration. The two
oil refineries on the Kenai Peninsula, the refinery outside Fairbanks and the
proposed Alpetco refinery at Valdez (Figure 7.4), have the most potential for
cogeneration in the Railbelt region. Generally, oil refineries have a poten-
tial for producing 11-12 kWh/bbl; of that, 50 to 67% would be in excess of the
producing facilities• needs and available for transfer to the utility grid
(Gyftopoulos, Lazaridis, and Widner 1974). Current production capacity has a
potential for developing approximately 50 MW at existing refineries. About
210 million kWh/yr of saleable energy could be produced assuming that adequate
demand for power exists and the refineries operate at an annual load factor of
80%. The proposed Alpetco refinery had the potential to generate approxi-
mately 300 million kWh/yr. In the Railbelt region other petroleum-related
activities with cogeneration potential include oil pipeline pumping stations,
natural gas pipeline pumping stations, and natural gas liquefaction (LNG)
facilities, if such plants are developed.
7.14
Outside the petroleum industry, manufacturing focuses on lumber and fish
processing. The 51 lumber mills in the region are small (e.g., 1000 board ft/
day) and are well below the scale required for cogeneration. The fish pro-
cessing industry has little potential for cogeneration (Resource Planning
Associates 1977), although some cogeneration may be occurring in these
industries (U.S. Bureau of Census 1978).
Industry in the Railbelt currently generates 414 million kWh/yr and
military installations generate 334 million kWh/yr. This generation repre-
sents a combination of self-generated power and cogeneration. The University
of Alaska, for example, generates 22 million kWh/yr using a steam topping
cycle system. The combined 748 million kWh of self-generation represents 24%
of the total 3,140 million kWh generated in the Railbelt region in 1980.
Hospitals, large apartment complexes, and other institutions in Anchorage,
Fairbanks, and Valdez provide potential for central space heating systems
fired by cogeneration (total energy systems).
7 .2 TIDAL POWER
Tides are caused by gravitational attraction of the moon and sun. Both
the daily and annual positioning of the earth, moon, and sun affect the tides.
The full tidal cycle (peak-to-peak) is about 12.9 hours.
The variation of open sea tides is only about 2 ft, but as tidal flows
travel across the shallower water of a continental shelf, the open ocean fluc-
tuation is amplified by shoaling effects. By the time the tidal flow reaches
the coast, the surface level variation is amplified three or four times. Fur-
ther amplifications occur in certain estuaries where level variations increase
by another factor of two to four. Tidal fluctuations may be used to provide
energy for direct use or for electric generation.
Tidal mills were used as early as medieval times in the estuaries of
Britain and France. Dutch colonists built a tidal power grinding mill in
Brooklyn, New York in 1617. Early versions of tidal mills worked as simple,
undershot water wheels. Sea water was contained at high tide by wooden flaps
7.15
and released to drive the water wheels when the tide fell. These plants were
cumbersome and inefficient, but they could be relied upon when river mills had
ceased to function in periods of drought.
Tidal-electric power has thus far been developed at only two sites: the
Rance Project (240 MW) on the northwest coast of France, and the Kislogubsk
tidal power station (0.4 MW) on Kislaya Bay, USSR (Cotillan 1974). Develop-
ment of tidal power plants has been slow because the technology for low-head,
high-discharge turbomachinery is still being developed. In its present state
of development, the low-head reversible hydraulic turbine is easily controlled
and long lived, but is neither compact nor highly efficient.
Cook Inlet is one of the few sites in the world with significant tidal
power potential. A reconnaissance study sponsored by the State of Alaska
identified sixteen potential tidal power sites in Cook Inlet ranging in size
from 46 to 25,100 MW installed capacity (Acres American Inc. 1981a).
The underlying principles of tidal power plants are similar to those of
hydropower. The electrical energy that can be developed at any tidal site
depends on several interrelated factors, including usable head (which varies
continuously with tidal fluctuations), area of the tidal basin, capacity of
sluiceways to fill the basin, capacity of turbine and generating units, and
mode of operation.
Tidal power•s major benefit is that, like hydropower, the plant operation
uses a renewable energy resource. The primary disadvantage is that elec-
tricity generation depends on the cyclical pattern of tides. Since tidal
power plants can provide only intermittent energy, either backup generating
capacity or a complementary storage technology such as hydro pumped storage
must be available to meet load.
7.2.1 Technical Characteristics
Tidal power projects consist of one or more reservoirs (or basins), a
barrage, a switchyard and transmission lines. A typical tidal power project
is depicted in Figure 7.5. The barrage usually consists of a powerhouse, a
sluiceway section, and dike or dam connections to shore, thus forming a con-
trolled tidal basin. The powerhouse contains turbines, generators, control
7.16
.,LJJ
~vii!Jo~,JJ~
;S,E~~IN<4, Wf~t
7
...
.. ~'' r.sr.owr ..,,.. j
!
1\A.,HUl!lollH
M'lddleton J
PETROLEUM REFINING IN THE
RAILBEL T AREA
in Barrels Per Day
(Bbi!D)
SOURCE: "Petroleum Refineries in the U.S. and
U.S. Territories." DOE/EIA 0111 (80)
\• ·~·-..... -~ ,AoD"·
SCALE 1: 2 500 000
NATIONAL GEODETIC VERTICAL DATUM OF 1929
ALASKA RAILBELT
REGION
USGS ALASKA MAP E
FIGURE 7.4.
7.17
Petroleum Refining in
the Railbelt Region
BARRAGE
SEA
BASIN
SCALE 0 500 1000 ft.
FIGURE 7.5. A Typical Tidal Power Plant
and switching apparatus, and transformers. Additional components may include
trash racks on both sides of turbine water passages, concrete forebays, and
tailrace approaches. Existing tidal generating plants range in size from less
than 1 MW to 240 MW. Generating efficiencies are about 60%. Outage rates
would likely be similar to conventional hydroelectric plants. Typically,
conventional hydro plants would experience a 5% forced outage rate, 1 1/2%
scheduled outage rate and 94% equivalent annual availability. Because of the
modular design of a tidal power plant, full outages would be unlikely. Plant
life would be 50 to 100 years.
Tidal power is a relatively inflexible technology for the following
reasons:
• Because power generation is a function of cyclical tidal character-
istics, demand occurring out of phase with the tides cannot be
accommodated without retiming facilities such as pumped storage
plants.
• Full power is only available at maximum tide levels.
• Without retiming, tidal power plants have no dependable capacity;
i.e., the plant cannot serve a continuous load over extended
intervals of time.
Because of these characteristics, tidal power developments must be used in
conjunction with complementary cycling generating capacity or energy storage
systems. An alternative approach to compensate for the intermittent nature of
tidal power generation would be to incorporate pumped storage in the project
to artificially prolong the natural tidal cycle. A tidal pumped storage
facility still must be complemented by flexible load plants, such as pumped-
storage, hydroelectric, or cycling thermal plants. Certain industries capable
of using the intermittent power of a tidal plant have been proposed for devel-
opment in conjunction with tidal facilities to better use the intermittent
energy production of tidal plants.
Refinements in equipment technology and construction procedures are
necessary to accelerate commercialization of this technology. Specific
obstacles to the development of tidal power technology have included limited
7.20
availability of low-head turbogenerator units and the difficulties and expense
of barrage construction. Recent renewed interest in low-head hydropower
development is helping to spur the manufacture of low-head turbogenerator
units. In addition, the cost of construction can be reduced through the
development of prefabricated barrage sections. For example, power house and
sluiceway modules may be prefabricated in drydocks, or on slipways. Each
module includes a horizontal water duct incorporating an intake, space for a
turbogenerator set, and a draft tube (Figure 7.6). Provision for two or more
turbogenerater sets might be incorporated in a single module. Modules are
then floated to the barrage site and sunk at slack water level onto dredged,
level, rock-rubble foundations. Similarly, sluice gate sections could be
prefabricated, floated to the site, and installed. This prefabrication method
was used to build the tidal-power station at Kislaya Bay, USSR (Bernstein
1974). Design and construction periods for a tidal electric plant would be
lengthy. A seven-year preconstruction period and an eleven-year construction
period were estimated for the Eagle Bay site studied in Acres American (1981a).
7.2.2 Siting Requirements
Three site conditions are necessary for an economically viable tidal
power development: 1) a mean tidal range of about 20ft or more, 2) an
estuary or coastal indentation that, when dammed, will not substantially
reduce the tidal range, 3) shoreline configuration permitting use of a reason-
ably short barrage, and 4) an interconnected electrical generating system
capable of supplying capacity during slack tide periods. Without any one of
these three prerequisites, a tidal energy development will probably be pre-
cluded, although the latter constraint can be overcome by constructing a
complementary energy-storage system.
Foundation conditions should be level hard rock, although shallow sedi-
mentary deposits overlying level hard rock can be accommodated. Sharply
irregular or deep, porous sedimentary foundations should be avoided. Ideal
sea depths are about 60 to 100 ft.
7.2.3 Costs
Reconnaissance-level cost estimates have been prepared for the three Cook
Inlet sites selected in the Acres American reconnaissance study (1981a) as
7.21
TYPE A-BULB TYPE TURBINE, DIRECTLY COUPLED GENERATOR
-----~-----
TYPE B-BULB TYPE TURBINE, GEAR COUPLED GENERATOR
TYPE C-TUBE TURBINE, DIRECTLY COUPLED GENERATOR
. .
TYPE D-STRAIGHT·FLOW TURBINE WITH RIM GENERATOR
FIGURE 7 .6. Types of Turbine/Generator Sets for a Tidal Power Plant
having the best prospects for development. A summary of estimated costs for
these three sites is provided in Table 7 .4.
7.2.4 Environmental Considerations
The placement of a barrage to harness tidal power separates a natural
embayment into two artificial basins. This separation can cause major changes
in the water circulation patterns of the unrestricted outer basin. The pre-
sent hydrologic regime of the Knik Arm of Cook Inlet, the prime tidal power
candidate site, is governed by large tidal fluctuations in this shallow, narrow
7.22
TABLE 7.4. Representative Cost Estimates for Tidal Power Plants(a)
(1980 dollars)
Cost of Energy(c)
Rated Current 1~
Capacity Capita 1 O&M(b) Raw Useable d
Site {MW} {$/kW} {$/kW/~r) {mills/kWh} {mi 11 s /kWh)
Eagle Bay 720 3587 72 53 80
Eagle Bay 1440 2466 49 44 111
Point McKenzie 1260 3051 61 50 123
Rain bow 928 2820 56 49 97
(a) All costs except those indicated from Acres American (1981a) were
discounted to July 1980 using total Hydro Production Plant, Pacific
Region, Handy Whitman, 1982.
(b) Not provided in Acres American (1981a), estimated at 2% of total
investment cost.
Retimed(e)
{mills /kWh}
70
73
76
71
(c) As calculated in Acres American (1981a), discounted as described in (a) to
July 1980. Financial assumptions used are similar to those used elsewhere
i n t h i s rep or t.
(d) Based on energy that could be absorbed by current Railbelt electric energy
system without retiming.
(e) Assumes retiming using pumped-storage hydro.
basin. Because of this characteristic, waters are well mixed laterally, longi-
tudinally, and vertically with each tidal cycle. In summer, a net outward
movement of inlet waters occurs, caused by large inflow of glacial meltwater
from tributary streams, whereas in winter with reduced runoff, practically no
net outflow occurs (U.S. Army Corps of Engineers 1972).
With development of a tidal power project, tidal flow would no longer
move uniformly up the Knik Arm but rather through sluice gates and reversible
turbine locations. The circulation and mixing patterns of this basin would be
greatly affected. Waters would probably not be as well mixed and lateral
separation could be expected. Also, the amount of water exchanged between the
Knik Arm and the Upper Inlet would be reduced. This aspect would decrease
Knik Arm's flushing rate. The net movement of water out of the Upper Inlet
would also be affected by the reduction in water exchange, although the
magnitude of this impact would depend upon the plant's specific design
characteristics.
7.23
Circulation and flow patterns in the mid-Inlet and 11 outer 11 upper Inlet
could also be affected. At present, this area is characterized by a net
inward movement of saline oceanic water up the eastern shore and a net outward
movement of fresh water runoff from the Knik Arm and the Susitna River along
the western shore. These water masses are well-mixed vertically, but lateral
separation is maintained throughout the mid-Inlet (U.S. Army Corps of Engineers
1972; Science Applications Inc. 1979). The phase shift of outflow from the
Knik Arm would affect this pattern, but the magnitude of the change would
probably not be significant because of the relatively small freshwater contri-
bution of Knik Inlet tributaries. If, however, the tidal power project encom-
passes both the Knik Arm and the Turnagain Arm or if the project is coupled
with a Susitna River energy development project in the future, significant
changes in Cook Inlet circulation patterns would be likely.
These alterations in flow patterns would probably lead to water-quality
changes. Pollutants, such as treated sanitary waste from facilities in
Anchorage, Eagle River, and Palmer, are discharged into the inner bay. The
decrease in flushing and subsequent increase in residence time would increase
pollutant concentrations. Constricting the water flow to a few intake and
outlet conduits also would alter the spatial distribution of these pollutants
and other biologically important substances such as nutrients. While the
water quality of the area is generally considered acceptable, high concentra-
tions of nutrients, organic material, and iron can be experienced, especially
during spring and summer runoff (Selkregg 1974; U.S. Army Corps of Engineers
1972). Depending upon the specific reduction in flushing rate and mixing,
localized water-quality conditions could become problematic.
The modification of a natural embayment to a controlled basin also changes
the marine environment from a high energy area to a low energy area. This
change would especially affect sediment distribution and movement. The dam
would act as a sediment trap so that the large sediment load derived from the
Knik and Matanuska Rivers would no longer easily move seaward with the tides
but would accumulate at a faster rate in the inner bay. This could change
sediment transport and shoaling patterns in the entire Inlet, and possibly in
the area of the Palmer Bay Flats and Eagle River Flats.
7.24
Water transportation may also be affected by tidal power projects that
obstruct navigable waters. This problem can be overcome with locks, which
then places constraints on the number of boats traveling to and from an
estuary. This could be significant to the traffic entering the Port of
Anchorage, but depends upon the specific location of the barrage.
No impacts on air quality or meteorological resources will result from
the development of tidal-electric power generation facilities.
The major potential impact on aquatic ecosystems for a tidal power plant
located on the Knik Arm of Cook Inlet would be restricted movement of aquatic
organisms, such as salmonoids, larval shellfish, and plankton, and the
increased mortality of these organisms when they pass through the turbines.
Of particular concern are the major salmon runs that pass through Knik Arm
into several major streams, including Fish Creek, Eagle River, Ship Creek,
Knik River, and the Matanuska River tributaries (Alaska Department of Fish and
Game 1978). In addition to salmon, smelt pass through this area to the Knik
River to spawn. These fish are not only important commercially but also
supply sport fishing in many of these streams (U.S. Army Corps of Engineers
1972).
Restricted flow inside the bay could result in increased siltation from
the large quantities of sediment discharged by the Matanuska River and other
Knik Arm tributaries. This sediment discharge, in turn, could result in habi-
tat destruction and increased benthic organism mortality. Flow patterns may
be altered outside the tidal barrier, changing movement of plankton and other
marine organisms. One advantage of such a structure may be to reduce turbid-
ity in the outer portions of Cook Inlet, possibly resulting in higher primary
production from increased light penetration. Also, the structure itself may
provide a substrate for attachment of sessile marine organisms.
Similar problems to the Knik Arm may occur if a tidal power facility were
constructed on Turnagain Arm because of the many similarities between the two
areas. Salmon, although not as abundant, are also present in some of the
small streams that enter this area (Alaska Department of Fish and Game 1978).
Siltation may not be as significant in these regions due to the lack of major
stream inflow.
7.25
Marine mammal habitats will be reduced as a result of the barrier pre-
sented by the tidal power barrage and by the modification of shoreline vegeta-
tion by changes in the tidal cycles. In general, seal and sea-lion haul-out
areas could be eliminated. Intertidal vegetation and organisms fed upon by
aquatic furbearers and waterfowl would be modified, and bald eagles and other
fish-eating raptors could also be negatively affected if anadromous fish pas-
sages through the barrage were reduced.
The Knik and Turnagain tributaries of Cook Inlet are environmentally sen-
sitive areas. Both tributaries are used by seals, sea-lions, and water fowl.
The Turnagain tributary contains three key waterfowl areas: Chickaloon Flats,
Potter Marsh, and Portage Marsh. Various puddle ducks, geese, and sand hill
cranes feed and rest in these areas during seasonal migration periods. These
groups of birds also use Palmer Flats and Eagle River Flats of the Knik tribu-
tary. Irregular tidal cycles could alter the intertidal biotic communities of
these areas and could reduce their value to waterfowl and various shorebirds.
Both tributaries are also used by harbor seals. Establishing a barrage
would effectively end their use of these areas. Lastly, only the Knik tribu-
tary appears to contain major salmon runs, which if blocked or substantially
reduced, could negatively affect bald eagles and ospreys that feed upon salmon.
Terrestrial impacts resulting from tidal energy development of the Knik
and Turnagain tributaries could be partly mitigated. However, losses to
marine mammals could not be relieved. Waterfowl and various shorebird habi-
tats could be kept relatively unchanged by maintaining tidal cycles similar to
normal ones. Tidal cycles could not be maintained if tidal energy production
were supplemented by a combination pumped-storage system. The loss of salmon
as a food source to fish-eating raptors could also be relieved by increasing
salmon production on nearby tributaries, if densities of fish-eating raptors
on these streams are not at saturation levels for reasons other than food
availability. If these streams were saturated for other reasons, then losses
could not be mitigated.
7.2.5 Socioeconomic Considerations
A tidal power plant requires a large construction work force and a small
operating work force, creating the potential for a boom/bust cycle. A work
7.26
force of 200 to 500 would be required for a Ranee-scale (240-MW) plant for
7 years. The size of the construction work force would not vary greatly with
plant scale since excavation and barrage construction are general requirements
independent of generating capacity. The larger plants proposed for Cook Inlet,
however, would require approximately eleven years for construction. A staff
of 20 to 50 would be required during the operating phase. Compared to other
fuel-saver technologies, tidal power has the greatest potential to impact
smaller communities.
Since the two tidal sites (Knik Arm and Turnagain Arm) identified in the
Railbelt are located close to Anchorage, impacts on the surrounding area due
to construction should be minimal. The project offers potential employment to
unemployed persons residing in the greater Anchorage region. Therefore, a
work force would not have to be brought in from other areas of Alaska, which
would alleviate the demand for housing or services.
Since tidal power is a labor-intensive technology and participation by
the Anchorage area labor force is expected, the expenditures for labor should
be kept primarily within the region. Some of the material expenditures,
particularly those for embankment materials, would also remain within the
region. Therefore, approximately 67% of the total capital expenditures would
be spent within the Railbelt. Approximately 33% of the total capital cost
would be for equipment imported from the lower 48 states or foreign suppliers.
Approximately 11% of O&M expenditures would be spent outside Alaska and 89%
spent within Alaska.
7.2.6 Potential Application in the Railbelt Region
A tidal power reconnaissance study of Cook Inlet was recently completed
for the Alaska Power Authority. This study identified sixteen potential sites
in Cook Inlet (Acres American, Inc. 1981a). The sites ranged in size from a
site at Port Graham with the potential for an installed capacity of 46 MW and
net annual energy production of 584 GWh to a site at Anchor Point across the
inlet with a potential installed capacity of 25,100 MW and net annual energy
production of 318,000 GWh.
7.27
Based on the scale, likely development costs, location, and potential
environmental effects, a subset of three more favorable sites were selected
for further study (Figure 7.7). These three sites were Rainbow on Turnagain
Arm, Point McKenzie/Point Worongof on Knik Arm, and Eagle Bay/Goose Bay on
Knik Arm.
Further study of these three sites resulted in recommendation of the
Eagle Bay/Goose Bay site for further study. The proposed plant would consist
of a tidal barrage extending across Knik Arm at the narrowing of the channel
above Eagle and Goose Bays. The barrage would consist of an access dike from
shoreside to the first powerhouse unit; 60 powerhouse modules, each containing
a bulb turbine-generator of 24-MW rated capacity; 36 sluiceway modules, and a
closure dike to the far shore. A substation and 230-kV or 345-kV transmission
tie would be provided. A vehicular causeway would be optional. Total
installed capacity would be 1440 MW. An estimated 1600 GWh of energy of a
total potential of 4000 GWh could be used by the Railbelt electric energy
system without retiming (energy storage). Provision of a 1200-MW pumped
hydroelectric storage retiming facility would increase the useable energy to
3200 GWh annually.
An alternative using thirty 24-MW turbine-generators was also proposed.
This alternative would produce 2300 GWh of raw energy, 1530 GWh of useable
energy without storage and 2050 GWh of useable energy with an accompanying
450-MW pumped hydroelectric storage project. Estimated capital and O&M costs
and costs of energy for the proposed Eagle Bay/Goose Bay project are summa-
rized in Table 7 .4.
Advantages of Cook Inlet tidal power development include provision of an
electric energy supply based on a renewable energy source, relatively free
from the effects of inflation. An additional potential advantage is the
possibility of a shorter highway access to lands borderig Knik Arm across from
Anchorage. Disadvantages include potentially severe environmental effects,
high capital cost and the need to either effectively absorb intermittently
generated power or to provide an ancillary energy storage facility.
7 .28
TIDAL POWER
-SITES SELECTED FOR
FURTHER STUDY
0
SCALE
50
FIGURE 7.7. Tidal Sites Selected for Further Study
7.29
7.3 LARGE WIND ENERGY CONVERSION SYSTEMS
Until the mid 1930s wind energy supplied a significant amount of energy
to rural areas of the United States. With the advent of rural electrification
wind energy ceased to be competitive with other power alternatives. However,
rising fuel costs and the increased cost of power from competing technologies
has renewed interest in the development of wind resources. This energy source
may be significant in electric power generation in rural areas, small communi-
ties, and possibly for large, interconnected energy systems.
This section will focus on large wind turbines of 0.1-MW or more rated
capacity that might be employed as centralized power-generating facilities by
a utility. Currently, several machines are in the demonstration phase. In
1979 the MOD-1.2-MW, 200-ft diameter turbine was completed at Boone, North
Carolina. Three MOD-2 wind turbines, each rated at 2.5-MW capacity, have been
recently completed near Goldendale, Washington by the Bonneville Power
Administration (BPA), U.S. DOE, and NASA. These and other wind turbines in
the 1-MW range of rated output are available for production, but the economics
of assembly line production have not yet been realized.
7.3.1 Technical Characteristics
A typical wind machine consists of a rotating blade assembly, a trans-
mission to convert the relatively slow blade rotation to appropriate generator
speed, an electrical generator, a supporting structure, and electrical trans-
formation, switching and control equipment. Horizontal machines also require
equipment to control the position of the machine relative to the wind. Large
wind energy conversion systems range in size from 100 MW to 2.5 kW each.
Machines of larger capacity are in the design stage.
Design Features
The wind machines used to convert the energy in the wind to rotational
energy are classified according to the axis of rotation relative to wind
direction as: 1) horizontal axis, 2) vertical axis, and 3) cross-wind
horizontal axis.
7.30
Horizontal axis rotor systems represent the conventional, windmill-type
machine whose axis of blade rotation is horizontal and parallel to the wind
direction. This design is illustrated in Figure 7.8. Vertical axis rotor
systems have a vertical axis of blade rotation. The most common represen-
tatives of this system are the Savonius and Darrieus machines (Figure 7.9).
Vertical axis systems are generally less efficient than the horizontal rotor
systems. However, since they do not need a tower, their construction costs
are less and they have the added advantage·of being insensitive to wind
direction. Cross-wind, horizontal axis systems are of a paddle-wheel design
and do not represent an improvement over either of the other two designs
(Inglis 1978). At the current stage of development, horizontal axis designs
appear to be preferred for megawatt-scale machines.
Wind energy is characteristically a diffuse source of energy in which the
theoretical output of an individual wind machine is a function of the cube of
the wind speed, the wind machine efficiency, and the area intercepted by the
turbine blades. Therefore, the factor of primary importance in establishing
wind power potential is the wind speed characteristic of a site.
Wind generators operate within well-defined wind speed ranges. The
11 POwer profile depicts the power output of the turbine as a function of the
wind speed. The power profile for the MOD-2 (Figure 7.10) indicates the
cut-in speed (14 mph), rated speed (28 mph), and cut-out speed (47 mph).
Because wind turbines must be designed to fit load system and wind conditions,
a smaller wind turbine with a lower cut-in speed, a lower rated speed, and a
lower power rating may be preferred in some cases to a larger machine with
higher cut-in wind speeds.
The production of wind power electricity is an intermittent process
because of the nature of wind itself. The physical or structural reliability
of the wind turbines is generally well established for the small units but is
uncertain for the newer, large units. The availability of large wind machines,
when fully developed, is expected to be approximately 87%. (a) The capacity
(a) Electric Power Research Institute. 1982. 1981 Technical Assessment Guide
(Draft). Electric Power Research Institute, Palo Alto, California.
7.31
t CONTROLLABLE TIP
45ft
* ~ROTOR
WIND Q rNACELLE
-r--I
300ft dia. ~
f-4--TOWER
200ft
rSWITCHGEAR AND
TRANSFORMER
J \ .----,
FOUNDATION
FIGURE 7.8. MOD-2 Wind Turbine Generator
factor for wind turbines will probably range between 30 and 50%, but this
factor is a function of the wind resource at the site.
Weather factors such as icing or high winds reduce the machine•s relia-
bility. Equipment life in the Railbelt•s harsh climate may pose a problem.
Towers and blades must be able to withstand storms, winds, icing, or snow
loading. Tower foundations need to withstand repeated freezing and tha\'Jing.
High mechanical loads are experienced during tower and blade icing conditions.
Equipment exposed to the elements may experience lubrication problems in sub-
zero temperatures.
7.32
I
I
FIGURE 7.9. Vertical Axis Wind Turbine (Darrieus Type)
7.33
\
\
32 CUT-IN RATED CUT-OUT
~
v; 2.4 ~ "' 3:
"' 01
Q)
E
I-1.6 ::J
Cl..
I-
::J
0
0:::
LLI =s: 0.8 0
Cl..
o~----~--~~~----~----~------~-
0 8 16 24 32 40 48
WINDS PEED (mph at hub)
FIGURE 7 .10. Power Profile of the MOD-2 Wind Machine
Grouping wind turbines into "wind farms," as at Gambell, Alaska, can
reduce problems with equipment failures. Any one turbine could be shut down
for repair or maintenance without greatly affecting the farm's output. The
farm's overall reliability is much greater than the reliability of single-unit
generation systems.
Optimum use of wind turbines may require backup power generation and
storage requirements because of the variability of wind speeds. Wind turbines
or a wind farm may be developed at sites where the wind pattern closely
approximates the load pattern. Such development helps alleviate storage
requirements and load management difficulties.
In a grid with existing hydro capacity, storage can be accomplished by
displacing hydro production; that is, not as much water is used to generate
electricity when the wind generators deliver power. The water not used is
held behind the dam for future use. The rapid response time of hydropower
installations effectively complements the intermittent production of wind
energy conversion systems. However, the displacement storage cannot be used
unless hydro provides a large portion of capacity; otherwise, the hydro
facility will already be scheduled to provide peaking power. Simple-cycle
7 .34
combustion turbines may also be used in conjunction with wind systems to
provide power when the wind machines are not operating.
Because generating capacity can be added in relatively small increments,
wind turbine construction can easily follow load growth. Wind power capacity
additions, however, must be coordinated with provision of complementary power
generation and storage capacity. Machine lifetime is anticipated to be
30 years.
7.3.2 Siting Requirements
The siting of the wind turbines is crucial to satisfactory performance of
wind energy conversion systems. The
average wind speed and variability.
scale weather patterns but are also
most significant siting consideration is
These considerations depend on large-
affected by local topography, which can
enhance or reduce the average wind speeds. Since wind energy potential is
directly proportional to the cube of the wind speed, siting wind machines to
take advantage of even small increases in average wind speed is important
(Hill 1977). Extremely high winds and turbulence may damage the wind
turbines, and sites exhibiting these characteristics must be avoided.
Other important siting considerations include the proximity of the site
to load centers, site access, founding conditions, and meteorological condi-
tions. Undesirable meteorlogical conditions, in addition to turbulance,
include glazing conditions, blowing sand or dust, heavy accumulations of snow,
and extreme cold.
Wind-powered energy requires varying amounts of land area for development.
The amounts of area required depend on number, spacing, and types of wind-
powered units used. The area can range from approximately 2 acres for one
2.5-MW generating unit to over 100 square miles for a 1000-MW wind farm.
Developments of the 1000-MW size, because of their requirements for persistent
high-velocity winds, would probably be established in remote areas.
7 .3 .3 Costs
The major costs of developing wind power are the equipment and erection
costs. The O&M costs are difficult to project because of a lack of standardi-
zation and little operating experience. Estimated O&M costs are, however,
projected to be small compared to initial installation costs.
7.35
Costs for large turbines adjusted to 1980 dollars range from $740 to $850
per installed kilowatt (Inglis 1978). These costs assume production runs of
100 or more machines. Estimates provided by the Boeing Company for this level
of production for the MOD-2 turbines being installed near Goldendale,
Washington indicate a cost of about $800 per installed kilowatt capacity.
Currently, the 2.5-MW MOD-2 machine sells for $6.5 million each (2600 $/kW).
Costs of installation at remote locations are uncertain, particularly if
shipping the units or installing them onsite is very difficult. Estimated
costs for large wind energy conversion systems located in the Railbelt are
shown in Table 7.5.
TABLE 7.5. Estimated Costs for Large Wind Energy
Conversion Systems (1980 dollars)
Rated
Capacity
2.5 MW
Capital
($/kW)
1500
O&M
($/kW/yr)
13-22
Cost of
Energy
($/kW)(a)
72-54
(a) Levelized lifetime costs assuming a 1990 first
year of commercial operation. Range represents
capacity factors of 30% and 40%, respectively.
7.3.4 Environmental Considerations
Wind turbines extract energy from the atmosphere and therefore can cause
slight modifications to the surrounding climate. Wind speeds will be slightly
reduced at surface levels and to a distance equivalent to 5 rotor diameters,
which would be approximately 1500 ft for a single, 2.5-MW facility. Small
modifications in precipitation patterns may be expected, but total rainfall
over a wide area will not be affected. Nearby temperatures, evaporation,
snowfall, and snow drift patterns will be affected only slightly. The
microclimatic impacts will be qualitatively similar to those noted around
large, isolated trees or tall structures.
The rotation of the turbine blades may interfere with television, radio,
and microwave transmission. Interference has been noted within 0.6 miles
(1 km) of relatively small wind turbines. The nature of the interference
7.36
depends on signal frequencies, blade rotation rate, number of blades, and wind
turbine design. A judicious siting strategy could help to avoid these impacts.
Stream siltation effects from site and road construction are the only
potential aquatic and marine impacts of this technology. Silt in streams may
adversely affect feeding and spawning of fish, particularly salmonids, which
are common in the Railbelt region. These potential problems can be avoided by
proper construction techniques and should not be significant unless extremely
large wind farms are developed.
Because of the relatively large land requirements, the potentially remote
siting locations, and the possible need for clearing of vegetation, wind energy
projects could significantly affect terrestrial biota through loss or disturb-
ance of habitat. Also, wind generating structures could cause collisions with
migratory birds. Other potential impacts include low frequency noise emanat-
ing from the generators and modification of local atmospheric conditions from
air turbulence created by the rotating blades. The impacts of these latter
disturbances on wildlife are unclear at present.
In the Railbelt region environmentally sensitive areas having favorable
wind resources include exposed coastal areas along the Gulf of Alaska,
mountain passes, and possibly hilltops and ridgelines in the Interior. Altera-
tion of coastal bluffs could affect seasonal ranges of mountain goats in the
Kenai Mountain Range, and nesting colonies of sea birds in the Chugach
Islands, Resurrection Bay, Harris Bay, Nuka Pass, and other areas along the
Gulf Coast. Shoreline development could affect harbor seals and migratory
birds. Harbor seals use much of the coastline for hauling-out. The Copper
River Delta is a key waterfowl area. Scattered use of shoreline habitat by
black bear, brown bear, and Sitka blacktailed deer occurs in Prince William
Sound. The presence of wind energy structures in any of these areas could
potentially cause collisions with migrating waterfowl, bald eagles, peregrine
falcons (an endangered species), and other birds, if situated in migratory
corridors. If situated on critical range lands, inland development of wind
energy could negatively affect Dall sheep, mountain goat, moose, and caribou.
7.37
These terrestrial impacts can generally be mitigated, although habitat
lost through development is irreplaceable. However, these losses can be
minimized by siting plants in areas of low wildlife use. Critical ranges of
big game, traditional haul-out areas of seals and nesting colonies of birds,
and known migratory bird corridors or key feeding areas could be avoided. The
feasibility of mitigation will, of course, depend on the size of the wind
energy development.
7.3.5 Socioeconomic Considerations
Construction of a 1 to 2.5-MW wind turbine would require approximately
2 years for site selection and monitoring and 6 months for field erection.
During the monitoring period, a survey party would periodically visit the site
to collect data. A wind turbine requires a small construction work force of
10 to 15 persons, no permanent onsite operating work force, and minimal main-
tenance requirements. In comparison to the other fuel-saver technologies,
wind power would create very few demands on community infrastructure.
Since the construction and operating and maintenance requirements are
minimal, a community•s population size is not a siting constraint. Individual
wind turbines should therefore be compatible with communities of all sizes.
Installation of a 100-MW wind farm would require a construction work
force of approximately 60 over a period of a few years. The impacts of
constructing a wind farm on small communities may be significant because of
the work force size and length of construction period.
The cost breakdown for a wind turbine investment is based on the assump-
tion that the monitoring field work, site preparation, and installation would
be performed by Alaskan labor and that all components would be imported from
outside manufacturers. Under these assumptions approximately 80% of the
expenditures would be sent outside the region, while 20% would remain within
Alaska.
A wind turbine system consisting of five machines has been installed at
Gambell on St. Lawrence Island in Alaska to provide wind electric power for
community facilities. Another wind turbine has been installed at Nelson
Lagoon on the Alaskan Peninsula.
7.38
7.3.6 Potential Application in the Railbelt Region
A comprehensive wind energy resource atlas of Alaska has been recently
completed for the U.S. Department of Energy's Wind Energy Program (Wise
1980). This atlas was compiled by the Arctic Environmental Information and
Data Center of the University of Alaska. The principal information contained
in this atlas are maps of wind power density and corresponding certainty
ratings for the state as a whole and in greater detail for four major sub-
regions ·(northern Alaska, south central Alaska, southeastern Alaska, and
southwestern Alaska). Other information that is provided includes estimates
of the percentage of land area subject to various levels of wind power density,
seasonal average wind power and wind characteristics of selected stations.
The information is presented at a macroscale level based on data cells of 1°
longitude by 1/2° latitude in size (717 cells for the state). The resulting
wind resource maps are at a far greater level of detail than any previously
compiled for the state, and while not of sufficient detail to support specific
siting decisions, are of suitable detail to suggest specific subregional areas
having promising wind resource potential. A map of wind power density in the
Railbelt region, based on the Alaska Wind Energy Resource Atlas, is provided
in Figure 7 .11.
Seven classes of annual average wind power density are shown in Fig-
ure 7.11 and the characteristics of these classes are shown in Table 7.6.
To provide some perspective on the relative significance of these wind power
classes, a minimum annual average wind speed of 6.5 m/sec at 10m height has
been estimated to be required for a wind resource to be considered as a viable
energy option (Hiester 1980). This estimate roughly corresponds with wind
resource Class 5. This criterion is based on estimated mass production costs
of the current generation of large-scale wind machines as represented by the
MOD-2 design. The Goodnoe Hills site in Washington State, where three MOD-2
machines are currently being tested and considered to be a prime wind resource
site, is in wind power density Class 6. The cut in speed of a MOD-2 machine
is approximately 14 mph (Figure 7 .10), equivalent to the mean wind speed (at
approximate hub height) of wind power Class 2. Full power output of a MOD-2
7.39
·WIND POWER DENSITY
2
3
4
5
7
100 WATTS/M2
150 WATTS/M2
200
250
300
400
1000
FIGURE 7 .11. Wind Power Density of the Railbelt Region
(Wise 1980)
7.40
TABLE 7.6. Wind Power Density Classes
10 m ( 33 ft} 50 m {164 ft)
Wind Wind Power Mean Wind Power Mean
Power Density Wind Speed Density 2 Wind Speed
Class ( watts;m 2} (mph) ( watts/m } (mph) --
1 100 9.8 200 12.5
2 150 ll.S 300 14.3
3 200 12.5 400 15.7
4 250 13.4 500 16.8
5 300 14.3 600 17.9
6 400 15.7 800 19.7
7 1000 21.1 2000 26.6
machine is achieved at 25 mph, greater than the mean wind speed of a Class 7
site. In general, Class 4 areas and above are considered to have "high"
annual average wind power.
Three areas within the Railbelt are considered major wind resource areas
from a statewide perspective (Wise 1980). These areas include the Lower Cook
Inlet, the Gulf of Alaska coast and exposed ridges and summits of the Alaska
Range.
The lower Cook Inlet area from Iliamna Lake to the Barron Islands (off
the tip of the Kenai Peninsula) is a corrider for strong winds. Whereas
large-scale, offshore wind power development is probably not feasible in the
near term, onshore locations at the tip of the Kenai Peninsula are at the edge
of this resource area and may possess promising sites. Some thought has been
given to construction of offshore wind machines. Power could be transferred
to shore using submerged cables, or hydrogen produced by electrolysis of
water. However, such designs are presently speculative (Considine 1976) and
most likely would not be developed until terrestrial machines have been more
fully deve 1 oped.
Exposed area along the Gulf of Alaska coast should experience mean annual
wind power of Class 4 or higher. Offshore data indicate wind power of Class 7
7.41
or higher. Existing settlements tend to be at sheltered sites and do not
exhibit strong wind characteristics; however, more exposed coastal sites may
prove to be more favorable.
Class 4 and higher sites are thought to be located along ridge crests in
the Alaskan Range to the west of the Susitna River and at Isabell Pass north
of Paxson. The wind power potential of ridge top sites tend to be highly site
specific and wind speeds can vary significantly from one ridge crest to
another as a result of orientation and proximity to other ridge lines. The
mapped data of Figure 7.11 represent the lower limits of wind power for
exposed areas.
Finally, a Battelle-Northwest study that addressed the wind resource
potential of the Cook Inlet area (Hiester 1980) concluded that no conclusive
evidence indicates that large-scale generation of electric energy by megawatt-
scale wind turbines is a significant energy option in the Cook Inlet area.
However, six sites were judged to have sufficient wind energy potential to
warrant site-specific wind measurements. These sites include the following
(Figure 7.11):
• the hills north of Homer
• Portage Creed Valley
• Bird Point (Turnagin Arm)
• Cantwell-Summit-Broad Pass area
• Anchor Point (Cook Inlet)
• Tahneta Pass (Glennallen Highway).
Wind resources showing considerable promise for large-scale wind energy
development appear to be present in the Railbelt Region. The most promising
area appears to be Isabell Pass because of its very high wind power density,
winter peaking characteristics and relative accessibility. The primary draw-
back of this area is its remoteness from major load centers. Other areas
showing promise include ridge tops in the Alaska range west of the Susitna
River, exposed locations along the Gulf of Alaska and at the tip of the Kenai
Peninsula, and selected sites in the Cook Inlet area.
7.42
Further studies are necessary to assess wind energy potential of the
areas identified above. These studies include the following: preparing and
examining detailed contour patterns of the terrain, modeling selected sites,
monitoring meteorological conditions at prime sites for at least 1 year
(preferably 3 years), analyzing site meteorlogical characteristics using
modeled and measured data, developing site-specific wind duration curves, and
selecting final sites.
7.43
7.4 SMALL WIND ENERGY CONVERSION SYSTEMS
Small wind energy conversion systems (SWECS) are wind machines with rated
output of 100 kW or less. Typically, the siting of these machines would be
dispersed at individual residences or in small communities, as compared to the
large wind energy conversion systems (Section 7.3), which would be sited gener-
ally in clusters, as centralized power production facilities.
7.4.1 Technical Characteristics
Historically, battery-charging systems have been the primary application
for small wind energy conversion systems in Alaska; however, this situation is
beginning to change. Several small wind machines are now in commercial pro-
duction in sizes ranging from 0.1 to 37 kW. Figure 7.12 shows some of SWECS•s
many possible uses, both currently existing and under development. The profile
in this section focuses on SWECS that interface directly with the utility grid.
Off-grid installations are not considered.
Design Features
SWECS are available in horizontal and in vertical axis configuration.
Horizontal axis machines (Figure 7 .13) exhibit superior efficiency but require
a substantial tower to support the generating equipment as well as the blades.
In addition, the blade/generator assembly must yaw in response to changing
wind direction, requiring provision of head bearings, slip rings and machine
orientation devices.
Although of lower efficiency than horizontal axis machines, the vertical
axis designs (Figure 7.9) minimize tower structure and eliminate the need for
head bearings or slip rings. Because of these advantages, vertical axis
machines may exhibit superior cost characteristics in the small wind machine
sizes.
The three most common types of generator systems used in SWECS are induc-
tion AC generators, synchronous AC generators, and DC generators. Synchronous
generators must be driven at a constant speed, corresponding to the desired
frequency of the power produced. Synchronizing microprocessor controls are
7.44
no AL.
A.C. POWER L
..
SWITCH LINEAL.
~ D.C. POWER
D.C.
D.C. HOT DIRECT HEATING
WATER BEATER
AL.
'-I . D.C .
+::>
(.}1
[L_ D.C.
IIYDHAULIC IIOT WATER DIRECT D.C. HEATING BHAKE SYSTEM PUMPED WATER
AL.
AL. ..
~ PUMPED L_--=_ )1 .... _w_A_TE_R_.,
FIGURE 7.12. Alternative SWECS Configurations
FIGURE 7 .13. A Typical Horizontal Axis Small Wind Machine
built into the machine to control frequency. This type of machine may be used
to generate 60 Hz alternating current either in conjunction with or independent
of a utility grid. The rotor must turn at constant RPM, somewhat sacrificing
7.46
machine efficiency at extreme wind velocities. Future SWECS using synchronous
generators may incorporate variable speed transmissions, allowing rotor speed
to vary with wind velocity.
Induction generators will provide synchronized alternating current at any
speed above a given minimum speed. Rotor RPM can thus vary with wind velocity,
enhancing machine efficiency. Because it requires external synchronization,
machines using induction generators normally must be connected to a utility
grid.
SWECS that generate DC power are typically used for charging batteries in
remote sites. Either a brush-type DC motor or an alternator and DC rectifier
are generally used. The DC power can be used directly, can charge batteries,
or can be inverted to AC power. A synchronous inverter may be used with a DC
generator to convert the DC power to AC synchronized with the utility.
Performance Characteristics
Horizontal axis machines have somewhat greater conversion efficiencies
than vertical axis machines; however, the capital cost advantage of higher
conversion efficiencies may be offset by the structural advantage of the
vertical axis machine. The theoretical maximum conversion efficiency of a
SWECS is 60%. Most wind generators currently manufactured in the U.S. have
conversion efficiencies of 15% to 30% (electricity at the base of the tower).
On-grid SWECS are usually not considered to be firm capacity and operat-
ing as fuel-saver devices. However, in regions as climatically diverse as the
Railbelt, studies have shown that with simple load management techniques, wind
machines can be given significant capacity credit in grids without storage
( Timm 1980).
Energy storage is "built into" grids having hydroelectric facilities with
reservoir storage capacity. Energy produced by wind machines offsets hydro
production requirements. During periods of calm, stored water is used to
follow load. Hydroelectric pumped storage, or other energy storage facili-
ties, could be used to augment grid storage capacity.
Because of the short lead time required to install a SWECS (less than
1 year if wind data are available, 2 years if not) and because of their small
7 .47
size allowing for incremental additions, SWECS are extremely adaptable to any
load growth pattern. Potential machine lifetime is not presently well
understood but most likely would be about 20 years.
7.4.2 Siting Requirements
A minimum wind speed of 7 to 10 mph is typically required for operation
of a SWECS. An annual average of 10 mph is usually considered a lower eco-
nomic cut-off for most applications; however, this figure depends on the site,
costs of energy from alternative sources, and particular wind generator design.
Each site must be evaluated for terrain (Figure 7.14) and what affect
that may have on wind speeds at different heights (Figure 7.15). Sites having
favorable exposure to the wind typically include ridge crests, hilltops,
mountain summits and large clearings. Local topography, such as valleys ori-
ented to the prevailing wind, may enhance general regional wind characteris-
tics. Locations such as valleys oriented perpendicular to the prevailing wind,
canyons, sites in the lee of hills, and forested and urban sites tend to have
less favorable wind characteristics.
A small wind machine that is to be intertied to the utility grid must be
reasonably close to existing or planned power lines. This requirement may
eliminate many ridge tops because of the transmission line costs. Small wind
STREAMLINES
WIND DIRECTION c:::>
GOOD LOCATION:
FLAT OPEN GROUND
FREE OF ADJACENT TREES
TOP OF GENTLY RISING
HILL, FREE Of ADJACENT
TREES
REGIONS SHIELDED
BY ADJACENT HIGH
CLIFFS OR BUILDINGS,
IN TURBULENT AIR ON
TOP OF CLIFFS OR IN
SHADOW OF STEEP
HILLS, ESPECIALLY WITH
ADJACENT LARGE TREES
FIGURE 7 .14. The Effect of Local Terrain on Wind Machine
Performance
7.48
180
:E 160
L.U 140 u
<(
LL.
0::: 120 :::::>
Vl
L.U 100 > 0 co 80 <(
I-:r:
{!)
L.U :r:
1
WIND SPEED
2 3 4 5 6 7 8 9 10
' INCREASE FACTOR
FIGURE 7.15. Example of Increase in Energy Available
with Increased Tower Height
11
machines mounted on towers require no more than 100 ft(2 ) at the base plus
any exclusion area that the owner wishes to fence off for safety reasons
(usually no more than about 5 blade diameters).
7.4.3 Costs
Depending on the application, tax credits, and the type of system,
installing a residential-sized unit with an installed capacity of 2 to 10 kW
would require an initial investment of $5,000 to $20,000 (Table 7.7). O&M
costs of 1% of installed costs ($50-$200/year) would be representative, but
depends on the system.
TABLE 7.7. Estimated Costs of SWECS (1980 dollars)
Rated Cost of
Capacity Capital O&M Energy (a)
{kW} {$/kW} {$/kW/~r} {mills/kWh}
2 2500 25 113-56
10 2000 20 91-46
12
(a) Levelized lifetime costs assuming a 1990 first year of
commercial operation. Range represents capacity factors of
20% and 40%, respectively.
7.49
7.4.4 Environmental Considerations
Studies have shown that SWECS have somewhat enhanced local wildlife due
to downwind shelters. A possible adverse impact on low flying night migratory
birds in bad weather also has been indicated, although the kill rate is not
significant. Aesthetic impacts are difficult to assess and highly subjective.
Many people surveyed have found small wind machines to be visually pleasing.
Noise from small generators is not significant with proper blade design.
Radio frequency interference can be mitigated with proper blade design
(nonmetallic) and siting. Potential safety risks involve the possibility of
tower or blade failure and aircraft collision. Actions taken to decrease
those risks include: a) maintenance of an exclusion area around the turbine;
b) automatic monitoring of turbine operation; c) regular preventative mainte-
nance; d) visitor control measures; and e) adherence to FAA requirements for
tall structures. No injuries or deaths are anticipated over the life of the
plant.
7.4.5 Socioeconomic Considerations
By siting SWECS in 11 Wind farms, .. rows of generators can be lined up as a
wind break for combined use in an agricultural project. Land use in cities
would pose a significant problem with safety considerations and building
codes, but rural land, which constitutes most of the Railbelt, presents no
such difficulties.
Typically, SWECS require a small, two-to four-man crew for installation,
and maintenance can generally be performed by two people. No major influx of
temporary or permanent labor forces should result from construction or opera-
tion of a facility. The necessary manpower, talent, and expertise are cur-
rently available within the Railbelt.
The chief advantage of SWECS is that once they are installed, no capital
is required for fuel expenditures and very little is needed for operation and
maintenance (all of which would stay in the region). If SWECS were manufac-
tured in the Railbelt region, a significant portion of the capital cost could
also stay in the region.
7. 50
The convenience of this technology to the consumer depends on the system.
Induction generator systems require only an annual inspection and lubrication
of the wind generator. Synchronous generator systems being installed today
are totally microprocessor contra ll ed and need no rna i ntenance other than
periodic generator inspection and lubrication. Maintenance contracts, which
would free the consumer from any maintenance responsibilities, are presently
available.
7.4.6 Potential Application in the Railbelt Region
Until recently only a few SWECS manufacturers existed. Today over 50
exist, with a half dozen mass-producing generators at a rate of 20 to 200 per
month. The demand, however, is currently outpacing the supply, and several
manufacturers report back-orders of 120 days, or more. However, 60 to 90 days
is generally quoted as delivery time.
A dealership and repair network already exists in the Railbelt region and
would grow as the number of installed SWECS increases. Engineering and design
expertise is also present in the region. A survey conducted in 1981 indicated
that five system design organizations, four suppliers and one installer were
operating in the Railbelt.
The major obstacle to the availability of wind generators seems to be the
lack of venture capital in an unstable economic climate, which makes needed
plant expansion difficult for manufacturers. Once market penetration and mass
production have brought the unit cost down and manufacturers have internalized
major R&D efforts, then widespread use of SWECS is possible.
A wind energy resource atlas has recently been compiled for Alaska
(Battelle, Pacific Northwest Laboratories l980b). Figure 7.16 shows Railbelt
areas that are estimated to have average annual wind speeds of 11.5 mph or
more at elevations typical of SWECS (10m, 33ft). Wind resource data of Fig-
ure 7.16 are based on conditions expected in locations of favorable exposure.
As Figure 7.16 shows, the major population centers of the Railbelt are
not located in areas promising adequate wind resources for SWECS applications.
However, localized topographic and meteorological effects may provide local
7.51
WIND POWER DENSITY
150 WATTS/M2
200
250
300
400
1000
FIGURE 7.16. Potential Wind Resources for SWECS Development
in the Railbelt Area
7.52
occurrences of wind conditions favorable to the operation of SWECS in areas
not appearing favorable at the macro scale of the existing Alaska wind
resource assessment. A few examples are as follows:
• The annual average recorded for Anchorage is 5 mph taken at the
international airport. Closer to the mountains at the site of an
installed wind generator the average is 6 mph. At Flat Top
Mountain, a homeowner who plans to install a SWECS has recorded
months of 15 mph averages.
• In Homer the recorded annual average is 9 mph at the airport, while
on the 11 spit 11 the average is reported to be closer to 13 mph. Fur-
ther up the hill at the site for an 18-kW SWECS, the winds have not
been measured but are expected to be better than at the airport.
• In Fairbanks the average windspeed is recorded as 4 mph, yet the
speed increases going out of the va 11 ey. The average wind speed
almost triples near Murphy Dome.
• A recent study done by Battelle-Northwest (1980b) of the Cook Inlet
area identified six regions with potentially sufficient winds for
megawatt-scale turbines, but lack of useful wind data did not allow
candidate sites to be selected or site-specific costs to be identi-
fied for large wind systems.
Because of the lack of local wind resource data, little basis exists for
a quantitative assessment of SWECS•s possible contribution to the Railbelt
region. The bulk of future SWECS development, however, appears to be
scattered in localized 11 Wind spots 11 that are not presently inventoried and
in the few communities located in areas of more favorable general wind
characteristics.
An order of magnitude estimate of the potential contribution of small
wind energy conversion systems to the Railbelt electric power system was
prepared for this report. Estimates were based upon full penetration of SWECS
(i.e., one for every residence) in all areas having wind resources of
150 watts/m2 or greater (Figure 7.16). Within wind resource areas charac-
teristic of the populated areas of the Railbelt, SWECS begin to be cost
7.53
effective at marginal power costs of 60 mills per kilowatt hour. Assuming
full penetration, it appears that approximately 5 MW of SWECS capacity,
generating 15 GWh annual average energy, would be cost effective at marginal
energy costs of 60 mills per kilowatt hour.(a) At marginal costs of
100 mills per kilowatt-hour it is estimated (Table 7.8) that approximately
37 MW of SWECS capacity, producing approximately 96 GWh annual average energy
would be cost-effective.
The estimates of Table 7.8, as noted above, are based on full penetration
of SWECS. In practice, penetration would be substantially less due to such
constraints as spatial limitations on SWECS installation in urban areas and
homeowner reluctance to install and maintain SWECS.
(a) Note, however, that customers see average, not marginal energy costs and
thus would not invest in SWECS based on pure cost effectiveness.
7.54
TABLE 7.8. Estimated Small Wind Energy Conversion Systems
Development Potential, by Load Center
Anchorage L.C. Fairbanks L.C. Glennallen L.C. Total
Cost of Installed Installed Installed Installed
Energy Capacity Energy Capacity Energy Capacity Energy Capacity Energy
(mills/kWh) ( MW) (GWh) ( MW) ( GWh) ( MW) (GWh) ( MW) (GWh}
50
60 5 16 <1 <1 <1 <1 5 16
70 10 31 3 7 <1 1 13 39
-....,J 80 14 41 5 13 <1 2 19 56 .
c.n 90 14 41 5 13 <1 2 19 56 c.n
100 28 71 9 22 <1 3 37 96
150 34 81 16 34 4 9 54 124
(a) Order-of-magnitude estimates of development potential, assuming full penetration of SWECS
whenever cost effective for cost of power shown. In practice, penetration will be
substantially less due to constraints to development.
7.5 SOLAR PHOTOVOLTAIC SYSTEMS
Two basic methods for generating electric power from solar radiation are
under development: solar thermal conversion and photovoltaic systems. Solar
thermal systems involve the conversion of solar energy to heat via a transfer
medium. This medium (working fluid) can be water, steam, air, various solu-
tions, or molten metal. Energy is realized as work when the fluid is used to
drive a turbine. In photovoltaic systems solar energy is converted to elec-
tric energy by activating electrons in photosensitive substances. The subject
of this section is solar photovoltaic systems.
Available solar energy is diurnally and seasonally variable and is subject
to uncertainties of cloud cover and precipitation. Solar energy facilities
must either be employed as a 11 fuel-saving 11 option to displace conventional
generation, or they must be installed with storage capacity. In addition, if
the diurnal and annual load profiles are out of phase with available solar
energy resources, the inducements for developing this resource are further
reduced. Load profiles and solar resource availability generally do not cor-
respond in the Railbelt region, where demand generally peaks in winter and at
night.
7.5.1 Technical Characteristics
Photovoltaic cells operate by using a semiconductor material to capture
the energy in light. Energy is captured when a light photon collides with an
atom in the semiconductor material with enough energy to dislodge an electron
and to permit it to move freely in the material. A vacant electron position
is left behind at the site of this collision, causing a migration of electrons
within the collector material. An electrical current is created, which induces
a voltage specific to the cell material.
At present, comnercially available photovoltaic cells are made of silicon
wafers and are assembled largely by hand. Nearly two dozen technologies and
automatic assembly techniques are under development. Photovoltaic technology
is undergoing a burst of innovation comparable to the integrated, circuit-
semiconductor technology. New and more efficient cell designs capable of
converting 30 to 40% of the sunlight falling on them to electricity have been
proposed.
7.56
l.l esi,a11 Eeatu re'S
P)Jot&~oltai<;-llells are. mar,ufia_c~ul'ed in moiluT4r J.nrits· hn~:n~l s.) .vl]th vol-
t~'!!!!S ~f '3 to .24 yo1h y,nd cur-t•ent o1,1 t pu t s f i'OQl the mH llamp ran:~· tO' C!'lrout .
-a; a:mp'S-, Th~ 5~1.1s ar.e 9 oad .sel!s H:ive ; as 1:11e W<1tl is i •r,ci1eas.ell1 the vo1bge
.det"reases . B .e.c·au ~~< th~ p~ne· T.s a.~ ·msrdu.1 ·:ar; -th~J. t~11 Re ~as"i 1.¥ a.t!.d ~ to.g e lil<ter~
tq: ftltm units oJ val'iOI.l,S; $i z ~.. Poss i b 1$· -<lPP l:i ·gt i'On ,s -rf3!1£fe :frpnl' d iSTJetisea
·i·ooftop. m·ou n t .ed atr·ays to ~en t.l'ta 1 s't-a;t -i oit -a:pp.l i ~at l ons~
/!. ,ph a·tt>voJt_qi(;; ],)ower statjQfl cons'i!i h ·at art"it,v-s l}f Uh.O't.Qv.q l t -aic li.an..e1 ~
moun t ed on t racM·mg QJY nonti'l;ioki i l:l_g .supp"Ort s,tr ucture., i ·nvertel"s to .t:.P:nver-'t t ne
dt PtJtpu t -of i:n~ ~hot.c{)vol :i::atc ¢:e lls. t o <tt e utremt , a.Qd .gr ·i d intel'etmt:rect;i·cn
equipment up to th.e 1 imiU of .v.arl cus aux-:I Har.y sy s-terils t~i"'1 1911), f\hoto-
V!l .ltiiH: S.,:tstem (;Qnl!~i's1,t\1l affic,1ent1es currently r~lilJe fro m.· aj}p r.oJ<im_at~ly 2
' . '
t6 !3%.
Sp:ec ifi !; ~JI)es o'f 'PhgtovG Jta,i c. ~.YS.t.em~ th~t ar!i! ~;~ni!e.tt'!JQl i'IQ .. l'e s,\ta )'Gh .a_nd ·
devel9]i11Tient l 1\~ll.lda CO!IC61l tta ted S,IJn )i"gh ~ ·~ho ~OVO I ta i ~& Md 'C Og1'?rfet.rat.~.OIJ
p11ot0~o Tba i c sys t ems .
Con~:entra l:ed Sunlight Photovol 'tai c:;, Par~li o Hc re f~ectot<s are. IJ-sed ftrt-
con.cen tt·,a~1rtg s-un \~~ht fl'l'l ·ta' an ;~;r•ray qf soiar c!a1 ls ~o rMu.ce t-h~ rt\f111b er of
·Co? ll~ req!),lre.d fiJp a g-i vi;rr powe r-Qlf•tput.. GotWt!¥-S1.oi] !!ffi,c ·1eo·e ie"S. <!S h t~Jt ·a'<
18~ t\a>~e ll~en reptt~'tel! for ce'l'l's o~e rai ing i 'll sun light. tol')t~ntr-a'fied· :mo time s
(t'leliz a:nd l;ii\11illo M 19,7$;). R~~·~!ll"t;'fl e:~ ~e T1 ~~~bs lw:ls-prQdl.1~-e~ '* t:cmtent'raWd
sunlight plio):Q v.o ltai 4S system ·l~'ith an e.f'f"iciency of 15'% (~awl $ 19,81 ). Oe n ~n;
i mp~Q vement:$ -are· e xpe>ct£-d 'to tesu li& i.n ce 11s tl\at have an 12n i1:1 ~n .c:_y or ;~1i
h !i! ~ ~-•. (o(it!i s l:i;gP,t. j.-ncl'eij,se.s i n Gpst~. P arabo 1~¢' reft e dQr~ h'ave 6~
~J?ecV·ic d isaclN P,n~~ -~o I<Q r l\ 1-~e 11 t aij;tom didc tratli0hg mecha-n .;;s tlfs. mu st be
p,rov id<;d to keel?' t{l ~ reflec'ters-f-gcl)s-~· a-t the Si:lll· \~ith. tli ~ sun Jo'w in t he.
SKY. gu rli ·ng tnt} lvi ,n~r ·[116nttts H1 A l ~~o ot .i'n _early ~nd l-ate: .after nooi], tt.hes e-
SY.:Stetm WGJu 1.il be: i r:1effi ¢ i ·en t..
!lo.generat ion Photovo1 Jia i c ?'>:stem ;.. 1'he attNP·t i v.ell~~ ·!'If ~tn l)tp vel.tai'c
dev i C~:!-S c.an t;:e htcr<ea·sed· s i.gtr1'fi,c .a;fltr. \i H ,\;he ener,~ t1o.t C:'011ver-ted t lil el ec:·-
~dc i t,y ,1!ifO be ll sei L . Ei1e .-gy uat. cl!(nve rted to e•Jectr-i'r,H·y app;ea f's ;;s the r.tn ai
energy, warming the photovoltaic cells. This energy can be captured by water
pumped over the back surfaces of collecting cells. The resulting warm water,
between 60°F and 170°F, can be used for space heating and for domestic hot
water heating.
Using photovoltaics in a cogeneration mode reduces the electrical effi-
ciency of the cells. However, high-efficiency cells are less affected by
high-temperature operation than are silicon devices. In most cases, if a use
for low-temperature thermal energy exists, accepting the losses of electrical
conversion efficiency and using the thermal output from the cells directly is
preferable. Using these systems could be more efficient than using straight
photovoltaic systems for certain applications. However, even in regions hav-
ing favorable solar resources, these options are expensive.
Performance Characteristics
As stated earlier, conversion efficiencies for photovoltaic systems range
from 2 to 13%. Including resistance losses of interconnection and power condi-
tioning equipment results in typical control station conversion efficiencies
of 8%.
Experience with photovoltaic systems to date have shown the systems to be
extremely reliable. Maintenance can be scheduled during periods of no sun-
light, essentially eliminating scheduled plant outages during hours of sun-
light availability. Likewise, due to plant modularity and generally high
reliability of plant components, it appears that unscheduled outage rates
would be low. The resulting plant availability is high, estimated to exceed
90%.
Because of the high plant availability, the capacity factor of photo-
voltaic plants will be largely controlled by the availability of solar
radiation. Available solar insolation data for the Railbelt are extremely
limited; however, it is unlikely that an average annual capacity factor
exceeding 20% could be achieved in the best sites. As discussed in Sec-
tion 7.5.6, available solar radiation in the Railbelt region would be greatly
skewed to the summer months, with relatively little available to meet peak
winter loads. Estimated economic life for a central station photovoltaic
system is 20 years.
7.58
7.5.2 Siting Requirements
Solar electric generating systems are optimally located in areas with
characteristically clear skies. The geographic latitude of the proposed site
also plays an important role in determining the intensity of solar insola-
tion. Low sun angles, characteristic of Alaskan latitudes, provide less solar
radiation per unit area of the earth•s surface, requiring a greater collector
area to achieve a given rated capacity. Increasing the 11 tilt 11 of collectors
relative to the surface of the earth increases the solar power density per
unit area of collector but results in shading of adjacent collection devices
at low sun angles. These factors, plus low solar radiation availability
during the months of greatest demand, place severe constraints on the devel-
opment of solar energy in the Railbelt region.
In addition to the latitudinal and cloudiness constraints, potential
sites must not be shaded by topographic or vegetative features. This type of
shading does not present a severe restriction for development in the Railbelt
region. The potential for snow and ice accumulation also inhibits development
of solar energy resources but should not be a severe constraint at most
locations.
Because of their relatively low conversion efficiencies and the diffuse
power of incident solar radiation, photovoltaic systems would be fairly land
intensive if used for centralized power production. A 10-MW photovoltaic
plant would require approximately 20 to 50 acres, depending upon cell spacing
and other variables.
7.5 .3 Costs
Table 7.9 gives the estimated costs for solar photovoltaic systems. Costs
of photovoltaic systems are extremely high compared to other technologies,
mainly because of cell manufacturing costs. The costs of photovoltaic cells
are currently much higher than projected to be by previous research and
development progress.
Capital cost for a 4-ft 2 photovoltaic array (18 volts, 2.5 amps) with a
rated capacity of 30 watts is $500 or about $17 ,000/kW of capacity. Costs as
low as $11,000 kW of capacity have been reported by the federal government
7.59
TABLE 7.9. Estimated Costs for Solar Photovoltaic Systems
(a)
(b)
(c)
Cost of( a)
Capital Costs O&M Costs Energy
Rated Capacity {$/kW) { $/kW/,iT) ($/kW}
10 MW 11 '000 (b) 30-40 620
10 MW 500 (c) 30-40 54
Levelized lifetime cost assuming 1990 first year of commercial
operation. 15% annual average capacity factor.
Current (1980) costs.
Department of Energy estimate, 1986.
when buying in large quantities. DOE had forecasted these costs to be
$2000/kW in 1982 and $500/kW in 1986, and as low as $100 to $200/kW in the
mid 1990s (EPRI 1980b). However, these projections are largely based on
efficiency improvement and production cost reduction goals, and as mentioned
earlier, projections of cost reduction have failed to fully materialize.
The average life of a typical photovolatic cell is about 20 years, so
provisions for replacement will have to be included in the maintenance costs.
Other costs include maintenance of battery storage systems, voltage conversion
systems, and the auxiliary backup system. Operating labor costs include clean-
ing the photovoltaic array (removing ice, snow and dirt), checking batteries
and conversion systems, and maintaining a backup system, if one is used. O&M
costs are estimated to be 30 to 40 $/kW/yr.
7.5.4 Environmental Considerations
Photovoltaic systems do not require cooling water or other continuous
process feedwater for operation. Small quantities of water are required for
domestic uses, equipment cleaning, and other miscellaneous uses, but if
standard engineering practice is followed, water resource effects should be
insignificant. If hot water cogeneration systems are employed in conjunction
with photovoltaic systems, continuous feedwater will be required to offset
system losses. Because cooling water is not required, water resource effects
should be minimal.
7.60
Photavo1 Jta1t elec'trtc po wet> oon ve·fsiofl systems have no impact" on atobien·t
a •ir Cjual'ity bet:ause the,y dti tlilt em1t gase·tlU<\ po11t~tants •. Oniy rn rli1or mtttH f.i-·
t>a·f'ions of t~e m1cl".ac :n ma:J:e wtl1 oc;eur ·near a s~la:rr epergy f-,at;1lity •• Ntl net
djs.(:.l:'ia,rg~ o f heat-ocwrs -as with i'os.s ti, P.lpmas~ ar1,d 11t.lc: leq,r fac.H ;t,ir;s, a nd
tnt! pet 1'-ff.~-t t~: a .s-lig ht r~dlJ ~t.ign tn ttte tJeqt av4i1ab1e . frorJl -sQfar
raoiahpn, oo'l'respend ing lQ tt:le p l ant efi"i e1 ency.
Utre to l)linimal •J~at.er t>~Quiremerrls ~ t ·he .opera.tJ.oo of )11~otovo lNk sy.stem~
will have iflsigr'l)f'tJ:atJt 1J11Raets on f.resh wa ;r;er ot lli~ti,ne· tdo.t a. IttE m~jlll"
J;err.estr1a1 i mp·ae t . o'f P.IJ,otf1vo Jta,fc syste:ms; 'fs ho.b i tat l.nss. Ttl i$ 1ttss· c:oul!'.l
.be se~ere f.or tJtfi Ht..t-·st a 1e sy~e)ns Mc~y se, o'f tl)e lancH'trl:et•~ ive· ·ch arac-
t'etisti c M 'lllit!-Se· tli!CilhpT.og.j es . !(f' ·tt;~ese ">~s:tem;. an! 1 oe.l(t~ in remote areas,,
tiH! f)Qt?ntt\\1 f.nr wi1.Hil e. 'lli'sttrrbQ.~:~te tfrtl)~gn fncrea..~,e.o )1.u.!nM acces·s may !!'lso
l>e sig)i lftCMt..
1.)5 .? Soc i.iiJkbttomi c eon~illera:l:-io.ns -
&r:11 ·ar ph otovo1'talc systems· reqllir~ tJ 1al'ge co n ~t'i<uc.tiof\ ,ww k liorc.e .and a
~llla l l oper.atfng antl rochn terrant)t staff. A 10.-~. ptiMuvo1'tdit: 1r1ant-wou l d
reqb11'e a ¢Oil~ll'l!C.f:~ on wor ,k force ali 1:0.Q atttl an oper<);M n;g :aM. maint.eqan<.l! wor:k
f.orc·e of 10.. Tt\e: impactS WClti1d r~p~ from rnqQerate tQ -?:eve re .on cO'nnr tm!it.)es·
witft \:l·DiN1atioM' af, l 'e:;-s t~.a11 5;QQ11. C1ltr~tr,!!eti OrJ leaGl time wgu ltl r-qnge; from
1: to, 2 year s .
Allihtmg h a rl!l .dtiv:el) l'a!"'ge. conl>truotion wor tt force i-s-u·sei1, ·so l ar· elec.-
trlt:;. general;.i n!# ·!'ip ~i on s-r eq!J 'i ~.e large i·nve-strnen'lls in h i ~h-torohno n o;gy equipment .
Or the pm.J:ect iilve-stfll~nt , 8'0% ·~u1d fle Sf;!!Jlt OCJtsiOE Al&~"o: i!i\d 20 ~ wnuH:I
rema:io in Mask ~ •.
7.5 .. '6 'Pot<>ntla l Appl~cd,tion lri tfle l{afl'li e11 Reg56n
~<:r}~r ins-olat..i.on ia:tq rm .n ·e-c.t:e(:l ~t Fairoanlq;., a:n~ at.l4 a1i~ri~sK~, 1\e;J.r
/'-JI'dh orage, ,wer.g e g~mi(le.'d .. rlle. .(Ia til l~enet,t. the. infl!Jl!ti ¢'~ of· Mt!;\ ,;,1 -or:ld 1f)'e~\i
alld the o,Mua1 c;vc.l:e in su!\ o.rrgle .at ff1 ese Tocat-i·on s. A•t fa i 17bankls tl'ie total
r;l'a i1y !lll1"a.r n.W tat'ion .on :a 1\@ri:z:onta 1 s urfase. i-s 1~ Btu/n.2· 1n Dec.emhe r. o.T\Q
1 ,.,9.69 \ll:ufft 2 i'n June . ~t. tilat~pu.S:ka the.s·e :V~ll•es r ange: f.r.&m .<fa ll't..Li/ft2 fr •
Detember ·to. 1,730 StiuJif11 2 tl'l .ltille (flgu,•e 7 .. 17). fn r:bnlpal'slo!l', ~n lt'fe ar HI
1.61
SOLAR RADIATION
BTU-DAY /FT2 1500[1] L.l!:A
lOOO l dill i ' ' ~
I ~-~ "---.._ 500 ~
,..-! ----,
SCALE
0 ~0
FIGURE 7.17. Solar Insolation for Selected Railbelt Locations
7.62
sGJuthwestern Url 'it~Ll .Stat~ .. ll~nUary v.alYe''>' a:f .J,20~ ~t:Y /rt2 arg cb•rmo'rl ·wihll
ma rlS' ~rea& l:l<IY il\9' Ju l(y .values ov"r :2:,'5\lQ Bt..u/ft~. Ey~n in llt~ favor:ed
are<}s, s~ch 4& Miml~sota, the!.e ·sa:me values vary f rom '550 Btu t~t2 to i?.QQ'O
Btu;n2 dtlrf ing t oe y.ear. l'·~~s·e 4iitlt 1 ndi cat~ t~at Wh l1e. .art iibunclar~t s·ifPP1 'J
,,:f s01a1· er'l,er.gy ex i <;1\S, Oil a ~o1'11 2 o~"tai SJJ.r-f~~ tn mid'S.UJffil~r Hr Alaslta, t he
mfd~vi ·n ter va lti ~s are. .at1 drd~r.-of .magnit ude less 'l;hlin tlldse .o.-f ev'1!n p oo.-.s i.t-es·
in t\he rem9-i :od~t :of 1ille cour.rtrJ~ E:v~ on south-f.at·irx9 vert ic<~1 v{a1ls{ t h~
tlaily t o•t.a.l ~o l11 r r-aili~tiol'! i rr Mat.anus~a i.~· only .JQQ' l}tu/ft:2 'in D!<QemiYer ,
WIH~:h indi~ates that l;.l1e me ve treorie:ntat tCln o.f. eon.ectin~ "~Jrhces wi}l nli ~
al.1~vi.at-e t ne l·ac k· ·Of w'inte r>t ime solar ~n.so l'll'tton,
lila la.ct ttf winte-r s unsh i ne ~n tha RC~iliJ-elt deal''l Y itm jt~ t he d.eYe-lep-
·me"!.t :of so. 1 ~r · :err~rgy ~~ 9-res.o~rc;.e f or · e l:~t·trfc ,)io)'le"r · '9~.ii~J"at1 o'h t:or tY10
l'ga.~~rrs. F"i r'st, P.ltll)·t u.M lii4t.i .0n tn · ttre 'fl 'lru:~r l'iDJ.fld il10 e&:l\reroely low ,
le4!li'li!J: to lm-1 ~nn~pl c .. aRac ity f ·adOi"s , r~suttiltg in .trig}t p:r,til1uctiq(l L;;Q"t$,
Se~nd., the Railb:elt ;~ tlfqta~tertzed b,y a .wirltl;r l'e.a~irr~ el~c tr'iG<a1 l'oad'
'becal.lse o:f tncreasefl demand s 'for s pac e heait rng and .e1ectr1 1!: li~hti<\19 in the
winter rnonth.s , So;hr-.Qa·s ed eil.ectril!:'al' produc1lien wotlld no-t coinci~ wnm t he
period elf :ma xi mUJ!f -alJnu;al loa,d , l'~q ~:it•i ng no n so Jar ge ne:ra ti'ng f.ac;11 li1¢s -tl)' be
u ser;! du r.jn~ t he win t e1· ni'ortth s,. A·lt&\"na~Jvei;v. an ef'tremel'y l ao~'ge amQurt ~:~f
so l ot c;ap,a~;1t..Y. .~Q~t ld -~~ iJ1S'tial1'E!d t o"metl't w'ir;Jiett.i)ne Toa~s ; hQw~vel', t~i~
•cap~ 'i't.Y wi>ul ·r;l ,p-e id Te d.ur ing ~uiJiller mont.hs, .aQ'\ i 1'1 lea.;! fnq tg 11 i gh 'Pr.Q.dg~t fon
CiOI'. t S.,
7.6 3
7 •P SOLi!.R l'HEIRMi\l ELECTRfC 5~·Stft'fS ' ·-' -
As .d'JS"C!J$."S:ed in t!l<! preca~in·g, s~tiorr two basic me~twr:is for gen-e•'a~f·ng
ai .actri" fHlW.$" fMITI i>ol;fr rao 'i .at.jorr -a.re. una.e .. d ·~ve1oJllneftt:: sb'l a'r 1lt"l1'!rm~.1
gonver.s·i on and pliofovo Jta. i'.c s.Y$tern.s:, s~ Tar thermal srlt~m ~ i 'trvo~ve tf~e c.,OI:i-
~ersion Qf sohr e'nergy t o neaT. via a irran ·s'f.er med~~lfl. lh f s medi4m {V!JkkiflQ'
f lu id). '"an bt1 w~tt1r-, aH~m .. a 1r. -vari·lllis so 1 ut.1ons .• or rna 1\en 1neta 1. .E-nei'gjl
~s r·.eaHzed as work 1vherr ~he f.JL(id is use;:! to dt•lve a tu t•bine •.
Avatl a.b ·le. so la:r ener~ is di:utirtafl;y ana seasonally Yarl'~b1e and is· suJi-·
;1 ect U> l.m tl~fr~~i nt;i ~ ·af c·.l olld c:ovar. a_n(J llrec ~·l?i 4tt.i et'l. Tfius .so·l '(l.r tllerma·l
,;;ystem~. HKe solar photovo lEa i .e :$'YitJ2~. must eiEtrer> :tie: empl'o,Y,etl · as . .s "fUe!l--
5\\V'j •ng" op t i>Go, :or th~Y. ·mu;,;-t be i n·.s.ta 11 gd II' i'th ~dequa<l:i~· ~llQr a~i! .t;;.4pae i'ty. In
add ~~io.n . if t~_e. diurrTiil anlll :annual load i>Filfile~ ill.rer out of plj-ase .wit!i a\\all•
al> 1.e. so 1 ar l!nerw t"e ·snut<ees • t ire· i nd~.tem~nt!i fer deve1 ~p (ng uh is res;eJJI"ee> -~
f'yr-the " !reduc ed. C!'l.dd J:!rOfJl~s ar>tl s:o.1ql• 1'e$0Ui".t:';l ~vai1ab111t,y ·g®ei•a.ll'y. ,QQ
ntlt t:o r·r~S·!l.o.nd. ill ·t;he Rallbelf l'~iqtr , t.Jhe.'<'e deman d. g!OMrallJ pea'*s 1n.winte,.
.wlla a); !li g~t .
l-6 -l Te~'hni :t-al .Gt\.J:ra¢.t~ri .s•ti~s
S'otar therma,l syst~.n\s J.IS.e 'fot;1.fsed Sul11ight to p·r.av f~e ~\itrc~trate.Q iheTifllal
eoef!!Y·· Thls .ener<\lY · iS th~n ·l!S'\ild to ~ro!J..a)Ct het\t. tq wanltin'g fli,fi •d, whi 'G~ j's:
t lien used t~;~ dr·i.Ye t'ur bog;en·erators to pf o:duce e.l:ec.tr ·tti·ty.
De s''i gn teat.trra.s,
' J
The. two most al:lvanced so iar thet'ma 'l s,y st.ems a-re· p,ower · co.t~e 1•s-and pard.-
bol1.c. diSh ·ool'iec t 6'('$.
Powe~,. T'o.w:ers.. A _pm~er to.w(lr >Jse-5 so1<!.r eMrR¥ t o ra is.e a 1/orrl:in.g, f •ltJ1'<'1
to htgtr ten1per·aliur~s fQro :tljle. geoeratipn gf el~ctr1df,y -or · prq ~e:5'~ h ·~a t .
Qp1il·Cil.l s.1.u·d·ie::s Maw th ·a,t J:he Jn5t ·"'il,l/ to go;ner..at:e· 11 i9h teJilpe'~'a:tlii:'e? us ·; o,g
~a lar ensrgy is. w>t th a p oin~-·flil.c~,tsing ilrray of m11"rors: }ltat tr-a.:k th'e . ~Wl
(he li o:ttats), The ·So 1 ar Nd i ·atoion j ~ focu s.ed Qn 4 l:t o.il.er se ti atop· d \arg~
tower. fie JXI'!s'MU ~ha.'t cont:entr:tl.'te stJnl i 9~ ~ :S,eiiera T ~u>1d re:d time-s are IJWeO to
'I'd lse the-tetilperatu•·e in ·th~· 1.\o.t l~r ll.o 500"'t, and the•f1'_es-tJl ting s:ileam t .an lie
7 ._64
used to produce electricity using a steam turbine. Back pressure or extrac-
tion turbines can be used to obtain process heat for cogeneration applications.
The first solar thermal test facility (5 MW) has been completed at Sandia
Laboratories near Albuquerque, New Mexico, for $21 million. The second is a
10-MW electric plant built near Barstow, California, developed at a cost of
$130 million. These two projects, largely funded by the government, are due
to be followed by a 100-MW demonstration plant in the late 1980s, and finally
a 100-MW prototype commercial plant in the mid 1990s.
Parabolic Dish Collectors. A regime of intermediate operating tempera-
tures (300 to 600°C) can be provided by solar systems in which the optical
standards are not as critical as those required for high-temperature systems.
The efficiencies, however, are markedly superior to those of the low-
temperature collectors used for space and water heating. Intermediate tem-
perature collectors could be used for process heat, crop irrigation, and
decentralized generation of electricity.
One such system is the parabolic tracking dish. The system operates by
directing the sun•s radiation to the focus of a large dish where the energy is
absorbed by the working fluid. To produce electricity, the fluid is circu-
lated through a small heat engine (Hill 1977). Higher temperature systems are
being studied. The Solchan concept uses solar energy to drive an endothermic
reaction of gaseous compounds to achieve an operating temperature of 750°C
(Krieger 1981).
Performance Characteristics
Conversion efficiencies for solar-thermal systems are climate sensitive
and range from 10 to 70%. Because of the lack of operating experience with
solar thermal systems, no reliability data are currently available.
Assuming that unscheduled outage rates will approach those characteristic
of other generating facilities and that scheduled outages can be performed
during hours which the sun is not shining, capacity factor will be controlled
primarily by the availability of solar radiation. As discussed in Section 7.5,
information on solar insolation in the Railbelt is extremely limited. It is
7,65
unlikely that an average annual capacity factor in excess of 20% could be
achieved even in the best sites. In addition, available solar radiation in
the Railbelt region would be greatly skewed to the low-load summer months.
Estimated plant life for solar thermal power plants is 30 years.
7.6.2 Siting Requirements
Solar thermal systems, like photovoltaic systems, are optimally located
in areas with characteristically clear skies. The geographic latitude of the
proposed site also plays an important role in determining the intensity of
solar insolation. Low sun angles, characteristic of Alaskan latitudes,
provide less solar radiation per unit area of the earth•s surface, requiring
greater collector area to achieve a given rated capacity. Increasing the
11 tilt 11 of collectors to the surface of the earth increases the solar power
density per unit area of collector but results in shading of adjacent collec-
tion devices at low sun angles. These factors, plus low solar radiation
availability during the months of greatest demand place, severe constraints on
the development of solar energy in the Railbelt region.
In addition to the latitudinal and cloudiness constraints, potential
sites must not be shaded by topographic or vegetative features. This type of
shading does not present a severe restriction for development in the Railbelt
region. The potential for snow and ice accumulation also inhibits development
of solar energy resources but should not be a severe constraint at most
locations.
Solar thermal plant efficiencies are higher than for photovoltaic systems,
resulting in somewhat less land requirements. A typical, density-packed 60-MW
tower would require approximately 160 acres (Metz and Hammond 1978).
7.6 .3 Costs
Cost estimates for solar thermal systems in the 10-to 100-MW capacity
range are expected to be 1500 $/kW (1980 dollars) when commercially available
(1997) (Table 7.10). Construction time is estimated at 5 years. Annual O&M
costs are expected to be 30 to 40 $/kW/yr (EPRI 1980b).
7.66
iiilillG. 7.. W, E ~l! ima ·'l&i co s ts. 'f'llr So 1 ~r rn ;:;mn a·l SysMillS'
1Q ~
100' MW.
1500
110.0
O&M CIY~ts
l$/~W/!?1")
'30" '4Q
2P-'36
Gds t dfLa1
·r ni;!J\Il.Y
_j;~/~W') ..
.91
1~
l ~'l.fri'i~ed ll fe~11'1fe C:[1$..t. ass u lll~lliJ: 199/ f:i 'i"s11 year o{ tll11111e rc ial
op~'t~th1h ancl ' 15~ c-ap.ii-c5t.y f at tor ( .;omJY afa b .l ~ w 1990 HI"'~ ~ear
pf .operat tb11 tost s !]'~'len e 1Be'tlhere itl t j1·1s reP,o•·'t. .(Ju e to 1 a<;J< Qf
fue1 esC~~.T aJ,I on ').
7.6 .4 EtWjf onrnentd.l Cons 1rl¢J"atif:o!J2.
So iar ~11e~m.al. .co,nvers iot1 systems .1worJ Ttl p i'Ochl ce water re·seurce> ·ef.ffeds
;tmil a!t to tticlse o.f o·ther -s,team -cy,crl e f.acr il Hi e s. rtoii.er f~edwater and
ccmtJ~ntrer· GO.Q }'ing .)'tllt-er l'l·i 11 Q~ r e.quir;e(J and w~ 11 neces'S-i tate ~t'OP~r' ma,nagr;-
ment itMhn i ques (·r..ele·r t;a , ,1\ppeodi·x 1)), CQe 1in-g 1i<l1:er re.qli i r.el1)'\!11t?-<Ire
·ex t re.me l·Y s.i t e spe~;1 fi c,, as e:ffi c i-en e'i e.s t)4.1JQ i 1'\9 fnom l:U to rU~ are ~ds-s i<b·J e
~ependi[lg up on ~1 imat k fa~tor-~.
5Q l ar thenna, l elJTT ve l"s 1011 s,vst.ems m·ay ~ l ~o 1:1e-o.!>i!tat.lf.d l.l 'l;ii1lJ a WO'I'k tng
fi11·i d otthef' .than ~~at:er. Prop J:ls:etl WOl"~ing f l 1-1 td,c; i nr;,l.ude ~ i qu1 d s.od t um, s.octium
nyd)'oxi <;te-, llYd te:e~fhM oi'l s,, aml ~ad i urn ilttd trnt~s.s; u!ll r~.i tr.~tes ·,;.ntl n iUr<it$!S.
These s.ubsta·nte-s. havE! the. 'Pb:t.ert!:i a. 1 1'.<1 . ad verse 1 y aff'ec.e. Wate'r' •(1\J;<tli't\y-'tlli'rouljlf
aoc;: 1deJ.fa1 .~,p·; ns Mil 1io~'1i)a l sy,$te)11 fiu{Sfl ing,. ~ec ia liz;ei;J tr anspf'l'r'f.~hp!1 -aod
l'u!ndll i\,g t.'~~tan\\IU"eS '\~ilT ~.e-~et{uirs<l t Jl mi '1J ilil1le t h.e r~sk .af'.spi l h · aod 'to
m'iti~at~ llot:.en"t,la1 itJJpact.s.
S.cll~r t-11 ~rc.ma 1 ss.stems h-a,ve no inJ~tad ofi ?dll\ll:l~n.t a ir qua ]1 ~,)1 oec:<ause: tt.teJ.
do t10 ~ emi't gaseot•s po 111:.1t:8·11t ~. .Ho.wev et'• ~~te--r · vap·or· pluin.es. m ~y e111~n q~ f ~m
.coo l ·i n~ sysJ;elil!'i•-Tnese p \t.lt'n~~-I'IOLI ]'d h~~h' 9e g f le.ss con'S?'Jll.~nce t~~~~ f.'or
nUC'M!ir or c9rollu ~t1 o(J -f k·~ sti!<J.Il\•el e\:;t r·ic P.·1 a·~~:1:s 'bee; au se ~ol ar -tlierm ~ 1
s.ystems u pe ~t.e. llegt to f u·ll stAn 1 i ght when the hu!J1td i ty, tends b1 be. I'll' n ~e1o\,?
~liu 1')!tfQrt . Uo!':!er-these cend. iti J;ms , t li e-\1'1:\ter propi·ets ·are qu i.c:kJ y B'liljlflnted
in t o -tne pry .rtmosphe 't'e. The plumes c-an -also t;e mi tqgated by us i11g :dry ar
Wl!thll'y coo1 1'!ll.l to1~!!f' -systems-.
7.61
Only minor modifications of the microclimate will occur near a solar
energy facility. The heat is merely redistributed within the facility and
will not affect climatic conditions offsite.
The major terrestrial impact of solar thermal conversion systems is
habitat loss. This loss could be severe for utility-scale systems because of
the land-intensive characteristic of this technology. If these systems are
located in remote areas, the potential for wildlife disturbance through
increased human access may also be significant. Spills of nonwater working
fluids, if used, could adversely affect local ecosystems.
7.6.5 Socioeconomic Considerations
Solar thermal conversion systems require a large construction work force
and a small operating and maintenance staff. A 10-MW central receiver would
require a construction work force of 60 and an operating and maintenance staff
of 25. The impacts of the system would range from moderate to severe on
communities with populations of less than 5,000.
Although a relatively large construction work force is used, solar elec-
tric generating options require large investments in high technology equipment.
Of the project's investment, 80% would be spent outside Alaska and 20% would
remain in Alaska.
7.6.6 Potential Application in the Railbelt Region
As discussed in Section 7.5, data indicate that while an abundant supply
of solar energy falls on a horizontal surface in midsummer in Alaska, the
midwinter values are an order of magnitude less than those of even poor sites
in the remainder of the country.
The lack of winter sunshine in the Railbelt clearly limits the develop-
ment of solar energy as a resource for electric power generation for two
reasons. First, plant utilization in the winter would be extremely low,
leading to low annual capacity factors, resulting in high production costs.
Second, the Railbelt is characterized by a winter peaking electrical load
because of increased demands for space heating and electric lighting in the
winter months. Solar-based electrical production would not coincide with the
7.68
pel"iQd i:lf ma_)l;\mum Mffua1 l trqcJ, rE;ql1 irin-g non so1 a1"trener<~tl ng hci1if11:;s t6 M
us.ed l;i ur'l ng · thg wfn~~r mo rftt•s . 'l\"1terna fively, -an· e·mtremely Ta.r ge a,mou.nt qf'
solar (;1i~ac lty c'OI!J,ld be in'*a1led to tneet wtnt:e.l'1: i!ll~ l oads; tlowe vei-, t:h·i"S
:e apa;ci :l._y woliilll be q·ct1e atrring .scumrer manths 1 again 1eadl'ng to h i:g~ p'r'eau-ctio.n
cost s .
7 .6~
7.7 SMALL-SCALE HYDROELECTRIC AND MICROHYDROELECTRIC POWER PLANTS
Small-scale hydroelectric plants are those having installed capacities of
15 MW or less. Microhydroelectric facilities are defined for this profile as
facilities having installed capacities of 100 MW or less. There is, however,
no consistent cutoff between microhydro and small-scale hydro facilities, and
the interface between the two classes of facilities may be as great as 1 MW.
7.7.1 Technical Characteristics
Small hydroelectric and microhydroelectric facilities differ from larger
conventional hydro facilities in several ways. First, most small hydro and
microhydro projects have heads of 100 feet or less. The turbine and other
powerhouse costs are more closely correlated to river flow rather than head,
and therefore the per-kilowatt costs of this equipment can be relatively
high. Second, such facilities are generally constructed based soley on the
benefits of power production. This is in contrast to many larger projects
that may be justified on flood control, recreation, or other benefits in
addition to the power generated. Finally, many small-scale hydro and
microhydro projects have little or no working storage and they operate as
run-of-the-river units. Capital costs are therefore reduced, but scheduled
peak power generation is not available.
At minimum, a typical microhydro or small hydro electric generation facil-
ity consists of a hydraulic turbine, an electric generator, a powerhouse, a
water intake structure and a penstock. Grid-integrated units also require a
power transmission system. Also, depending on the specific site situation and
facility configuration, additional equipment and structures may be necessary,
including dams/impoundments, pressure tunnels or conduits, and other civil
features.
Design Features
Principal turbine components consist of the runner, a supply case to
convey the water to the runner, wicket gates to control the quantity of water
and to distribute it to the runner, and a draft tube to convey the water away
7.70
from the turbine. Hydraulic turbines are generally classified as either
impulse or reaction turbines. The impulse type turbine derives its mechanical
output from the pressure of one or more high-velocity jets of water hitting
the periphery of the runner. Reaction turbines use the combined action of
pressure and velocity of the water that completely fills the runner and water
flow passages.
The net head of water available dictates the type of turbine suitable for
a particular site (Figure 7.18). Reaction turbines are classified as either
Francis (mixed flow) or Propeller (axial flow). Either type of turbine may be
mounted vertically or horizontally. Propeller turbines include such trade
named units as Tube, Bulb, and Straflo. Impulse turbine designs are classi-
fied as Pelton and Turgo. Cross sections of the various commercially avail-
able turbine types are shown in Figure 7.19.
Water wheels can also be used to generate electricity, although at a sig-
nificantly lower efficiency than higher speed turbines. The undershot, breast,
poncelet and overshot wheels are usually large diameter, slow turning wheels
best suited to generating mechanical power for such equipment as pumps and
lathes. In many areas they must be housed in large structures or provided
with some form of protection to avoid freeze-up during cold weather operation.
The generators, either synchronous or induction, are selected to match
the turbine type, turbine orientation, and the nature of the grid intercon-
nection. A generator for a bulb turbine is located in the bulb, whereas a
horizontal generator is generally required for tube turbine. A vertical shaft
generator is appropriate for most Francis turbine installations.
Off-grid installations use synchronous ac or de generators. Synchronous
ac g~nerators require a turbine governor to maintain the required constant
operating speed, but have the advantage of providing alternating current.
Direct current generators allow direct connection of battery storage facili-
ties, but require inverters if ac power is de.sired.
On-grid installations typically use induction ac generators, with fre-
quency controlled by the utility grid. Single-phase utility interconnection
may be made with a de generator with a solid state static inverter (Federal
Energy Regulatory Commission (FERC) 1979).
7. 71
300 t 1
t2QO
l.'t
,i:j -2:
~ <( .... If ...... 100
..1 0: 90 "'· :5 so. <J.
j"" 'J:' .ffi ~ '1'0 >.
j;; 60.
~ ILl ... eo ... .., 40
"' z
~ $0 a: Ci
!-
~0
10
D 5 lO
~ENEFIA'T'Off 10AP.A'C.1iTY ( M ~)
PIGUE!E t.l.B'. 'TUI'b l·ne J;J.pe·r·.gping .R aJ)g e
~ti!fl¥ m~nUfar::.tL'"~~s of tur-:bi'ne....ge'ler .at or u.n tt s f.or mi ·.:•·oh)'droe le~tr ·t·E r.tlil·We-1"
plant-s are CU·Y'~'ent.ly, UJar~t.e:tinSJ .Smq 11 wa<~ag,ed unit~ rai\d ~tat'fdard ~UJ ,g!ls,
par·~ i l>JJ l.ar),r r eac.t i..on t l!r·b ine sy.l;tero:;. The-s e (l(a nu f )ctur.e rs ;w<: l.oG'.a tetl both
'i 1'1 Et:J ~op.e :p,nd Ntjrth A))led oa.
~IS De s p-1 o.eif in· S.'~c t i ~~~~ 5. 4 .1 , follY bas 1 e ea'f:!=!9'Pf' l es of d,a!ns e~-i.st..
~e~f!r-Vn i l"'S may 'tre ooe o:f P¥1o P ~'finar)l ilY.P~s . l)ne i·s. a n(n-o'f-tl.he-r'ivef'· ini~.O\ln(l~
ment· l'!l:!er~ tto.e head i5' hlw and 'ttle rese:rv.o tr ~tap .;:j\::'it..y is ~tna.Jl . Jr; 'l:ms; t :jpe
VERTICAL FRANCIS RIGHT ANGLE TUBE
HORIZONTAL FRANCIS BULB
VERTICAL PROPELLER • RIM
OPEN FLUME FRANCIS OR PROPELLER HORIZONTAL PELTON
TUBE CROSSFLOW(OSSBERGER)
FIGURE 7 .19. Turbine Cross Sections
of reservoir, the water level fluctuates little. Storage reservoirs have a
greater capacity and are designed to acconmodate significant fluctuations in
level, depending on power demand requirements.
7.73
Associated with these dam-reservoir installations are various appurtenant
works to control the flow, including spillways and outlet structures. Fish
ladders, navigation locks, and log sluices may also be required for certain
sites.
Performance Characteristics
The typical efficiencies for various hydroelectric facilities range from
50 to 85%, depending on the components and scale of the installation. If the
head and discharge rate are relatively constant, an overall efficiency rating
of 85% can be achieved. When the head and/or flow rate varies, a more precise
analysis of the efficiency is obtained by taking the product of the turbine
efficiency and all other losses (generally assumed to be 0.95). As the head
and/or flow rate vary, the expected efficiency of the turbine drops off from a
maximum of 90% at 100% rated capacity to about 75% at 20% capacity.
For microhydro installations, the average overall efficiencies of reac-
tion and impulse turbines are about 80 to 85%. Water wheel efficiencies range
from a low of 25% for undershot units to 60 to 70% for overshot wheels. On
the average, microhydro plants are 50 to 70% efficient, with the higher effi-
ciencies occurring in high-head, high-speed turbine units.
Specific information on plant availability is not available but is likely
to be high. Grid-connected microhydro units are generally operated as fuel
savers. The typical plant capacity factor for these units ranges from 60 to
100% (Alward, Eisenbart and Volkman 1979) with an assumed plant life of about
13 years.
7.7.2 Siting Requirements
The primary siting requirement is the need to ensure that a sufficient,
minimum continuous flow of water exists. Both the minimum flow rate and the
portion of this flow that is available for power generation must be known.
The percentage of the minimum flow that can be diverted to power generation is
influenced by factors such as fish requirements, agricultural needs, and
recreational/aesthetic restrictions. One manufacturer of microhydro compo-
nents suggest that no more than 25% of the stream flow be used for power
generation. This is only a rough figure and each site must be evaluated
individually.
7.74
In siting a small-scale hydroelectric or microhydroelectric facility,
considerations must be made for the distance to existing transmission grids
and roads. Overall capital costs for smaller installations are very sensitive
to the cost of access and transmission facilities. Land requirements for
nonreservoir civil features should be relatively small because typically such
installations are unattended and remotely operated. This reduces the require-
ments for working space, storage area, maintenance facilities, and operations
facilities. If a dam is necessary, the siting of a hydroelectric plant must
also be based on a full understanding of the physical characteristics of the
1 and.
7.7.3 Costs
Cost estimates for microhydroelectric facilities cover a wide range.
This range results from the numerous design variables inherently involved in
such units. Some of the major cost features include the hydraulic turbine,
the generator, the turbine generator accessory equipment, the civil works, the
transmission system, and the access roads. The size and resulting costs of
these and other design features are site dependent -the available operating
head and the general remoteness of the site have a signficant effect on the
facilities• total cost. In Table 7.11 the estimated capital, O&M, and power
costs for small hydro and microhydro plants in Alaska are presented for both
remote and local facilities. The distinction is made due to the major costs
associated with access road and transmission systems needed to develop a
TABLE 7.11. Cost Summary for Grid-Connected Small Hydro and Microhydro
Plants (1980 dollars)
Type of
Facility
Local Facilities 0.1-15.0 MW
Remote Facilities(b) 0.1-15.0 MW
Cap ita 1
($/kW)
800-15,000
6,500-20,000
O&M
( $/kW/yr)
16-290
130-410
Cost of
(m~~~~J~Wh)(a)
10-190
83-260
(a) Levelized lifetime cost assuming 1990 first year of commercial operation;
80% capacity factor.
(b) Five miles from existing roads or transmission lines.
7.75
re'mote: hyd.r oe Jec t l'i·r: <;ite , The cost tJata pFe-se11·tea i·n Tij]i l;; /,i.J were pasei:l'
Qfl 1n>Format icm frQn\ the Col"ps of Engineers {1:'179). PER C (1':17~), a.n11 Ah~ard.
E i>re nba1•t and Vo ~kman (19 79).
The~~ cost est1Jnates compl\r!!. fav ~r a!J l y with e~tim"tes. mile!~ hy th e Oll~"llS.
of' En:gineel"s ar1t! ot he rs \n a~ssessm~rlts of th~ coi'J)"ita 1 costs. for var1ous , sma 11
hYd r.Qe 1 ectl" i ~ ,prp~fid!. cLAr·r;ent 1¥ IJ!'id·ergni ng feJl~ 1 b l1 Hy studies i h 1\ hs~a..
The$e ~rl)jeet~~ lO\lclJeQ i •r\ the Chlgnik, Perryv1 n·e. i!nd ~~~ko l skt ~r~a§. VIJ::)'e
esti'mat.ed tu gel]e.ra lly cos~ bet1~een $~000 artd $18 .,000 /kW.
7. 7,4 Env 1 rtr mnenta 1 Cons l.de 1•a t i oas
Beoat!Se of: ~he S!na n sf.z:e of mict'ol·w~r.Q a1)d sma 11 h.Yrl'rll fadnties, t heir
erW ·frotlrn!m ta I' imp act~ .gelle r.a l iY sftolllc'J not ~e '>i gn tfi c:.ant. l'he fat i lit ies are
not .anti C:ipated to pos~ s1 gnffl ca nt threat w p l ant~ and malltnals in the a.rea
l'llc to t.rea;~e any majof' l'm:HJ1em5> wit!~! the su ·r rtamdir\9 -eeol'ogical CQITillUOitfes -
pa r t' cu hr1Y where nu reservo~r is required , Hov1e ver, one ~rea pr t:oilciill'n i ~
~he l(npaot on the passage .nf the ~nadromous fish, If present. Fish passa-g e
'fiici'1t~i.es ·I'IOU1 ti o.e f equir.ei:l to mit i gate thi9' prp)llem . Sual\ p.;.ss-age fac ili-
ties should •b:e n-p erate~ otrlY. at l:,iiTIE!s of l'esid~lit fisiT rnigr'a'tiEI!i M p.r event
:tl'le blossage of .tJtJ/jE!s fratile fish, !'Mi~h t!laY have ti£¥ett p.re vi.oiJs ,IY blocke~ f~'>6111
enter ~og th~; yps'tl':iiali\ ~r~;as bY snta 11 wate 'rf!'! lh i~ the ;tream s.ystem,
/1nfl ~her item Qi( r.oncerfl is th ee env ironma11ta,;1 effect$· ,of the tl?an~rnis s.1on
ac«:e~s at1~ f;aci i'i:l\:es need~d tl'l 'ti'e the hYdro faai iity t .a the uH11ty gritl .
The new e uts ~hr:-ou9h tt•e forest f~;~r the p_!JI'ier carorid 'ors ·<lll fl qccess FOatls .eou1d
:disrupt ''ild li•f'e 1\aClHat$ and tnig ·rdl;i.on pa·tterns·, The more remote the 'Sltes
.arli! from e>J\ioti,ng power transmi;siG!n corr ~·~ort 11nd ~ecess fl)ads , t he g·reatP.r
th~ 1ike1ihMd ef s udt detrimental 'tnpar.ts.
Other ·env iJ•onroell ta 1 cortsidera t; ohs EJ f pot~?r\ti a 1 itil]Jor ta·nce in c lud~ t ·he
aestflet.ie ililp~ts ~:if the a~;:ces.s Mads4 transmission lines~ and ti vi ! war:~~ if
nume 'l'ous sJl)a.n hydropower plil,rrts w~-re t:teveld,petl, and the human irthusi.oh Hlto
prev1tiU$1YJJ!1d'fstU'i"br;d Wild11ft< habitat 'to .deve·loll and Operate tiill·$af~ci11-
~ i BS . The patenti a 11 Y l.arg!l •lYI!te r .of ml ~rol!;1'4r.O· ~ ftes-reCfU 1Ncl ~ produ (~
.s ignificaM r:Hnou~U of enei'SY ~~ou ll'l ;~gg rav.<>te these· problem&.
'A prenm;,nar;Y asse!ssment of th~ let·t>aln, preci~itatfon ,. t:r.ans-rni ~·lifl'l
systems, and ;q,tcess rcoad & {,Maf•l<" F.yer and ~ssoc·iates. Hao)· i 'tient t f.i•eo tlia
Fa trb.<U\k~. Sewcwa·-Ro,.,ta.~e Mil AnchQrage~P/aJme\" !!reas a,s po~~ ib 1 ~ h~vil'!!f
s.\l;ta.b 1~ nii,al!"oh,yi:lr(l <~nd sm<~,ll hyd~o $i ~es , iihe Bl¥!1inal l -e)1 .. -V,a l.dez al'e~ may
'i!''hb t\.ave. S"imilar lltltenit:i~1 f·or mkroQ;y,O:I'o and ~ma·n h~'feo d-e.v~lo,pmen.t. t.and.s
·SIJ(·l"Oll(li! i'r\Q' ttJe:se pot{Onti a] S i1;.e~, c·on,t"a lJJ 'W¥terfl}W·1 a'(jd 5€\lSOnil. 1 ra'ng'e)l Qf
mMse. 'fhe· :Sew.a:td t•eg 'i'on t;'Qiita.il'ls Jl !i!p~1.atiOll'S of bhek be;rr.-, rni.!Jr]lct1 ull
cof'r'i"®r:s.:, .(l(lJJ seas1.mal Nnges· nf cadll,OIJ. Jmpt\c:ts on thes"~< an lnra.l popul a -
Mon~ w.~ n de-pe)1d on the thii¥'-ae..tel"i st i'cs ·of the spettf1t; !>he AJ'id t he· deos1 -
tl'e\', 'Qf'tl1e 11iliih"fe p\?pU]:a;t iP't\S I n the S"ft:e arl'!.il· D'u.~ 1;o trw re.laf.1\lei y
~Jila )'1 ttlurtt C!i!J <(¢ i't J' e s tnvo 111/lt(i, h9W~-,(!!r, l(~p,q'Ct,$' .ShOV b;l be mi h ltnii ed ~hl"UU)Jh
t'lu~ ,n'l·a:nt sitJrtg ·prac~!l..
7 •. ii' . .S :Se.l!:i oeco11om.ic C'G fl.si deration s
M 1 ·~roh,ydro a11tl small hydro fad1 i U ·es 1</.f 11 r~equ ire a r.e lilt i ve W ~rna t 1
labor· i:or~ f ·o:r ~Qrrst,.~.~et.ioJt ·Md ?. min im ·i~Jl ntJmller tJ:f -pedf11.e 'for· operation •.
6e.c::aijse su.ct.J hy,dro 'fac iH'I'.:ies-a.re si1te \lpeci f<i ·c, s.vec "if~f l19 tlie s\"Z i!! M' ttres.e
cotrs t ruttl.otl a.M oP.~r a:jtions f·or~~s i~ d!iffi,,u H., De);lemd ~ng oi) tfie-s-fze of· !:lie·
f.~c.jltt;y, t~e d;s·t;;mq:¢ M e.:sH;tin,g !ietv-ic:~s •. and tne retruir~d dvil teatun~;;.
the tt!ll'f~tr-~:~cttoJI foNe C'a'!l range u,p to about :?{) ~ 11!:11vl.c(u.a,15'. Opel'atinn <1nd
1n~int.eh~n~e can i'lHIU ~,.e ai'T,yw\l .ere from enJ: p.ar.t-t~1ue irra ·ivia.ua 1 to allout .3 to ~.
·Ct>l'f &tl'tmtitJn (t~d ,~ds· for 100 kw ~Ci lS ~-kl fl!trll;ties . c.<tn aJ ~o .s·pa:n a· .w,ide
.1'\a hg~. )\ pr~ Hmin<lr y .esj:;.ill)~t:~ fQt' ~6l'i'$try ~,ti t)n Mil !;ffartiJP iJ> 11! tQ Z4 mon ~IJ:S'
(1$t 1 uiHn.g tM 1 i ten~'i:ng prOJie~:> ]. P.reton S>ti~:>Utti·cm ~ud .'i es 'a tid l 1 cetts:i ng iilM
't"F;iqu~re art ad~i,ti'!ln a l 12 to '?4 Ofdn,th!>,
Posslb1"B . l.Glc<dions of slna l.l nydro atrJQ tilitooi'IYdilo f'acilit.i-e·s would· include
.s f ~es n!O.ar the e11rnn un iH e:s nt S~Nar~~ MMSe P.a s·s, Wfli"t:t 1 er, Attetwr age 1 P·o. 1\wer-.,
G l'ei'!M n e11·, v a.idez,., and :F ai"tbank.s .. 'Fa t·rltartks. t ;;:e Ancflohge-'P almell at;ea,1
V.al'di!i,; ~ ~nn<~.llen a,)'li:l Sel'/~ro ·should. oe .<~b l:e t,o aocorrvn.oda..te th~ GOi"Jt.tr:unti;on
ani:l opei'l a l\~ a'ri !;' .f(.ll"ces re.q,li irB"d fqi? $tna il-s~J;: MaM.1 .T'aci l W i es· Ni .th m'i p\m·a.]
~och!l }Jld ec~momic i!ilpa c:t .. B.eGAuse of t:lle small PO'P-\Ihti an-s and undev:e16p:e!:l
'inrl"a,~lrll~tu1'~ of Whittif.ir qf'ld Mtl()~ p.~·$-~~ tJt~;;~ e;ompun~ies tut~Jg po.ss ·lb ly
e~:perl~nte. a m1nor to. moder'l(te. im~ac·t, detrend~l\g on the :typ~ aY(d .s ize pf: wdro
1 • .'17
development. The transfer of up to 20 or more workers and their families for
a period of 1 to 2 years may cause a strain on the social and economic struc-
ture of the towns. These impacts would be significantly reduced for small
hydro or microhydro facilities that require only minimum civil works.
The breakdown of capital expenditures is expected to be 60% outside the
Railbelt and 40% within the region. Approximately 10% of the O&M expenditures
would be spent ouside the region.
7.7.6 Potential Applications for the Railbelt Region
One small-scale hydroelectric project, the 15-M.oJ Cooper Lake project on
the Kenai Peninsula, currently exists in the Railbelt region. One additional
small-scale project, the 7-MW Grant Lake project near Seward is currently in
the planning stage. An interim feasibility study (U.S. Army Corps of
Engineers 1981) has been completed on a third site, Allison Creek, as dis-
cussed below. A review by Acres American (1981b) identified technically
feasible hydroelectric sites in the Railbelt region (Table 5.8). Of these
sites, 15 (including Grant Lake) are small-scale projects (Table 7.12).
Further assessment by Acres American (1981b) of these sites on the basis
of economic, environmental and land use considerations resulted in the identi-
fication of two sites, Allison Creek and Silver Lake, as having promising
potentia 1.
Three potential small-scale hydroelectric projects, Grant Lake, Allison
Creek and Silver Lake, totalling 25 M.oJ installed capacity and producing an
estimated 99 GWh annual firm energy, thus show promise for development in the
Railbelt. Environmental and cost characteristics of these projects are
surrrnarized in Table 7.13.
A preliminary assessment of potential microhydro capacity in the Railbelt
as a function of cost was prepared for this report, based upon an earlier
assessment of the Seward to Fairbanks 11 COre 11 area of the Railbelt (Mark Fryer
and Associates 1980). Within this area, Fryer and Associates identified the
Seward to Portage and the Anchorage to Palmer areas as being potential areas
for mi c rohydro and small hydro d eve 1 opment.
7.78
TABLE 7 .12. Technically Feasible Small-Scale Hydroelectric Sites
in the Railbelt Region
Site
A 11 i son Creek
Chulitna (East Fork)
Chu 1 it an (West Fork)
Crescent Lake II
Eagle River
Grant Lake
Lower Be 1 uga
Lucy
Ne 11 i e Juan
Power Creek I
Silver Lake
Soloman Gulch
Upper Lake Creek
Upper Nellie Juan
Van Cleave
Stream
Allison Creek
East Fork Chulitna River
West Fork Chulitna River
Crescent River
Eagle River
Grant Creek
Beluga River
Chu 1 itna River
Nellie Juan River
Power Creek
Duck River
Unnamed
Lake Creek
Nellie Juan River
Unnamed
Firm
Energy( a)
( GWh?
32(b
59
68
29
45
19(b)
72
71
47
66
48
11
74
57
10
(a) Data from Acres American (1981b), except as indicated.
(b) U.S. Army Corps of Engineers (1981).
(c) CH2M-Hill (1981).
Average
Annual
Energy
7
NA
NA
NA
NA
27(b)
NA
NA
NA
NA
NA
NA
NA
NA
NA
Installed
Capacity( a)
( MW)
8(b)
12
14
6
9
7(b)
15
15
10
14
10
2
15
12
2
The Fryer assessment took into account the terrain features, the annual
average precipitation, access roads and the transmission systems. Several
critical factors that were not examined because they were site specific
included the seasonal flow variations and the annual freezing index, a para-
meter used to estimate the depth of frost penetration and the thickness of
lake and stream ice.
Fryer and Associates estimated that development of 50 microhydro projects
averaging 50 kW of continuous power each was possibly the upper limit for
these areas, although the specific cost of the energy generated by these
facilities was not given.
7.79
-....J
(X)
0
TABLE 7.13. Summary of More Favorable Small-Scale Hydroelectric Sites in the Railbelt Region
Waterfowl,
Rap tors
____ _j_l_te ___ _JH~l .§~!!! J~re se1!!_ __ -~ ndan~!~!!_jp~J~-
Allison Creek Black Bear Res idenl Seab lrds
Gr lzzly Beat· and Rap tors
Peregrine Fa leon
Grant lake Hoose (fall & winter) None
Hounta in Goill (winter) I dent If led
Sheep {winter)
Silver lake Block Bear Re~ illent Seall h·ds
Gr lzz ly Bear and RJp tors
Seals
. -·-· ------·---
(a) Data frum Acres-l'lnerican (198lb) unless otherwise Indicated.
(h) U.S. Army Corps of Engineers (1901).
Anadromous Agricultural
_fjsherkL Potential
Spawn lng None
Area I dent If led
Hlgrat ion None
Pathway I dent if led
Present Western ltemlock
Sitka Spruce Forest
(c) ZX of capital cost.
(d) Levelized lifetime cost of energy. assuming a 1990 first year of comnerctal operation.
(e) Cost of energy estimated using cost Indices of APA (1980) wllh Allison Creek as • base cost.
Estimated Est imtlt ed fsl imit.lerl
WI lderness Cultural, Rccreat lana I r;ap ita! co,t(h) O~H Cur Cost or Power
___ f!!.t~u.~_L_ ___ _j!~ .. ~f_t~n.U!J.c" !.~.'!~!!!'~~ _ .... .l~Nil. [VkW/yt· c) l11•U 1_~/_k~hJ
Good to lllgh Hone lrlentlfled 4,2na(b) 86(<:) su(d)
Quality Scenic Area
Average Quality llunt iny 2,zzo(e) Jo(e) Js(d)
Scenery
Good to High Quality Chugach H.f. HA HA 46(e)
Scenery, Pr imit tve Boat lng Potentia I
Lands
Because of the significant percentage of capital costs associated with
the construction of access roads and utility grid intertie transmission lines,
Battelle's preliminary resource assessment considered only areas within 5 miles
of an existing highway or road. Based on this assessment (Table 7.14) it was
concluded that very little grid-connected microhydro development would be cost
effective at marginal energy costs of less than 100 mills per kilowatt hour.
At marginal energy costs of 100 mills per kilowatt hour, less than 1 MW of
microhydro capacity producing approximately 2 GWh annual average energy would
be cost effective.
Further study of potential microhydro sites would be required to more
firmly establish the potential of this resource in the Railbelt.
7.81
TABLE 7.14. Estimated Microhydroelectric Development Potential, by Load Center
Anchorage L.C. Fairbanks L.C. Glenna 11 en L.C. Total
Cost of Insta 11 ed Insta 11 ed Installed Installed
Energy Capacity Energy Capacity Energy Capacity Energy Capacity Energy
{mi 11 s /kWh) {MW) {GWh) {MW) {GWh} {MW} {GWh) (MW) (GWh)
90
-.....! 100 <1 1 <1 <1 <1 1 <1 2
OJ 150 1 8 <1 <1 1 6 2 14 N
8.0 LOAD MANAGEMENT
Because electric utilities are required to satisfy the electrical demands
imposed by its customers at all times, they have to provide sufficient genera-
tion, transmission, and distribution facilities to meet the annual peak load.
Activities that reduce the magnitude of load peaks will thus reduce the
investment in generating capacity required to meet peak load. Load management
is any action taken by a utility to directly affect customer loads or to
influence customers to alter their electrical use characteristics. The objec-
tive of load management is to shift or shed peak loads to derive a more eco-
nomical load profile.
8.1 LOAD MANAGEMENT TECHNIQUES
Load management techniques consist of changes in consumption patterns on
the customer side of the meter. The customer may be either an end user of
electric pONer (e.g., residential, corrmercial or industrial) or a utility
distributing power from a wholesaler to end-use consumers.
This section summarizes five general load management methods that may be
applied to the Railbelt region:
1. direct control of customer loads by the utility
2. passive control of customer loads
3. incentive pricing of electricity
4. education and public involvement programs
5. thermal energy storage.
8.1.1 Direct Load Control
Direct load control is the control of specific customer loads by the
electric utility. These loads are cycled or deferred during periods of peak
loads or emergencies. Residential loads for space and water heater use can be
controlled directly, but interruptions in this type of service can cause cus-
tomer inconvenience or discomfort. Economic incentive (i.e., lower rates) may
be provided to compensate for customer inconvenience. The effectiveness of
these incentives depends on their operating parameters and importance to
customers.
8.1
Studies evaluating loads subject to direct-load control have been con-
ducted primarily in urban areas having load characteristics different from
those found in the Railbelt. These studies constitute the most complete set
of data on load shaping. If these data are to be presented in their complete
context, a variety of load shaping experiences must be shown, including some
not applicable (e.g., air conditioning) to the Railbelt. Such general data
are presented in this section, whereas a more specific discussion of applica-
tions to the Railbelt region can be found in Section 8.4. The types of elec-
trical loads that have been selected most frequently for direct load control
are shown in Table 8.1.
TABLE 8.1. Electrical Loads Most Frequently Selected for Direct Load Control
(Economic Regulatory Administration 1980)
Cla~s of Service
Loads Residentia1 Commercial Industrial
Water Heaters X X
Central Air Conditioners X X
Central Space Heaters X X
Swimming Pool Pumps X
Nonessential Loads X X
A recent Electric Power Research Institute (EPRI) study (1979a) summa-
rized another study that surveyed 2,000 United States households and obtained
data on electric consumption by major appliance from August 1976 to July
1977. Tables 8.2 and 8.3 contain information cited in this study. Table 8.2
shows market penetration for major electric appliances. Table 8.3 presents
daily electric consumption by appliance per month. Unfortunately, the study
did not include data on time-of-day characteristics. Nevertheless, the infor-
mation in the tables indicates the potential importance of these residential
loads for direct control applications.
Unfortunately, appliances currently used for residential lighting, cool-
ing, and refrigeration are not designed to permit load management. Refrigera-
tion may have potential for load management if thermal storage can be econom-
ically incorporated into the design. Electric clothes drying is a substantial
8.2
TABLE 8.2. Regional Market Penetration for Major Electric
Appliances (Western U.S.) (EPRI 1979a)
Penetration
Appliances (Percent}
Freezer 37.89
Range 37.89
Cook top and Oven 29.21
Dishwasher 42.37
Clothes Washer 84.21
Clothes Dryer 45.00
Water Heater 11.84
Central Air Conditioning 6.58
Room Air Conditioning 18.16
Swimming Pool Pump 3.68
Electric Heater 3.16
load that usually can be shifted to off-peak hours. In the commercial sector,
water heating and space heating offer the most potential, whereas other poten-
tially controllable loads include lighting, air circulating fans, and perhaps
elevators. The potential for using off-peak energy in the industrial sector
is limited because most loads cannot be deferred or avoided without adverse
economic consequences. In the agricultural sector, irrigation pump motors,
space heating of animal dwellings, grain drying, feed grinding, and specific
dairy cooling operations offer potential for load management (Arthur D. Little
1979).
Direct load control may be implemented by either local or remote con-
trol. Local systems depend on the use of a timing or physical sensing device
to determine when end-use devices should be employed. Local control devices
include the following:
• clock timer switches
• temperature sensing controllers
• photocontrollers
• load levelers.
8.3
TABLE 8.3. Average Daily Electric Consumption by Appliance Per Month
(kWh/day) ( EPRI 1979a)
1976 1977
App 1 i ance August Sept. Oct. May June July
Refrigerator 4.80 4.81 4.57 4.73 4.87 4.97
Freezer 4.13 4.10 3.88 3.78 3.84 3.81
Range 1.84 1. 95 2.20 1.87 1. 74 1. 76
Clothes Washer 0.24 0.25 0.26 0.25 0.23 0.21
Clothes Dryer 2.70 2. 72 2.83 2.74 2.68 2.40
Dishwasher 0.36 0.37 0.39 0.42 0.39 0.36
Water Heater 11.66 10.42 10.50 10.49 9.42 9.45
Central Air Conditioner 21.96 14.53 4.41 11.22 25.23 31.25
Room Air Conditioner 6.54 4.63 1.42 2.23 5.96 8.98
Swimming Pool Pump 3.03 2.72 3.20 4.83 4.53 2.20
Electric Heat 1.57 1.30 1.77 1.97 1.60 1.80
Cook top 1.45 1. 52 1. 70 1.16 1.12 1.10
Separate Oven 1.00 1.21 1.55 1.16 1.11 0.97
Clock-timer switches are electrically driven controls that automatically
turn external circuits on or off at a preset time. These switches have been
used for several years, particularly for off-peak electric water heater con-
trol. Temperature sensing controllers are outdoor thermostat-cycle timers
that can control heating or air-conditioning loads. In a test case run by
Georgia Power Co. on central air conditioners, the diversified peak demand was
reduced 1.4 kW per central air-conditioner unit controlled by the thermostat.
Photocontrollers are light-sensitive controllers that have been used to con-
trol outdoor lighting, but could also be used to control appliances where use
did not depend upon specific time-of-day operation. Load levelers establish a
priority of operation among circuits. A single-circuit, load leveler removes
one circuit from service when a predetermined current load in a priority cir-
cuit has been attained. In residential use, first priority loads might
include electric range or dryer. The circuit being controlled would be a
water heater, electric heater, or air conditioner. Multicircuit load levelers
8.4
can control up to five loads in sequence. The multicircuit controller can be
used on residential homes with zoned heating and has resulted in a 32% average
reduction of kW demand (Economic Regulatory Administration (ERA) 1980).
Remote systems permit a utility to control loads through direct communi-
cation. Special or separate meters are not necessary. Remote control techni-
ques include the following systems:
• ripple-control
• power-line carrier control
• sine-wave alternation
• radio-control
• telephone-control.
Ripple control systems use the utility's existing transmission and dis-
tribution network to transmit control signals. Ripple control signals are
transmitted at frequencies of 200 to 1500 Hz, superimposed on the underlying
60Hz frequency. Although bidirectional ripple systems have been recently
developed, most systems employed over the years are unidirectional from the
utility to a customer control point. Power line carrier (PLC) systems are
similar to ripple control systems in principle except that PLCs operate at
higher frequencies (5-300 kHz) than ripple systems. The sine-wave alternation
system is under development. With this system, signals are sent by brief
fluctuation of the electrical frequency. Prototype units of an experimental,
two-way, automatic sine-wave alteration communication systems (TWACS) designed
for New England Power Service Co. by A. D. Little, Inc. have been built by
Emerson Electric Company. Radio-control systems use FM radio transmitters to
transmit encoded commands from the utility to radio-controlled switches on the
customer's appliance circuits. Telephone control systems link the utility
with its customer through the telephone system. At present, the most likely
application for telephone control systems would be for meter reading.
8.1.2 Passive Controls
Passive controls are load-control devices that are owned and controlled
by the customers themselves. For the utility, these types of control systems
are less reliable than the more active forms of demand control because they
8.5
are controlled by the consumer, not the utility. This method has a major
advantage, however, because the utility makes no direct investment in the con-
trol equipment. These controls are similar to direct controls except that the
customer, not the utility, retains the ultimate control over their operation.
Passive controls are typically implemented through economic incentives
and disincentives to encourage change in consumption patterns. However,
unlike active controls, power is always available to loads controlled by pas-
sive controls if the customer desires. Thus, the load management benefits to
the utility with passive controls are not as dependable as under direct
controls.
8.1.3 Incentive Pricing of Electricity
Under the pricing technique, rate structures are established so that load
management objectives are achieved through the market mechanism. Rates are
designed so that a premium price is paid for electricity during the periods of
highest demand, thereby encouraging customers to delay consumption to periods
when demands are not as great. Incentive pricing schemes include time differ-
entiated rates, interruptible rates and inverted rates.
Time Differentiated Rates
Two fundamental types of time-differentiated rates exist: 1) rates based
on time-differentiated accounting costs (TDAC); and 2) rates based on time-
differentiated marginal costs (TDMC). Accounting costs, as used in TDAC
rates, are average costs of producing power. Marginal costs, as used in TDMC
rates, are costs incurred to supply additional increments of electrical power.
Allocating costs to specific time (rating) periods enables rate designs
that give explicit information to customers about the costs of power for use
at various times. The use of TDMC (marginal) costs results in higher incre-
mental costs for the use of electricity during peak periods than TDAC rates
and therefore provides greater disincentive for curbing peak period consump-
tion. Both TDAC and TDMC rates, however, can reduce peak loads, but the
actual level of reduction or shift depends upon customer responsiveness to
time-differentiated prices (EPRI 1977).
8.6
If demand is very price sensitive, time-differentiated pr1c1ng can cause
changes in load shapes. Moreover, time-differentiated pricing should promote
efficiency in the allocation of generating resources to the extent that con-
sumers are willing to pay prices that reflect marginal costs. In a nation-
wide survey conducted for the Electric Utility Rate Design Study to measure
residential response to time-differentiated rates, the following conclusions
were reached (Elrick and Lavidge, Inc. 1977).
1. Most residential customers who had not experienced time-differenti-
ated pricing or load controls preferred voluntary reductions or more
power as ways to handle growth in peak load.
2. Residential customers, when faced with limited power availability,
preferred voluntary reductions to time-differentiated pricing or
controls.
3. Almost 80% of the residential users and more than 50% of the commer-
cial and industrial customers stated that they would reduce energy
consumption to save money or to avoid higher charges when faced with
time-differentiated peak use charges four times as great as charges
for off-peak use.
Interruptible Rates
Interruptible rates have been set up for customers who have usually
agreed to have their electrical use controlled or modified during peak periods
or system emergencies. The most straightforward rate of this type is exempli-
fied by a discount or credit to customers who agree to have some portion of
their loads interrupted under specified peak or emergency conditions. Inter-
ruptible rates might also be available to customers whose loads are regulated
by active load-control devices.
Interruptible rates may or may not cause a change in the existing rate
structure. These rates should reflect the savings that accrue to the utility
as a result of users foregoing some electrical power during peak periods.
Curtailment or interruption of service usually entails an agreement or special
contract that modifies another standard rate.
8.7
Inverted Rates
As opposed to the usual declining block structure, inverted rates estab-
lish unit price increases as consumption of electrical energy rises. The
rationale behind this approach is that new capacity tends to be more costly
than existing capacity. Therefore, the growth in electricity consumption that
tends to increase costs over time should be dampened by the price mechanism.
One advantage of incentive pricing is that requirements for capital
equipment are relatively low. Time-differentiated rates require special
metering equipment; interruptible rates and inverted rates require no special
metering devices. However, for larger customers, the costs of metering repre-
sent a relatively small percentage of their total electric bill. Time-differ-
entiated meters would permit customers who monitor their energy consumption to
determine cost savings realized by altering energy consumption patterns.
8.1.4 Education and Public Participation
All load management options require the consumer to alter electricity
consumption patterns. Effective communication with customers is thus a pre-
requisite to successfully implementing any load management technique. Educa-
tion and public involvement programs are needed for each of the options
described above and are potentially an effective load management tool in them-
selves. The effectiveness of such programs depends on the relationship
between the utility and its customers and public attitude and awareness. In
areas where people pride themselves on their individualistic styles of life,
appeals to the general need to modify consumption patterns may not be effec-
tive. This method of load management also not is as reliable as others in
that the utility has virtually no control over the exact amount of load that
will be shifted.
Under current economic, energy, and regulatory conditions, the role of
marketing and public relations activities has changed in direction and scope.
Instead of promoting the use of electricity, utilities now often strive,
through the promulgation of information and incentive programs, to retard the
increased use of electrical energy. Today, utilities foster conservation and
load management in their advertising in public newspapers or in informative
8.8
materials included with the electrical bill. Examples of such techniques
include energy tax tips about eligibility for federal tax credits for energy
conservation, and brochures describing energy-saving devices in the home such
as special shower heads, clotheslines, solar water heating, insulation, etc.
These and other public participation techniques merit consideration in pursu-
ing load-management objectives.
Although some state regulatory commissions may prohibit utilities from
promoting electrical consumption and now require utilities to promote load
reduction, the Alaska Public Utility Commission (APUC) has no orders to this
effect. The APUC, of course, encourages energy conservation and load reduc-
tion activities by utilities and their customers. However, APUC does not
monitor the loads of various utilities in Alaska.
8.1.5 Thermal Storage
The basic objective of thermal energy storage is to store heat produced
during off-peak periods for use in space or water heating during peak
periods. Energy produced by solar collectors, industrial waste, or base-
loaded generators during off peak periods is used to heat a fluid that is
stored for later use. In most applications, customers purchase storage equip-
ment to obtain operating cost reductions through low off-peak rates. If the
storage devices are appropriately sized, the customer should not experience
inconvenience or discomfort even if the storage unit is controlled by the
utility. On-off switching of the storage devices may employ the same communi-
cation and control technologies as direct and passive load control. A separ-
ate meter is usually used to distinguish the power requirement of the storage
system from the balance of customer load.
Currently, water is the most commonly used fluid for storage because of
its abundance, low cost, nontoxic nature and relative ease of handling.
Thermal storage systems may range in size from large, central storage units to
residential scale devices. Proposed large-scale central storage systems
include deep sea insulated bags with steel reinforcing nets, flexible bags
under noncohesive overburden, fixed volume tanks with separating disks, or
underground porous rock formations (aquifers). The Alaska coastline in the
8.9
Railbelt area has been identified as suitable for undersea storage. The
criterion is suitable depth a short distance from shore (Powell and Powell
1980). A recent study has concluded that a large bag system (4.5 x 106
3 . 1 ft ) stonng 450°F water at a pressure of 420 psi at 900 ft wi 1 cost about
$1/ft 3 for storage only. The stored hot water can be used for feedwater
heating in a central station, space heating in densely populated areas, or for
a flashed-steam peaking turbine for electrical production during peak-demand
cycles.
Energy storage equipment available for space heating and cooling and
water heating in the residential and commercial sectors are listed below (ERA
1980).
storage space heaters
• static room storage heaters
• dynamic room storage heaters
• centra 1 ceramic storage heaters
• hydron ic centra 1 storage heaters
• in-ground heat storage
storage domestic hot water heaters
bulk storage devices
• multiple reservoir storage
• Annual Cycle Energy System (ACES)
• Supplemental Electric Storage System (SESS)
• Constant Energy Input System (CEIS).
Static room storage heaters consist of a ceramic brick storage core
heated by electric resistance heating elements during the off-peak power
period. Although not widely used in the U.S., static room storage heaters are
used in Europe to heat hallways, foyers and small rooms such as bathrooms.
Dynamic storage heaters are similar in construction to static room storage
heaters, but the dynamic heaters use fan-forced convection to achieve better
control of room temperature. Dynamic room storage heaters can be used for
heating single family or multifamily dwellings and office buildings (ERA 1980).
Central ceramic storage heating units use off-peak power to charge a
ceramic brick core and have thermostatically controlled fan-forced convective
8.10
discharge. An average size heater, for example 20 kW, weighs over 3000
pounds. Central storage heating systems of the ceramic brick type have
potential in the residential housing sector.
Hydronic central storage heaters consist of insulated tank(s) in which
water is heated by electric immersion heaters, an electric boiler, or a heat
pump during off-peak periods. The heated water is then circulated during peak
periods to hydronic heating units in the spaces to be heated. Alternatively,
the water is used to heat air, which is circulated through the spaces to be
heated. Residential-scale hydronic storage units are available. A typical
unit consists of a sealed and insulated water tank of 212 gallons heated to
265 -280°F and 50 psig. Hydronic storage can be used for commercial heating
(and cooling) as well. An in-ground, heat-storage reservoir beneath a build-
ing can also be used for space heating. The thermal reservoir can be charged
using resistance heat or heat pumps operated during off-peak periods radiated
to the building at different times, depending upon building temperature (ERA
1980).
Storage domestic hot water heaters store water heated during off-peak
periods for use during peak periods. The control of water heating is the
simplest and most often used approach of residential load shifting (ERA 1980).
Bulk storage devices include multiple reservoir storage, annual cycle
energy systems (ACES), supplemental electric storage systems (SESS), and con-
stant energy input systems (CEIS). The multiple reservoir consists of several
storage media that can work in parallel. In the ACES system a heat pump draws
heat from a large tank of water in the winter; in summer, melting of the ice
provides air conditioning. SESS is essentially a water heat-storage system
being tested for residential and commercial use. Stored water is heated off-
peak and circulated through a water coil to supplement a heat pump. CEIS is a
water heat storage system with electric resistance immersion heaters sized for
24-hour level operation to satisfy design heating requirements (ERA 1980).
8.11
8.2 LOAD MANAGEMENT APPLICATIONS
Load management techniques are used in many industrialized countries.
The earliest use of load management was found in Europe. Recently, in the
United States, many load management programs have been implemented or are in
various stages of development. These projects are too numerous to summarize
here and the reader is referred to recent summaries published by Energy Utili-
zation System (EUS), Inc. (1979) and Electric Power Research Institute
(1980a). Many of these programs have proved to be cost effective, although
generally, they are in experimental or demonstration phases and findings are
not conclusive.
The feasibility of load management techniques depends on a specific elec-
tric utility's operating system, load profile, type of loads, as well as
socioeconomic factors. Therefore, although favorable results have been
obtained by some winter-peaking utilities outside Alaska, implementation of
similar programs in the Railbelt should be attempted only after detailed,
utility-specific studies.
8.3 COST EFFECTIVENESS OF LOAD MANAGEMENT ALTERNATIVES
Load management programs are considered to be cost effective if the capa-
city and energy cost savings (benefits) exceed the incremental cost of alter-
native generation and transmission sources plus the costs of implementing the
load management and technologies. In addition, customer acceptance and tech-
nical feasibility need to be considered in making an assessment of a load
management technique (Barron 1979).
8.3.1 Costs
Three types of costs need to be considered when evaluating a load manage-
ment option: 1) the direct costs of installing and operating the load manage-
ment options; 2) foregone revenue; and 3) production costs incurred to meet
demand shifts to nonpeak periods.
The direct costs of installing and operating load management options
include the capital and operating and maintenance costs of control hardware,
meters and storage devices; and general administrative and promotional costs.
8.12
Capital cost information on load management control systems is presented in
Table 8.4. Capital cost information on thermal storage systems is presented
in Table 8.5.
Revenue is foregone as a result of implementing load management schemes
if incentive rates are used, either directly as a load management option, or
as a promotion to adopt load management hardware. Incentive rates for the
latter purpose are necessary to compensate for customer costs and inconveni-
ence of using load management devices.
The third cost that must be considered is the incremental cost of meeting
demand shifted to periods of low demand. This cost will generally be the
variable cost of baseload equipment operation, although new, baseload capacity
may be required. If new, baseload capacity is required, then the capacity
costs must be considered.
8.3.2 Benefits
Benefits to be considered when assessing the economics of load management
include reduced operation of intermediate and peak load generating facilities
and possible deferrals of capacity additions. If effective, a load management
option will result in reduced operating requirements for peak and possibly
intermediate load capacity. The cost savings will be the variable cost of
operation (energy cost). Fixed costs of existing idle capacity will still be
incurred. A load management program may also defer need for new peaking capa-
city. If so, the benefits will include avoided fixed (capacity) costs.
8.3.3 Timing
An advantage of load management programs is that they can be implemented
rather quickly (e.g., 2 to 3 years to conduct a small load management test)
(EPRI 1980a). Therefore, many years of the costs do not have to be incurred,
as they do when constructing a major power plant).
8.4 INSTITUTIONAL, REGULATORY, AND ENVIRONMENTAL CONSIDERATIONS
A load management program controls an individual's use of energy through
direct or indirect methods. Such control methods do not rely on the supply
and demand mechanism of an uncontrolled situation, but rather on the belief
8.13
TABLE 8.4. Load Control Cost Summary (EPRI 1980a)
Average Central Control Total Installed Cost as a
Installed Hardware and Transmission Function of Total Customers~$ 1000's}
S~stem Cost ($ Per Point} Cost ($ !2000's} 12000 5,000 10,000 20,000 40,00 80,000 1002000
Radio 85 500 585 185 135 110 97 91 90
Ripple 110 850 960 280 195 152 131 120 118
CXl Un i direction a 1 PLC 95 950 1,045 285 190 142 118 107 104 .
I-'
+=> 50% Bidirectional PLC 140 950 1,090 330 235 187 163 152 149
Hybrid 90 515 605 193 141 115 103 96 95
Priority Relay 55 55 55 55 55 55 55 55
Load Management Thermostat 95 95 95 95 95 95 95 95
TABLE 8.5 . Tbetmal E~ergy Storage ~stems Su!Wllary Of P aybaejt Period Ca l tu l~t lons (EPR I 1960il)
~ts.ntUI P•}'i>«~ p.,.;r,: '•-"'otk p ....... , •rnc' ,.,.ICf '"Jb'IC't Prriod •-1 ~teo<IIJO kli $-~ Pu'tf' c ... Ed R>t•s M .~<uey e.tlt>~l Rll t! Pe•Uot) C"" b1 R•tos ~tllllNI ~i""" a.:.e-Jl••m lffnltr il' )C. !£! t ) !hars J tt ur.sJ _ .1!'~ 1'·~!1. ~.t .. !, .. ,.,
Rce11t Cor'JI'It i c. ltor;t•lt h otb<>Ofri 6 1,21Q l, l 8.8 3.~ 5.2 1A .6
Ct••t,.'al £ffal!rl c rlctrtc: fUrt'llt c 12 l,i1B!> 1.8 •• 9 :.&rfl J,~ 9.7
m ""f1Sut1)PO ~I<• .... £ l el'"At1 (i. FW'""C6 lz 2,593 a~t: 1n.o ~.ot~~ s.~ Is.)
Ul rn•>ro •rut E 1 tt tr1 ~ St~~botr~ u .. IJI o.~ o.s
Ann "' I Cyel. tn.-r<p,y t.)UOfll
tl~bl PlllllfJ wlt.h
£lttt n l c .\htil,-~Otftllr u 3 a,292 U ,'ll l !~. 1.4 l2,6QII LU ,I~ 50.9~
Dofly r.Yt I ~
l:lltl'!ll' Sy•ten, ll .. t P•"'' te !;130 a. a ~~-" 1 1 ft u ~ IJ. 2 )/.'2.-
Oua1 ~ ... Ina S)<fe" I loctrlc f\!rn••• to 6.1!i ii.~E 1.i !,VIII • u h,o
(aJ lncl "dtS: f1ld ~ntr"•nca.
1~\ ~•14 on p• .. •nt11 orro.-ad f1•~'""'"d'v r>J;e ,
that a fair program will be developed for all customers. If a control program
is instituted, certain individual choices can be opted in favor of the ''fair"
plan.
With direct control load management techniques, the individual homeowner
or commercial customer relinquishes considerable control of personal energy
use as the utilities cycle or defer loads during local or system peak loads.
Indirect methods, such as pricing mechanisms, cause the customer to alter
individual consumption patterns, which does not give the utility as much con-
trol over the load as do the direct measures.
In most areas where load management has been tried, programs have been
well accepted. With an effective public communications program by the local
utilities, similar results are expected in the Railbelt region. If such a
program is successfully implemented, it can produce certain institutional and
environmental benefits. These benefits should be evaluated in assessing the
merit of a load management option. For example, a successful program will
defer and possibly will eliminate the need for certain energy facilities. Any
delay or elimination of these facilities will suspend associated environmental
problems. The extent of benefits to the environment are assessed by comparing
the electricity savings from the load management plan to the specific genera-
tion option that is foregone. In general, air and water emissions and other
impacts of resource extraction will be avoided.
Recent activities of regulatory bodies have led to several attempts at
curbing load peaks. Because of the multiplicity of rate designs and objec-
tives, a review of the actions of individual states is not included in this
profile. However, some states have made major advances in this area. Of
particular importance to the electric utility industry is the Public Utility
Regulatory Policies Act (PURPA) of 1978.
PURPA, part of the National Energy Act, set standards for electric
utilities in the followiung areas: 1) cost of service; 2) declining block
rates; 3) time-of-day rates; 4) seasonal rates; 5) interruptible rates; and
6) load management techniques (PURPA 1978). Rates charged by the utility for
providing electric service to each class of consumers are to reflect the cost
8.16
of providing such service. In general, the energy component of a rate may not
decrease as kilowatt-hour consumption increases, except when the costs of pro-
viding electric service are demonstrated to also decrease as consumption
increases. The rates charged for providing electric service to any class of
electric consumers are to be on a time-of-day basis, reflecting the costs of
providing electric service to that class of consumers at different times of
the day unless such rates are not cost effective. The rate charged by an
electric utility for providing service to each class of consumers is to be on
a seasonal basis, to the extent that costs vary seasonally. Electric utili-
ties are to offer industrial and commercial consumers an interruptible rate
reflecting the cost of providing interruptible service. Each electric utility
is to offer to its electric consumers such load management techniques as the
state regulatory authority (or the nonregulated electric utility) has deter-
mined are practicable, cost effective, and reliable and can provide useful
energy or capacity management advantages to the electric utility.
8.5 POTENTIAL APPLICATION IN THE RAILBELT REGION
The opportunity for load management in the Railbelt region appears to be
limited mainly because few loads are controllable. For example, in the AMP&L
residential class, less than 10% of the customers have all-electric homes and
fewer than 10% have electric water heaters. The availability of inexpensive
gas in the Anchorage area has induced many residential customers to convert
from electric to gas water heating. Additional opportunities for load manage-
ment in the commercial sector appear to be limited because energy-saving
devices are used in most of the office buildings. The municipal dock area and
local military bases seem to be the only potential areas for load management
in Anchorage.(a)
The AMP&L rate structure reflects energy conservation and load management
objectives. The "all-electric" rate schedule has been eliminated, a 12-month
ratchet(b) clause has been adopted, and an electric time-differentiated rate
is available to residential customers.
Although a few obvious opportunities for applying load management techni-
ques in the Anchorage area exist, further shaving of winter daily peaks
8.17
.app.~?,ars to be PQS'S ·j tL l<e ·<11\d: m.i g ht, 'be ~;~re:fer.J'ed to fi~W !Je·ne.r.a tl \)n Ci!P ~~l to/. Th !;
dajtiru_e w-i·nter< p-eal{s ar e abbut twke-i!S i arg-e as )!'re n ~.'lllt l oad -s.. ~fith ·a peq k
load of rJbotJ t !2'0 }'M , .a XQ~ r>'edt.ft:c't f M 1"> inqtl •10li~d r .epr>t'S ent 12 :.nt Caf\tro~
of water. h'eaEer~ m ~g~~ be e .COJlOTJl'i~g;l, al t'hQu'!Jf; ta~ll&:fi eQvrts.i<Qe.r.etl '1/ilt'el" heo,~~t.~
wt1ih t herma 1 stl}~:.ag~· but de.t:e-rmi ne.tl, bcal>e"d on p,re:lim i rran .e~;orrom ;f~ a:naly s i s.
t hlit tf:te;r .~~ere not co s.t effective. TM: winter. :spaa-e hea.ti'ng l o<ld i s ,IJ nifcmil
a H d~ and t.her e rore' p.,ovi de s no .o!ipor tun il.y f'o l' s h'if t.i'Yl9 spat e tfeat l'ng l oad s
tCJ othe1· hou r s .. An add4 't:i':(}na1 constr>a t nt that m!lst b.e. eonsi·der,ed ts t ha ne'*
rur sc:·herJu l ed mai nt~narrc..e of )l!:!rt~rati 11 !1 ~~n-fts . Sd'reaui ed rn a~ n,ter•anee' ;;;. g~-11-
el'aliy a_ceomp'lfsilad f n 'the s,QiliTif!J' :dur.-"ing peMod s of ' low. lnad .
fa 'irll~-ok& MtJ!li c. ipa l 'ha·S 'btJi 1:t I o'<j an~ !l!fer gy-~:orrse.r :v;1''i9 fea.±ur~s. j fifo
-tt•1dr rate t.l;r u ?;tu r~. How~v.er , 1'n tile. Fairb~n!St: area~ l !i;td rn'cV)ag gmeri<t gos~'i~
b·i lfties a l sA allpear tq Jle limited , Li k'e Ancf.\Ol"'i\g':e, nttH~ or· no tndu.s'h\-i~l
l ead exi·s-ts an<J th·e q'1mm:ePcia '1 1oaa is r ·elatl-ve:l_y ·n.,t from> 8:.00 ' a.m. to
S:!Oll ~~m ,fa) Oi1 i l'i U:setl 'for ·tie;;;li~~r, and i !! is exr.reo ~lve; ~elle t , e·l lk-
\;r 1t·i·t Y ~s even more e*pan:s.Ne on a compa\<a.b1e ti a<.;·is. O.na a.rtE-a 1y~ere: ]oad
I'.Bd tu:.Ho'1 1'111!Jbt b:e. ,pgs.Si\)'Te WOlll <l' b:¢. <eQnt<rci ,l hng e~ect:r i '!;' auto, eng tne
l•e.PXers. Tpi't'ia-1 .,rtal fii'S s·ag'![e;!>ts, Mweve'r, tH Jl.t. f:tt i sc T-ll<id -rnaJ: be rJ'tffit;v l't
\!r .co n.trb l ev,en t hougl1 it Gon tril:tu,t-e s ~i91'lifi·c·a!it1y fo l aad . jlleiiks ..
111 ~·u~m~e ~"J, the l\ai·1beJt uti1ft~es ar·e curren·~.ly. emp l ayh1g 1oo.:d m ana~e
fi]ei'lt al tel'ftac'tli ,\<t:s:, Tn,~y .w<il'l ertntinli e t o be us ~fu1 f.o r-.sttap:ing. lo<td,o;l 1n ·a
ma111ier CPnlpat.ib::Je l'fit'h f 'U t tlre r~~au•'cg ~,eye lopin r;'lt. and e rectl:'~·ca l tpn~i.Jm p.tJion
llaotterns . Tltese ' techrti'qt~es , however., ~an on l y· P,e. eJnpl i\Wd vkbtfin i he .G;ont'e)lt
pf t ile uti lit i;es \ p·l a M·in,g· and .\lpeNting s.ystems an d t:onnect-ed l Qacl. !it ·~;~r~
serrt , t he na J:ur-e ·(}f' ccnnet-1ied lnad ssroe'l/h .q,t 1im'its-ppl:fer t unitie-s f at. $l!bs hn -
ti';;.l l -oad maiHH;IelTent, H l olv --co s-t; power wecre, til becom:e· ~~-i de1y <t va i l ati.l e in
t he f!J.tl.it€1 r;~u i U'nq irr .f.~p.ansi .ori fif '>~'!ace anti wiit.er heatfrt[ e:l~J;.t1'1t'cfT'
]oad.s . ~9 te~.t1 v~ 1 oal'i manag~tnent. programs rhii? becorrre desj .. -able·. ~ow-Mer,. th~
Ia~ OBtai ned f;t"olll' pel's6)'la l cotntnyn N:at~ on wftli, H~·. r:lY:T es 'l etk e ~,, ~li'hif
Er\'g_inaer, :-runi co;tpa 1 L 1•ght ·Md f'uj~et, A.r{c:;hoN g-e:, Febtuar.y f), l8&-J,..
(~·J A ~em~d raectret 4l~us-e ~tJ~e~· O),a~~mum · Pi\:;l or-;pre$~n t qero~trds tg b"e t ~kell
{nt,d 111::~oun it in e-qt qpli~hi .ng b f'll f ng, f or g r·~·en t a nd stJ~~equ.en t p-erl.od.s .•.
This t}1:Ie, of ~l a!J se h;M the effee't of ~n~rea ftil1.g ~· c:ll~t·omer ·'s-t>il1in.g r >\t.e
f.Q'r· ~tie ' :en:t i'r'e year i.f dWJ9Wl.? i!utf o;g ll 'eO:k. ~>~r i ads :e~Q,'Ef~d c~t~ t n lev~h;.
e. ;~,·s
need for such programs would depend upon the type of generation and storage
capacity available in the future. Use of hydroelectric generation, for
example, or construction of energy storage systems, would reduce the need for
load management techniques.
8.19
9.0 ELECTRIC ENERGY CONSERVATION IN BUILDINGS
Conservation technologies, as defined in this study focus on the benefits
of significantly reducing a structure's overall heating load. A few indivi-
duals in the Railbelt have reduced their fuel bills by as much as 70% by
adding extra insulation and reducing air infiltration when building. Others
are realizing less but still significant savings by upgrading their existing
homes and structures.
Most buildings constructed in the Railbelt use materials and techniques
better suited to more temperate climates. Only in very recent years have
designers and builders begun to recognize the need for an ''Alaska-specific"
approach for designing a building's thermal envelope.
The measures addressed in this report, if implemented on a large scale,
would contribute to reducing fuel demands in the Railbelt region. Whereas
relatively little electric space heating currently is found in the Railblelt,
building conservation could significantly reduce electricity demand if low-
cost electricity became widely available and electrical space heating became
common.
9.1 CONSERVATION MEASURES
Conservation, or thermal efficiency, is not difficult to achieve in most
buildings. Conservation is the end product of applied current knowledge and
of techniques already commonly used. The following four factors determine the
energy efficiency of any building, and if properly implemented, they offer the
greatest potential for energy savings in both new construction and retrofit of
existing structures:
1. an insulation envelope to reduce conduction
2. sealing to minimize infiltration of air
3. vapor barrier to retard moisture transfer
4. efficient space heating and hot water systems.
These factors are discussed for new construction and the concept of an
"Alaska-specific'' design. The "Alaska-specific" design is a house that has
9.1
lle¢11 deyeioJH!d ~ ith par't 1~1a r com;i de,.a:t t~rr ~Q· 1lhe St'\let ltl( ot' t he -r~g i&n_a1
ifJtm'ate-. rt 1 nc·o,rpqi"j~_t:e'S bu 1ld''in§ techntq~~s .that all ow for add'i:t ')'onal insLi--
1ation J;ei r>e~s i ~t ll~a t transfer -dnd to enhance tl:lerma 1 efHr. 1 ency , 1'/Ye <de·s1 go
co.u lt:l.anQ snou ltl llet'ome even more s-pec lfi,~; to ·loc-ation.. for· in'stahce 1. ·a.
:stntt:}JJ.re, in Fta~t·ban~s woultJ b.e more ·~:teay qy insulated tt:r;ui one· In ·Ar)ctrorage
\t o ace,ci [Tll)odat~ t.h~ (Jlore ~~vere Ittte '('~or ~; l'imaJ:?.
9 .1 ,1 t n;tu l,at' ltm
Conduction i.s the transfel" Qi'' ·heat: t hi'014.9h a so ltd tn.aterlia1. fn b!!!i1 .d-
i _n&J .'> oonduc:t ton C~ccurs t nrough tt;te ••enve-lope·," w11cj oh ~ons-ists ·of tne wa 11-s ,
windol.~S'.; flMt$ and cetii rt\') SliJ!.arating lh.e itrtrer~ot uMd1ttt:~ned -s-~tac-e from -tihe
eieruer~ts. l'h,e r!!$·1stan(e of l'ii;!ar tr;m·sfet·· th);otfg)i t;-hese c,dmpo·neflts f-s me.asu't'ed
in "{( \ia1uest" \.Jft'icb is u.c;M to: rHe Lrl5tJ:liitfon ma.tei'ia.,l-$ comt~ar-ij,ti've1y. T~e
iiif.lb {!'i' tile "R" "aWe. tll\l :gl•ea'tiet· :t-M i ·l($\l l ;tt~llg a!'lil'ffy ~f t~ maJ;etial. The·
twv ma,jgr t~<W~ of r~d(lt:.iQ~ ,ro'ndu c:t'iv.e h·eat l ii~Ss~s are lo r~duce the total araa
of t..he er:l,ve 1op e eltpct'S'ed' to '!:tie eNter tor· at:ll;l to prov idtt therm~1 res i&,i<ari'oe ir~
the mi!t.er 1 a 1<. oom!:!i'>ts tn.9 tile Jtn.v.e 1 rii1Ja.
iVIO furtdam·Mt'dl. P<l t lim·etars apply ~o mi(l!fm\zi n.!J .s.Litf<!ce tl,rrea-Fir.st,
str'uctures. J>llQu ht :be, mJ.i lt i ~s.tory rather th:;ut sl)'r'etl.d ou.t, wtt'h a 1 a~•g·e-rop f .area
( Ca 1 if oflnia. "''a-nth"· stj/.1 e ), . See:onii Jy, the s:.imiJJ.er •the-~11ape, the r(mre-·efl.er~y.
eff.i c; t~;nt i-t ts-. For ex·O-tWle, a rounc;i ·or s;;t~:~a loe tu.ri ltl jng .h~~ tl\e lea~t <l.i'e-a:
el{pt)S'ed to-~he e lements . ~n t.he ·other 11\\nd, t.fie inc reased. e~teri:Or surfac.e 9T
a liu ·ild'ing el onga teil 31ong iihl' east-fwefit, axis m t;~Y be offset, by: the-;SQ 1~1' :!Jilin . ' . .
avallaMe bec;aus-e JYf lts <wi.entat10i), if it is-desl.9nea to take. advM ,b~e. o f
sn1ar gain.
'l/i nd ow, are'~ ;~ tdt ;.c~ 1 tl). -th~l'(lli! I :eff i ~ ierl~ t .o'e.z 9-~se th is C.Omporjeo t of
tti~< ·enve·1fiJ1 1!' l'ii-ses more· M~t: . .tll&r\ othe'i' area'?. W'i'n.tlo1~s c_a,i] lo:Se up tb !len
:hiru~> t he aihPun·t o.f.· 'Ileal 1if tlile: atljatent wa 11'?-· An ene)''g,)l -·effideot tle;S;i,gn
i.i\~oi'p,or.a t~§ th?-'l :e~i>t a(l1qu nt r.tf wi rtdow a n;tl ~ons i s-J;en,t w jth ae s t;l)?,t:\c." -or
livab·t')tty -Of t lte 1ttt-er i i'!r' sp~·a~, l4ind.ow ~dent-atil)n is &lso ill]pcatta ttt,
5Qytb'er1y-ot e/ir.te r 1:v-ori>enhHon oiln gain heat-duri11g nt.ost-of the ·.n~?r ana
tilu s cQ!l't-r ibu te ro t l\.e llea:.t.i ~.9 of the inter ipr· s;p-ace. .Conv.erse-ly , no tltb,e~:~1y
or · vle $\,er1t W•tn~OW'S l'crse 'C( iar.g er ~meMt Of kJ:tit .and Shou10 Jl'.E: kel;lt t~ a
,;, , , ·~
minimum. Additionally, window heat loss can be reduced by using hermetically
sealed thermal units in wooden frames or aluminum frames with a thermal break,
and by incorporating multiple glazing. Conductive losses through multiple
glazing will remain high, but can be reduced further by using thermal shutters
or movable insulation, which are placed over the windows at night or during
cloudy periods.
Considerable disagreement exists but, not much practical information, on
the best window insulation system for Alaska. Several manufacturers are mak-
ing thermal shutters, most at a fairly high cost. None have yet been proven
effective in Alaska, although significant product testing is occurring. Some
quantified answers should be available in the next year.
Walls, floors, and ceilings can be made more resistant to heat loss by
adding more insulation than has been recommended in the past. However, the
structural design must provide a sufficiently thick shell to accommodate addi-
tional insulating material. Walls, in particular, pose a problem for the
designer of Alaska-specific housing because of traditional framing systems.
In these systems, the framing members of the wall are made up of wooden studs
and plates (Figure 9.1, no. 1), which contribute significantly to conductive
heat loss. Wood is only a fair insulator, and plates and studs allow greater
heat transfer between the interior and exterior than intervening insulated
spaces.
Several methods of improving the thermal resistance of conventional
construction have been used in Alaska. The most common approach is to use a
rigid foam board insulation, either on the exterior or interior, under the
finish skin (Figure 9.1, no. 2). This board increases the insulating value of
the stud wall, reducing the conduction loss through framing members. Because
conventional frame construction depends upon the diaphragm action of the
exterior and interior sheathing to provide shear strength, the structural
integrity of the wall must be taken into account when placing foam board
insulation beneath the sheathing.
In a second approach, known as the "cross-hatch•• method (Figure 9.1,
no. 3), 2 x 2 or 2 x 4 furring strips are nailed perpendicular to the wall
studs, usually on the inside of the wall. The horizontal members are placed
9.3
2x4 OR 2x6
TOP PLATES
l
EXTERIOR
SfiEATHING /SIDING~
1 .2x4 OR 2x6 STUDS
;-:: 3 112 OR 6" '1 INSULATION
1
_ VAPOR BARRIER
LGYPSUM BOARD
EXTERIOR
SHEATHING /SIDING-
RIGID INSULATION-
2x4 OR 2x6
/SOLE PLATE
2x6 STUDS
6" INSULATION
VAPOR BARRIER
-GYPSUM BOARD
•~-!---2x6 STUDS
6" INSULATION
VAPOR BARRIER
2x2 URRING
__..'lrLA--GYPSUM BOARD
EXTERIOR
SHEATHING /SIDING~
EXTERIOR
SliEAHIING /SIDING-
2xl2 TOP PLATE TO
TIE WALLS TOGETHER
~.. :.s-DOUBLE 2x4 WALLS
~
lr~~-12" INSULA liON
>~ --.. .. ./'" >· -,.:::::"'
VAPOR BARRIER
GYPSUM BOARD
I. CONVENTIONAL
CONSTRUCTION
2. RIGID FOAM WALL 3. "CROSS-HATCH"WALL 4. DOUBLE WALL
FIGURE 9.1. Energy-Conserving Wall Systems
usually at 2 ft on center, and the interior finish nailed to them. This
approach reduces the area of transfer by conduction to a 1 1/2-in. square at
each junction of the framing members.
Two 11 cro ss -hatch 11 designs are in use. In one design the exterior wa 11 is
insulated and a vapor barrier is applied. The 11 cross-hatch 11 is then added.
Electrical cables and "thin-line" electrical outlet boxes are put in the space
created by the furring, thus better ensuring an unbroken vapor barrier. In
the second design, rigid insulation is applied in the 1 1/2-in. space created
by the furring, giving a greater insulating value and avoiding structural
problems resulting from applying rigid insulation to the exterior of the wall
framing.
The third wall system employed is the double wall, in which two 2 x 4
walls are set a specified distance apart and are joined only at the top plate
(Figure 9.1, no. 4). The space between is filled with insulation. The main
advantage of this approach is that the walls may be set any distance apart and
filled with relatively inexpensive fiberglass or cellulose insulation. If
this method is used, conduction losses may be reduced to a minimum.
The cost effectiveness of these wall systems varies throughout the
region. However, the increased thermal resistance offered by these wall
systems in comparison to conventional 4-in. and 6-in. frame walls, developed
for use in more temperate climates, is important to note. While urethane
insulation can be used to give high insulating values in conventional walls,
it does nothing to eliminate conduction loss through the framing members.
Ceilings are relatively easy to insulate heavily since most designs
provide for an attic that is spacious enough to accommodate insulation values
in excess of R-60, which is adequate in most of the Railbelt. The problem
lies at the point where the roof meets the wall. Here, the available space
for insulation is insufficent to accommodate adequate insulation and to still
provide air circulation above the insulation layer.(a) The solution lies in
(a) Ample air circulation must be provided to prevent "sweating" or condensa-
tion and subsequent deterioration of the insulation and surrounding wood.
9.5
,y sJng an "arct<i,r;'' m• "Ark~.tJiias ~ tnrs:s. (Fi·~Ci r.f 9 .~').. l'b e · -ar.~;:ck ¥russ i -s •c.oo-
struct~d 1~a th ra i s e1;1 er~Jfs s01 tha t a e onsta;nt tJ:i icJ:1 ness Qr in su lati-on can
e!itH~.rrd t.o t he t.ciOf !3tl!]¢,_ M)iie sH1l all01<il.1'1g r-oom !.or v·e'fi ~Ha Ho n ~ Even 1f
f?X t rli ihS I.il<itfM jS qp.t •3 j)plfi'e i1 dl.tf'iQg ;¢d~t \"~c t·ion , tile {!(1 fii l'!! rQ,o f a\"~a
r.il•JJ .:I b~ lll!gqded h ·ter w,ith f)lis mel lt'Q1l ..
,'{9~ lf;S~ !N"S:W!;AD ON
A r .~().Q F E't!Gii
NQ'I'E' ;{A !S.EP END
/\'Nil J;ONstM-rr
~AYER bf !Nsu r,m hN
I'n th.e p.a st~ ttes.t gfi l!l,t'S. and b u.11 d~rs . !11-!.S,tal!:rin ly 'beJ1elled that floor· 1rrsu -
lall:1 on cou1GJ ·be ·m·i·n·imi z!!(l ". ano dfl .}' .e;X ~fa. eox pe tltli't llr es . .fi'cir i n S.tl latioi] i:l01J1d 'lie.
.app l ~etl to :the ee ·i 1 in~. Rec·ent s t »d i es·· a r e stJo•ll'irtg ttiat aelell!uq f..e f 1Mrl-\11su -
·1at.ion mi nt mi£eS' st rat ifi ~·~tipn of, air \:emf1e ra,1u.!NS tr.e.tweetl fl ovr .;oo t:e~l'Hi9·
The cqliler H oi;J r i'ii standard QQnst r .w;ti i:!tJ pi'i:\res 'V<a'l'm~r a i'r t o tile qe4 1 ng ,
add illiJ tp hea:t lu ~s .,
Condoot t ve 1:v2 ~ los s can ;1 l so be l't:du cred b y-t~s+ng in'S o1ated ~.e·a£!~?1""1;· oy e·l'
w.a11 op·errirrg s t atKe.r hha"l !iolid v1ood, ~~<O .ad· .ll -liearos-i·ll', t he f1oor., gnd cl ~sed
ro.of' sy.st erns. T he~e mett1 o.d.s prnent a much smal1 e:r.· are a to th:e ex t e,·ior t han
t.h~i n-t;,o un terpart-s construe ted of so 1ie t i mber.
9 ,.6
9.1.2 Sealing
Infiltration is air leakage into a building through cracks and crevices,
around windows and doors, and through floors and walls. Its magnitude depends
on type of construction, workmanship, and condition of the building and cannot
be effectively controlled by the occupants (American Society of Heating,
Refrigeration and Air-Conditioning Engineers (ASHRAE) 1977). Current research
indicates that infiltration accounts for up to 50% of the heating load of a
typical building. Principal sources of infiltration include sole plates, win-
dow and door frames, door operation, furnace combustion air and ventilation
devices.
The primary measure to reduce this heat loss is to freely caulk critical
areas such as the sole plate and around window and door casings to close all
holes in the envelope. Texas Power and Light Co. has found that the sole
plate of the walls, which is seldom caulked in conventional construction,
accounts up to 25% of the infiltration load on typical buildings. Other areas
of heat loss due to infiltration include electric outlets, vents, and ducts.
These areas should be sealed as tightly as possible. The larger joints can be
sealed with a foam urethane.
A large volume of warm air is spilled out each time the outer door of a
house is opened. This infiltration loss can be reduced by adding an arctic
entry, which is basically an enclosed porch or vestibule. The outer door
provides a trapped air space on the porch, and assuming only one door is
opened at a time, warm air exchange will be reduced.
The source of furnace combustion air can contribute heavily to infiltra-
tion. If air is drawn from within the house, it creates a draft, drawing warm
air out of the house. As the warm air is expelled, it is naturally replaced
with colder air entering through cracks in the envelope. A simple remedy is
to draw combustion air from the exterior, taking precautions to thoroughly
seal around the penetration in the envelope. A damper that prevents infiltra-
tion when the furnace is not operating also should be installed.
A good vapor barrier (discussed below) also retards infiltration -if
moisture cannot escape, air cannot enter or escape. If the vapor barrier is
9.7
properly installed and measures are taken to reduce infiltration, the number
of air changes per hour (ACH) can be reduced from a typical 1 1/2 to 3 to less
than one. However, reduction in air changes can lead to a deterioration of
the indoor air quality. An air change of less than 0.5 per hour is considered
detrimental to an occupant•s health. If cigarette smoke or other interior
pollutants exist, minimum air exchange should be as high as one ACH.
Insufficient air change can be remedied with a heat exchanger. The
trapped moisture and stale air can be expelled by an air-to-air heat exchanger
that draws out stale moist air and replaces it with fresh outside air. At the
same time it uses the expelled warm air to preheat the incoming fresh air.
Manufacturers of air exchange units claim a heat transfer efficiency rate of
65 to 70%. However, these units have some operating problems in colder cli-
mates. Condensation tends to form on the coils, resulting in ice formation
and subsequent unit failure. This problem is not insurmountable, however, and
more testing is being done to further develop these units. They most likely
will become an integral part of the Alaska-specific house.
All of these measures to reduce air infiltration are fairly inexpensive
when compared to the resulting reduction in infiltration and the subsequent
fuel savings.
9.1.3 Vapor Barriers
The primary objective of a vapor barrier is to prevent the transfer of
moisture from the conditioned interior space into the insulation itself.
Tests show that a 3% moisture content can reduce insulation effectiveness by
almost 25%. The vapor barrier is particularly important in the Alaskan cli-
mate where the extreme temperature difference between the interior conditioned
space and the atmospheric temperature accelerates moisture transfer. Not only
does moisture drastically reduce insulation effectiveness, it also leads to
permanent deterioration of the insulating material and structural members.
A vapor barrier must be continuous and sealed on all seams and around
penetrations in the envelope, such as plumbing and electrical outlets. This
important element should be installed on the warm side of the insulation.
9.8
Whereas a vapor barrier is installed in most new Alaskan buildings, they are
often poorly installed, resulting in leaks and penetrations that allow mois-
ture transfer.
9.1.4 Space Heating and Hot Water System Efficiency
Hot water heaters account for about 15% of the fuel consumption in many
homes. Establishing the exact load represented by hot water systems is
difficult because of the many variables, such as lifestyle, preferred water
temperatures, etc.
One major weak spot in the domestic hot water system is with the storage
tank itself; most have only 1 to 2 inches of glass fiber insulation, resulting
in an insulation factor of approximately R-6. By covering the unit with an
insulation jacket, the R-value can be raised to R-20 or 25. If the tank is
located in an unheated space, such an improvement can provide savings of
approximately 1.2 MMBtu/yr on a 52-gallon tank maintained at 120°F (Carter and
Flower 1980). With these savings the insulation jacket will pay for itself in
a matter of months. If applied on a regional level, these savings could add
up to a significant amount of energy saved.
Other hot water energy savers, such as flow reducers, thermostat set-
backs, stack robbers and water preheaters are all worth implementing. Collec-
tively, they may result in considerable savings.
Space heating units can consume excessive amounts of energy due to impro-
perly maintained burners, dirty stacks, and dirty intake filters. All of these
are easily repaired.
A more difficult problem might arise if a furnace is larger than neces-
sary. Excessive size can result from an improper judgment in initial design
or from a reduction in the heat load following an extensive retrofit of a
building. This furnace will be operating at less than design efficiency and
consequently will be using more fuel than necessary. At current fuel prices,
replacing expensive furnace equipment is difficult to justify. However,
homeowners need to be aware of inefficiencies in their heating systems. In
some cases they might choose to replace a furnace if remodeling or other
extensive home improvement is planned.
9.9
9.1.5 Retrofitting
The objective of retrofitting is the same as that of an Alaska-specific
design -to achieve maximum thermal efficiency in a building. The methods
used are basically the same. The limitations are obvious; rebuilding, partic-
ularly when adding additional insulation to existing walls, is more difficult
and often more costly.
The design and condition of the existing structure are important factors
in retrofitting. A total upgrade on a fairly new building may not be cost
effective; caulking and other simple measures may be best in that case. On
the other hand, an older structure with little or no insulation could easily
pay back the investment on a total upgrade in a few years.
If the structure has an attic space, additional insulation can be added.
Rigid insulation at the junction of the roof and wall may be a good approach
to providing more insulation in this confined space because rigid insulation
gives a higher R-value per inch than blanket insulation. Floors built over a
crawl space can have insulation added either between the floor joists or along
the perimeter wall. Masonry basement walls can be insulated either inside or
out.
The walls of a house are a prime example of a 11 Closed 11 system with fin-
ished surfaces on both sides. If additional insulation is desired, a second
wall usually must be added either outside or on the interior. This addition
is often done using rigid insulation and applying a new skin. This approach
is labor intensive and thus costly, so usually is considered only after other
retrofit measures, if at all. However, in an older building with high fuel
bills, it may well prove cost effective.
Upgrading windows in older buildings is easily done by adding thermal
glazing. Thermal shutters will further retard heat loss; however, shutters
that are functionally reliable and that will appeal to the mass market demands
have yet to be developed.
Adding a proper vapor barrier when retrofitting is difficult unless all
interior finish surfaces are removed. Barring this, several paints are avail-
able that will act as a vapor barrier. While not as effective as a continuous
9.10
polyethylene vapor barrier, the paints will nonetheless help keep the insula-
tion dry, an important consideration in a thermally efficient house.
Infiltration can be reduced in the retrofit by caulking the entire peri-
meter of the sole plate and around penetrations in the envelope. Residents
can usually perform this task in a single day at a nominal cost. Caulking to
reduce infiltration is the least expensive retrofit measure and yet returns
·large savings to the consumer. Simple caulking can reduce infiltration losses
by as much as 50%. Another effective measure that reduces infiltration is the
addition of an "arctic entry'' to frequently used exterior doorways. Such an
addition greatly reduces the volume of cold air entering the house when doors
are opened.
9.2 PERFORMANCE CHARACTERISTICS
Performance characteristics of interest include efficiency, coincidence
to load, adaptability to growth, and type of load service.
9.2.1 Efficiency
The energy efficiency of a structure depends on the extent of conserva-
tion methods employed. The amount of energy saved by building conservation
measures depends upon the lifestyle of the occupants and upon weather condi-
tions. A hypothetical but representative Alaskan house was used to provide a
comparative demonstration model of the heat loss and resulting annual heating
load in each of three cases: before retrofit, after retrofit, and the Alaska-
specific design. These comparative results are detailed in Table 9.1. Each
of the three cases was then considered for three population centers of the
Railbelt -Homer, Anchorage, and Fairbanks -and summarized in Table 9.2.
Conservation technologies as defined in this study can be said to be 100%
efficient in that once installed, they are working to their full potential.
Insulation vapor barriers and sealing that is protected from the weather will
generally last as long as the structure with little or no maintenance. Wea-
therstripping and exterior sealing subject to physical wear and weathering
will need to be periodically repaired or replaced. Conservation will continue
9.11
TABLE 9.1. Comparison of Heat Losses for Three Design Variations on a
Representative House
Building Area
Element lli._f!_)_
Floor 1,500
Walls 1,280
Windows 130
Doors 36
Ceiling 1,800
lnfi ltrat ion
(a) Shuttered at night.
{b) Air changes per hour.
Case 1
Before Retrofit
Design lie at Loss
~!.J.L_ (Btu/hr/'fl
R-10 150
R-10 67.4
R-1.84 70.6
R-2.5 14.4
R-19 94.7
1.5 ac/h{b) 324
Case 2
After Retrofit
Design ----.re'-'a'-;:t-,Lc--o-s-s-
_lt::_iteria (Btu/hr/"F)_
R-19 78.9
R-19 67.4
R-2. 79 46.6
R-8 4.5
R-30 60
.75 ac/h 162
Case 3
~aska.::_~_ecific Design) ..
Design Heat Loss
-~J.teria_ ilil!l.~r.L:.U
R-22 67.5
R-40 31.8
R-10{a} 13
R-19 1.9
R-57 31.6
.25 ac/h 54
TABLE 9.2. Comparative Annual Heating Loads and Costs: Retrofit of Representative
House and Alaska-Specific Design
Annual Annua 1 Savings Annua 1 Costs Heating Annual
Load Savings Base load Oil (a) Electricity!b} Oil {a) Electricity(b)
Location/Case (fiMBt!!l (fiMBtu) (%) _JlL ($) _JlL ($)
llomer: 10,364 degree days
Case 1 -Before retrofit 179.4 Base Base Base Base 2081
Case 2 -After retrofit 104.3 75 41.8 870 839 1211
Case 3 -Alaska-Specific design 54.1 125.3 6g.8 1453 1375 628
Anchorage: 10,911 degree days
Cdse 1 -Before retrofit 189 Base Base Base( c) Base 646(c}
Case 2 -After retrofit 110 79 41.8 270 774 376(c}
Case 3 -Alaska-Specific design 57 132 69.8 451(c) 1294 195(c)
Fairbanks: 14,345 degree days
Ca~e 1 -Before rett·ofit 248.1 Base Base Base Base 2879
Case 2 -After retrofit 144.4 103.8 41.8 1204 2258 1675
Case 3 -Alaska-Specific design 74.9 173.3 69.8 2010 3769 869
(a) 138,000 Btu/gal, 70% furnace efficiency with the follmiing January 1981 oil prices: Homer-$1l.60 r-v-1Btu;
Fairbanks -$11.60/t-t!Btu.
(u} Electricity at the following prices: Anchorage -$0.035/kWh; Fairbanks -$0.075/kWh; Homer -$0 . .04/kWh.
(c) Anchorage case is For gas @ $3.42/f/MBtu.
2002
1163
627
1852
1078
558
5398
3140
1629
to reduce the heating load of a structure to a constant level, relative to the
differential between indoor and outdoor temperature, throughout the useful
life of the insulation and sealing techniques employed.
9.2.2 Coincidence to Load
The relationship of conservation to load is different from those of tech-
nologies that generate power. The ability to adapt to loading demands is not
possible since conservation is static. However, widespread adoption of build-
ing conservation may result in a flattening of the annual load profile for two
reasons. First, the Railbelt load is winter peaking and secondly, space heat-
ing energy savings attributable to conservation increase in proportion to the
temperature differential between interior and exterior temperatures.
9.2.3 Adaptability to Growth
Conservation technologies are easily adapted to growth patterns because
of their simplicity and dispersed nature. However, an inherent danger is that
under sudden 11 bOOm 11 growth situations conservation measures can be s 1 i ghted to
hasten construction projects or to lower front-end construction costs. The
resulting inefficient structures will increase the burden on other energy
sources. A concerted effort and understanding of conservation efforts by
designers, builders, consumers and financial institutions will help to prevent
such a scenario.
9.2.4 Type of Load Serviced
Electricity for space heating does not currently comprise a large per-
centage of the Railbelt's heating demand. Electric heat from portable radia-
tion heaters generally tends to serve as a supplemental heat source during
extremely cold periods (contributing to the winter peak load of the Railbelt).
Thus, conservation measures as defined herein will have little overall effect
on the immediate electrical demand. However, if changing relative fuel prices
result in a future shift to electricity for space heating, building conserva-
tion may have a significant impact on future electrical demand.
9.13
The -cof.t of oonservatiat:l ts diff-h:.uH. tG il\eas~-tre 011' a lt~r.ge ·sca1e at Ur is
poi11t ,. due. tl1 itS -d ~~pJ<rseti .naturii;.. Retr-Ofit c,o_sts for< eHs~Ji'lg ~tr11clure'$
.\'1 111 va'tf.y subs t a;nti.al]y ije,peiTd~.ng on or'i _gi~:~a:J constrJJct'ion af:(d t)1e Mli!Hti·on
;;t ~he time oJ ret'ro f i·t.
Virtu.a ll y no :cost s:tud ~es on i:;onserv-a.t.i <9Jl have bee11 ~erfi!lrme!l i'n t he
~i1be1t area. Pr-eliminary c;o,st e-stimates. ,-e e:etrt 1y periurmed i·n northwe6t
AhsRa sl\owi?d un 1t eo;~~s ra ~g '\j pg lletwee,~ $l .J cr{MI1!ftu f.ci r :s tmp 1E caulking and
-wea ·tne .-str-' 1 pp i n9 to $16 .,·5D {~Bty f-or.-.a fu ll ~~a 11 /r<qo.F i nr.u 1 at 1 :on up.g_f.·ade •:iri.· M
ei.(ts'tir19 Ql.li l ,;ii'(Jfl.·· For the r eprg'$-entaiii,ve tl!luse rJ'.j~G:l.l$-~e\'1 if! Sect;~o n 9.Z. tile
r~trofi!. ~fea s·ure s returnee! :oav~og_.s p.f 41.8%. Qf t he annu~ T lt~tHrg load \n
cQm,:larit.on t o t he tl-4-S.e oase an(! t:he Ai ~ka -<:'&pl.ec ·i fi.c ilesi.~n r-eturned sa l/"1~~,:; d f
7L3%.
For a co[l 'le o t ion,:~1 house ~=,o,stl'r19 $lf}l'J •,Ofl0, ''·S\)P"ef'\I'ISill 'attoi)" can cost an.
~ddi'h.trna .i -~ ,000 l:o cover-heav1$1" 1nsu1aHt.il'f, e~:t-ra ;ap ucturt~1 ~temll tr,rs., atltlf-
tional l~Jyqr f ¢''1" ''il~t aill~'' ~15~ 1\IJuse t .o plug air leaks, lihtitt'.er,s ove-r t,h~:
·~/i 'l')llow~ •. and an ·1 i'r-..ta .. ~ ir 'IJ>e·tc. ex ·r*'a'D ·Y~I".. ve,~y jlr~Tfrn ~ p~y ~tud.ie~ d,one l!Y
1\lelsk a Retr~wa~ l e Etl'er·yy As~oc:=i'Atg-s h;we. s:ht~vm '!;h3t ~h-e cgnservat f<J'tl tnve$.t.men t
·e qua.ll ed 5 t1' '1-% of t.IJ e-tot-al i ~:~ve~tinent for ~:In~ ·t..o nv-ent itn:r£1 holi~-e:.. Th~·~e
f i ,glJ rErs. ar~ very· l('()u.~h 'alltl (!Jay· 'fie hi1Jh. A:s-s ·~niiflg tJiat t-he investmeht i 7
financed f.o r 3'0 years at 15~. i KJ teveost, et~st. pe); mil non Btu woiJ ·l'd b~ .$7 ,,ao.
'State ~Jf A 1 "s l(a h.onte. road pr oai'a:rns at lQ* I<'G.u ld llr~ng tn is fi Y.~H>e: -down. as
would the t o .ttse.rvat1on i oaF.! p,l'Og·r am at S~-inter•e st. As a. :CJ'IO'ip.adson, ·reeent
h\:llile ~eatfpg ail Cl.ists ~-~ ~~~jmo*fmat.~ iy '$6 .4Jl /l\1M8 t u i11 Ar(tilor:age and
$~k2.0 {J1'!BlHJ. in FP:.i'r b<Ifl k-5 (A,pr:~~ndiX B). F lj.rr]at~ 'ipe'ffi .trje l"'c~es . 11o_ultl J?e sul t; ·;n
some\¥~ at ~ i91.'rer ,t:Q'ropara.Hve ·cos t~;-..
f.\s sta,t~cj ?ather, cpn·s.ervati tm. 'lli'!i!s.Ures t~at ar(i! ~ro.teotea f rom weatne ~"
~.rrd physi.qa.l wear (:e.g., i ns y1at.1 Qn ·'!fld v.ap0r lilai.'Hel's,) .wi'll ~~~era ny r:eqil .11"e
no m~ i r\tenanc e:. wea t)1erts'tr1P.P.ing -<me -s:ea n 1.19 ~~pQ's,erl tg. the e~ement~--w~ 11
reJ'Iu i 1'!':. 1'1-er i od 1 c ~'~'P 1 acem el'tt.
9.4 ENVIRONMENTAL IMPACTS
Building conservation technologies have few detrimental environmental
impacts. The materials employed are usually nontoxic. Air, water and land
are unaffected by conservation. The technology need not have any impact on
conmunity aesthetics; the 11 styles 11 of buildings do not have to change at all.
The building envelope is affected, but not necessarily the exterior of the
structure. A positive environmental impact from building conservation tech-
nologies is that population growth need not lead to increased air pollution
and other effects of increased fuel combustion. The possibility of injury or
death to either the consumer or installer is negligible and most likely would
not result in any increase beyond what is now experienced in the light con-
struction industry.
9.5 SOCIOECONOMIC IMPACTS
Since conservation technologies require little or no operational mainte-
nance other than that already necessary in the home, the individual experiences
little inconvenience after the initial installation, with the exception of
movable insulation/shutters. However, this inconvenience would seem to be a
relatively minor inconvenience when compared with the control an individual
gains over heat loss. An energy-conserving building is comfortable and rela-
tively draft-free. The reduced cost of heating allows occupants to keep the
building warmer for less money.
As conservation measures become more widely implemented, new business
opportunities will result and existing business may be revitalized. Consult-
ing and technical support groups, installation contractors, and suppliers will
be needed to accommodate regional retrofits and new construction demands. An
attractive aspect is that these support businesses can be at a community level
and thus may create local jobs and enhance local economies.
Determining the impact of conservation on employment is difficult because
many homeowners will probably do their own work, but retrofitting jobs could
help to balance the loss of jobs in new construction due to high interest
rates. The duration of these jobs and businesses is, again, difficult to
determine without more research.
9.15
Certain skills and businesses can be adapted to accommodate the variety
of services and materials related to conservation. For example, materials
used in conservation can complement the inventories of local hardware and
general mercantile stores. New 11 Conservation specialty .. stores may develop in
larger communities. Also, existing home repair contractors and handymen can
easily include conservation technologies as a part of their services.
On a regional level, conservation measures will result in a reduction of
fossil fuel expenditures and an increase in mortgage and short-term home loan
expenditures. Assuming cost-effective conservation measures are undertaken,
surplus money will remain in the consumers• hands.
Community and regional governments could also have smaller expenditures
for fuel. Operation costs and taxes to the community then would be reduced.
The reduction in energy demand will reduce the need for investments in addi-
tiona 1 power plants. Because most conservation measures tend to be lower in
cost over the long term than are investments in generating facilities, proper
long-range planning could result in significant economic benefits throughout
the region.
9.6 POTENTIAL APPLICATION IN THE RAILBELT REGION
Addressing and quantifying the effectiveness of conservation technologies
in the Railbelt is difficult because it is influenced by the quality of the
existing structure, its use, and its occupants. Lack of a regional data base
on the condition of the building stock, type of heating systems, and the
resulting energy consumption is the most severe impediment to quantifying the
potential impact of conservation within the Railbelt.
Building conservation technologies are immediately available as mature,
well-developed technologies. Building conservation can be easily implemented
into existing and new construction at a regional scale without complex manu-
facturing or distribution systems. The materials and techniques are available
throughout the Railbelt. Nothing more exotic than standard insulations and
caulking compounds are needed for most applications. Those items not readily
available soon will be, as interest and understanding grows.
9.16
The principal impediments to widespread implementation of energy conser-
vation measures include poor understanding of the cost effectiveness of con-
servation measures, the tendency among builders to reduce front-end costs to
improve the marketability of their products, and constraints established by
obsolete building codes. Poor understanding of the cost effectiveness of con-
servation, rather than the availability and level of the technology, has led
to the relative slow growth of conservation technologies.
Given that the ••state-of-t~e-art" is here, the designers, builders and
consumers must understand the benefits of conservation from an economic stand-
point. Education of consumers is needed to end the idea that conservation
means a return to pre-industrial revolution lifestyles. Education is equally
important for designers, planners and installers, who must understand how dif-
ferent conservation measures must be employed to achieve maximum effectiveness.
Further analysis of the cost and performance of specific new construction and
retrofit conservation measures is required to determine the appropriate order
and extent of implementing conservation measures.
Developers and financial institutions have historically attempted to
reduce the front-end costs of construction to increase marketability. The
concept of life-cycle costing needs to be promoted to consider the technolo-
gies that· increase heating efficiency and thus reduce operating and mainte-
nance costs over the life of the building. While practiced to some extent in
commercial building, this concept needs to be expanded and applied to residen-
tial dwellings. Real estate sales in the United States have had an impact on
financial policy, particularly in the Northeast, where an energy-efficient
home commands as much as 9% more in value than its inefficient neighbor.
~lthough this phenomenon has not yet become the standard in Alaska, such fac-
tors cannot be ignored in the future, considering escalating fuel prices. The
Jroblem of outdated and conflicting building codes has never been addressed in
\laska. More research is required to determine whether these pose a problem.
9.17
10.0 ELECTRIC ENERGY SUBSTITUTES
Electric energy substitutes include passive solar space heating, active
solar hot water and space heating, and wood space heating. A comparison of
selected characteristics of the electric energy substitutes is provided in
Table 10.1.
10.1 PASSIVE SOLAR SPACE HEATING
Passive solar relies on a combination of a thermally efficient building
envelope to contain heat, south glazing to capture solar energy, some form of
thermal mass to store this energy for release at night or during cloudy
periods, and design techniques to distribute heat by convection. Passive
solar uses no mechanical means such as pumps or fans to distribute heat from
the sun into the living space. Essentially, the building is the system.
Passive solar space heating technologies have been available since very
early times. The sun's benefits historically have been considered when
siting, designing, and constructing cities and homes. With recent dramatic
increases in fuel prices, individuals are once again realizing that solar
energy can provide significant benefits. Hundreds of passive solar structures
are now working successfully in the Lower 48. Although the phenomenon is
fairly new in the Railbelt, several buildings that rely on the sun for a large
portion of their heating needs have been constructed in the last few years.
Passive solar techniques can be implemented on various levels. Simply
orienting the house to the south will provide some solar gain. Enlarging the
amount of south-facing glass will further add to the effectiveness. In both
cases, however, solar heat is available only when the sun is shining. To be
most effective, the passive solar house must have some form of storage mass to
retain heat for release at night or during cloudy periods. The optimum solar
building will rely on a combination of the following features:
10.1
TABLE 10 .1.
Aesthetic Intrusiveness
Vi sua 1 Impacts
Noise
Odor
Costs
Capital Cost ($/kW)
O&M Cost ($/kW/yr)
Cost of Energy Saved (mills /kWh)
Public Health and Safety
Consumer Effort
Adaptability to Growth
Unit Sizes Available
Construction Lead Time
Availability of Sites
Reliability
Availability
Expenditures Within Alaska
Cap ita l
O&M
Fuel
Boom/Bust Effects
Consumer Control
Technical Development
Commercial Availability
Railbelt Experience
Comparison of Electric Energy Substitutes on
Selected Characteristics
Superinsulation with
Passive Solar Space Heating
(One Household)
Minor
None
None
Non~
Ni 1\ c)
610 -101S(d)
2Sld)
8 -12(e)
Potential effects from
interior air-quality
degradation unless adequate
air exchange is provided.
Consumer-operated;
minor effort
(less than hour/week).
Household scale.
Less than one year.
Most new housing;
physical and solar access
constraints on some
existing stock.
Insulation -100%
Solar ~40% annually,
less during space heating
season.
Not known
100%
100%
Minor
Direct
Currently available.
Little
Suoerinsulation
Active Solar Hot Water
and Soace Heating
( One Household )
Minor
None
None
Non~
Nil\ c)
Insufficient information
to estimate costs.
Potential effects from
interior air-quality
degradation unless
adequate air exchange
is provided.
Consumer-operated;
minor effort
(less than hour/week).
Household scale.
Less than one year.
Most new housing;
physical and solar
access constraints on
some existing stock.
Insulation -100%
Solar ·"40% annually,
less during space heating
sea son.
Not known
100%
100%
Minor
Direct
Currently available.
Little
Wood Space Heating
Wood, Furnace( 1 (One Household) a
Minor -Moderatelb)
None
Minor
None
None
154
3
59 -7aUJ
Potential increase in
fire hazard. Potential
air quality degradation.
Consumer-operated;
moderate to major effort
(several hours/week).
Household scale.
Less than one year.
Most new housing;
physical constraints
on some existing
stock.
Close to 100%.
Not known
100%
100%
Minor
Direct
Currently available.
Widespread
(a)
(b)
(c)
Effects cited are for household only; external effects due to wood harvesting will be experienced.
Atmospheric haze could result from extensive use of wood heating in populated areas.
(d)
(e)
(f)
Additional site coverage may be required to accommodate sunspaces -no additional developed area should be
required unless lower density development is required to preserve solar access.
Based on average kW savings during six-month heating season of 10 kW. Includes both superinsulation and
passive solar features.
Based on 30-year bond life at 3% interest (comparable with financial parameters used for other alternatives in
this study). Note that cost of savings would be greater to homeowner if nominal conventional mortgage rates
were used.
69 mills/kWh for Fairbanks; 78 mills/kWh for Anchorage.
10.2
1) a thermally efficient building envelope to contain heat
2) south glazing to capture solar energy
3) thermal mass to store the energy for later release
4) proper design techniques to distribute heat by the natural properties of
air convection.
Passive solar may appear to be an inappropriate technology for the Rail-
belt because the solar resource provides the minimum amount of energy when the
need is greatest. In December and January in all areas of the region, south
glass will actually lose more heat per square foot than it will gain. However,
the high heating loads and length of the heating season make solar attractive.
During late winter and early fall, the properly designed, passive solar struc-
ture can obtain nearly all of its heating needs from the sun in Alaska•s
Ra i lbe 1 t.
10.1.1 Passive Types of Solar Systems
Three distinct types of passive solar systems have been studied and
installed in the Railbelt. While other options are available, none have been
seriously considered to date in Alaska. A brief description of the three (see
Figure 10.1) follows:
1. Direct Gain -Direct gain, the simplest of solar strategies, uses south-
facing windows to bring sun directly into the living space. It therefore
provides the greatest amount of solar heat for immediate use. Some form of
storage mass, usually stone or tile flooring, water containers, or phase
change materials, is used to store excess gain. The major drawback to direct
gain is that the heat captured can escape back out the windows at nighttime or
during cloudy periods, unless some form of insulation is placed over the glass.
2. Indirect Gain (greenhouse/sunspace) -An attached solar greenhouse works
on the same principal as direct gain. The difference is that the sunspace
acts as a buffer between the elements and the main living space. Solar
radiation enters the greenhouse through south glazing; heat not needed in the
sunspace is directly vented into the main living area with heat that is
conducted through the common wall. Windows, doors, and vents in the wall
10.3
.....
' '
01 RF'CT GAIN
lr..O IR!CT CA IN
MASS WALL
JD . q
-- -SCXJ;~ RADIATION
-.... ..-~ INTERIOR RADIATION
w~:an J>Mss
==GLAZING
fiiJ!HD INSUlATION
are commonly used. At night, heat lost from the house must first pass through
the sunspace before being lost outside.
Several factors will affect the system•s performance. A poorly insulated
or inefficient greenhouse will not allow much heat transfer into the house
because the bulk of the sun•s energy will be used up in heating the sunspace.
Venting into the main structure must be designed correctly to efficiently move
the heat. Finally, the effect of a large expanse of glass is much the same in
this strategy as in direct gain; a significant amount of heat is lost back out
the glass without night insulation.
Some form of heat storage is usually applied in this strategy also. The
back wall of the sunspace is sometimes constructed of stone or concrete, as is
the floor. Containers of water placed along the rear wall also are used.
The attached greenhouse has other benefits, such as plant and food pro-
duction, added living space, and psychological benefits.
3. Mass Wall (water/masonry) -The mass wall employs quite a different con-
cept than the first two approches. In this strategy, sunlight passes through
the glazing and strikes a water or concrete mass located directly behind the
glass. Heat is absorbed by the exterior surface of the storage mass and slowly
works its way to the interior for subsequent release to the living space. As
with the other systems, night insulation is important in this system. Without
it, stored heat will be lost back outside. Insulation is usually placed on
the exterior of the glazing or between the windows and the storage mass on the
interior side. Venting the space between the wall and the glazing to the
living space will facilitate, by convection (either natural or fan assisted),
rapid morning warm-up when the sun is shining. Such a strategy is called a
Trombe wall.
Several important considerations must be taken into account when consid-
ering a passive solar home or structure in the Railbelt. The amount of south
facing glass is a variable in direct relation to the square footage of the
building and the thermal efficiency of the structure•s envelope. Indiscrimi-
nately placing glazing to the south will not necessarily ensure an effective
10.5
~'l''a.r 'de:S i'9•h \i verg l.a-z1ng c.a11 ••es ui t 111 a to t'!·l 'heat:HJ9 load l11.g~e i" th9-n ~he
11 <S"'tanda r tl" home odn s:tru~ l;i!d ' toda}f, a'S l~e il as-ove r h i!a.t'i rt 9 pti'ob lerns -i.h the
su lllller.
A~ men.t Mr:led-, mov.ab-t.e insu1€!..t ion is :;m 1mpol'tant hdor t:o imp r>!~V e
perf ~rma:nae of pas-she· s l!l 1ar in t~ ·r e.!J'irG n. wne t::ea.~ bene-!~t.s can he .dei'iv-ed
fr·om SO.tl ~h !!1 a:ss: wit-hout shu t..tr.e1•s •• the most eff e.ct i 11e s_y st em \~·~"11 emP 1'a:y
1nsulat:1on to rf<t~d. Mellt 1oss: dli)'t ng r.itlns·lJnln ,aer Hia5 t h ro.~gn. g\,l.s:s , ohe.n
·ure· ~1eaKest po ·i ilt i rrt tMe ~LH h l 'l'llg" s ~n Y e l:ope .•
Som~ f .orm of s~t age rn<l.\>5 ,s·houlCI oe pl·-Wid?d if! q 11 s_ys-1~1!1~ tQ. .so~lt l.IP
e~>C?S5 •sQ'1:ar !!iltn am! t o dampen the wide-o.r.·dti_;J 5 irt the tn l\~rtor tempe_rat ur !!•:>,
~.tiii::tr r,:an ''es.ult !'rom var i ~ti011 i~:~ av-a:J lab-le. so1ar raeti_ation , Tin (:l\rei~t gain
and s·ijns-Pa ce '411P·l i c.atAon 'S-. -mn.fr>rete Ho.ol"& and· wa 11 s .•. water :dr.Ums and .
tont>a iners arlt a11 used ~ p:rordcle mii .S.s·. .BUil.d-er;s !l ave f ound that e ven an
ad.d it ion a 1 1a_ya l' of gyp'S um troard w\11 tre· iP reQI! 1 ate ~empe-ratCJr~&c.
~a t~r wi II t r.atlsfer neat fa ~ter a na hoiq l;fo 'lienf;ial }Y' 50~ rnt;i"e hea•t-per
llfl it vo.l u~ tl'l<~n ~@rr.cretr?. Th~ £ea lli U.re~ m ~ke 1·:tr an at.tr~ct,i ve st>qrag~ rn'edium ,
bu t j ittTe wo rr& ha'$ lleen dune w-ith it in Ala$ka beca\J~i; qas-}gM~ fear tl!&t
t he ~la:ter c:lose to th~·liJ ,l 'a':iS Uliti' frtee1ie .• bo~s t iflg Its !"Ont.ainment. n· t hese
des-1qn ~7·oblems cao be :so:1ved , v..ater. l'(aHs. ro<U( be a f e.as:lble so1ytion., s'i n.:;e
tn~Y tenl1 tm oe les-s. :eosn:~ t'll,an C:!>irle't-et-e·.
Oflwr stqr-age llf\'!ifia rzan: tle-lfs~>~-111 c(m:j ll r,et i·On Yl'tttJ .. ttre var'i1·ous sYs tem
type~. Ttu; h1a mo.~ l;Omnbl'l ~re r:qt.J!· ti.ed ·stpl'age -a;ttj P.hi!s"e -en:.ange, ma;•ter.i~ l's ..
V.e ry. li ~t l ~ is k·nov1(l ab-out ttu:~ effective"nell;; pf ei Wer in 1lJ1e Rl! i lb e'lt ·li~!?giJ!ig
i'n'ita lla l;t·oo.~ J;re.f ew :M.iil r.ecenlt . Reel{ !Jeds j n p ~'t icu-rar .ttlw~-beer:r l!votxie'Q
II¥ ·ae signe.rt<; ·JJec:au<>e they ~equi i'e· a lar,g-e llnlume t.G l)nll vide act'eqti.a'te soli!l'
sl:orag-.e hl the. r-.eg ion , Tl'le-vo1.ume r.et~u ir.e:d ma,y Hmi t. th e pl"ae'tq aaitty or
i'etrM'itti nq t ill exi ·st >i'~rg s t rl(O tJH'eS'; due J;o t.lt.e ~o:!;.t., l'lf i·ncoi'porat11lg 'th'e.
rack bed into tire ex ts·til'\Q sti'IJC t.ur a. i sys:tems· artd 1 {vtng spa ces. Rot-~ ~eds •111 a;y
b.e m<11•e e.f f'eot. i ~~:e. i'rt new a¥f rt!q;rtJcti o)l>; 11'1.\wl?vet, ll'li -~otly has 11.eer;r clone.
P,liase ci;J&ng~ r~at.er·'ials haYe .tile Q'dVa\'ltage o.f b~f'lQ -~a i r l y h gfl 't,; l{hey m~
be t ncor j)!Jfited fntp· e xi~tirw i •t 'tur;tll ·r.·ii 1 sys t;~ll)~ w~~re concrete tll" ~liit.e t' may
be $o q 1\e~vr • il-hase chM!9 ~ •lilater 1a Js !;:OI'lS 'i li t of a l pw me ftfng p.oir~t chemi :cal
10.5
encapsulated in a container. The chemicals will change from a solid to a
liquid at a certain temperature (81°F in several models), storing the heat of
fusion. Once fully charged, they will release this heat back to the space,
slowly changing from liquid to solid as they give· up energy. Phase change
materials offer the second advantage of requiring much less volume than other
storage mediums for the same amount of energy stored. However, they are fairly
costly at present and have no long-term record of success. In addition, the
temperatures needed to achieve phase change may not be constantly met in all
passive solar applications. Nonetheless, phase change materials may be a via-
ble solution to the problem of providing heat storage in existing buildings.
Much study needs to be done with these new products to determine their effec-
tiveness in the Railbelt.
Finally, the thermal efficiency of the structure will have an overwhelming
imp~t on the usefulness of solar heating systems. Given that solar access is
more limited in Alaska than in the southern United States, a structure built
to the same specifications as those in more temperate climates will not rea-
lize a significant benefit from the sun's heat. A building that is heavily
insulated in recognition of the severe climate in Alaska will reduce its
heating load accordingly. Once this load is reduced, passive solar becomes
much more attractive as a heating source.
10.1.2 Technical Characteristics
Technical characteristics important to evaluation of passive solar appli-
cations include system efficiencies, coincidence to load, adaptability to load
growth, convenience and control, electrical load offset and complementary
technologies.
Passive Solar Efficiencies
The efficiencies of passive solar technologies can vary widely with the
type of strategy employed. A multitude of other factors in addition to the
system type (direct gain, greenhouse, etc.) will also affect efficiency.
These factors include, but are not limited to the following: orientation,
obstructions and shading, exterior temperatures, building heat loss, and the
10.7
absorption and heat capacity of thermal storage. Because solar energy relies
on the sun, it does not produce a constant amount of energy as might a central
fuel-fired plant.
Because the amount of energy produced will vary with each particular
installation, the actual efficiencies cannot be quantified on a widespread
scale at this point. This situation will continue until existing systems in
the Railbelt region are monitored. The examples below help illustrate the
broad range of possibilities.
A direct gain system using double-pane vertical glass, oriented due south
with no obstructions or shading, will transmit approximately 75% of the avail-
able solar insolation when the sun is striking the glazing at a perpendicular
angle. Direct gain offers the highest efficiency of any passive solar approach
because the only variable affecting the solar gain is the irregularities in
the glazing itself. Several disadvantages exist, however. Glare and overheat-
ing of the living space may result unless accounted for by proper design.
Furniture and rugs may fade over a period of time from exposure to direct
sunlight. Finally, heat gain will be quickly lost at night without some form
of movable insulation over the windows. Although figures will vary throughout
the region depending on location, studies have shown that without shutters a
net loss occurs through solar glazing during much of the heating season.
Shutters are essential for optimum performance. The thermal performances of
windows with various levels of glazing are compared in Figure 10.2. For each
case the performance is compared with and without an R-9 shutter in place
during the nighttime. South-facing windows with shutters clearly are the best
performers.
The efficiencies of the greenhouse/sunspace are much the same as those of
direct gain, with one major difference. Since solar heat must be transferred
from the sunspace to the house, the thermal efficiency of the greenhouse
itself will have an overwhelming impact on the amount of usable heat for the
main structure. As mentioned earlier, a minimally insulated greenhouse will
use most or all of the solar gain to maintain ambient temperature within
itself. On the other hand, a thermally efficient sunspace using night
10.8
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-1
-2
EXPOSURE
SOUTH EAST OR WEST NORTH
---wiTHOUT SHUTTER
SOUTH EAST OR WEST NORTH
---WITHOUT SHUTTER
SOUTH EAST OR WEST NORTH
---WITHOUT SHUTTER
SONDJFMA SONDJFMA SONDJFMA
C. QUADRUPLE GLAZING
FIGURE 10.2. Solar Gain Versus Heat Loss with Various Levels of Window
Glazing and Directional Orientation in Anchorage, Alaska
(thermal energy transfer = 104 Btu/ft2)
10.9
111s~l.atHln .oveo·· t11e w1r1 tlGif5 ·~d il p,rov1ile a sig:ni 'f.:l cal'l~ amou nt o1 f].ea~ 1.0 'tile
1 lv 1n1! ~rea. S,t4dte~ don.e fpr AnGhoraqe t a» sh·o..v th'at the amoJJn ); nt:· h~at ttJat
·h crHl~C:·.ted in .a 'f<a 'irjy ~rna rf, g_'t~achetl 9T"e.ell'h9.u ~e. a't!Jj t h<tt 1~ a>la ilab·l e . f ot
use ir~ t he l)l afn ~tru~~Ur'& ~>~il l r11 ng e from fl~. it-1 -an all -gl~!;$, coDmer c ia ll :Y
ITJanoJfaGJ.t~re.d gr een hc:tl!M t.o 5~~ for a e us tom,..d ~s ~gned unit i ·nsu 1"ate.d tQ R'-5Cl 1
wiPI M.utl), .g; a ~trrg .rn1 y (~e lab.ie 10: .. 2~.
Ih'l? $!'h::l'eot:i<es :of til~ 'lrtas~ wa lJ fcooe,rl!!te/Wa'ligr ) con.ce,pt i s lihe mo s t
cl lffi .\!Ul t. !:v tiuilrlt ify. •f.lo. ~~'t ~~~l ~ll.P.lfr.;af.iOITS 'lll;l i'JW,I' to ;eifi s t i·fl th~ 'R<~H
tielt, J'. A, G$1 1<'l¢s n1re trnrtr Alat.IHI. Renewabll! .Ener.oty Ji;~sot iate'S ha·~ dg.signe!l
Vi~ at is tiel1eve(i t_a.tt~ th~ first T.rortrl:!e wa 11 ,}.o b~ b,uiH il'l 8<1~-sk.a. Nn da ta
on H:s p:erf<otiJJance -a re, fiQ.WeVel", avil. naMe:.
The Mb· e :t-tst-tng st tictY of' Trornbe wa·lls ~n t il e R'a.il'be 1( ~~~s ,gener.ated b..9
AlasRa R~rte.wao1e 'WI:flgy As-sociares ('S ei f el"t 19.80), u.s·l'f\g c-ompu ter s imul ation
110 tmd a i perform~rtce t.r~1 ng 150 itt. 3 wa 11 s 9 z~s i n iSoo ita h~av ll y 1 n s-~ ~
Jat~~ b~vse s-. P.er\~entase~ of t ~e .Y ilarl ¥ h ~;;~:t if'l.9 l oad tl is(ll&~e~. BY soia" !)a in
Viil"Y fl•om 3'6% i'n !Ca r:r b an l<.~ t o: ~~X HI ~omer . Wh fj e t}l e res l.(.1J;.-~ ( H~teit' in
T<ib l e iO .,4 ) f·ndtc<~.te ~h at sk\rage walls can b..e e ffec-Hv,~, ac t ua·l l11~ta i 1 C!.'t 'i ons
mu st 'f>!l ~rd 'tor.~d to va jidate the! Hndirt_\l s"
Thlf 'S·R~ee b.etyle·eA 'J!h;e g1azi .~.g anl;l t he-mass wall can react! temj<eralillres as
h i!!lb a.s 13.0 to Zd(I QF, Because he'at 1rr .,_n~t'er& :f~'JJlJJ war m. to co.1d 1 ex ter ,iot 'bem-
per .a'll!JF-4 .vlll'1 have' an illli'Jac,t O!l t llll'-~yS::te,u·•s ~-ff1 ci.eMY· The ~ta 1ct'et-:ll h.e· ,o"Ut-
.s ige a'ir TS, tl)e-(JIC)re hed;t 1A1'Jl b;e lo.st fl:ack. .out Jil1 e gl..azit!,g, b_et;all ·Se of t )le
1ii9.t1 MfliP~ratur(}s ery~l.iy n te'r·ed in ttre. ~Pii'li~ '!l f!t~:t'l~ tb¢ wa 11 a n~ ttre g'lat in.l).
Th js, 1{'t~S: .~:ap b~ r<ed u~:~Q.. ho!'lev!'l', by 1:rr.s1:1).1l i ng ad~ it i'OJIB; 1 g Jaz rng or mq yB,ble.
i'nsu 14 (i em.
3olar eff'i :ci en c:ii!s 11ar,s wl :d E'.:iy :d.epend 1n9 !lfl m:a.ny far=tGJrs , ~a t e.no'I:Jgll \1/QY.k
has been done to make afZt u ~a t.e pl"o le.cti ons .. Ac tual tAs'ta llatitms Md studl.e;s,
dt)n·e sn ow tha:t pa;ss·tve: Stl la;. '"ar, P.r'Ovit:l~? s-igni!fi c arrt amouitt of the heat·i!Jg
needS'; .at-tua1 man1·Mr+«!!, of. sj·stem!> 11i1l Ire! tl ~tte.ssar:y ro. quan ttfy HH 's war~
f'u t the r.
f a j l\ l a:!lk& Rene.wafl J e ~.rr<"rw ~-sQc i at~s [l\KR}lA'J, 1 ~~0 (t)t:\l-'ft) .. U ss i v.e .SO' l,ar
_Gt"aetth Gus es. f.Dl' Jl:·laskia·, ·Alaska Renew11ble Ener g~ Assocfates, Ar#lol-(l{(e,
AT(jtk"'.
10' .1 0
TABLE 10.2. Usable Solar Heat for the Main Structure(f)om an
Attached Greenhouse At Anchorage, Alaska a
Yearly So 1 ar % of
Yearly Heat Radiation Heat to Heat to
Greenhouse Type Load ( MMBtu) (MMBtu) House (MMBtu) House
R-2 (All glass manufactured 61 42.4 -18.6 -30
greenhouse-2 panes)
R-19 Insulation (130 ft2 31.7 2.7 9
glazing-unshuttered) 34.4
w/shutters (R-lQ)(b) 22.1 12.3 36
R-30 Insulation ,(130 ft2 28.3 6.1 18
glazing-unshuttered) 34.4
w/shutters (R-10) 18.7 15.7 46
R-50 Insulation (130 ft2 25.9 8.5 25
glazing-unshuttered) 34.4
w/shutters (RIO) 16.3 18.1 53
(a) Assumes an 8' x 20' greenhouse with 130 ft2 south glazing, opaque end walls and
roof one insulated door in end, and full solar access with due south orientation.
(b) Assu~s shutters closed 12 hours per day during the heating season (September-May).
Coincidence to Load
The ability of a passive solar installation to offset a structure's heat-
ing demand will depend on several factors: the type of system, proper design,
and coincidence of insolation with demand (both diurnal and seasonal). Because
of these factors, each case is very likely to be different. The few existing
Railbelt systems are showing that during the mid-winter months (December and
January), some type of backup heat is required. As outdoor temperatures warm
and the amount of sunlight becomes greater, the systems appear to be meeting
most of the heating needs. However, these homes are very heavily insulated
and therefore have a reduced heating demand compared to the typical structure.
These are very preliminary findings and should not be considered conclusive.
Without some form of storage mass to carry solar gain over into the nighttime
or cloudy periods, passive solar systems are reliable only when the sun is
shining.
10.11
TABLE 10.3. Simulated Comparative Heating Needs of HQm~ Built to
ASHRAE 90-75 Versus Passive Solar DesignlaJ
Heating Needs
ASHRAE 90-75 AQnual
Heating Load(bJ (MMBtu)
Passive Design
Annual Heating
Load (MvlBtu)
Percent Decrease in
Heating Load
Heat Provided by
Sunlight (MMBtu)(c)
Sunlight as a Percent
of Passive Heating
Load
Heat Provided by
Backup Fuel (MMBtu)
Passive Design
Heating Savings
(MvlBtu)
Percent Reduction in
Fuel Consumption
Homer --
155
89
43
47
53
42
113
73
(a) AKREA, computer simulations.
(b) Based on 1,500 square-foot home.
(c) Assumes 150-cu-ft Trombe wall.
Location
Matanuska
Valley Fairbanks
162 218
89 111
45 49
42 40
47 36
47 71
115 147
71 67
Adaptability to Alternative Future Growth Patterns
Passive solar technologies may be added quickly on an incremental basis.
The length of time between construction startup and operation is extremely
short. A simple retrofit may require only a week and a new structure may
require only up to 3 to 4 months. Consumer acceptance, site solar access and
the economic feasibility of applications will be the major factors determining
future adoption of passive solar technology.
10.12
Consumer Convenience and Control
Passive solar offers both advantages and disadvantages to the consumer in
terms of convenience and control. Its effectiveness depends on the willingness
of the individual to understand and to make maximum use of the sun's ability
to heat space.
For the passive system to achieve optimum performance, movable insulation
must be placed over the glazing when the sun isn't shining. Although the
amount of time required for operation will differ depending on the amount of
glass and type of shutters used, a broad average would be 10 to 15 minutes per
day, or 5 to 7.5 hours per month.
Type of Electrical Load Offset
The majority of structures in the Railbelt region are heated by natural
gas, oil, and to a much lesser extent by wood. Electricity for space heating
comprises such a small percentage of the electrical load that passive solar
space heating would have little immediate effect on the demand for electricity.
The ability of passive solar to affect the daily load curve will depend
on the storage capacity of systems installed. A simple direct gain system
with no storage will require full backup heating at night and during periods
of no sun to alleviate wide swings in temperature inside the dwelling. The
addition of storage mass will help dampen these swings and will reduce depen-
dence on traditional modes of heating during times when the sun is not shining.
If all installations were of the direct gain type, with no heat storage,
the effect on demand would be to reduce the baseload. The peak load would
remain the same since full backup systems would be needed when the sun was not
shining. If all systems were to incorporate some form of storage mass, the
peak load would be reduced because the carryover of heat in the storage system
would offset load during the peak loading hours. In all cases annual peak
loads would be unaffected.
10.13
Complementary Technologies
A thermally efficient building is a prerequisite for optimum solar per-
formance. The amount of heat available from the sun does not equal heat loads
in "typical .. Alaskan buildings during much of the winter months, but by reduc-
ing the heating load through conservation, solar energy systems can provide a
large percentage of the remaining loads.
Passive and active solar used together constitute a hybrid system. In
the Railbelt, such systems can work well together, particularly when passive
is used for space heating and active is used for domestic hot water heating
(DHW). The DHW load will be fairly constant throughout the year, including
summer months. Computer simulation has shown that the sun can provide virtu-
ally all of the DHW needs in the summer and can act as a preheater for the
main system during much of the spring and fall months.
Even with a combination of solar and conservation, a backup space heating
system is required in the Railbelt. A typical large home in Anchorage might
use between 100 and 150 thousand Btu/hr during the colder winter months to
maintain comfortable temperatures. A super-insulated passive solar home of
the same size will use only 35 to 45 thousand Btu/hr, a reduction of 65 to
70%. The remaining energy requirement can be met by a typical wood stove.
Burning with wood is not for everyone. Other alternatives include con-
ventional central heating systems (downsized to compensate for reduced energy
demands of a well-insulated, passive solar structure) or 11 Spot" heaters in
critical areas of the house. Spot heaters may make economic sense; they are
less capital intensive to install and potentially less costly to operate over
the life of the structure.
10.1.3 Siting Considerations
Siting considerations for passive solar installations include insolation,
orientation, and solar obstruction.
Insolation
Insolation is defined as the total amount of solar radiation, including
direct, diffuse and reflected, which strikes a surface exposed to the sky.
10.14
Incident solar radiation is measured in langleys per minute, or Btus per
square foot per hour or per day.
Insolation varies throughout the Railbelt region, depending on several
factors, including latitude and percentage of cloud cover throughout the year.
A very broad average figure would be 300,000 Btu/ft 2;yr on a horizontal sur-
face. In comparison, Albuquerque, New Mexico, has approximately 700,000 Btu/
ft 2/yr of insolation. Obviously, solar radiation in the Railbelt falls far
below those figures of geographical areas nearer the equator. However, the
long heating seasons and high heating loads in the Railbelt can justify use of
available radiation.
Because the zenith angle of the sun is so low in the region, obstructions
in the sun's path can be a problem. However, that postion is an advantage in
maximizing usable solar radiation. The greatest amount of available energy is
intercepted when the sun's rays strike the collector surface at a perpendicular
angle. The greater the variance from perpendicular, the more radiation is
reflected away from the glazing surface. Because of the low sun angles preva-
lent during the heating season in the Railbelt, vertical glass is an excellent
collector.
Research done in the region shows that the difference in percentages of
solar rain between vertical glass and tilted glass is minimal within a ~20%
range. a) Vertical glass, particularly stock manufactured window units, is
cheaper to install than custom designed tilted glazing, particularly when
retrofitting existing buildings for passive solar.
Only Anchorage and Fairbanks are currently measuring insolation on ver-
tical surfaces. Longer term data gathering of insolation on vertical surfaces
at many sites is necessary to form a scientific base of available solar radia-
tion in the Railbelt region.
(a) A general rule of thumb for optimum tilt of glass is latitude plus 15°.
Thus, in Anchorage: 61° latitude plus 15° = 76°, which is very close to
vertical.
10.15
Or i entation
The bulk of solar radiation usable for space heating is found in the
southern sky. Therefore, the collection area should be oriented close to due
south. However, a variance of 20° or so from due south will not have a signi-
ficant impact on performance (see Table 10.4).
Developers often have failed to take into account the impact of the sun
when designing subdivisions and building sites. As a result, some existing
structures would have difficulty capturing solar radiation. On the other hand,
many existing buildings can be retrofitted to use solar gain. Some assessment
of current building stock must be made before a knowlegeable forecast can be
given. New construction usually can be oriented correctly, if the topography
of the building lot will allow siting to the south.
TABLE 10 .4. Percentage of Radiation Striking a
Surface at Given Incident Angles(a)
Incident Angle
(degrees)
0
5
10
15
20
25
30
35
40
45
50
55
60
65
70
75
80
85
90
Solar Intercepted
(percent)
100.0
99.6
98.5
96.5
94.0
90.6
86.6
81.9
76.6
70.7
64.3
57.4
50.0
42.3
34.2
25.8
17.4
8.7
0.0
(a) The incident angle is the angle in degrees
at which the sun is striking a surface.
10.16
Solar Obstruction
The single largest problem facing solar technology in Alaska centers
around the possibility of obstructions in the path between the sun and the
collector surface. The sun is low on the horizon during much of the winter in
the Railbelt. It rises to a zenith angle of only 6° in Anchorage and 4° in
Fairbanks on December 21st. Because of these angles, short objects can block
useful solar radiation (see Figure 10.3).
/
/
/
/
NORTH SLOPE SOUTH SLOPE
BUILDINGS ON A NORTH SLOPE WILL CASTLONGER SHADOWS
lllll SHADED ALL YEAR
!if FALL AND SPRING SHADING
~ WINTER SHADING
--------230' ---------1
SHADOW LENGTHS BEHIND A 10 FOOT HIGH OBSTRUCTION
AT 6Jl<l NORTH LATITUDE
MARCH 21
A;:t --.:_p
DEC. 21
FIGURE 10.3. Solar Shading Effects in the Railbelt
Because of insufficient information, the severity of solar shading in the
Railbelt cannot be currently assessed. The problem is less significant in
areas where housing density is lower, particularly in the more rural areas.
The lack of large trees and tall buildings in the region further reduces
shading and obstruction problems. However, the mountainous terrain causes
some solar obstruction. In urban areas where the density of housing is high,
the possibility of shading problems increases.
10.17
Resolution of the siting problems will require studies to develop optimum
siting patterns for higher density development to use in planning and review.
In addition, design professionals, developers, builders, and the general pub-
lic must be made aware of the benefits of orienting structures to take advan-
tage of solar insolation.
10.1.4 Costs
Virtually no estimates of the capital costs for passive solar systems are
available for the Railbelt. This stems from several factors: the relatively
small number of existing applications, the wide range of types and degrees of
passive solar installations, the reliance of most solar buildings in the region
on heavy insulation and efficient thermal envelopes to reduce heat load, and
the difficulty in differentiating between passive solar systems costs and
general building costs. In addition to these factors, differences between new
structures and retrofits usually exist because retrofits often involve some
expense in tearing out and revamping to accomodate passive solar components.
Preliminary studies show an increase of between 6 to 10% above normal
construction costs for a new passive solar, superinsulated home. Thus, in a
$100,000 11 typical 11 home, an added expenditure of $6000 to $10,000 could be
expected. Total heating load would be reduced by 65 to 75% through conserva-
tion and solar measures. However, some passive solar or conservation strate-
gies have little or no incremental costs. For example, in new construction
the movement of window glazing from a north to south wall carries no incremen-
tal costs, but significantly reduces heating loads. Similarly, a well caulked
and well sealed home is only slightly more expensive to build but much less
expensive to heat.
Early figures show an increase in installed cost of 4 to 12% over base
costs if solar is added to the home. The low-end figure reflects the addition
of simple glazing, and the high end reflects a heavily insulated structure with
some form of storage mass built in. These translate into unit costs ranging
from $3.50 to $15/MMBtu. The least expensive installation is not necessarily
10.18
the most cost effective because it may not displace enough of the heating load
with solar to pay for itself within a reasonable amount of time. The following
example will help to illustrate the possibilities:
Base Case: A 1500-ft 2 home in Fairbanks is built to ASHRAE 90-75
standards with a 218 MMBtu/yr heating load.
Passive Solar/Superinsulation Case: Conservation (superinsulation)
and passive solar design with concrete storage mass (150 ft 3) will cut the
heat load of the above house to 71 MMBtu/yr, a savings of 147 MMBtu/yr.
O&M costs are $25.00/yr.
Costs per incremental MMBtu saved were then estimated for the passive
solar/superinsulated case, assuming $6,000 and $10,000 incremental capital
costs of the passive solar/superinsulated design.
A.
B.
$6,000 incremental capital cost--
1. 15% interest, 30-yr term, conventional
1 oan
2. 10% interest , 30-yr term, State loan
3. 5% interest, 20-yr term, alternate
energy loan
4. 3% (real) interest, 30-yr term(b)
10,000 incremental cap ita 1 cost--
1. 15% interest, 30-yr term, convention a 1
1 oan
2. 10% interest, 30-yr term, State loan
3. 5% interest, 20-yr term, alternate
energy loan
4. 3% (rea 1) interest, 30-yr term(b)
(a) For electric resistance space heating.
Cost
$/MMBtu
6.38
4.49
3. 58
2.34
10.53
7.38
5.86
3.52
of Savings
mills/kWh(a)
22
15
12
8
36
25
20
12
(b) Real interest rates, as used for comparison elsewhere in this report
(no tax cred its) .
10.19
By comparison, the cost of fuel oil in the region as of January 1981 was
as follows:
Anchorage $8.40/MMBtu
Homer $8.69/MMBtu
Fairbanks $8.20/MMBtu
These examples constitute broad averages only and represent only one particular
case, a superinsulated new house with maximum solar considerations. This par-
ticular example is an 11 extreme 11 case. Capital costs will be less with struc-
tures employing lesser degrees of insulation, sealing and passive solar design.
The varying range of fuel costs in the region makes it difficult to determine
how much of a front-end cost is economically feasible. The cost effectiveness
of the passive solar/superinsulated case would be improved if tax credits were
considered. Also, note that conservation and solar technologies are virtually
inflation proof once installed, whereas fuel oil is not.
Until further study is done, particularly with solar retrofits, these
figures should be viewed as estimates. However, the retrofits show economic
potential in many parts of the region, particularly since the examples neither
reflect added tax incentives nor address future fuel inflation costs.
In the examples a figure of $25 dollars per year was set aside for O&M
costs. This figure reflects a 11 worst case;11 in reality these costs may
approach zero because passive systems are extremely simple, with few or no
moving parts. The costs depend on the particular system, but generally,
passive systems will last the life of the building with little maintenance
costs.
Various financing scenarios further complicate cost estimates. The State
of Alaska presently has a program to install alternative energy systems at 5%
interest on a 20-year term, up to a maximum of $10,000. This sum is sufficient
to incorporate most passive solar installations on a small scale. Obviously,
unit costs would be much lower over the life of the structure under this rate
than with conventional financing.
10.20
Costs can generally be viewed on an incremental basis. A new structure
that is oriented south with the majority of its windows placed there will cost
little, if any, more than a standard structure. Adding a larger expanse of
glazing will increase the cost. Finally, adding storage mass in conjunction
with glazing will mean higher initial investment. Several options for a 1500-
square-foot structure are analyzed in Appendix L.
The useful life of a passive system will generally be as long as that of
the structure. Virtually no replacement of parts or maintenance are needed
because the components are part of the structure. Because the system is
"built in," system operation time and cost are minimized.
10.1.5 Environmental Impacts
Environmental impacts from passive solar technologies are minimal, almost
nonexistent. No traceable air or water pollution has been recorded in
dispersed application. Solar is an ideally benign fuel source for the
environment.
The potential detriments to the environment center on two factors:
aesthetics and reflected glare. Aesthetic appeal is, of course, subjective
and not quantifiable here. It is however, an important factor. Since the
concept of passive solar centers on the building and its components, the
designers must ensure an aesthetically pleasing structure. Numerous examples
of passive solar buildings throughout the United States are considered "ugly"
by their critics. On the other hand, just as many or more examples of success-
ful installations can be found. Entire solar subdivisions, such as those in
the city of Davis, California, are both pleasing to look at and pleasant to
live in. Perhaps the strongest point to make is that passive solar housing
does not have to look different from the more "traditional" buildings, except
for the expanse of south facing glass. Figure 10.4 shows an example of a
building incorporating passive solar design.
Reflected glare off south glazing is a potential problem in solar appli-
cation. The extent of the problem in the Railbelt is not known at this point.
Glare is more prevalent when the sun strikes the glazing at an acute angle;
i.e., the less perpendicular the sun•s rays to the collector surface, the
10.21
1--'
0 .
~
< ro
(./)
0
s:u
)
0 ro
Ul
(:(:'01
more glare encountered. During the winter, vertical glass·will not cause
excessive glare problems. In summer, proper design of the roof overhangs will
ensure that enough of the glass is shaded to alleviate most glare. During the
spring and fall the phenomenon could cause problems to passing motorists and
pedestrians. The few solar system installations in the Railbelt region pre-
cludes answers at this time. However, newly introduced "etched•• glazing or
various glare control films can mitigate glare problems.
Consumer safety poses no real problem with passive solar if precautions
are taken to avoid impacting and breaking the glazings. Glazing in locations
susceptible to impact should be of tempered glass. Because most systems are
simple and benign, danger to the consumer is far less than, for example, a
central fuel-fired furnace system. Workers certainly face a higher percentage
of danger when installing systems, but potential injury and death is limited
to those instances the worker might encounter during standard construction.
10.1.6 Socioeconomic Impacts
The socioeconomic impacts of passive solar technologies for space heating
center on three areas: 1) land use, 2) consumer convenience and control, and
3) regional economics.
Land Use
The patterns of land use would be affected if passive solar technologies
were considered on a widespread scale. Solar obstruction and shading would
need to be addressed in site planning to prevent the degradation in efficiency
of an individual solar application by a building placed in the sun•s path at a
later date. Such a measure can be implemented through zoning, subdivision and
site planning procedures. This type of legislation has been adopted in a few
5tates. The 1979-80 session of the Alaska legislature passed SB 438, a bill
·elating to energy. One section of the bill states:
"An easement obtained for the purpose of protecting the exposure of
property to the direct rays of the sun must be created in writing
and is subject to the recording requirements for other conveyances
of real property."
10.23
However, the wording implies a policy statement and not a regulation. As such,
no administrative network of funding was provided to institute such action.
Without further development of land-use management procedures that include
consideration of solar access, an individual risks losing the benefits of his
expenditure for solar energy by unregulated obstructions to the south.
Land-use planning for solar access is a fairly new science. Although
studies have been done in the Lower 48, no such work has been done in the
Railbelt. Existing studies show that such access does not necessarily require
lower density of housing.
The low sun angles prevalent in the Railbelt during the middle of winter
would probably be a limiting factor on solar gain in 11 typical 11 subdivision
design. Two options are available. The first involves limiting density of
units so that solar gain is available during the entire year. The second
approach leaves the density of units per acre as exists today, with the plan-
ning process including proper orientation and placement of structures. From a
purely economic standpoint, the second option would be chosen unanimously.
However, shadows would probably negate solar gain during December and early
January in such cases. Because of the long heating season, solar would still
be beneficial during a large part of the winter. For development plots with
greater than a 5% south sloping grade, no reduction in housing density is
required to assure solar access.
Consumer Convenience and Control
Passive solar offers the following advantages:
• virtually no maintenance or replacement of parts during the build-
ing's lifetime because the components are a part of the structure
• little or no operator attention with the exception of optimal ther-
mal shutters
• a significant portion of heating needs provided in case of power
failure or fuel shortages
• reduction of dependence on uncontrollable factors affecting fossil
fuel pricing and availability
10.24
• reduction of fuel expenditures and thus more disposable income
available to the individual
• safety.
Potential disadvantages include the following:
• necessity of operating shutters
• wide temperature swings within a heated space if no storage mass is
present to regulate the variance in available solar radiation.
Regional Economics
Because passive solar is a decentralized technology, it will create jobs
and new capital ventures at a local level as well as at a regional level.
Since the skills required to design and to install systems are relatively
straightforward, using standard materials and techniques, most of the human
resource needed most likely exists in the region. If pursued on a fairly
widespread scale, the potential for long-lasting jobs in new and existing
businesses is promising. Although numbers are not quantifiable within the
limits of this profile, early studies in the United States have shown that
decentralized options provide more benefits in terms of local employment than
larger, centralized projects (Buchsbaum and Benson 1980).
An increase in employment and business at the regional level would most
likely result in an increase in the amount of capital staying in the region,
further providing economic benefits outside the construction sector. The
extra income available to the consumer by reduced fuel expenditures would
become part of the region's economy. While an in-depth economic analysis
cannot be done until the degree of penetration of the solar technologies in
the market place can be better assessed, preliminary study and common sense
indicate that passive solar would have a positive imp~t on the economy.
10.1.7 Potential Application to the Railbelt Region
Passive solar is an emerging technology in the Railbelt. Currently, only
a few structures have been designed specifically to take advantage of the
maximum amount of available solar radiation. Until very recently, cheap fuels
have provided little incentive to explore alternative forms of heating.
10.25
During times of major building activity so prevalent in the boom and bust
economy of the region, the trend has been towards minimizing front-end cost,
with little or no regard to future operating costs.
A combination of energy conservation and passive solar in new construction
can cut energy demands by 60 to 70% in an individual dwelling. The potential
of passive solar and conservation in existing buildings is difficult to quan-
tify without knowing the structure's existing condition and solar access. A
30 to 50% reduction in the heating load is possible if these two technologies
were combined. Without an assessment of existing building stock, an aggregate
projection is difficult (Seifert and Zarling 1978).
The potential contribution of passive solar is difficult to assess on a
region-wide scale. Little data exist on the performance of the few installed
systems, and the number of buildings having good solar access in the Railbelt
is not known. Therefore, two examples of typical structures are presented
here to illustrate the impact passive solar can have on an individual unit.
The first model is a house insulated to the standard level now prevalent in
the Railbelt; the second is a superinsulated home using heavy insulation and
other techniques to radically decrease its energy consumption. Both structures
have floor areas of 1500 square feet. Glass area is varied to show the impacts
of different glass sizes on passive solar heating (see Table 10.5).
TABLE 10.5. Solar Heating Fractions for Various Railbelt Applications
House
Anchorage
1. Typical House
2. "Superinsulated" House
Fairbanks
1. Typical House
2. "Superinsulated" House
Solar Heating
w/150 n 2
glazing
23
45
17
33
Fraction (%)(a)
w/ 200 ft 2
glazing
30
57
22
41
(a) Amount of annual heating load supplied by passive solar heat.
10.26
Obviously, the less heat that has to be supplied to a structure, the more
attractive solar heat becomes. Note that in the superinsulated structures the
heating load has already been reduced radically, and although passive solar is
supplying 40 to 50% of the heat, the combination of conservation and solar
reduces the load up to 70%. Several of these structures in the Railbelt are
using 25 to 30% as much energy as their neighbors by combining an efficient
thermal envelope with solar heat.
Passive solar technologies use materials and building techniques common
to the building trades -an important attraction. Because passive solar in
the Railbelt is best exemplified by an energy-efficient house coupled with
south glazing, it is easily accessible to the designer•s and builder•s present
skills.
Development of a thorough understanding of the cost effectiveness of
various levels of passive solar design followed by education of designers,
developers, builders, and consumers is the key to successful implementation of
solar technologies. The efficient passive solar house in the Railbelt employs
a combination of several techniques: a thermally efficient building envelope,
south glazing, a continuous vapor barrier, reduced infiltration, and some form
of heat storage system. All of these components can be integrated into a
house with materials already available in the region. A few components not
stocked in the state would help to refine passive systems, and they are
available on fairly short notice from suppliers in the Lower 48.
Education of the building trades is essential. The building industry is
historically slow to adapt to changes in technology. No matter how well the
design and specifications are drawn up, education of builders and craftsmen
will be necessary to ensure that passive solar systems work to their designed
efficiency. However, interest among builders in the region toward passive
solar technology appears to be high.
Existing financial practices present an additional obstacle to developing
passive solar technologies in the Railbelt. Commercial lending institutions
historically tend to consider the front-end costs of constructing a building
only. The concept of life-cycle costing must be taken into consideration if
10.27
passive solar is to be successful; O&M costs (i.e., fuel) over the life of the
building must be integrated into the overall cost. The degree of acceptance
of the life-cycle costing concept among lending institutions is not clear.
Scattered reports indicate some bankers' resistance to extra costs for solar.
On the other hand, several lending institutions in the Anchorage area have
extended loans for passive-solar-designed homes, despite higher initial costs.
Real estate appraisers present another possible obstacle. Most do not
seem to understand how to include passive solar in their reporting. To quote
one appraiser:
"I suppose what I'm trying to say is that I really don't know (how
to appraise the market value of a solar house). An appraiser's job
is to estimate value based on fact occurrences and, unfortunately,
there haven't been enough fact occurrences to give a true and
accurate answer." (Seifert 1980).
Most Alaskan appraisers of solar homes do not understand how to value
reduced heating bills. Energy use is simply not a factor in the training and
scope of work of the appraiser. Once again, education of these professionals
is necessary.
The State of Alaska has an alternative energy revolving loan program
available to the consumer at low interest rates to help offset the initial
costs of systems. The loan ceiling is $10,000, at 5% interest with a 20-year
term. In most cases, this money in itself will cover additional costs for the
passive system. While several administrative problems have occurred in the
first year of the loan program operation, consumer interest is high, and
efforts continue to resolve the flaws. The program is an important step
toward solving some of the financial obstacles discussed.
10.2 ACTIVE SOLAR SPACE AND HOT WATER HEATING
"Active" solar systems require auxiliary pumping energy to function prop-
erly. These systems differ from passive solar systems, which require very
1 itt 1 e or no auxiliary energy. Active so 1 ar energy use is an accepted tech-
nology, with thousands of installed systems throughout the United States.
10.28
10.2.1 Types of Active Solar Systems
Three varieties of dispersed active solar systems are currently available
in Alaska: liquid-based, flat-plate collector systems for space heating;
liquid-based, flat-plate collector systems for hot water heating; and hot air
systems for space heating. A large variety of manufactured collectors is
available throughout the United States, and several models applicable to the
systems mentioned above can be found at wholesalers and retailers in Anchorage
and Fairbanks. In addition, site-built and locally manufactured units fabri-
cated by sheet metal and plumbing shops are available, particularly in the
Fairbanks area.
Liquid-Based Flat Plate Collectors for Space Heating
The flat-plate solar collector (Figure 10.5) is the most common configu-
ration used today in active solar energy systems. Active solar systems employ-
ing flat-plate collectors are the most common type used to retrofit homes and
TRANSPARENT COVER PLATE
PASSES SUNLIGHT BUT TRAPS
HEAT AS A GREENHOUSE
DOES.
INSULATION KEEPS
HEAT IN
FLOW PASSAGES WHERE FLUID IS HEATED
FIGURE 10.5. A Typical, Liquid-Based, Flat-Plate Collector
10.29
businesses because they offer greater installation flexibility. In flat-
plate, liquid-based collectors, the absorbing surface has several tubes run-
ning lengthwise through it. Liquid is pumped through the tubes. Sunlight
heats either the tubes directly, or the plate, which then transfers heat to
the tubes. The heated liquid can be used for either space or water heating
applications (Figure 10.6). For year-round use in the Railbelt, a liquid-type,
flat-plate collector must incorporate antifreeze in the heat exchange fluid to
prevent freezing.
Flat-plates can accept either direct or indirect sunlight from a wide
range of angles. The absorber plate is fabricated from a material that is a
good conductor, such ascopper or aluminum. It is painted black to absorb as
much radiation as possible. As the plate warms up, it transfers heat to the
fluid within the collector, but also loses heat to its surroundings. To mini-
mize this heat loss, the bottom and sides of a flat-plate collector are insu-
lated, and a glass or plastic cover is placed above the absorber with an air
space between the two. The cover permits sunlight to come through while
reducing the amount of heat escaping. If the collector is located in a cold
region (such as the Railbelt), two layers of glazing are sometimes used,
although the cost effectiveness of double glazing needs further research.
(>\
' ' ' ' ' ' ' ' '
SOLAR
COLLECTOR HEAT STORAGE
==~=d)
\PUMP OR FAN
0
~==t==
VALVE
HEATED
SPACE
FIGURE 10.6. Typical Active Solar Space Heating System
10.30
Currently less than 20 operating double glazed systems exist in the Railbelt
area, and none have been monitored to determine the efficiency of double
glazing.
A version of the flat-plate collector, which may be applicable for Alaska,
is called SolaRoll~.(a) The system consists of a unique exchanger/absorber
plate made of a black, flexible elastic monomer that can withstand freezing.
The system has an anticipated 30-year lifetime and performance tests indicate
that SolaRoll encased in a standard site built or locally manufactured insu-
lated collector frame performs better than average metal solar collectors.
The system is tailored for do-it-yourself installation and requires no nails,
screws, plumbing elbows or tees, or battens for assembly. Soldering, welding,
sealant, or paint also is not needed. SolaRoll is an example of the types of
technological advances that continue to make solar collectors cheaper and
better (Seifert 1980).
Active systems require an energy storage system for optimal effectiveness.
Storage for the liquid types usually consists of a well-insulated water tank,
with an exchanger to draw off heat as needed for the main distribution system
(see Figure 10.6).
Liquid-Based Flat-Plate Collectors for Hot Water Heating
Active solar systems for domestic hot water systems use the same type of
collectors used for space heating systems. Figure 10.7 shows a typical hot
water heating installation. A heat exchange loop must be provided in hot water
heating systems to prevent the antifreeze from contaminating the potable water
supply in the event of a leak.
Active solar for hot water heating offers many attractions in the Railbelt
region. Water heating is a year-round activity, so a much closer match exists
between resource availability and load than for space heating. The collector
can be much smaller than that needed for space heating; thus, installation
costs are much lower. Although solar hot water heating will likely not pro-
vide a great portion of midwinter needs, during fall and spring months it will
supply a large portion of the load. During summer, nearly 100% of hot water
(a) A trademark from the Bio-Energy Systems, Inc., Ellenville, New York.
10.31
C\
' \ \
\
\
\
\
SOLAR
COLLECTOR
STORAGE
TANK
AUXILAR~ER
u==u~ TO LOAD
0
n ~ WATER FROM
L::l = = MAIN AT
34° TO 40°
FIGURE 10.7. A Typical Active Solar Domestic Hot Water Heating System(a)
(a) R. Seifert. 1981 (Draft). Alaska Solar Design Manual. Institute of Water
Resources, University of Alaska, Fairbanks, Alaska.
can be heated by the sun. Appendix M gives examples of performance character-
istics for active solar water heating in two prototypical homes in Fairbanks.
Hot Air Systems for Space Heating
Active air collectors (see Figure 10.8) are usually thicker than liquid-
based collectors because they handle higher mass flow rates; because a given
volume of air absorbs fewer Btus than a similar volume of liquid. To keep the
collector temperature low, thus improving efficiency, more air must pass
through the system per unit time. One approach to this technology is to pump
the hot air directly into the living space. Preliminary calculations show
this to be effective when combined with a thermostatistically controlled fan.
A more common approach involves ducting the heated air from the collector into
a rock bed to provide storage for later use. A separate ducting system then
carries this air into the living space. No data on the performance of these
systems in the Railbelt region are available.
10.32
BLACK ABSORBER
PLATE
AIR IN
GLAZING
FINS TO INCREASE
SURFACE AREA
FIGURE 10.8. A Typical Air Solar Collector
On first examination, the use of active solar for space heating in the
Railbelt region would seem to be inappropriate because the building heating
load is greatest when the resource is at its minimum. However, in many parts
of the Railbelt, space heat is needed at least 9 to 10 months of the year.
The number of heating degree days in Homer, Alaska in May is greater than that
of Davis, California in December. Davis is considered a model solar community,
with 500 to 600 solar homes. This comparison would suggest that although
active solar will not make a significant contribution to heating during mid-
winter months in the Railbelt, it can reduce heating bills on an annual basis.
10.2.2 Technical Characteristics
Important technical characteristics of active solar systems include system
efficiency, coincidences to load, adaptability to load growth, convenience and
control, electrical load offset and complementary technologies.
Active Solar Efficiencies
In the Railbelt, active solar collectors make effective use of 30 to 40%
of the sun•s energy that strikes their surface. This is their raw performance
10.33
under optimal conditions; it assumes no obstructions in the sun's path and the
collector tilted perpendicular to the sun on an average annual basis (usually
at the latitude angle for domestic hot water, and latitude plus 10 to 15° for
space heating). Several other variables can reduce the efficiency of a system.
For example, the greater the temperature difference between outside ambient
air and the collector surface, the less efficient the system because of exces-
sive heat loss back out the glazing. A differential of 100 to 180°F is gener-
ally acceptable. The "optimum" situation described above assumes that the
temperature of the collection fluid is about 140°F.
A collector's efficiency can only approach 30 to 40% if the heated medium
is used directly, such as water out of the tap or air ducted into the house.
Transfer of the heat from the collection fluid via heat exchanger, as in a
copper flat-plate domestic hot water system with an ethylene glycol collecting
fluid, will reduce efficiency by another 8 to 12%. In space heating installa-
tions where heat is transferred from the collection fluid into a storage
medium and then again to a distribution fluid, an additional 8 to 12% loss can
occur. Until some monitoring of installed systems in the Railbelt is under-
taken, actual performance cannot be accurately predicted.
Coincidence to Load
The ability of an active solar installation to meet heating loads (whether
for space or hot water) depends largely on the efficiency of the installed
system, the collector area, and whether a storage system is used. The degree
of solar access is also a factor. While little data exist, active solar is
expected to have little impact on loads during the coldest and darkest of the
winter months because of the relative lack of insolation and high heating
demands. During the rest of the heating season the impact of solar will be
greater, although the degree is not yet known. One thing is certain without a
storage system to carry over the benefits of solar gain to nighttime and cloudy
periods, the load-following capability of an active solar system is limited.
Adaptability to Load Growth
Active solar is just as adaptable to future growth as the other dispersed
technologies. Because solar is dispersed, installers with a minimum of train-
ing can put solar into place quickly with little lead time.
10.34
Consumer Convenience and Control
Active solar space heating and hot water systems are largely automated,
not requiring homeowner attention for normal operation. Periodic maintenance
requirements are slight, typically consisting of seasonal cleaning of collector
glazing and winter draining of heat exchanger fluids to prevent freezing.
Type of Electrical Load Offset
Electricity for space heating comprises such a small percentage of the
electrical load that active solar space heating would have little immediate
effect on the demand for electricity. Moreover, because of the limited avail-
ability of solar insulation in the winter, active solar space heating systems
would require a full backup locating system, and, for homes using electrical
backup, generating capacity to supply the backup systems.
Active solar hot water heating systems typically have substantial storage
in the form of water storage in the heat exchanger unit as well as the backup
hot water tank. These systems could thus trim daily peak loads during late
spring, summer and early autumn months. The backup hot water heating system
and associated generating capacity would be required during winter months.
Complementary Technologies
Active solar for space heating can provide a significant portion of the
heating needs to a structure only when the building has been upgraded to con-
sume less energy than a standard building. Building conservation is therefore
not only a complementary but also a necessary technology that should accompany
an active solar application. A popular and cost-effective approach is the
"hybrid" system, where passive solar is used for space heat and active solar
for hot water needs.
10.2.3 Siting Considerations
The same meteorological considerations apply to active solar systems as
were discussed for passive solar systems (see Section 10.1.4). The sun angles
are so low in the region that collectors placed vertical or close to vertical
are more effective than horizontal collectors; a collection surface perpendic-
ular to the sun•s rays will capture the maximum amount of radiation.
10.35
Or i entation
As discussed in Section 10.1.4, the collector surfaces should be oriented
as due south as possible, although a variance of several degrees will not
seriously affect performance. In fact, recent research in the Lower 48 states
indicates that active solar hot water systems will still perform very well
when oriented as much as 90° off of south (Solar Age Magazine 1980). No test-
ing has yet been done to verify this phenomenon in the Railbelt, but the poten-
tial ramifications may be significant for retrofitting active solar systems to
existing housing. Most housing in the region has been oriented haphazardly in
relation to solar access. Collectors can be mounted in several places and by
several means: on a rack on the ground, on a wall of the structure, and on
the roof using mounting racks. Such mounting racks are often used to "skew"
the collector, so that it faces south on a roof that may be oriented in another
direction. However, mounting the collector "in line" with the roof of an
existing structure is simpler, less costly, and generally more aesthetically
pleasing.
The number of existing structures adaptable to active solar space and/or
hot water heating in the Railbelt is not yet known. Field work will be
required to determine this.
Solar Obstructions/Shading
The same solar obstructions/shading considerations apply to active solar
systems as were discussed for passive solar systems (see Section 10.1.4).
10.2.4 Costs
Unit costs of active solar energy will vary widely, depending on type of
system installed, the amount of collector area used, and the efficiency of the
end use of the system. Little work has been done in this area. Matt Berman
and Eric Myers of the Alaska Public Interest Research Group have compiled one
of the most complete cost analysis to date on active solar in Alaska. They
used a standard home, a retrofitted structure, and a "superinsulated" house
for space heating cost comparisons and they also looked at hot water heating
(Table 10.6). They calculated the cost of energy based on several different
10.36
TABLE 10.6. Active Solar Cost Analysis for Fairbanks, Alaska(a)
Load
Served (%)
Standard Home (Space Heat) 5.2-37.3
Retrofitted Home (Space Heat) 6.3 -39.1
Superinsulated Home (Space Heat) 7.5-41.9
Hot Water Heating 15 -61.6
Cost of Energy Saved
($/MMBtu)
12.83 -34.16
12.60-32.31
12.61 -31.10
12.53 -24.30
(a) Assumes a collector cost of $15/ft2, including storage, with
financing at 9.5% interest over 20 years with no down payment.
co 11 ector sizes to define the 11 optimum 11 investment. These cost figures are
projections only; not enough systems have been installed to know actual ini-
tial capital costs.
O&M costs will be a part of every active solar system; the amount depends
on the type and size of the installation, as well as the care given to design
and construction.
exists in Alaska.
A very broad estimate must be made, since little precedent
An average figure of $25 to $50 per year over the life of
the system seems likely for such items as burned out pumps, piping or ducting
repairs, and glycol solution replacement once a year if the system is drained
down annually.
10.2.5 Environmental Impacts
The environmental effects of active solar energy use are almost entirely
positive. Once the system is manufactured and installed, it should supply 10
to 20 years of pollution-free energy at an average rate of 400 Btu/ft 2/day
in the Railbelt. Early concern over the aesthetic devaluation of neighbor-
hoods from many roof-mounted solar collectors has been replaced by the
increased real estate appraisal values for homes with solar systems.
Injuries and deaths accredited to the solar technologies are rare.
Because most installations tend to be small and relatively simple to install,
the hazard rate is no higher than that involved in standard, light
construction.
10.37
10.2.6 Socioeconomic Impacts
If active solar were to be employed on a widespread basis, it would most
likely have the same socioeconomic benefits that the other dispersed technolo-
gies have. Design and installation would be provided by Alaskan firms, on a
widely dispersed basis. As a result, cash flow would also tend to be dis-
persed, with more of it staying in the region than if a large centralized
project were undertaken. However, an outflow would occur because both manu-
factured collectors and components for job-built collectors largely would be
shipped into Alaska.
The reduction in capital expenditure for fuel at the individual level
would obviously result in more spending power, and more cash would likely be
available for other items. The impacts of the benefits would depend on the
amount of market penetration, but generally, the socioeconomic impact of
active solar would be beneficial.
Because active solar is an isolated gain system, it does not affect an
individual •s lifestyle in the same way that a passive solar design does
(opening and closing shutters, etc.). Much depends on the particular system;
some systems are totally automatic, while others require at least a minimum
degree of daily participation. Whether this is a potential burden depends on
the user and would be difficult to assess here.
Benefits from reduced fuel usage and subsequent dollar savings are obvi-
ous. An ability to maintain comfortable temperatures in the dwelling (or hot
water supply) during times of fuel disruption is an additional advantage.
Finally, the investment is inflation proof, which is not true for most tradi-
tional heat sources.
The amount of maintenance required for an active system depends on how
well the initial design and installation incorporated repair and replacement
considerations. If copper is used in the collector, the system will have to
be drained down during the coldest months of the year to prevent freezing and
subsequent bursting of pipes. A plastic absorber can eliminate this require-
ment. Because so few systems have been installed in the region, estimating
10.38
the maintenance and operation time required by the consumer is difficult. A
figure of 3 to 6 hours per month for a well-designed system is a reasonable
estimate.
10.2.7 Application to Railbelt Energy Demand
The high cost of fuel and the extreme heating loads of the Railbelt region
combine to make active solar use attractive. However, the use of active solar
energy in Alaska has many constraints. The low winter sun angle coupled with
extreme, low temperatures makes active solar collection difficult for 1 to
3 months of the year, depending on latitude, cloud cover, and site variables.
The effect of the interaction of these variables has never been studied for
Alaska, and definitions of solar access angles for the state are not currently
available. Until latitude-specific, economic-based definitions of solar access
data are gathered, a collector for a site with an unobstructed south view is
assumed not to be useful between December 1 and January 15 at the southern
extreme of the Railbelt, and between December 15 and February 1 in Fairbanks.
Although no in-depth studies have been done, preliminary work in various
Anchorage neighborhoods has shown that as much as 35 to 45% of the existing
building stock may be adaptable to retrofits for active and/or passive
solar.(a) Determining th~ overall potential of active solar would be
extremely difficult at this point. The number of dwellings with solar access
is unknown, the actual performances of active systems are undocumented, and
market penetration of active solar technologies is difficult to assess because
availability is still fairly low in the region.
In a study performed in 1980 by the Alaska Center for Policy studies,
Richard Seifert (1980) of the University of Alaska Institute of Water
Resources writes:
11 There is very little basis upon which to predict the impact and
market penetration of (active) solar energy systems for Alaska.
Presently, there are active technology systems functioning in
Alaska, but they are rare and usually not commercial systems, but
(a) Alaska Renewable Energy Associates, in-house study, 1980.
10.39
rather owner-built. Without further demonstrations of the technology
within Alaska and marketing development, the prospects for active
solar applications look grim. The most probable level of use of
active solar systems will depend upon the commitment of the state
and other government agencies to promote this technology. Being
optimistic, but more realistic, the contributions are likely to be
from 20 to 25% of the maximum possible."
Even a 20 to 25% level of use seems optimistic, as Seifert points out. The
high cost of initial investment in an active space heating system would likely
preclude a large market penetration. This situation will remain unless
front-end costs decrease significantly.
Active hot water heating, on the other hand, could conceivably provide a
significant reduction for electric power demand. Prospects for offsetting
load look better. Research by Seifert shows that, on an annual average, 50%
of the hot water needs can be met by active solar collectors in a typical
Railbelt installation. If 40 to 50% of the building stock had good solar
access, 20 to 25% of the energy needed for water heating could be displaced.
All of these figures are based on broad assumptions and as such must be con-
sidered preliminary. Further work needs to be done to define active solar's
impact in the region.
Several dealers sell active collectors. Most of the collectors are for
hot water heating and are part of a kit that includes the tank, collector, and
other components. Sheet metal shops in the Fairbanks area will custom make
collectors on demand. In general, however, the consumer will have little help
when looking for an active system. All of the dealers surveyed had no idea of
the effectiveness of their particular systems, and they did not know the opti-
mal number of square feet of collector area for a particular installation.
This lack of design knowledge appears to be widespread also among architects
and engineers. Demand for active solar has not been sufficient for many to
have had experience with it in the Railbelt.
10.40
Many obstacles to commercialization, such as lack of designers, installers
and dealers, have been mentioned. Resistance by financial institutions is
likely to be an impediment, as the high initial costs may tend to reduce the
willingness of financial institutions to lend money for active solar systems.
The largest single obstacle centers around the complete lack of knowledge per-
taining to active solar use in Alaska. Until technical and economic feasi-
bility is demonstrated, a large segment of the population will likely remain
skeptical.
10.3 WOOD FUEL FOR SPACE HEATING
Several factors point to wood as an alternative to gas, oil and electri-
city for residential heating in the Railbelt area. Although the future role
of wood in meeting space heating needs is difficult to quantify, information
indicates recent dramatic increases in wood fuel use. This profile examines
the nature and extent of wood usage for home heating in the Railbelt area,
including the potential for growth and the adaptability of this alternative to
increased demand.
10.3.1 Technical Characteristics
The principal types of wood-fired space heating systems include fire-
places, fireplace inserts, box stoves, airtight box stoves, base-burning air-
tight stoves, front-burning airtight stoves and wood-fired furnaces. The
characteristics of the major types of wood-burning units are reviewed below.
Emphasis is placed on measures that enhance the energy efficiency of wood-
burning units. These measures include draft control, combustion of volatile
gases, use of outside air for combustion and ways to transfer heat to living
spaces.
Fireplaces
Fireplaces are still used for some home heating needs, chiefly as a sec-
ondary source. Conventional fireplaces do not permit any draft control and
generally have little capability to transfer heat of combustion to the living
area. The more sophisticated, steel fireplace shells incorporate provisions
for outside combustion air, circulation of living space air around the shell
10.41
and glass doors. The latter provide relatively ineffective draft control but
do serve to control warm air loss up the chimney when the fireplace is not in
use. Few masonry fireplaces are being incorporated in new residential con-
struction; most new installations have steel fireboxes and chimneys.
Fireplace Inserts
Fireplace inserts provide an opportunity to use an installed fireplace
while incorporating some of the advantages of wood stoves, such as draft con-
trol, baffling for secondary combustion, and improved heat radiation. Many of
these units draw combustion air from the outside, thus cutting the loss of
warm air from the structure.
Box Stoves
Box or chunk stoves are the simplest and most common type of wood-burning
unit available. They come in many forms, including kitchen, Franklin, pot-
belly and parlor stoves. These types generally do not have very good draft
control and therefore burn excessive amounts of wood. Most introduce air
under the fire, which allows large amounts of unburned gas to be carried up
the chimney, taking with it a good deal of potential heat. Most use room air
for combustion.
Airtight Box Stoves
Airtight box stoves have controlled-draft damper systems, some with auto-
matic thermostats, to give more positive control of both primary and secondary
combustion air. Most introduce air below and above the fire to promote com-
bustion of volatile gases. Some designs preheat incoming combustion air. Some
incorporate thermostatically controlled stack heat exchangers to recapture heat
for space heating.
Base-Burning Airtight Stoves
Base-burning airtight stoves take the principles of the controlled draft
(airtight) box stove one step further and add a second chamber for better
combustion of gases. These stoves bring secondary air through a preheating
channel so it will not significantly cool the volatile gases. In addition,
10.42
the flue outlet is located at the base of the firebox, forcing all the exhaust
products to pass by the hottest part of the fire before leaving the stove.
Under proper conditions these stoves can be fairly efficient, but need frequent
tending.
Down-Draft Airtight Stoves
Down-draft airtight stoves are relatively simple in design. Air is drawn
through air ports in the stove top, producing a blow torch effect. Volatile
g~ses from fresh fuel are driven through the glowing coals promoting combustion
of these gases. In some models, primary air enters above the fire but below
the main load of wood. This primary draft flows down and outward through the
coals, pulling volatile gases with it. Secondary air is introduced under the
coals where it can oxidize these superheated gases. Gases continue to burn in
the secondary chamber. This draft pattern prevents heat of the fire from
rising up through a fresh wood load, isolating it from the fire until the wood
has dropped into the combustion zone. Thus, even a fresh load of fuel will
not cool to the fire below. Volatile gases from the new fuel wood are released
more slowly for more efficient burning.
Front-Burning Airtight Stoves
Front-burning airtight stoves characterize the Scandinavian approach to
efficient burning. Primary air is directed into the coals, forcing volatile
gases into the burning area. Secondary air is introduced above the fire to
burn escaping gases in a baffled secondary chamber.
Wood Furnaces
Wood-fired furnaces are also available. These allow the installation of
a central, forced-air heating system fired by wood. Wood furnaces generally
have substantial fuel capacity to allow a long burn time between refuelings,
thermostatic draft control, and Btu ratings sufficient to heat larger residen-
tial dwellings. A typical wood-fired furnace incorporates the combustion fea-
tures of the better free-standing wood stove designs.
Mixed fuel systems are also available. They incorporate many of the fea-
tures described above while providing the advantage of flexibility in fuel
choice. A typical mixed-fuel unit will burn wood as well as coal.
10.43
Estimates of conversion efficiencies for the eight stove types and for
standard fireplaces are given in Table 10.7. Other factors, such as the
material used in the stove's construction, may significantly alter these
figures. Warpage of stove walls or door frames may introduce unwanted air, as
well as signal the end of the stove's useful life. The effectiveness of a
system is indicated not only by Btu output but also by the ability to put the
heat into the structure instead of losing it to the chimney.
The feasibility of converting to wood heating as either backup or a full-
time system varies widely with the area to be heated and the structural impli-
cations involved in installation. In most cases, special accommodation must
be made for pipes or chimneys, requiring careful attention to safety factors.
Additionally, it may be desirable to integrate the wood heating system with
the central heat distribution system of the building to distribute heat from
the wood system throughout the structure.
TABLE 10.7. Conversion Efficiencies for Wood-Fired Units
Wood System Type
Standard fireplace
Fireplace with glass
doors & outside com-
bustion air
Simple box stove
Airtight box stove
Base-burning stove
Down-draft stove
Front-end combustion
stove
Mixed-fuel furnace
Conversion
Efficiency (%)
up to 10
15 -25
20 -30
40 -50
40 -60
50 -65
50 -60
50 -60
Typical
Heat Output
(Btu/hr)
30 -50,000
53,000
40' 000
20,000
50,000
40 -50,000
15 -40,000
112' 000
In sta 11 ed
Cost ( $)
1129
299
339
700
6000
Source: Matson/Oregon State University Extension Service.
10.44
Design features that contribute to the overall energy efficiency of a
structure all work to improve the reliability of wood for heating purposes.
These features include siting, window size, placement and building size, as
well as standard conservation measures, such as proper insulation and weather-
stripping. Proper installation and the operation (fire-tending, drafting) of
wood heating systems also contribute to the reliability of wood as a fuel.
10.3.2 Fuel Requirements
Table 10.8 lists mechanical and physical properties of tree species found
along the Railbelt (USDA Forest Products Laboratory 1974). For the consumer,
the column representing millions of Btu per cord is the important considera-
tion. This column illustrates the relative superiority of birch (prevalent in
the Railbelt area) over other species by a significant margin. Inherent mois-
ture values vary according to species. Moisture content (MC) of 20% is con-
sidered acceptable by most technical sources and wood stove manufacturers.
TABLE 10.8. Railbelt Wood Characteristics(a,b)
Area SQecies
MMBtu/{o)d
20% MC c
Coast: Sitka Spruce 15.2
Hemlock 17.2
Interior: White Spruce 15.2
Black Spruce 15.6
Aspen 14.1
Birch 19.3
Cottonwood 12.5
(a) Source: USDA Forest Products
Laboratory 1974.
(b) Values are given for a standard
128-cu ft cord, containing 90 cu ft
of solid wood and bark.
(c) Derived from Galliet, Marks, and
Renshaw (1980).
10.45
For wood fuel to reach combustion temperatures, its inherent moisture
must be heated and turned to steam. Therefore, the moisture content is
directly related to the available heat: at 50% moisture content, 13% of the
fuel•s heat value is required to vaporize the moisture. At 67% moisture, 26%
of the heat value is needed for drying.
Changes in moisture content of fuel complicate control of combustion. If
combustion is running smoothly with fuel of 50% moisture content and suddenly
much drier fuel is introduced, the combustion rate will increase rapidly. A
oxygen deficiency will result, leading to incomplete combustion, which results
in a plume of dense black smoke.
Consumers have considerable control over moisture content of wood. The
type of wood used and the length of drying time are two factors affecting
moisture content. In addition, cutting wood during the dry seasons will
usually ensure a lower moisture content.
Wood is generally available year round, although consumers must plan for
harvest or purchase of wood supply. Important factors include wood type and
quality and storage. Most wood used in the Railbelt (see Table 10.9) for fuel
is harvested by small operators or individuals using chainsaws and pickups or
snowmachines. Wood appears to be gathered year round and is typically gathered
from areas accessible by public roads.
Only one commercial firewood supplier in Anchorage considers his opera-
tion to be full-time and relies on it as a sole source of income. He would
not disclose any data concerning wood sources or volume because he felt it was
confidential information. Of the other suppliers sampled, none had been in
business more than 1 year, and only one plans to expand his operation into a
full-time business.
90 mi 1 es ( one -way) •
Distance traveled to cut wood ranged from 2 miles to
The source of wood is state and private lands but the
greater amount is taken from private lands being cleared for development. All
suppliers stated that their sales were limited only by accessibility to har-
vest areas, and not by resource shortage.
Birch is the most common wood in the Anchorage area and ranges from $75
to $95 per delivered cord. Spruce is most common wood in Fairbanks and ranges
10.46
TABLE 10.9. Survey of Railbelt Wood Suppliers(a,b)
Distance
Traveled (mi)
Pub 1 i c Private
Land
Annua 1
Harvest
(Cords)
Primary
De 1 ivered
Price
Anchorage: Land Wood Type ($/Cord)
Supp 1 i er: 1
2
3
4
5
6
Fairbanks:
Supplier: 1
2
3
50 to 90
90
80
35
5
2
40
25
50
X
X
X
X
X
X
X
X
X
X
6
NA(b)
45
15
500
25
400
400
200
(a) In-house survey by Alaska Renewable Associates, 1981.
Birch
Birch
Birch
Birch
Birch
Birch
Spruce
Spruce
Spruce
(b) The primary Anchorage commercial supplier will not reveal data.
from $80 to $90 per cord. Distances traveled range from 25 to 50 miles (one-
way) and state land is the primary source.
10.3.3 Costs
85
90
85
75
95
80
80
90
85
Space heating costs using wood compare very favorably with other sources,
especially when harvested by the dispersed, individual method. This situation
will continue, unless transportation fuel costs rise dramatically.
The unit cost for wood heating over the life of the structure is difficult
to assess, as several assumptions must be made. These assumptions include
future costs of firewood, whether it is gathered commercially or by the
individual homeowner, and the installed cost of the woodburning unit.
The installed cost of the woodburning unit will vary, depending on the
intended end use and quality of the unit. Simple box stoves can be installed
for as little as $350 to $400, although the useful life will almost always be
10.47
under 10 years. Well-built, airtight stoves will range in cost from $700
to $1600 and will last 20 to 30 years with a significantly higher heat output
than the type listed above. The wood furnace units with full ductwork can
run $3000 to $6000, particularly if a multipurpose unit is purchased (e.g.,
oil/wood).
Table 10.10 lists typical fuel wood costs for both the Anchorage and
Fairbanks regions. These figures are based on costs quoted by commercial
suppliers in each area and do not take into consideration the efficiency of
combustion units.
O&M costs are difficult to assess because they will vary on a case-by-
case basis. Some of the wood furnace units burn at such high temperatures
that they will not require stack cleaning as often as those types of wood
stoves that accumulate creosote in the stack with lower burn temperatures.
Professional stack cleaning ranges from $60 to $85 in the Railbelt region.
Obviously, the homeowner could do this work himself and save considerable
expense. Other maintenance items include stove and stack repair, wood pile
maintenance, and repair or replacement of chain saw parts (or units) if wood
is cut by the individual. A broad O&M cost per year for someone relying
largely on wood for heating might be $100, depending on the individual.
Estimates of the cost of wood heating are provided in Table 10.11. The costs
of energy provided in Table 10.11 are based on 3% financing for comparability
with costs provided elsewhere in this report and are not representative of
costs experienced by a homeowner under current (nominal) financial conditions.
TABLE 10.10. Fue 1 Wood Costs for the Ra i 1 belt Area
Location $/Cord (a) $/MMBtu
Fairbanks $80.00 $5.48
Anchorage $90.00 $6.30
(a) 90 ft3 of wood within 128 gross
cubic feet (4•x4•x8•) used for
standard cord.
10.48
TABLE 10.11. Representative Wood Space Heating Costs (1980 dollars)
Fuel Costs(b) Energ~ Costs(c)
Equivalent (d)
Electric Energ~ Costs
Capacity Capital Cost(a) O&M Cost Anchorage Fairbanks Anchorage Fairbanks Anchorage Fairbanks
T~e of Unit ~tu/hr) ($/unit) ($/unit/~r) ($/MMBtu) ($/MMBtu) ( $/MMBtu) ($/MMBtu) (mills/kWh) (mills/kWh)
Box Stove 0.04 654{e) 100 11.54 10.04 41.8 47.7 142
Airtight Stove 0.05 1150 100 11.54 10.04 19.2 21.7 65
Furnace 0.1 4500 100 11.54 10.04 20.1 22.8 69
(a) As installed.
(b) Levelized fuel costs over a 20-year operating life at 1-1/2% real escalation/year. Based on base year (1980) costs as
follows: Anchorage -$6.30/MMBtu; Fairbanks -$5.48/MMBtu.
163
74
78
(c) Levelized 20-year lifetime costs for energy input to the residence based on the following efficiencies: box stove -25%;
airtight stove -57 .5%; furnace -55%. Costs are real (3% discount rate).
(d) Levelized 20-year lifetime costs, based on displacement of electric resistance space heat. Costs are real (3% discount rate).
(e) Includes replacement of unit at 10 years, discounted at 3% to first year of installation.
10.3.4 Environmental Considerations
Wood for heating poses three environmental issues: fire hazards, air-
quality effects and impacts of wood harvest on forests.
Fire Hazard
House fires resulting from wood stoves can usually be attributed to
faulty installations and improper maintenance of the stack. When a stove is
heavily dampered, the flue temperature is lowered, which allows creosote from
flue gases to condense and build up on the stack. When the fire is later
stoked and allowed to burn hot, the creosote can ignite, creating a 'stack
fire •.
Burning green wood tan increase creosote buildup as well as spark emis-
sions that can ignite a roof or surrounding vegetation. Both of these fire
problems are avoided through frequent cleaning of the stack, at least twice
each year, by a spark arrestor screen in the flue, by proper use of the stove
itself, and by burning a hot fire with well-seasoned wood.
Table 10.12 summarizes data on residential fires attributed to "failures
in heating systems." Anchorage data refer to heating systems in general;
"wood-specific" data are not separately available. Fairbanks data are avail-
able for wood-specific systems. The data for the two municipalities are cate-
gorized differently and are thus difficult to compare. The Fairbanks data are
the most useful because of the high usage of wood there. The low occurrence
of chimney fires suggests that safety is not a problem. Furthermore, chimney
fires have decreased, whereas wood consumption has increased.
10.49
TABLE 10.12. Wood Heat Fire Hazards
Type of Fire
Heating
Total S,lstem Failures Chimne,t Fires
Area Year Residential Fires No. % No. %
Municipality( a) 1980 326 23 (7) 1 (0.3)
of Anchorage 1979 777 29 (4) 1 ( 0 .12)
Municipality( b) 1980 Not Available Not Avail ab 1 e Not Avail ab 1 e
of Fairbanks 1979 166 Not Available 7
(a)
(b)
1978 66 Not Available 4
1977 81 Not Available 5
1976 107 Not Available 9
1975 119 Not Available 4
Figures provided by John Fullenwider, Deputy Fire Marshall, Fire
Protection Division, Municipality of Anchorage
Figures provided by Eric Mohromon, Fire Inspector, Municipality of
Fairbanks
(4)
(6)
( 6)
(8)
(3.4)
Fire Department sources from both areas emphatically stated that most
fires attributed to wood result from improper installation. The most common
fault seems to lie with stoves and stacks being located too close to combusti-
ble material.
Air-Quality Effects
Air-quality monitoring in Anchorage in 1980 could not detect suspended
particulates attributable to wood combustion. The total suspended particulates
did not exceed the state standard of 150 micrograms per cubic meter over a
24-hour period and has actually decreased over the past 3 years. Percentages
of decrease on an annual basis are not presently compiled.
Monitoring for suspended particulates has not yet begun in Fairbanks.
However, the amount of carbon monoxide produced by the wood combustion has
been extrapolated to be 4.25% of the total carbon monoxide in the air. Also,
70% of the carbon monoxide resulting from space heat of all types is attributed
to the use of wood. The level of carbon monoxide in Fairbanks also decreased
during the past 3 years. Although annual data were not available, the cause
is attributed to mild winters and reduced traffic.
10.50
No effort has been made to quantify public perception of woodburning aes-
thetics. Wood smoke creates a visual and odor impact that is not pleasing to
all. However, as yet no indication has been given that this is of major con-
cern to many.
Wood Harvest Effects on Forests
The nature and extent of environmental degradation from wood fuel harvest-
ing will depend upon harvest methods and enforcement of land-use regulations.
Dispersed, small-scale, wood fuel harvest will tend to follow other develop-
ments such as road and residential road building; permanent patterns will
emerge more clearly as land status stabilizes. Multiple-use public lands will
probably be increasingly important for this type of harvest. Public lands
close to urban areas will probably be more actively managed in the future.
Although federal and state government and Native corporations own the largest
areas of commercially viable timber,(a) future plans for these areas are not
presently known.
Coastal forests regenerate quickly and thoroughly in most harvest areas.
Site-specific problems may result from high concentrations of slash, insect
and animal damage, climatic conditions, or soil deficiencies. Interior forests
are less likely to regenerate naturally and may need some form of artificial
regeneration such as planting or direct seeding to ensure renewability. Plant-
ing costs per acre are high for both types, averaging $150 to $400, depending
on density, cost of planting stock, labor, transportation and overhead. Direct
seeding costs for the Fairbanks area are about $20 per acre, when equipment
and adequate seed supplies are available. Although seeding of spruce requires
more effort than hardwoods, more research on all species is required before
full-scale planning for "energy plantations" can be developed in the Railbelt
area.
10.3.5 Socioeconomic Considerations
Socioeconomic impacts of wood fuel for space heating center on three
areas: 1) consumer convenience, 2) adaptability to growth, and 3) regional
economics.
(a) Commercial timber stands are those having a potential wood formation rate
of 20 ft3;acre or more.
10.51
Consumer Convenience
Wood fuel provides an independent source of heat in case of power failure.
In the Railbelt heating systems that accommodate wood as well as other fuels
(coal, oil and/or gas) are available and are capable of rapid and easy change-
over if necessary. Firewood is also a relatively inexpensive heat source,
particularly if the user provides the labor for producing the wood supply.
However, the weight and bulk of wood in storage and handling, whether cut or
purchased by the user, can create an inconvenience. Unlike other heat sources,
wood fires require regular attention in stoking and ash removal. Like other
sources, to maintain safety and optimal performance of heating systems, wood
burning equipment requires regular maintenance. The amount of maintenance
varies somewhat depending on the type of wood-burning system and the type of
wood as well as the frequency of use. Generally, manufacturers recommend that
stoves be stoked every 2 hours to achieve maximum burn efficiencies. Stoking
can typically be accomplished in 5 minutes or less. Using this figure and a
16-hour "stoking period" (assuming that stoking does not occur at night), an
individual would spend 40 minutes a day or 20 hours per month tending the stove
during the season requiring continual heat. Assuming this "heating season"
could last 6 months or longer in parts of the Railbelt, up to 120 hours per
year would be required. Approximately 2 hours per month would also be required
for cleaning the stove and maintaining the wood pile.
Adaptability to Growth
Suppliers of wood-burning units in the Railbelt area could meet consid-
erably greater demand for both primary and secondary heating systems. Avail-
able systems include several models that can accommodate other fuels (coal,
oil, gas) and that are adaptable to incremental increases in heating capacity
without installation of a new central source in a given structure. Wood
resources in the Railbelt area also appear to be capable of sustaining
increased demand.
Although the dispersed individualized process of harvesting wood for fuel
in the Railbelt area is not highly visible, demand for firewood has increased
dramatically in the last several years. Both state and federal land managers
10.52
have designated areas near Anchorage and Fairbanks under their jurisdiction
for wood-cutting or gathering purposes. State-required permits for firewood
cutting are issued by the Alaska Department of Natural Resources. The permits
are issued by two offices, the South Central District Office for the Anchorage
and lower Railbelt areas and the North Central District Office for the
Fairbanks and upper Railbelt areas.
Table 10.13 shows the number of personal use permits issued by year, the
estimated number of cords taken, and the number of commercial sales to fire-
wood distributors in each area. These figures do not represent the total wood
fuel consumption in the area since cutting from private lands is not monitored.
In the case of commercial cutters this consideration is significant because a
large portion of their annual supply is removed from sites for development
such as subdivisions. Additionally, trespassers remove a large amount of wood
from state land without permits. The number of "illegal" harvesters was
estimated to be 10%(a) in the North Central District, and 45%(b) in the
South Central District. Consequently, the table does not reflect the real
demand for firewood in the Anchorage area but it does indicate to some degree
the increased demand for 1980 -49% in the South Central District (Anchorage)
and 28% for the North Central District (Fairbanks).
Some sources estimate that about 50% of the households in the North Star
Borough use wood as primary or secondary heating source, which implies that
about 7,000 homes are heated with wood. However, AKREA has not been able to
confirm these figures, and the North Star Borough Public Information Office(c)
has confirmed that the Borough does not have data on the percentage of homes
heated by wood and cannot support the 50% estimate. The only data available
show that in 1979, 6.5% or approximately 910 of the homeowners in the munici-
pality possessed permits to cut firewood. It is also known that 36% of the
(a)
(b)
(c)
Based on conversation with Mike Peacock, Timber Management Forester, South
Central District Office, February 1981.
Based on conversation with Fred Bethune, Administrator Forest Practice
Act, North Central District Office, February, 1981.
Source: Heather Stockard, Environmental Technician, Fairbanks North Star
Borough.
10.53
Year
{Jan. }
1981
1980
1979
1978
1977
1981
1980
1979
1978
1977
(a)
(b)
(c)
(d)
(e)
(f)
TABLE 10.13. Summary of State Firewood Permits
North Central District(a)
Personal Use Permits Commercial Sales
No. of No. or No. of
Permits Increase {%} Cords b) sales(c) No. of Cords
400 4,ooo(d) 7 700
2300 28 21,000 60 6,000
1800 125 18,800 22 2,200
800 110 1,800 0 0
380 3,800 0 0
South Central District(e)
74
960 49
643
Not avail ab 1 e
Not av a i 1 ab 1 e
222(d,f)
3,ooo(f)
1,829(f)
(unknown at this time)
14 1,175
0 0
Source: Department of Natural Resource, Division of Forest, Land
and Water Management, South Central District Office.
Estimated at 10 per permit.
Issued by bid to commercial suppliers.
To date of writing (January 1981).
Estimated at 3 cords per permit.
Source: Department Natural Resources, Division of Forest, Land &
Water Management, South Central District Office.
1800 permits issued in 1979 were issued to people who live within the munici-
pality of Fairbanks. The 6.5% appears to be a low estimate of the total number
of homes using wood since wood-cutting permits are not required for cutting on
p r i v ate 1 and s .
To further define the increase in wood heating, AKREA surveyed major wood
stove suppliers in the Anchorage area.
sales increased 300% from 1978 to 1980.
for 1981, with a 25% increase expected.
tion of the trend, but it appears to be
Based on dealer estimates, average
The increase seems to be leveling out
Clearly this is a very rough indica-
the only available data. The 1981
sales might exceed the expected 25% because of a state loan program that
provides for the purchase of wood stoves.
10.54
Management officers from both state districts expressed concern over their
ability to meet the present demand for firewood. Both officers stated that
the resource is sufficient to meet future demands but it must be made accessi-
ble by cutting in logging roads for public use. Neither office was able to
quantify the present or future demand, but efforts are being made in that
direction. A report from the North Central District Office is expected in the
near future.
With an array of landowners of divergent interests gaining title to lands
in the Railbelt area, a more comprehensive approach to managing lands for
firewood procurement may be needed. Permitting may be adopted by federal or
municipal agencies, and additional lands will probably be designated for the
purpose. Consideration will have to be given to access across private and
public lands, and a distinction between wood cutting and deadwood gathering
may have to be made. Pressure will probably be applied to permit use of these
areas by small commercial operators within certain guidelines if demand con-
tinues to grow at present rates.
Two other factors may have a positive impact on fuel wood supply: the
availability of slash resulting from predictable increases in large-scale com-
mercial logging operations, and the possible use of other sources of fuel such
as driftwood along rivers, streams and coastal areas. Also, wood is now being
recovered from the lands being prepared by the state for development of agri-
cultural sites.
Regional Benefits/Employment
Jobs per million board feet of wood harvested are estimated by the U.S.
Forest Service at 7.5 for harvest, transportation and manufacturing sectors
combined. These figures apply only to Southeast lumber and pulp operations.
Just as primary industrial wood harvest and processing tend to generate sec-
ondary jobs, including those in direct industry support and community infra-
structure and services, a smaller, but similar benefit is realized from
dispersed, small-scale wood fuel gathering. Each cord of wood harvested in
the Railbelt area displaces about 15.6 million Btu of other energy forms. A
significant point related to displacement is the retention and recirculation
10.55
of dollars saved by individual wood users in the community after more costly
forms of energy have been displaced. Impacts of wood-cutting on employment
and local economies are unquantifiable but predictably favorable.
10.3.6 Potential Application to the Railbelt Region
The Railbelt region contains large reserves of commercial and noncommer-
cial grade timber. The bulk of the Railbelt forests are of the Interior Forest
type with birch, spruce, aspen and cottonwood the dominant species. (The fuel-
wood characteristics of these species are provided in Table 10.8.) Regenera-
tion of these forests is slow, but could be improved with mechanical seeding
techniques.
Many site-specific or small-scale forest studies and inventories have been
conducted in the Railbelt area, although the data base remains incomplete on a
regional scale. A 1967 U.S. Forest Service study remains the most recent com-
prehensive attempt to inventory the forest resources of Southcentral, Interior
and Western Alaska to date and is the basis for estimates of available Rail-
belt forest resources used in this report.
Table 10.14 provides a summary of forest resource data, including total
wood volume, standing wood energy, and annual potential wood energy figures.
In general, an abundant supply of wood of several types is available to meet
large increases in demands for many types of uses. However, land ownership
status poses an important and unknown factor in attempting to define how much
energy the wood resource can satisfy. Land ownership status continues to shift
dramatically because of land selection and use by Native corporations, the
State of Alaska, municipalities, and management decisions by federal land
agencies.
Land title is a social constraint that limits wood energy development.
Public and private land ownership within the Railbelt area is changing quickly
and will remain unsettled in the near future. Although no clear pattern of
development has emerged, pressures are great to put land in private hands and
to classify public lands for multiple uses. Wood usage is heavy in the area
with most of the wood coming from state and federal lands.
10.56
0
U1 ........
TABLE 10.14. Wood Energy Summary/Rai1be1t Area
Forest Type
and Total Wood Volume Standing9Wood Energy Annual Potent~al Wood Energy
Unit Number ( a) (million cu ft} po Btu} po Btu}
Commercial{b} Noncommercial Commercial b} Noncommercial Commercialb) Noncommercial ------
Interior
1. 827.3 1,461.2 140,790 25,538 2,277 1,149
2. 525.7 32.9 91,877 5,742 1,110 259
3. 1,431.0 590.2 250,100 103,147 3,939 4,642
4. 192.2 130.3 35,362 30,648 5,289 1,025
5. 434.8 217.8 75,994 38,058 1,197 1, 713
TOTAL 3,411.0 2,432.4 594,123 203,133 13,812 8,788
Coastal
2. 515.0 100.2 88.963 17,234 1,018 971
3. 859.1 294.7 147,756 52,019.2 1,646 1,468
4. 50.7 34.9 8,705 14,864 97 173
TOTAL 1,424.8 429.8 245,424 84,117 2,761 2,612
RAIL BELT TOTAL 4,835.8 2,862.2 839.547 287,250 16,573 11,1100
(a) Units correspond to units designated by U.S. Forest Service (1967) that fall within the Railbelt area.
(b) Commercial timber stands defined as those representing 20 cu ft/acre/yr or more of potential growth.
Private ownership is increasing because of programs to transfer state
lands to private ownership under the Alaska Native Claims Settlement Act.
Preliminary indications are that most Native land with commercial forest
potential will be placed under long-term management. Most small-lot private
landowners prefer to obtain wood from someone else's land, whether for fuel or
construction. They believe, correctly, that trees enhance their property
values.
Vandalism of private property and illegal cutting of green wood are only
two potentially severe land management problems associated with wood harvest-
ing. Terrain and road systems pose additional constraints on accessibility to
wood resources. Future air-quality guidelines may also inhibit development of
wood as an alternative fuel. Dramatic increases in particulate levels, either
cumulatively in the long term from the increases in wood burning or from
periodic short-term situations resulting largely from climatic factors, may
provide the incentive for greater controls. Regulations governing wood smoke
emissions may also be influenced by concern for increases in pollutants from
other sources, such as auto exhaust.
Factors contributing to an increase in wood fuel use include the relative
simplicity of wood stove installation and operation, the adaptability of units
to a variety of structural heating requirements, and the aesthetic attraction
of wood heating. Wood has long had a foothold as a practical heat source in
the Railbelt. Recent studies point to a dramatic increase in wood burning in
the residential sector. Many people, usually outside the larger urban areas,
depend on wood for their sole heating source. In the larger population cen-
ters, wood heat tends to be more of a secondary source, although this may be
changing to some degree.
The amount of heat that wood can provide in an individual unit will depend
on the stove or fireplace used, and the condition of the structure. A small
and/or tightly built building can be entirely heated from wood. A larger and
older house in Anchorage and Fairbanks will lose too much heat during times of
peak loading (colder winter days and nights) for wood to provide all of the
heat, unless some conservation techniques are first undertaken. However, wood
10.58
could supply all needs during less severe months. Whereas determining the
amount of space heating energy that wood-fired units would contribute to the
region is difficult, a figure of 10 to 15% of total demand is quite realistic
eventually.
10.59
REFERENCES
Abelson, R. H. and M. Dorfman, eds. 1980. Advanced Technology. American
Association for the Advancement of Science, Washington, D.C.
Acres American Inc. 1981a. Preliminary Assessment of Cook Inlet Tidal
Power. Prepared for the State of Alaska, Office of the Governor, Juneau,
Alaska by Acres American Inc., Buffalo, New York.
Acres American Inc. 1981b. Susitna Hydroelectric Project Development
Selection Report. Prepared for the Alaska Power Authority, Juneau, Alaska,
by Acres American Inc., Buffalo, New York.
Adlhart, 0. 1976. "Fuel Cells." In Van Nostrands's Scientific Encyclopedia,
5th Edition. Van Nostrand Reinhold Company, New York, New York.
Alaska Department of Commerce and Economic Development. 1978. Oil and Gas
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R.11
APPENDIX A
ELECTRIC ENERGY TECHNOLOGIES NOT SHOWING PROMISE FOR
APPLICATION TO THE RAILBELT REGION
APPENDIX A
ELECTRIC ENERGY TECHNOLOGIES NOT SHOWING PROMISE FOR
APPLICATION TO THE RAILBELT REGION
Energy technologies selected for consideration in this study were limited
to those technologies having a reasonable probability of significantly contri-
buting to the generation or conservation of electric energy in the Railbelt
region during the planning period encompassed by this study (1980-2010). Thus,
selection of candidate electric energy technologies for the Railbelt region
was based on two screening criteria: commercial availability and technical
feasibility.
Commercial Availability. A candidate technology should be currently com-
mercial or be projected to be commercially available by the year 2000. A
technology that would be commercially available by year 2000 was believed to
have the potential to significantly contribute to the electric energy needs of
the Railbelt prior to the end of the planning period of this study. Projec-
tions of future commercial availability of emerging and advanced technologies
are based on current developmental progress (i.e., they do not assume unanti-
cipated acceleration in the rate of development).
Several potential candidate technologies do not appear likely to achieve
commercial maturity by the year 2000. These include magnetohydrodynamic gen-
eration, fast breeder reactors, fusion reactors, ocean current energy systems,
salinity gradient energy systems, ocean thermal energy conversion systems, and
space power satellites.
Technical Feasibility. Candidate technologies should demonstrate reason-
able potential to operate successfully in the Railbelt environment. Five
technologies do not at this time appear to have this potential. Four are
resource limited in the sense that the energy source required for their opera-
tion is not available in adequate concentrations in or near the Railbelt
region. These technologies include ocean current energy systems, ocean thermal
energy systems, salinity gradient energy systems and wave energy conversion
A.1
systems. A fifth technology, space power satellites, does not appear to be
technically feasible at the latitude of the Railbelt because of the large area
of antenna required to receive microwave power transmitted from space power
satellites in geosynchronous equatorial orbit. Brief overviews of the rejected
technologies are provided below.
MAGNETOHYDRODYNAMIC GENERATORS
Magnetohydrodynamics (MHO) is an energy conversion technology that has
the potential to increase the efficiency of thermal electrical generation
plants from about 34 to 48% (Corman and Fox 1976).
In an open cycle MHO generation system (Figure A.1), fossil fuel is
burned at a sufficiently high temperature that the product gases are ionized
(4000-5000°F). Electrical conductivity of the hot gases is increased by
••seeding" with readily ionized material (salts of cesium or potassium). When
the gas is channeled through a magnetic field, an electric current is produced
in the gas. The current (DC) can be removed directly with metal electrodes.
The DC output of the MHO channel is converted to alternating current using
solid state inverters (Corman and Fox 1976). The gases exit through a series
of heat exchangers and a heat recovery steam generator, which drives an AC
generator.
The seed material, heat recovery potassium carbonate (K 2co 3), is
used to both increase conductivity and capture sulfur as potassium sulfate
(K 2so 4 ). A regenerative seed recovery system with integral Claus plant
converts K2so 4 to K2co 3 plus elemental sulfur.
Problems that may delay implementation of MHO technology include predicted
high forced outage rate, short plant life expectancy, difficult partial load
operation, difficult operation and control, corrosion problems and poor poten-
tial for retrofit (Corman and Fox 1976).
An open-cycle MHO facility would be a large central fossil-fired power
plant. Gaseous emissions of oxides of nitrogen (NOx) and oxides of sulfur
(SOx) are estimated to be substantially less than those from a conventional
coal-fired power plant (Corman and Fox 1976). A MHO facility is estimated to
A.2
Sulfur
Reducing Gas
Raw Cool ~ Processing
MHO
Seed
Recovery
Inlet Temperature
Pressure Ratio
MHO Exhaust
Steam Plant
Throttle Pressure
Throttle Temperature
Reheat Temperature
Condenser Pressure
Power Output
MHO
2560. c
10.75
2020 ·c
3500 psig
5~0 ·c
5~o ·c
2.3 Hg
1406 MWe
Steam Turbines 959 MWe
Air Compressors 372 MWe
Net To1at 1932 MWe
DC/AC
Inverters
Air Preheaters
and Steam Generator
Economizers
Condensers
Precipitators
and Stack
Cooling
Water
Makeup
L---------+--Air
FIGURE A.l. Open-Cycle MHO/Steam Power Plant (National Academy of Sciences 1977)
Wet
Cooling
Towers
consume only 60% as much make-up water as a conventional steam plant and to
use less than 40% of the total water requirement of a conventional plant
(Corman and Fox 1976).
A 250-hour test of a 200-kW system was run successfully in 1978 (Energy
Daily 1978) at Avco Everett Research Laboratory in Everett, Massachusetts. A
coal-fired power plant with a demonstration open-cycle MHO generator is under
construction in Butte, Montana.
In 1976 a commercial MHO facility was estimated to be operational by 2003
(Corman and Fox 1976). In an International Energy Agency (IEA) study, the
reference start year for a coal-fired MHO electric power plant was 2005 (IEA
1980). Because the Reagan administration believes that confirmation of engi-
neering feasibility and commercial demonstration should be the responsibility
of the industry, MHO funding has been cut from $60.5 million in FY 1981 to
zero in 1982 (U.S. DOE 1981). Therefore, the time scale for development of
commercial MHO conversion systems most likely will not be consistent with the
planning period of the Railbelt Electric Power Alternatives study.
FAST BREEDER FISSION REACTORS
A fast breeder reactor (FBR) is a facility designed to generate electri-
city by using the heat produced by controlled nuclear fission of plutonium. A
breeder produces more plutonium from uranium than it consumes by converting
238 u to 239 Pu at a greater rate than 239pu is fissioned. When isotope 238 u
(which constitutes 99.3% of natural uranium) in the fuel absorbs a neutron,
it subsequently decays to 239 Pu, which is the main energy source for the
breeder. The heat generated by fission is removed by liquid sodium coolant in
a primary loop. Heat is exchanged to an intermediate sodium loop. From the
intermediate coolant loop, heat is exchanged to water coolant using a steam
generator. The following steam cycle is similar to that of conventional fos-
sil or nuclear power plants.
The overall thermal efficiency of an FBR is slightly higher than that of
a light water reactor (LWR) because it operates at higher temperature. A com-
mercial breeder facility would be about 1000 MWe capacity, operated as a base-
load plant.
A.4
Siting considerations for an FBR are the same as those for conventional
nuclear plants. These include adequate water for cooling, geologic and seis-
mic stability, and 100 to 400 acres of land remote from a large population
center. Rail or barge access for spent fuel transport is required. Impacts
from a breeder plant include local impacts during construction, heat release
to the environment and fog created by cooling towers.
Full commercial development of the breeder reactor requires the construc-
tion of reprocessing and fuel fabrication facilities. Fuel reprocessing pro-
vides for recovery and purification of plutonium contained in the spent fuel.
Fuel fabrication prepares the recovered plutonium for recycle to a power plant.
Current U.S. experience with breeders is being acquired at the Department
of Energy Fast Flux Test Facility (FFTF), which achieved full power in Decem-
ber 1980. The capacity of this reactor is 400 MW thermal, approximately equi-
valent to 133 MWe; it is not, however, used for generation of power. The
Clinch River Breeder Reactor, also sponsored by DOE, will generate 350 MWe.
The Conceptual Design Study Reactor (CDS) is a 1000-MWe facility. The pro-
posed schedule calls for completion in 10 years. A 1200-MWe commercial
prototype reactor is expected to be operational about 2001, with the first
commercial plant to be in the 2006-2023 period (DOE 1979). It is therefore
highly unlikely that breeder reactors will be established in the commercial
market by the year 2000.
FUSION REACTORS
Fusion power results from the conversion of mass into energy when two
light nuclei collide and combine (fuse) to become a single, heavier atom. The
heavy isotopes of hydrogen, deuterium (D) and tritium (T) are employed in DT
fusion, the first likely commercial candidate. The reaction is as follows:
iD + fT + plasma energy ~~He + 6n + fusion energy
Deuterium is present in water in sufficient quantities to potentially supply
power at present rates of consumption for millipns of years. The other fuel
A.5
component, tritium, is created by neutron capture in a lithium blanket region
surrounding the fusion reaction chamber (Dingee 1979).
The heat produced would be used with conventional steam generation via an
intermediate heat exchanger or possibly closed-cycle MHO (Dingee 1979). Fusion
power plants are projected to be large, 1000 MWe, for example, and would be
operated as base-loaded facilities. Siting considerations are similar to those
for a conventional LWR. A suitable site should have adequate cooling water,
and satisfactory geology and seismic stability, and transportation facilities
to a burial site for solid radioactive wastes. In addition, a large exclusion
area is likely to be required to preclude effects of strong magnetic fields
associated with the plant on electrical and communication systems and on human
health.
The inventories of tritium, a radioactive isotope with a 12-year half
life, would be greater than for present fission designs (Strand and Thompson
1976). Consequently, some tritium is anticipated to escape the plant in both
liquid and gaseous effluents.
Because of the high temperature involved, fusion plants may be more
efficient than present LWRs. Nevertheless, cooling water requirements, heat
releases and fog created by cooling towers may have significant impacts on
plant siting.
Net energy production using a fusion reaction requires the numerical
product of confinement time (seconds) and density (ions/cubic centimeter) to
be greater than 200 trillion at a temperature over 100 million °F. No fusion
device has yet to reach "breakeven 11 -where fusion energy release is just
equal to the energy supplied to run it. Breakeven is expected to first be
reached by the Tokama~ Fusion Test Reactor sometime in 1983 (Blake 1980);
however, commercial availability of fusion reactors is not anticipated until
late in the first quarter of the twenty-first century. This time scale is not
consistent with the Railbelt Electric Energy Alternative Study.
OCEAN CURRENT ENERGY CONVERSION
Several proposals have been written for extracting power from ocean cur-
rents using, in principal, relatively simple installations such as turbines
and paddle wheels (Isaacs and Schmitt 1980).
A.6
DOE has supported preliminary studies of large submerged ducted turbines
for ocean current energy conversion. In this device, turbines, driven by cur-
rent flow kinetic energy, drive electrical generators. Power is transmitted
to shore with a sea-floor cable. The structure envisioned is about 200 to
300 ft in diameter and of hollow aluminum construction and has a rotational
speed of 1 RPM. An individual unit would provide 75 MWe (Lissaman et al.
1980). The designers of this dev~ce have proposed mooring 132 such turbines
in the Florida current to deliver 10,000 MWe to the Florida power grid.
Even a major ocean current has very low energy density, equivalent to
about 5 em of water head, and the Florida current of the Gulf Stream is the
only candidate for U.S. production of energy from ocean currents (Booda 1978).
The Florida current runs at about 2.5 to 2.9 knots off Miami, whereas the
Alaska current runs at 1 knot (U.S. Department of the Interior 1970). Since
kinetic energy is proportional to the square of velocity, the Florida current
energy density is approximately six to eight times that of the Alaska current.
The preliminary design study of ocean current energy conversion was funded
by DOE. The study calculated turbine and power extraction performance, and
tested a 1-meter rotor model (Lissaman et al. 1980).
In 1980 ocean turbines were projected to be commercialized by 1999. How-
ever, DOE-funded work was assumed to continue, and a full-scale prototype was
assumed to be complete in 1985. Since ocean energy systems funding has been
terminated (DOE 1981), the continuing U.S. development of ocean current energy
conversion is uncertain at this time. Because of funding cutbacks, ocean
current energy conversion most likely will not be commercial in the U.S. by
the year 2000. Even if ocean current energy conversion were commercial,
Alaska would not be a good location for a facility, considering the very low
energy density of the Alaska current.
SALINITY GRADIENT ENERGY CONVERSION
Salinity gradient energy conversion, a large potential source of power,
involves the recovery of the energy mixing of waters of high and low salinity.
The energy density of this process is equivalent to about 240 meters of water
A.7
head (equivalent to an ocean thermal energy conversion (OTEC) plant with a
temperature difference of 23°F) (Isaacs and Schmitt 1980). Theoretical energy
available is 2 MW per 1 m3/sec fresh-water river flow into the sea (Olsson,
Wick and Isaacs 1979).
Three approaches have been proposed for extracting power from salinity
gradients: 1) osmotic exchange against a hydrostatic pressure (pressure-
retarded osmosis); 2) the dialytic battery (inverse electrodialysis) and
3) vapor exchange between two solutions (inverse vapor).
Pressure-retarded osmosis uses the osmotic pressure gradient (about
23 atm) across a semipermeable membrane, which separates seawater (at 35 parts
per thousand salinity) and fresh water. To extract power, the pressurized
solution is released through a hydroturbine (McCormick 1979). This concept
requires large amounts of fresh water, and the facility must be sited at a
river.
The dialytic battery consists of anionic-permeable and cationic-permeable
membranes in a battery container. Salt water is passed between alternate mem-
brane pairs, while fresh water separates one pair from another. Positive and
negative charges are transferred to electrodes at the ends of the membrane
stack. A 100-watt model has been studied (McCormick 1979).
Inverse vapor compression involves vapor exchange between two solutions,
preferably at elevated temperatures. Due to lower vapor pressure of salt
water, water vapor will transfer from fresh water to salt water in an evacu-
ated chamber. Power can be extracted if a turbine is placed in the vapor flow
between the two solutions (Olsson, Wick and Isaacs 1979). This scheme uses no
membranes, only heat exchangers and turbines. Vapor pressure differences
increase dramatically with temperature, so a low-grade source of heat would be
advantageous. Power is required to create and maintain a vacuum in the chamber
(Olsson, Wick and Isaacs 1979).
1 The energy density of a salinity gradient is a function of the difference
in salinity between the two working fluids. The energy density of a system of
saturated brine (260 parts per thousand) and fresh water is about 20 times
greater than a system of seawater (35 parts per thousand) and fresh water
(Isaacs and Schmitt 1980).
A.8
Energy densities for Alaskan salinity gradient resources would be slightly
lower than seawater-fresh water system values presented because of the lower
salinity of Alaskan coastal waters. The salinity of seawater off Alaska is
31.5 to 32 parts per thousand most of the year (U.S. Department of the Interior
1970), about 10% less than salt water in the referenced experiments.
Salinity gradient energy conversion is in the experimental stage. Salin-
ity gradient research was conducted by DOE under ocean energy systems, which
is no longer funded (DOE 1981). Therefore, the commercialization of this
technology is uncertain at best. Considering the current low state of devel-
opment of salinity gradient energy conversion technology and the funding situ-
ation, this technology most likely will not be an option in the time frame of
this study.
OCEAN THERMAL ENERGY CONVERSION (OTEC)
OTEC uses the temperature difference between surface water and ocean
depths to generate electricity. A conventional thermodynamic cycle is used
with ammonia or propane as the working fluid (Figure A.2). The working fluid
is boiled by the warm seawater; the vapor is run through a turbine where power
is extracted; the fluid is cooled by cold deep-ocean water and is pumped back
to the warm water heat exchanger.
The efficiency of the system is based on the difference in temperature
between shallow and deep water. Surface water in the tropics is heated by the
sun to about 79 to 84°F. Cold water from about 3000 to 6000 ft deep originates
in the Arctic or Antarctic and has a temperature of 39 to 44°F (Booda 1978).
The efficiency of a closed-cycle OTEC system is limited by the Carnot
efficiency of a heat engine. An ideal heat engine working at upper and lower
temperatures of 80°F and 40°F (540°R and 500°R, respectively) would have an
efficiency of 650-500/540, or 7%. Real equipment with friction and pumping
losses would have efficiency of about 3%. A 100-MW plant would have to pump
30,000 ft 3 of seawater per second (Forbes et al. 1979).
Tropical or subtropical seacoasts or offshore regions appear to be best
suited for OTEC power plants. A minimum temperature difference of about 30°F
and depth of about 2000 ft are required. DC power would be transmitted to the
A.9
f
Cold
r-
!
.t::
a. t "'
.!! ·-E
~
Water surface-======-
..
f
:
. ..
.· Warm seawater
discharge¢
Pump TkJ[J"f)
..J\ Cold seawater
l..-y' discharge
T4
l-50°F)
[T2 '"' I han
T 'j r4 less than T2
r3 less 1han T4
r 3 Cold seawa1er
(-4 0°F)
i:r
FIGURE A.2. Seawater Power Plant Using Ocean Thermal Difference
A.lO
load center by undersea cables. The proposed size of a commercial OTEC plant
is about 200 to 400 MW (Richards 1979). Potential impacts include interference
with ocean transportation, fisheries, and sea life, and influence on natural
ocean circulation.
A demonstration of the feasibility of OTEC has been performed by DOE.
Because the current administration considers the private sector responsible
for developing marketable systems once technical feasibility is established,
the DOE budget for OTEC has been reduced from $34.6 million in FY-1981 to zero
in FY-1982 (DOE 1981).
A commercial prototype OTEC powerplant was envisioned to be completed
about 1990 (Richards 1979). The reference start year for commercial operation
of a 100-MWe ocean thermal gradient electric power plant was taken to be 2000
in an International Energy Agency study (IEA 1980). Activity of the private
sector will evidently determine the actual development schedule for OTEC.
Sites for OTEC plants are generally re~tricted to 20° north and south of
the equator (Booda 1978). OTEC power is not feasible near Alaska because the
concept depends on warm (80°F) ocean surface temperatures characteristic of
the tropics. The mean surface temperature off the south coast of Alaska varies
from 42°F in winter to 54°F in summer (U.S. Department of the Interior 1970).
OCEAN WAVE ENERGY SYSTEMS
Many methods of ocean wave energy conversion have been suggested. Most
of these methods fall into the following categories: 1) heaving bodies,
2) pitching or rolling bodies, 3) cavity resonators, 4) wave focusers,
5) pressure converters, 6) surging bodies, 7) flapping bodies, 8) rotating
outriggers, and 9) combinations of the above (McCormick 1979). DOE-sponsored
efforts include a full-scale wave energy conversion program with the lEA. The
apparatus, known as "Kaimei," is a cavity resonator system (Figure A.3). On
the deck of Kaimei are three air turbines, which are excited by the air motions
above the rising and falling of the surface of the water (Figure A.4). Each
turbogenerating system is designed to deliver 125 kW in a 2-meter sea with a
wave period of 6 seconds (McCormick 1979).
A.11
U.S. System
Genera ter Japanese System
Turbine
FIGURE A.3. The 11 Kaimei" Floating Wave Energy Conversion System
(McCormick 1979)
Turbine
)))) } ) ) ) )JJJJ
U.K. System
Air Chamber
Average Water
Column Displacement
Still Water Level
FIGURE A.4.
-__r_--
A Water Column/Turbine System (McCormick 1979)
A.12
DOE has also sponsored research on wave-focusing systems. Wave focusing
is accomplished by four techniques: 1) radiant wave interaction, 2) Fresnel-
type focusing, 3) refraction, and 4) channeling.
Radiant wave interaction occurs when a body is in resonance with the
incident wave. Fresnel-type focusing is done by a lens-type structure that
causes wave diffraction or refraction. A refraction wave energy device, called
DAM-ATOLL, was developed at Lockheed. The device, a lenticular hump on the
sea floor, causes incident waves to refract and focus on a vertical axis tur-
bine located at the center of the dome. The dome could be constructed by
dredging or dumping (Isaacs and Schmitt 1980).
Wave focusing by converging channels appears to be feasible only in or
near the surf zone where energy is relatively low. Thus, DOE has not sponsored
studies in this area (McCormick 1979).
Wave energy density has been estimated to be equivalent to 1.5 meters of
water head. This compares with 570 meters for OTEC, with a 36°F temperature
difference (Isaacs and Schmitt 1980). Siting requirements will include an
ocean location with relatively consistent waves and near a load center. Such
a facility would probably be used as a "fuel saver" because of the variability
in wave action.
The DOE considers only the northern half of the Pacific coast a promising
area for ocean wave energy conversion. An estimated 5 to 50 MW per kilometer
of coastline could be generated (Booda 1978). The northern California and
Oregon coasts have 5 ft waves 20 to 30% of the time in spring and winter, and
30 to 40% of the time in summer and autumn. In contrast, off the Alaskan
coast, the frequency of waves of 5 ft and over varies from less than 5% in the
spring to 10 to 20% in the fall (U.S. Department of the Interior 1970).
Currently, wave energy systems are in the developmental stages. Problems
requiring resolution include the need for equipment to withstand large storm
waves, corrosion and fouling; energy storage and/or transmission devices for
transfer of energy to shoreside load centers; and the capital costs of fabri-
cation and installation (Forbes et al. 1979).
A.13
An IEA study assumed 1990 as the reference starting year for commercial
operation of a 2 MWe wave power plant (IEA 1980). Wave energy research pro-
grams have been supported by DOE and depend on government funding. Wave energy
studies have been about 4% of DOE's ocean energy systems budget. Since ocean
energy systems will not be funded in FY-1982 (DOE 1981), the fate of wave
energy development is uncertain.
The coast of Alaska is not an optimum location for wave energy power
plants, as shown by wave height/frequency statistics. In addition, the devel-
opment of wave energy technology is uncertain and may not be available in the
time frame under consideration.
SPACE POWER SATELLITES
The space power satellite (SPS) concept is based on large (5 km x 10 km)
solar collectors in geostationary orbit that transmit power to a receiving
antenna (rectenna) on the earth. The rectenna would consist of an array of
inclined solar panels 3 meters wide in long rows. Power is converted from DC
to AC and stepped up to 500 kV for transmission (Brown et al. 1980). The
microwave power transmission link cannot be scaled down economically to
capacities less than a gigawatt (1000 MW) (Sperber and Drexler 1980). The
conceptual design of a satellite power station developed in the DOE/NASA
Concept Development and Evaluation Program (1977-1980) calls for a capacity of
5 gigawatts.
The rectenna requires a large area of relatively flat land with an area
of low population density. Variables that exclude rectenna siting include
water, military reservations, settlement, marshland, or perennially flooded
areas, highways and unacceptable topography. Other potential exclusion areas
include Indian reservations and national interest lands. Other variables
affecting design and cost of the rectenna site include snowfall, freezing
rain, sheet rainfall, wind, lightning density, hail, seismic risk, timbered
areas, and water availability (Ankerbrandt 1980).
The Ground Receiving Station (GRS) should be near a load center, but
located to avoid radio interference. An optimum location would be a desert
A.14
area. In a prototype assessment of environmental impact of siting and con-
struction of a GRS, the California desert about 250 km north of Los Angeles
was used for baseline data (Bachrach 1980).
The land area required for a GRS is about 400 km2 at 35° latitude. At the
latitude of the Railbelt area, about 63°, an area of about 1200 km2 would be
needed (Reinhartz 1980). Construction of a GRS in a desert area at 36° is
expected to require 25 months, with an average work force of 2500. Approxi-
mately 450 workers would be required for 24-hour, 365-days-per-year operation
(Bachrach 1980). A GRS facility in more difficult terrain that covers three
times the area may then require a construction work force of 7500 or larger,
and an operations crew of 1350.
Construction of a GRS facility would displace existing land uses and would
totally disrupt the ecology of the site. It also would have great socioeco-
nomic impact from the immigration of construction workers. Significant issues
include health effects of long-term exposure to low-level microwaves and
effects on telecommunication, particularly interference with defense require-
ments (Valentino 1980).
The objective of the DOE-NASA-sponsored SPS program is "to develop by the
end of 1980 an initial understanding of the technical feasibility, economical
practicality, and the societal and environmental acceptability of the SPS
concept" (Glaser 1980). The technology will not be developed for at least
10 years, and commercialized in no less than 20 years (Glaser 1980). The
conceptual Development and Evaluation Study guidelines call for initial com-
mercial operation of power satellites in the year 2000 (Schwenk 1980). The
SPS assessment program has been completed, and the program is closed. Future
SPS funding appears uncertain. Principal problems requiring resolution include
solar cell conversion efficiency and cost, microwave power transmission, space
transportation, and construction operation, maintenance and active control of
the SPS structure (Schwenk 1980).
An SPS system currently does not appear to be a candidate technology for
supplying power to Alaska for several reasons:
A.15
• The time scale for development is uncertain; funding has been dis-
continued indefinitely.
• The projected size of a generation system, 5 GWe (5000 MWe), is much
larger than demand forecasts for the Railbelt region.
• The northern latitude of the Railbelt region requires a much larger
rectenna area and lower power density than a more southerly site,
which makes the system even less cost effective.
A.l6
APPENDIX B
FUEL AVAILABILITY AND PRICES
APPENDIX B
FUEL AVAILABILITY AND PRICES
Many technologies discussed in this report rely on fossil fuels (oil,
gas, coal, peat), renewable fuels (municipal waste and biomass) and light
water reactor (LWR) fuel. Forecasts of the future availability and prices of
these fuels are essential to assessing the technical feasibility and costs of
power for each technology. In this appendix, the availability and price of
fossil fuels over the forecast period 1980-2010 are addressed for the Railbelt
region. These fuels are covered in more detail in Volume VII of the Railbelt
Electric Power Alternatives Study.
Each of the various fuels currently has different prices, even if they
are reduced to dollars per/million Btu (MMBtu). Price differentials are
expected to continue in the future, although the differentials among fuels may
change markedly with time. Each fuel is addressed separately, with a consi-
deration of the Railbelt region•s geographic differences and the factors that
determine prices.
When a current price for a fuel is not available, the concept of oppor-
tunity cost is used to develop the back price and forecast. This concept pro-
vides that the resource price is equal to the price the resource will command
in an alternative market, less the appropriate transportation and handling
fees. Alaska is familiar with this net back method of price determination,
which is currently used to evaluate their royalty gas and oil resources.
Table B.1 and Figure B.1 summarize fuel availability and the price faced by
the electric utilities for the forecast period.
NATURAL GAS
Natural gas, from Cook Inlet fields (Figure B.2), is currently the pre-
dominant nontransportation fuel for both direct end use and electrical power
generation in the Cook Inlet Region. The cost of gas to the electric utili-
ties now ranges from about $0.25 to $2.30/MMBtu for use in combustion turbines
and from $1.55 to $2.46 per MMBtu for residential direct end use. These
B.1
OGla-1
llelt'l~a/C'Aok: in ~et
Ni<ncma lr nter·j a~
I'Jatqr,a 1 Gi\s
Goo!( In Ted o;'l
I'Jodtl ~ l ppe/
lnterior
L iCJuids/Methilnll ·l
N,, 2 Heti Hng 0 i 1
f'.eat
RE!.'f\l&e /Der:i v.eCJ
F·uel
· .~lrcno.rage
i>!l ir~.an ~s
E-st jln-a t~
Reserve•>
:t5:th; 1116 tcm s
2.40: .x Joo ton:s
~.990' Bcf
:;>.1. ~00 BM
'3¥800 Bd
Adeq pate
N/A
·-
PdcenoP B:P\1 -AM ua l Re~ 1
( J a:nu~ry· l~~~ . ' lisGa}atton
Ma il glllTVtx s~ sol .Ra ta
l9ae 1.,.69 Hih1l .2.1%'
!1f'.e:5 ~f!l: L 7.5, F O~ R"Q ·1'1 ~·~O'Id
'P.;~~.sent
H13~
0,~6 ' c~t:Y .Qa~ 6,6%-<W9 ·
~.92
J:S9.'i
Cicy ·Gate ·'4.3% ;w~.
Pr.eS'ent tt.EJd .D,e l i Vi!hed 'e%·
L968 (h) ~ i (i
t a) Vo1ume )Ve tght~ average· ~ 1"1 oe · t a A i asl¢a Gao 1111ti S'!'r V>te ano Cllug~t~h ~l ec tr k<rl
As .sliC 1 at. I on •
[J::o ) E':st'ima't~;$ r-ang~ fr.am I fa ~. t.1 m.e ~. 'the price ~i' t1l.a .l ..
p rit.eil: l!re the l (,l~,t i'rt tli~ unfted Stat!?S, .J'rrimarily .a~ a r~sulll Qf (l)ng-tern\
J:;On•trac;ts :si$1E!!L I)'}h'e_rt an e'XGe'S~ Of rra.t;ura ·l g~ exfst~'d qna the: prody"G.ers·,
lacki ng a. maJor market ou fl.et, heed a •J ~uJe1'·1 s.· market.11 This ,ptdt::P. si t uaMon
,;,. nn;t :e-,qrec.tei.:l to a:p n1?'irltJ!" -tn tloie future, p'!'ilnar11y because. of ~Xp fr-a titlh of
c;,on'tr<ao.t·s .a'nd naturij T ~~s :de.r;egu 1 itt i Oli s .
F'eri;cas-t ,i!\9 tlte !tUI'Pl.Y' a'nd ·~;r1ce crf. Cliok fnl!lt n!ltura1 9<~~ 1~ 91!.1.!!~ com ..
ple ,~ D-e~·a!I·S·.a ,_c_ortt:ratts 1i4:Ye est9b1)~11~\l th'l;' ttuant ft)l, ~u,•r~ll ~ pr:fg~;, .!(ncl p'r·i·ce
e.scala:f.ion rate fbr 't<ll•fous pqrt.lons of the g;as, "a)'ld ~ec:ause 'tti~ 1;e rm-s '"f
bh!!$£!-c_o nt.r/.lcts .d ·iff'!;!.r . 1n add jtion, new pr iru::)·~men ta1 SL!Piilie s us~ to m·E!"t
dema!ld in e xt·e~~ ot the (mntrac.ted .su~p1y are· P.titetl b.)( t hei" e·pportunity
a.;t
14.00
12.00
10.00
::J -co
:E 8.00 :E
iii:
N
CX) a-.--.
6.00
4.00
2.00
/ (3o/o REAL ESCALATION)
/
/ , ,
NO.2 FUEL OIL ,
/ , (2 'l'o REAL E SCALA T1 ON l
"" , ,
"" "" --"" ---(l 'l'oREAL ESCALATION) ----------
HEALY COAL =~ BELUGA COAL
;;;;;:_-
F< 'NORTH SLOPE >
GAS TO INTERIOR
1980 1990 2000 2010
YEAR
FIGURE B.l. Projected Fuel Prices to Railbelt Utilities,
1982 $/MMBtu, 1980-2010
value, which is the net-back from liquid natural gas (LNG) sales to Japan.
Determining price for Cook Inlet gas requires a forecast of both price and
quantity from each contractural source to develop the weighted average gas
price for the region. The result of this forecasting is a price escalation
that is not smoothed over the forecast period. This uneven price escalation
is evidenced in Figure B.1 by gas's constant price from 1980 to 1985 and the
escalation over the rest of the period, with stepped increases occurring in
1990 and 1995 when major contracts expire. After 1995, gas's price and esca-
lation rate are determined by its opportunity value because current purchase
contracts will have expired. The price of natural gas then is assumed to
escalate at approximately 2% faster than inflation -the same real annual rate
as for oil. Current information about Cook Inlet natural gas reserves and
B.3
NATURAL GAS &
PETROLEUM
f·.:·.\:·.1 NATURAL GAS FIELDS
lliiiOIL FIELDS
······PROPOSED NORTH SLOPE
NATURAL GAS PIPELINE
---NATURAL GAS PIPELINES
---PETROLEUM PRODUCTS PIPELINE
--NORTH SLOPE CRUDE PIPELINE
SCALE
~...;;;;,;,;,.~----..~--,--=
0 50 100'-lilu
FIGURE B.2. Natural Gas and Petroleum Resources in the Railbelt Region
B.4
total demand on those reserves indicates that availability to the Alaskan mar-
ket could become a major problem as early as 1990 and almost certainly by the
year 2000.
The North Slope reserves of natural gas are sufficient to supply the
Alaska Natural Gas Transportation System (ANGTS) to capacity (2 to 2.4 Bcf/day)
for the forecast period. This gas may begin flowing in 1986 or 1987. If only
Alaska•s royalty share is diverted to serve the Fairbanks area, the supply of
gas would be about 100 Bcf per year. A current estimate of the delivered
price of gas to the 11 lower 48 11 is about $10/!'1v1Btu in 1982 dollars with the
January 1982 maximum wellhead price of $2.13/MMBtu. The net-back provides a
first year city gate price of about $5.92/MMBtu to Fairbanks then declining
due to the pipeline tariff structure. The wellhead value of the gas is not
scheduled to decontrol under existing law and escalates only with the rate of
inflation.
COAL
Two sources of coal are available to the Railbelt (Figure B.3). The
Usibelli mine located at Healy .is the only mine currently producing coal. The
cost of this coal is assumed to escalate in real terms at the historical rate.
A second potential source is the Beluga coal field, which has been targeted as
a source of supply for the Anchorage area and as export to markets on the
Pacific Rim. As discussed below, this field may enter production about 1988.
Beluga coal is expected to escalate at the same rate as other coal supplies
serving the Pacific Rim export market at a real rate of about 2.1% annually.
Note that a great deal of uncertainty is involved in developing the Beluga
coal fields. These coal fields are now in the exploratory and predevelopment
phase. The coal has yet to be produced in any significant quantity and thus,
from an availability standpoint, must be considered prospective. Located in
an area with very little to no infrastructure development, these fields, while
containing very large reserves, are not likely to produce coal unless a firm
market of 5 or more million tons per year can be established. On an electric
power equivalent basis, this annual tonnage amounts to about 1400 MW of base-
load coal-fired power generation capacity.
B.5
COAL RESOURCES
-FIELDS HAVING SUPERIOR POTENTIAL
m8 OTHER FIELDS r
SCALE
0 ~0
FIGURE B.3. Coal Resources of the Railbelt Region
B.6
If coal-fired power generation becomes a significant factor in the Rail-
belt, generation capacity most likely would be added in increments of 200 or
400 MW. This staging requirement appears not, in itself, to support opening
of the Beluga fields. As a result, the establishment of an export market is a
prerequisite to the availability of Beluga coal for in-state use. Whereas the
Beluga fields could be developed for electrical generation only, the reduced
scale of such an operation would increase production costs markedly.
Alternative sources of coal in the Railbelt exist in the Matanuska Valley
(Evans Jones Mine, now abandoned) and on the Kenai Peninsula. The Matanuska
source would require more costly underground mining, and the reserves on the
Kenai are believed to consist of thin isolated beds suitable for low tonnage
local supply but not for central station power generation.
PETROLEUM PRODUCTS
Distillate fuel oils (such as home heating oil, diesel fuel, and combus-
tion turbine fuel) now serve substantial markets in the Railbelt (probably
second to natural gas in total), particularly in isolated communities and in
the greater Fairbanks area. These fuels are used both directly by consumers
and also by the electric utilities. In the Cook Inlet region, distillate
fuels are currently used as a backup supply by the electric utilities for peak
loads that natural gas supplies are not able to meet.
Refined petroleum products are the only fuels in which Alaska is currently
not self-sufficient. Alaska is not self-sufficient because of insufficient
refinery capacity for some products, rather than lack of resources. Alaska's
royalty share of crude oil production is sufficient to meet in-state consump-
tion at least through the year 2000, but refined products are imported. The
supply of petroleum products is not believed to be a problem through the
forecast period, however. The current price of utility fuel oil of about
$6.90/MMBtu is a good indicator of its current opportunity value, especially
in view of the recent price decontrol on oil.
at a 2% annual real rate along with crude oil.
of No. 2 oil over the forecast period for real
and 3%.
B.7
This oil is expected to escalate
Figure B.l also shows the price
annual escalation rates of 1%
PEAT
Peat is an abundant resource in the Matanuska and Susitna Valleys, on the
Kenai Peninsula and in the Fairbanks region (Figure B.4). The extent of its
use is currently unknown. Raw peat as harvested (essentially surface mined)
contains about 90% water and must be dried to less than 50% moisture prior to
use as fuel. Currently, no firm estimates of peat costs, including harvesting
and preparation, have been developed for Alaska conditions.
Although information for peat development in Alaska is lacking, a preli-
minary feasibility study (EKONO 1980) estimates a range of likely prices from
about 1 to 3 times the price of coal on a Btu basis, depending upon the har-
vesting and processing method used. The only real escalation likely to occur
is that associated with transportation and handling, which is set at less than
a 1% real annual rate.
Wood is used extensively in the nonmetropolitan areas of the Railbelt for
space heating. It is also used as a reliable back-up fuel. Costs of cordwood
for space heating purposes are currently about $5.50/MMBtu in the Fairbanks
area and $6.30/MMBtu in the Anchorage area.
Sufficient quantities of wood wastes may be available from logging and
sawmill operations to support a small-scale biomass-fired generating plant,
especially if municipal waste were also used for fuel. Harvesting trees solely
for firing electric power plants is generally not considered a viable option
in the Railbelt because of the slow rate of timber growth and availability of
alternative fuels.
MUNICIPAL WASTE
Municipal waste or refuse-derived fuel (RDF) is a candidate for central
station fuel in large urban areas where collection already takes place and
disposal occurs at relatively few landfill sites. The solid waste materials
currently generated in Greater Anchorage (including sawmill residue) have been
estimated to contain sufficient energy to fuel a 20-MW power plant. Municipal
wastes are generated in significant quantities only in large urban areas.
B.8
PEAT RESOURCES
[W/~ PEAT DEPOSITS
SCALE
~~----~ 7 0 ~ OOM~
FIGURE 8.4. Peat Resources in the Railbelt Region
8.9
Because wastes are bulky, transportation costs to potential power plants sites
outside of recognized air-quality control problem areas are expected to be
excessive relative to coal fuel to similar power plants.
PROPANE AND BUTANE
Propane and butane (low-pressure gas or LPG) are products of petroleum
refining operations or are extracted from natural gas prior to its transmission
through pipeline systems. Currently, LPG is not a major fuel in the Railbelt
region.
With the advent of natural gas production on the North Slope, significant
quantities of LPG would be produced and separated from the methane and ethane
fractions. As of mid 1981, the LPG is expected to be used locally as fuel to
support North slope oil and gas operations. Thus, extensive LPG availability
in the Railbelt region is highly speculative.
NATURAL GAS LIQUIDS/METHANOL
The delivery of natural gas liquids (NGL) to the Railbelt depends on the
construction schedule of the ANGTS and the real price of crude oil. Current
plans call for construction of an NGL pipeline following the ANGTS, with a
real crude oil price in the range of $50 to $52/barrel. This schedule pro-
vides for delivery of NGL in the mid to late 1990s.
Methanol production is tied closely to the ANGTS because the natural gas
from that system would serve as the feedstock, but the timing of methanol
production appears to be tied to petrochemical production that may accompany
the NGL pipeline. Current methanol prices have been in the range of $.90 to
$1.00/gal. The net-back price at Alaska tidewater would range from $0.85 to
$0.95/gal or $13.29 to $14.86/MMBtu. This price must incorporate Fairbank's
city gate price for the methane feedstock of about $5.92/MMBtu, suggesting
that production and transportation costs from Fairbanks to tidewater can be no
greater than $7.34 to $8.91/MMBtu. Currently, methanol production is not cost
competitive with other fuels in the "lower 48'' and is not projected to become
cost competitive until after the year 2000.
B.lO
SYNTHETIC FUELS
Considerable interest exists in the development of synthetic fuels derived
from low-cost and abundant reserves of coal and, to a lesser extent, peat.
Several processes are in the research and development stage and a few (e.g.,
gasification of coal) are nearing the commercial demonstration stage. These.
are capital-intensive projects, and their economic success primarily depends
on their ability to displace oil and natural gas at world prices and to achieve
economies of scale in large installations. To reduce transportation costs,
such plants are expected to be located near the primary resource.
Two firms, Placer Amex Inc. and Cook Inlet Region Inc., are studying the
possibility of low Btu gasification of Beluga coal followed by synthesis of
methyl alcohol. A fairly large market for the methanol product would be
required to achieve economies of scale. Should the methanol project proceed,
both low Btu gas and methanol could conceivably become available in the Cook
Inlet region. In the case of low Btu gas, power plant operations would have
to be closely integrated with the gasification operation. Additional discus-
sion of synthetic fuel production is provided in Appendix K of this report.
HYDROGEN
If surplus electrical generating capacity from hydroelectric or tidal
systems is available, hydrogen could be produced by electrolysis using that
energy, which might otherwise be lost. The hydrogen could be stored for later
use in fuel cells or in combustion turbines to generate electrical energy.
Alternatively, hydrogen could be supplied as a gas similarly to natural
gas for direct end use. Because of hydrogen•s physical and chemical nature,
existing natural gas distribution systems or appliances most likely could not
be used.
Finally, hydrogen can be used as an automotive fuel by conversion to a
metal hydride for compactness of storage. Hydrogen fuel technologies received
some interest in the 1970s, but currently little research and development
activity is aimed at commercial applications.
B .11
LIGHT WATER REACTOR (LWR) FUEL
LWR fuel costs are a function of uranium costs, waste management costs
and transportation costs. The energy density of reactor fuel is very high,
and the costs are believed not to be especially sensitive to location in
Alaska.
Estimated fuel cycle costs and forecasted uranium prices developed in a
recent study (White and Merrill 1981) were used to derive the fuel cycle costs
(fresh fuel plus disposal of spent fuel) of 7.8 mills/kWh. This cost is
leveled over a 30-year period with a 5% adder for transportation of fresh fuel
to a Railbelt location and return of spent fuel to the lower 48. Assuming a
65% capacity factor, the fuel cycle costs would be $44 million ($1980) for a
1000-MW reactor ($44/kW yr).
Long-term fuel supply for LWRs should not be a problem. LWRs currently
operate on an enriched uranium fuel derived from naturally occurring low-cost
uranium mined and processed in the lower 48 states. Recent estimates of U.S.
uranium supply show that ample low-cost uranium resources exist to support
about ten times the number of reactors now in service or under construction
(Piepel et al. 1981). When all low-cost uranium is committed, the fast breeder
reactor, which produces a surplus of fuel-grade plutonium, will become commer-
cially feasible. Because plutonium can be used to fuel LWRs, long-term fuel
supply should not be a problem.
B. 12
APPENDIX C
COST ESTIMATING METHODOLOGY
APPENDIX C
COST ESTIMATING METHODOLOGY
The purpose of this appendix is to describe common assumptions and pro-
cedures used to estimate costs cited in this report. Three aspects of cost
estimating are described: 1) estimation of capital and O&M costs, 2) estima-
tion of fuel costs and 3) estimation of energy costs.
CAPITAL AND OPERATION AND MAINTENANCE COSTS
The conceptual capital cost estimates and O&M estimates for the various
technologies described in each profile were derived by determining average
1980 costs for representative plants of varying capacities in the contiguous
United States.(a) Then, a location adjustment factor was applied for the
construction and operation of a similar plant in the Alaska Railbelt. Average
1980 costs were developed through a survey of power plant costs for recently
completed facilities, and projected cost estimates were derived from technical
studies for power plants in various stages of development. For electric
generating technologies that have not yet attained commercial development
status, such as fuel cells and solar conversion systems, costs were derived
from data contained in recent research status reports and various technical
studies.
Location adjustment factors were developed based upon an analysis of con-
siderations that contribute to Alaskan construction costs, which are typically
higher than costs experienced in the contiguous states. Prime contributing
factors to the higher construction costs in Alaska include remoteness, limited
accessibility, short construction season, and severe climatic conditions. For
(a) Only a few of the technologies considered in this report are presently
represented in the Railbelt region. To take advantage of cost experience
gained from installations in the lower 48, cost information from the con-
tiguous states was used to develop the cost estimates appearing in this
report.
C.1
example, the Railbelt region only has one railroad and a limited number of
highway routes. Travel to areas not served by highway or rail is by airplane,
water, or track-type vehicles. Typically, construction sites are remote and
require room and board construction camps for workers. The general practice
of working overtime during the long summer day also adds to the cost of con-
struction. Workers routinely work a a 60-hour week and therefore receive
overtime pay for the 20 hours over the standard 40 hours.
Cost adjustment factors developed by the U.S. Department of the Army
(1978) were also used. The Department of the Army (1978) has developed cost
adjustment factors for numerous locations within the United States and many
foreign countries. The data were developed from bid experience and are
intended as guidelines in preparing and reviewing conceptual cost estimates
for budgets. Adjustment factors identified for specific Railbelt locations
are shown in Table C.1.
TABLE C.1. Alaskan Cost Adjustment Factors
Location
Adjustment
Area Factor
Alaska (General)
Anchorage
Elmendorf AFB
Fairbanks
Fort Greeley (Big Delta)
Kenai Peninsula
1.32
1.7
1.90
1.9
2.2
2.1
These location adjustment factors reflect the average statistical differ-
ences in labor and material costs for the construction of similar facilities.
They do not reflect abnormal differences due to unique site considerations.
Washington, D.C. is the base with a factor of 1.00.
Based upon these considerations, location adjustment factors of 1.4 to
1.9 were used in this study to develop capital cost estimates, while a factor
of 1.5 was used for O&M cost estimates. Values at the upper end of the range
were used for labor-intensive technologies requiring extended construction
C.2
schedules, such as nuclear and large coal-fired facilities. Lower values were
used for technologies where expenditures are primarily related to equipment,
and where construction requirements are generally not extensive, such as com-
bustion turbines and diesel facilities. The assignment of an adjustment factor
also included consideration of the potential sites in the Railbelt.
Whereas the costs generated from these adjustment factors provide order-
of-magnitude estimates suitable for a comparative decision-making process,
limitations exist when using only a single adjustment factor. For the capital
cost estimates of constructing a power plant facility, three cost elements are
involved (equipment, material, and labor). A different adjustment factor could
apply to each depending on the specific technology considered. Also, a single
adjustment factor does not allow for site variations, some unique to the Alaska
Railbelt. For example, camp facilities might be required at a remote site but
not for a facility constructed near a population center. Similarly, O&M costs
are generally divided into fixed (salary related) and variable costs (equipment
and supplies). Separate cost adjustment factors might be appropriate for the
two cost categories.
The development of adjustment factors associated with each of the above
categories requires additional, more detailed study that is beyond the level
of these technology profiles. However, the use of a single adjustment factor
provides conceptual, order-of-magnitude cost estimates suitable for a compara-
tive decision-making process.
FUEL COSTS
Fuel cost and availability were estimated by a separate task in this pro-
ject. Summarized time series of the estimated costs of principal fuels are
provided in Appendix B of this report.
COST OF ENERGY
The energy costs provided in this report are (except where indicated)
levelized lifetime revenue requirements taken at the busbar of the plant
(for generating technologies) or at the point of end use (for conservation
technologies).
C.3
A revenue requirements analysis is a common and accepted method of
assessing investment alternatives of regulated utilities (EPRI 1982), differ-
ing from discounted cash flow analysis commonly used in corporate investment
analysis only in that a rate of return on investment is a given in revenue
requirements analysis (and cost of production is the objective), whereas in
discounted cash flow analysis, the rate of return is the objective, given a
market price. The revenue requirements analysis used in this study was
largely based on an approach developed by Phung and Rohm (1977). Costs
commonly included in a revenue requirements analysis include the following:
Capital Investment Costs
Return on debt
Return on equity
Income taxes
Book depreciation
Property tax
Insurance
Operating Expenses
F~l
Operation
Maintenance
Levelizing the lifetime revenue requirements provides a generally accepted
means of comparing alternatives, which may be subject to differing cost streams
through the life of the alternative. For example, consider the cost comparison
of a natural gas and a hydroelectric plant. The natural gas plant may begin
life with low energy production costs due to modest capital investment costs
and low fuel prices. However, as natural gas prices rise over time, the reve-
nue requirements of the gas-fired plant may increase substantially. The hydro
plant, conversely, may begin life with higher production costs due to capital
investment costs greatly exceeding those of the natural gas facility. Revenue
requirements, however, being largely comprised of fixed capital carrying
costs, will remain essentially constant through the life of the facility.
"Levelizing•• the production costs is a method of comparing the value of these
dissimilar revenue requirement streams. In levelizing, the present value of
C.4
each year's revenue requirements (PWRR) is obtained by discounting annual
revenue requirements from the year of occurrence back to a base year (Equa-
tion C.l) (taken as first year of commercial operation in the present study).
The present values of revenue requirements are summed (Equation C.2) to obtain
a total present value of all revenue requirements over the economic (PWRR)
life of the plant. An equivalent uniform annual revenue requirement (R) is
then determined (Equation C.3). This is the annual revenue requirement that,
if constant throughout the life of the facility, would lead to the same total
present value as the actual series of annual revenue requirements. The equiva-
lent uniform annual revenue requirement is divided by levelized annual energy
output (E) to obtain the levelized unit costs (C) provided in this report
(Equation C.4).
where
where
RRt = ---'---
( 1 +i) n
PWWRRt = the present value of revenue requirements occurring during
year t, n years into the plant life.
(C.l)
RRt = the revenue requirement of year t including capital invest-
ment costs (carrying charges) and expenses (fuel, operation,
and maintenance cost)
i = the discount rate.
m
PWRR = L PWRRt
t=l
PWRR =the total present value of all annual revenue requirements
over the plant life
m = the economic (book) life of the plant.
C.5
(C.2)
where
R = [CRF ( i ,m)] [PWRR] (c. 3)
R =The uniform annual revenue requirement (levelized revenue
requirement). When taken as a series over the life of
the plant, it has an aggregate present value equal to the
aggregate present value of the actual revenue requirement
stream.
CRF(. ) =the capital recovery factor at discount rate i over 1 ,m
service life m, as follows:
CRF ( . ) = 1 ,m
R C=
I
(C.4)
where
C = levelized unit cost of production (mills/kWh)
R = levelized annual revenue requirements
E = levelized annual energy production, obtained as follows:
-~ E(t) E = CRF(i,m) ~ t t=1 (1+i)
where E(t) =annual energy production, year t.
(a) Although a 1990 first year of commercial operation is adopted to facili-
tate a uniform cost comparison, all technologies could not be available
for commercial operation in 1990 due to maturity of the technology con-
struction schedule or other reasons.
C.6
All estimates of energy costs are predicated on a 1990 plant startup
date.(a) Use of a uniform 1990 year of commercial operation ensures that
all technologies are treated consistently from the standpoint of future esca-
lation in capital, O&M and fuel costs.
Project financing was, in all cases, based on 100% public (state) debt
financing. A 3% (real) interest rate on debt was used; other financial para-
meters used also corresponded to public financing (Table C.1). All cost
assessments were done on a 11 real 11 basis to purge the results of uncertainties
attributable to the effects of general inflation.
Real escalation in capital and O&M costs was taken to be zero during the
planning period. Fuel costs were escalated (in real terms) as described in
Appendix B. Because general inflation was excluded from the analysis, the
levelized revenue requirements at first year of commercial operation (1990)
were equivalent to the 1980 price year dollars used for all costs in this
assessment. No discounting from 1990 to 1980 was then required to express
levelized revenue requirements in 1980 dollars. The financial and technical
parameters generally used in the cost ca leu 1 at ion discussed above are summa-
rized in Table C.1. These premises generally agreed with financial premises
used in the Acres American Upper Susitna Project Development Study (Acres
American 1981a), and the Acres American Cook Inlet Tidal Power Assessment
(Acres American 1981b).
C.7
TABLE C.2. Premises for Cost Assessment
First Year of Commercial Operation 1990
Start of Construction
Economic (Bond) Life
Capacity Factor
Financing
Cost of Debt
General Inflation
Federal and State Taxes
Insurance
Capital Cost Escalation
O&M Cost Escalation
Fuel Cost Escalation
Discount Rate
Construction Payout Schedule(a)
Construction Period
1 year
2 years
3 + years
corresponding to construction period
cited in text
as cited for technology in text
constant over 1 ife of fac i1 ity, as
cited in text
100% debt
3% (rea 1)
none
none
0.25% capital value/year
none
none
As in Appendix B
3% (real)
Payout Sch edu 1 e
one shot
constant
weak sigmoid (Phung 1978)
(a) Used to estimate interest during construction.
c.s
APPENDIX 0
WATER RESOURCE IMPACTS FROM STEAM-CYCLE POWER PLANTS
APPENDIX D
WATER RESOURCE IMPACTS FROM STEAM-CYCLE POWER PLANTS
The construction and operation of any steam-cycle electric generating
facility will potentially result in three types of water resource impacts:
water consumption impacts, water-quality impacts, and hydrologic impacts.
Most of the potential impacts can be satisfactorily mitigated through appro-
priate power plant site selection, engineering design, and operating proce-
dures. Design criteria, operating procedures and resulting costs associated
with proper mitigation will vary considerably depending upon site technology
and fuel-specific factors.
Water resource impacts associated with each type of steam-cycle facility
and their mitigation alternatives are described below. Unless a specific
technology is identified, the discussion generally applies to all steam-cycle
facilities.
WATER CONSUMPTION EFFECTS
Consumptive water losses associated with the operation of any steam-cycle
power plant requiring a substantial water supply for cooling and other plant
uses can reduce the downstream flow of the water resource. The significance
of this impact depends on the magnitude of the plant's water requirements
relative to the flow of the river or to the hydraulic conductivity of the
aquifer serving as the supply. Because the Railbelt region's surface water
supplies are plentiful, use of groundwater for power plant operation should be
limited. Groundwater use can be envisioned in at least two applications:
1) the use of Ranney well collectors in alluvial aquifers close to a river
system for mitigating entrainment and impingement of aquatic organisms; and
2) the possible use of groundwater in coastal areas to supply a plant's fresh
water requirements when salt water condenser cooling systems are employed.
The amount of water required by a specific plant depends upon the type of
cooling system used (once-through or recirculating), the type of steam cycle,
D.1
the site, and the specific water management techniques used to maximize water
reuse and to minimize power plant makeup requirements. Estimates of water
requirements are presented in Table 0.1 for various steam cycles and plant
capacities.
To comply with existing federal and state regulations, once-through cool-
ing water systems will most likely be limited to coastal areas employing salt
water cooling. Interior sites will most likely use some form of recirculating
cooling water system (see Appendix I).
Based upon the general siting constraints presented in each technology
description, the most probable power plant water supply sources in the
Railbelt region are listed in Table 0.2. Selected USGS streamflow data for
these resources are presented in Table 0.3.
Since water withdrawal impacts are relative to the flow of the river, a
comparison of the information presented tn Tables 0.1 and 0.3 can provide an
overview of potential effects. If all water demand is assumed to represent
total consumption (as it would for a zero discharge plant), then the maximum
water consumption for any of the plants identified in Table 0.1, using a
recirculating cooling water system, would be less than 1% of the average flow
for rivers identified in Table 0.3. Plant water demand should also be a small
percentage of each river's minimum recorded flow. For plant sizes likely to
be constructed in Alaska, 200 MWe for example, total plant demand (again for a
zero discharge plant) represents less than 10% of minimum flow for all but the
smallest streams of Table 0.3. These conclusions suggest that impacts on
water flow should not be significant.
WATER QUALITY EFFECTS
Construction and operation of any steam-cycle facility can potentially
significantly affect water quality. For most steam-cycle facilities, con-
struction impacts are primarily associated with runoff and erosion from the
site while the soil is exposed. Other common pollutant sources include con-
struction camp and site domestic and sanitary facilities, concrete batch
plants, construction dewatering, and dredge spoil. The development of geo-
thermal fields requires large quantities of drilling mud, which requires
0.2
0
w
TABLE 0.1. Estimated Water Requirements Associ a ted with Various Steam-Cycle Facilities
Plants Utilizing Once Through Cooling Water S~stems Plants Utilizing Recirculation Cooling Water S~stems
Approximate
Cooling( a) Coo 1 i ng( c) Thermal
Total Plant Demand (1000 ~pm)(b) Efficiency Water Water
Steam Cycle (Percent) ( gpm/MW) 20 MW 50 MW 200 MW 400 W 600 MW (gpm/MW) -- --
Biomass 17-24 730 14.6 36.5 13
Coal 30-37 450 9.0 22.5 90 180 270 8
Oil 29-37 450 9.0 22.5 90 180 270 8
Natural Gas 27-34 450 9.0 22.5 90 180 270 8
Synfuel 24-30 675 13.5 33.7 135 270 405 12
Geotherma 1 7-16 845 16.9 42.2 169 15
Nuc 1 ear 30 620 124 248 372 11
Combined
Cycle 40 150 7.5 30 3
(a) Based upon estimates presented in Kim et al. 1g75 and adjusted for thermal efficiencies.
(b) Cooling water requirements assumed to represent 100% of total plant demand.
(c) Derived from methodology presented in Nelson 1g74.
Total Plant Demand (1000 ~~)(d)
20 MW 50 ~1W 200 MW 400 600 MW
0. 29 0.725
0.18 0.45 1.8 1.8 5.4
0.18 0.45 1.8 3.6 5.4
0.18 0.45 1.8 3.6 5.4
0.27 0.68 2.7 5.4 8.1
0.30 0.75 3.3
2.5 5.0 7.5
0.15 0.6
(d) Cooling water requirements are assumed to represent 90% of total plant demand for all technologies except geothermal. For
geothermal, cooling water requirements assumed to represent 100% of total plant demand.
TABLE 0.2. Possible Power Plant Water Sources in the Railbelt
Water Resources Possible Facility Type
Cook Inlet All
Prince William Sound All except geothermal
S u s i t n a R i v er A 11
Matanu sk a River A 11
Copper River Coal, synfuel, geothermal
Gulkana River Coal, synfuel
Tanana River Nuclear, geotherma 1
Nenana River Coal, synfuel, nuclear
Chena River Geothermal
management and subsequent disposal. Potential impacts from all of these
wastewater sources are generally mitigated through appropriate wastewater
treatment and recycle facilities. The water-quality parameter of primary
concern during a plant's construction phase is suspended sediment (SS).
Facilities to manage this wastewater constituent are generally incorporated
into a site erosion and sediment control plan.
The type and quantity of potential water pollutants resulting from power
plant operation are greatly dependent upon the type of steam cycle used and
the size of the plant. Potential sources of water pollution include cooling
system blowdown, fuel pile runoff, demineralizer regeneration wastewater, ash
handling and flue gas desulfurization waste, geothermal fluid discharges, fuel
oil releases, radioactive wastes (nuclear plants only) and miscellaneous
cleaning wastes.
Cooling Water Blowdown
In general, all power plants using closed-cycle cooling systems
periodically discharge ("blowdown") water from the cooling system to remove
accumulations of sediment and other undesirable materials. The quantity and
quality of coolant blowdown depend upon the type of cooling system used and
the specific characteristics of the source. In general, total dissolved
solids (TOS), chlorine, and waste heat are the primary pollutants of concern.
0.4
TABLE 0.3. Stream Flow Data for Selected Railbelt Locations
U. S.G. S. Years of Average Flow Maximum Flow Minimum Flow
Station Name and Location Number Record cTS Hl(j(j 9~ cfs Hloo gpm cfs IOOOg~
Susitna River near Cant we 11 15291000 11 6,295 2,825 55,000 24,686 400 180
Susitna River at Gold Creek 15292000 28 9,667 4,338 90,700 40,709 600 269
Tanana River near Tanacross 15476000 24 7,931 3, 559 39,100 17,549 1,400 628
Tanana River at Fairbanks 15485500 5 (17 ,OOO)(a) 7,630 68,300 30,655 3,100 1,391
Tanana River at Nenana 15515500 17 (22,000)( a) 9,874 186,000 83,483 4,000 1,795
Chena River near Two Rivers 15949300 10 680 305 16,800 7,540 20 9
Chena River near North Pole 15493000 5 756 339 12,300 5,521 50 22
0 Chena River at Fairbanks 15514000 29 1,450 651 74,400 33,393 ( 160) (b) 72
Ul N~nana River near Healy 15518000 27 3,527 1,583 46,800 21,000 190 85
Copper River near Chitina 15212000 22 37,100 16 ,652 265,000 118.940 2,000 989
Matanuska River at Palmer 15284000 24 3,857 1,731 82,100 36,849 234 105
Gulkana River at Sourdough 15200280 5 1,085 487 9,170 4,116 200 90
(a) Estimated, based on 2 years of record.
:b) Minimum not determined, 1978 minimum given.
Fuel Pile Runoff
Steam cycles using solid fuel, i.e., coal, peat and various forms of bio-
mass, require management of fuel pile runoff. For coal, this wastewater is
generally of low pH and high in sulfates and iron and has various concentra-
tions of other metals, depending upon the specific coal source. For biomass
fuels, the prime parameters of concern are the chemical and biochemical oxygen
demand, although other important pollutants may also be present, such as metals
in municipal solid waste.
Demineralizer Regeneration Wastewaters
All steam-cycle facilities except geothermal power cycles produce demin-
eralizer regeneration wastewaters that have high TDS levels and generally low
pH values.
Ash Handling and Flue Gas Desulfurization Wastes
Fossil fuel and biomass steam cycles produce ash as a by-product of com-
bustion, although the amounts vary greatly with the type of fuel. Wastewater
produced during ash handling and ash transport, and leachates from solid waste
landfills generally have high TDS levels and elevated concentrations of metals.
Coal generates the largest quantities of solid waste, including fly ash, bot-
tom ash, and flue gas desulfurization wastes.
Geothermal Fluid Discharges
At geothermal plants, the geothermal fluid itself can be highly saline
(high in TDS), and the dissolved substances in the fluid can be concentrated
during the process of electricity generation. The quality of geothermal
fluids is highly variable, however, and can exhibit significant differences
even between wells in a specific well field. Water-quality data reported in
the literature for geothermal plants located throughout the world exhibit
variations that range from benign to extremely toxic.
Fuel Oil Releases
Potential oil pollution impacts associated with oil-fired power plants
and other facilities that may use oil as an auxiliary fuel include accidental
release of oil through spillage or tank rupture. Potentially significant
0.6
impacts that may result from oil releases are generally mitigated through the
federally mandated implementation of a Spill Prevention Control and Counter-
measures (SPCC) Plan, as required under 40 CFR 110 and 40 CFR 112. This plan
is intended to ensure the containment of all releases and the proper recovery
or disposal of any waste oil. The plan must also be formulated in light of
the Alaska Oil and Hazardous Substances Pollution Regulations.
Radioactive Wastes
Problems associated with the release of radioactive wastes from nuclear
facilities are generally mitigated through compliance with Nuclear Regulatory
Commission guidelines. However, accidental releases are possible; therefore,
all potential transmission media, including groundwater and surface water
resources, are extensively studied during project development to minimize any
impacts related to such releases.
Miscellaneous Wastewaters
Steam-cycle plants generally have many other miscellaneous wastewaters
derived from floor drainage, system component cleaning, and domestic water
use. The quantity and quality of these wastewaters will vary considerably,
but oil and grease, suspended solids, and metals are the effluents of most
concern.
All of these enumerated wastewaters are strictly managed within a speci-
fic power plant. The management vehicle is generally termed a 11 water and
wastewater management plan 11 and for some plants is developed in conjunction
with a 11 SOlid waste management plan.11 The purpose of these plans is to bal-
ance environmental, engineering, and cost considerations and to develop a
plant design and operational procedure that ensures plant reliability and
environmental compatibility and that minimizes costs.
For Railbelt plants, relevant regulations would include the following:
Clean Water Act and its associated National Pollutant Discharge Elimination
System (NPDES) permit requirements and federal effluent limitation guidelines;
Alaska State water-quality standards (which regulate all parameters of concern
in all Alaska waters depending upon the specific water resource's designated
0.7
use); the Federal Resource Conservation and Recovery Act and Alaska solid
waste disposal requirements; and the Toxic Substances Control Act.
Compliance with all regulations does not eliminate water resource impacts.
Alaska water-quality standards permit a wastewater discharge mixing zone;
water-quality concentrations will therefore be altered in this area. Down-
stream water quality will also be altered because receiving stream standards
are rarely as high as the existing water quality of the receiving water body.
If secondary impacts associated with wastewater discharges, such as those to
aquatic ecosystems, are deemed significant, further waste management and
treatment technologies may be employed. Water-quality impacts can only be
completely avoided if the plant is designed to operate in a 11 Zero discharge 11
mode. This is technically possible for all steam-cycle power plants, but can
be extremely costly.
Typical water-quality values for selected rivers in the Railbelt region
are given in Table 0.4. Based on these values, no extraordinary or unusual
water-quality characteristics appear to preclude construction or operation of
a properly designed steam-cycle power plant. Most of the river systems can be
considered moderately mineralized based upon the total dissolved solids values
and the concentrations of the major ionic components. Values for calcium,
magnesium, and silica are not low and will limit the natural reuse (without
treatment) of several wastewater streams, most significantly cooling tower
blowdown. 11 Standard 11 power plant water management technologies will be
required to mitigate any adverse water-quality impacts.
A potential water-quality problem that can arise, not from wastewater
discharge, but rather from atmospheric emissions associated with fossil fuel
power plants, is acid precipitation (rain). Acid rain occurs when gases such
as sulfur dioxide, hydrogen sulfide, and nitrogen oxides are converted in the
atmosphere to sulfuric and nitric acids. If these acids are present in signi-
ficant quantities, they can acidify precipitation to below pH 5.6, the normal
pH of rain and snow at equilibrium with carbon dioxide in the atmosphere. The
effects of extensive acid precipitation on sensitive ecosystems can include
changes in soil and water chemistry with attendant adverse impacts to terres-
trial and aquatic biota. Sensitive ecosystems are generally in areas under-
laid by highly siliceous types of bedrock such as granite, some gneisses,
0.8
TABLE 0.4. vJater-Qual ity Data for Selected Alaskan Rivers(a)
U. S.G. S. Silica Iron Manganese Calcium Magnesium Sodium Potassium
River/Location Station No. Flow cfs ~ !1!.9L mg/ __I!!9L_ mg/ ~ mg/
Copper River near Chitina 15212000 6,100 14 36 9.3 12 1.6
159,000 8.5 0.02 23 3.5 4.3 2.0
Matanuska River at Palmer 15284000 11,600 4.5 0.02 28 1.8 3.8 0.9
566 6.3 0.07 44 4.8 8.9 0.9
Susitna River at Gold Creek 15292000 34,000 5.7 12 1.4 3.1 1.3
1,960 11 0.19 34 4.5 11 2.4
Susitna River at Susitna Station 15294350 6,790 10 0.09 0.13 26 4.2 7.1 1.5
148,000 3.6 0.07 0.85 17 2.3 1.8 1.5
Chena River at Fairbanks 15514000 10.200 6.4 2.7 0.75 12 2.3 1.1 2.1 .
182 23 3.2 0.82 36 7.6 4.9 2.8
Tanana River at Nenana 15515000 4,740 19 54 10 4.8 2.9
34,300 7.4 24 5.0 2.7 1.9
0 Nenana River near Healy 15518000 497 8.2 36 10 5.6 2.6
8,750 4.0 0.55 18 3.6 2.7 1.4
\..0
Gulkana River at Sourdough 15200280 286
6,130
Talkeetna River near Talkeetna 15292700 1,930 7.3 19 2.2 8.3 1.0
19,800 5.1 8.1 1.0 2.6 0.5
Yukon River at Ruby 15564800 345,000 6.2 0.19 0.02 27 6.1 2.2 1.9
26,900 12 0.39 0.02 46 10 3.9 2.0
Chakachutna River near Tyonek 15294500 6,640 5.3 0.03 0.01 9.1 2.1 1.4 1.5
15,100 5.3 0.94 0.05 14 1.8 1.5 1.7
Skwentna River near Skwentna 15294300 6,760 11 17 5.0 4.4 0.9
1,330 13 28 4.3 7.7 1.7
Lowe River near Valdez 15226500 5.0 28 0.8 1.2 2.7
390 2.0 0.04 0.02 22 1.0 1.4 2.5
Fortymile River near Steel Creek 1,100 11 0.08 20 7.5 4.6 1.2
(a) Adapted from U.S.G,S. Water Data Report AK-77-1 and U.S.G.S. Open File Report 76-513.
TABLE 0.4. (Contd)
U.S.G.S. Sill ca Iron Manganese Calcium Magnesium Sodium Potassium
R 1 ver /Location Station No. Flow cfs ~ !!1.9L mg/ __!!!9/_ _.!!!!!_/-~ ___l!!!lL__
Copper River near Chitina 15212000 116 26 18 0.09 174 7.2
78 15 3.2 0 98 7.6
Matanuska River at Palmer 15284000 61 29 2.5 0.2 94 7.0
100 41 13 0.25 169 8.1
Susitna River at Gold Creek 15292000 36 6.0 4.0 0.14 52 6.8
98 12 29 0.11 152 8.0
Susi tna River at Susitna Station 15294350 82 15 13 0.24 0.0 116 6.9
59 13 2.2 0.05 1.1 11.3 64 8.1
Chena River at Fairbanks 15514000 30 10 0.7 0.27 54 7.0
140 13 2.1 0.52 165 6.6
Tanana River at Nenana 15515000 173 33 2.4 0.30 212 7.5
72 34 2.5 0.10 113 7.2
Nenana R 1 ver near Healy 15518000 102 51 5.0 0.11 169 7.0
57 14 1.1 0.09 74 7.0
0 Gulkana River at Sourdough 15200280 110 0.15 0.03 10.1 7.5
40 0.04 0.15 11.0 7.1
I-'
0 Talkeetna River near Talkeetna 15292700 52 10 12 0.00 14.1 91 7.7
28 2.8 2.6 0.20 0.08 11.7 37 6.8
Yukon River at Ruby 15564800 94 1.4 0.2 0.04 113 7.6
165 25 1.3 0.23 183
Chak achutna River near Tyonek 15294500 26 12 2.0 0.00 46 7.1
26 11 1.4 0.03 51 7.5
Skwentna River near Skwentna 15294300 52 20 6.0 0.05 91 7.4
77 24 12 0.18 130 7.1
Lowe River near Valdez 15226500 57 3.2 0.8 0.32 100 7.6
46 22 1.2 0.34 77 7.3
Fort~nile River near Steel Creek 65 37 0.5 0.47 116 .7.4
TABLE 0.4. (Contd)
Total Dissolved Total Oissolved
Bicarbonate Sulfate Chloride Nitrate Phosphorus Oxygen Solids pll
River/Location mg/ mg/ __1!1.9L__ mg/ mg/ mg/ __mgj Units
Copper River near Chitina 116 26 18 0.09 174 7.2
78 15 3.2 0 98 7.6
Matanuska River at Palmer 61 29 2.5 0.2 94 7.0
100 41 13 0.25 169 8.1
Susitna River at Gold Creek 36 6.0 4.0 0.14 52 6.8
98 12 29 0.11 152 8.0
Susitna River at Susitna Station 82 15 13 0.24 0.0 116 6.9
59 13 2.2 0.05 1.1 11.3 64 8.1
Chena River at Fairbanks 30 10 0.7 0.27 54 7.0
140 13 2.1 0.52 165 6.6
Tanana River at Nenana 173 33 2.4 0.30 212 7.5
72 34 2.5 0.10 113 7.2
Nenana River near Healy 102 51 5.0 0.11 169 7.0
57 14 1.1 0.09 74 7.0
0
Gulkana River at Sourdough 110 0.15 0.03 10.1 7.5
40 0.04 0.15 11.0 7.1
Talkeetna River near Talkeetna 52 10 12 0.00 14.1 91 7.7
28 2.8 2.6 0.20 0.08 11.7 37 6.8
Yukon River at Ruby 94 1.4 0.2 0.04 113 7.6
165 25 1.3 0.23 183
Chak achu tna River near Tyonek 26 12 2.0 0.00 46 7.1
26 11 1.4 0.03 51 7.5
Skwentna River near Skwentna 52 20 6.0 0.05 91 7.4
77 24 12 0.18 130 7.1
Lowe River near Valdez 57 3.2 0.8 0.32 100 7.6
46 22 1.2 0.34 77 7.3
Fortymile River near Steel Creek 65 37 0.5 0.47 116 7.4
quartite, and quartz sandstone, none of which are extensively prevalent in the
Railbelt region (USGS 1978). These rock types are highly resistant to disso-
lution through weathering and are therefore generally low in dissolved solids
and have a low buffering capacity (a low ability to neutralize additions of
acids or alkalis). Hence, when acid precipitation falls on such an area, the
acids are not fully neutralized in the watershed, and so streams and lakes
become acidified.
Working with water chemistry data from more than 1,000 lakes in Norway,
the Norwegian Institute for Water Research has recently developed an empirical
relation by which the sensitivity of a given fresh-water system to inputs of
acid precipitation can be estimated (Likens et al. 1979). For example, the
relationship predicts that a soft water lake with about 80 microequivalents of
bicarbonate (corresponding to about 4.8 mg/1 of bicarbonate, 1.7 mg/1 of cal-
cium and a pH of about 6.5) will lose its buffering capacity to the point
where the pH drops below 5, a critical level for fish, if the long-term average
pH of precipitation is below about 4.3.
A review of the available water quality data (Table 0.4) for various water
resources in the Railbelt region indicates that bicarbonate and calcium concen-
trations are, in general, an order of magnitude greater than these critical
levels, and pH values are generally alkaline (greater than 7.0). Based upon
these values, there appears to be sufficient assimilative capacity in these
natural waters to mitigate effects from potential acid rain events.
HYDROLOGIC EFFECTS
Impacts to the hydrological regime of groundwater and surface water
resources can result from the physical placement of the power plant and its
associated facilities, and from the location and operation of water intake and
discharge structures. The siting of the power plant may necessitate the eli-
mination or diversion of surface water bodies and will modify the site runoff
pattern. Stream diversion and flow concentration may result in increased
stream channel erosion and downstream flooding. Proper site selection and
0.12
design can minimize these impacts. Mitigative techniques such as runoff flow
equalization, runoff energy dissipation, and stream slope stabilization may be
employed.
Other hydrological impacts can result from the siting and operation of
the makeup water system and wastewater discharge system. The physical place-
ment of these structures can change the local flow regime and possibly obstruct
navigation in a surface water body. Potential impacts associated with these
structures are generally mitigated, however, through site selection and struc-
ture orientation. Discharge of power plant wastewaters may create localized
disturbances in the flow regime and velocity characteristics of the receiving
water body. These effects are minimized through proper diffuser design, loca-
tion, and orientation. Consumptive water losses associated with the power
plant may also affect hydrological regimes by reducing the downstream flow of
the water resource. However, as discussed previously, surface water supplies
in the Railbelt region are plentiful, and hydrologic impacts due to reduced
streamflow should not be significant.
0.13
APPENDIX E
AIR EMISSIONS FROM FUEL COMBUSTION POWER PLANTS
APPENDIX E
AIR EMISSIONS FROM FUEL COMBUSTION POWER PLANTS
Air pollution is the presence of contaminants in the atmosphere in suffi-
cient quantities and duration to be harmful to human, plant or animal life or
property. Fuel-burning electric generating plants, including coal, distillate
and gas-fired steam-electric plants, combustion turbines, combinedcycle
plants, and diesel generators, are potentially major sources of air pollution
because they discharge potentially polluting products of combustion into the
atmosphere.
In this appendix, the discussion addresses the general nature of air pol-
lution that arises from fuel combustion, the broad regulatory framework that
has been implemented to control air pollution, and the regulatory considera-
tions that apply to the Railbelt region. The emissions of the different fuel
' combustion technologies used in electric power generation are compared also.
Finally, the general nature of siting requirements affecting the construc-
tion of combustion-fired generating facilities in the Railbelt region are
discussed.
POTENTIAL POLLUTANTS
Several kinds of air pollutants are normally emitted by fuel-burning
power plants. These include particulate matter, sulfur dioxide, nitrogen
oxides, carbon monoxide, unburned hydrocarbons, water vapor, noise and odors.
Of particular concern is acid rainfall, a secondary effect of air pollutants.
Particulate Matter
Particulate matter consists of finely divided solid material in the air.
Natural types of particulate matter are abundant and include wind-borne soil,
sea salt particles, volcanic ash, pollen, and forest fire ash. Manmade parti-
culate matter includes smoke, metal fumes, soil-generated dust, cement dust,
and grain dust. On the basis of data collected by the U.S. Environmental
E.l
Protection Agency (EPA}, suspended particulate matter in sufficient concentra-
tions has been determined to cause adverse human health effects and property
damage.
Fuel combustion power plants produce particulate matter in the form of
unburned carbon and noncombustible minerals. Particulate matter would be
emitted in large quantities from fuel combustion plants that use solid fuels
(coal, peat, wood, municipal waste) or residual oil, if high-efficiency con-
trol equipment were not used. Particles are removed from flue gas by using
electrostatic precipitators or fabric filters (baghouses). They are routinely
required and collection efficiencies can be very high (in excess of 99%).
Sulfur Dioxide
Sulfur dioxide (S0 2), a gaseous air pollutant, is emitted during combus-
tion of fuels that contain sulfur. Coal and residual oil contain sulfur in
amounts of a few tenths of a percent to a few percent, whereas pipeline natural
gas, wood, and most municipal wastes contain relatively little sulfur. Sulfur
dioxide, like particulate matter, has been identified as harmful to human
health, and it appears to be particularly serious when combined with high con-
centrations of particulate matter. It is damaging to many plant species,
including several food crops such as beans. Sulfur dioxide may, in addition,
result in acid rainfall.
Nitrogen Oxides
Nitrogen oxides (NOx) (N0 2 and NO, primarily}, gaseous air pollu-
tants, form during the combustion process by oxidation of fuel-bound or atmo-
spheric nitrogen. Nitrogen oxides damage plants and play an important role in
photochemical smog. Fuel combustion plants and automobiles are significant
contributors to these emissions.
Pollution control technology for NOx oxides has developed more slowly
than for most other air pollutants. Lack of chemical reactivity with conven-
tional scrubbing compounds is the main difficulty. Thus, current control
strategies focus on control of NOx production. Principal strategies include
E.2
control of combustion temperatures (lower combustion temperatures retard for-
mation of NOx) and control of combustion air supplies to minimize introduc-
tion of excess air (containing 78% nitrogen).
Carbon Monoxide
Carbon monoxide (CO) emissions result from incomplete combustion of
carbon-containing compounds. Generally, high CO emissions result from subop-
timal combustion conditions and can be reduced by using appropriate firing
techniques. HDwever, CO emissions can never be eliminated completely, using
even the most modern combustion techniques and clean fuels. Carbon monoxide
is toxic to humans and animals.
Unburned Hydrocarbons
Unburned hydrocarbons are emissions of vaporized unburned fuel or par-
tially burned products that escape combustion. Generally, they are produced
during periods of startup or shutdown or during faulty unit operation. For
combustion turbines they may also be emitted during periods of very low load.
Unburned hydrocarbons play a role in photochemical smog formation. They are
generally well controlled by employing efficient combustion techniques or
operational controls. Emissions of hydrocarbons in the Railbelt region should
not adversely affect the selection of any of the fuel burning options, nor
will they affect the selection of one option over another.
Water Vapor
Plumes of condensed water vapor are discharged from wet cooling towers as
the tower exhaust is cooled below the saturation point. The plume will per-
sist downwind of the tower until the water vapor is diluted to a level below
saturation. Under cold, moist conditions the plumes are particularly long
because the ambient air can hold little added moisture. Formation of these
plumes may be hazardous during 11 fogging 11 conditions when a high wind speed
causes the plume to travel along the ground. During freezing conditions, such
plumes may lead to ice formation on nearby roads and structures. Plume gener-
ation, fogging, and icing can be controlled or virtually eliminated by using
wet/dry or dry cooling towers.
E.3
Noise and Odor
Noise levels beyond the plant property line can be controlled by equip-
ment design or installation of barriers. Odors may be produced by municipal
wastes or some biomass fuels.
Acid Precipitation
The so 2 and NOx emissions from fuel-burning facilities have been
related to the occurrence of acid rainfall downwind of major industrial areas.
Acid rain results from the conversion, in the atmosphere, of gases such as
so 2, H2s and NOx to sulfuric and nitric acids. Congress may soon enact
laws to restrict these emissions because of the effects of acid rain. The
mechanisms of acid rain formation, subsequent acidification of lakes and
effects on soils, vegetation, wildlife and structures, and the relationship to
specific source emissions are not yet fully understood. Much research is in
progress in this area, and recent research indicates that some remote areas of
the western United States have been affected by acid rain.
On initial assessment, Alaskan lakes do not appear to be so sensitive to
acid rain as lakes in eastern Canada and the northeastern United States. Fur-
thermore, the total emissions into the Alaska environment are much less than
emissions from industrialized areas of the midwest and northeast United States
(Galloway and Cowling 1978). Acid rainfall most likely will never present
problems in Alaska similar to. those in the eastern portion of the continent.
Currently, no basis exists for assessing the impacts of acid rainfall
that might develop because of increased fuel combustion in Alaska. In devel-
oping any of these technologies, however, the planning agencies must be aware
that a significant research effort is being mounted against acid rainfall and
that a regulatory framework may be developed within the next several years to
analyze and mitigate its impacts.
REGULATORY FRAMEWORK
The 1970 federal Clean Air Act established the national strategy for air
pollution control. The Act established New Source Performance Standards
E.4
(NSPS)(a) for new stationary sources, including fuel combustion facilities.
Levels of acceptable ambient air quality (National Ambient Air Quality
Standards) were also established, and the regulations were promulgated to
maintain these standards or to reduce pollution levels where the standards
were exceeded.
New source performance standards (NSPS) have been promulgated for coal-
fired steam-electric power plants and for combustion turbines. In addition,
any combustion facility designed to burn coal or coal mixtures, or capable of
burning any amount of coal, or if such use is planned, is subject to the coal-
fired power plant standards. Standards of allowable emissions for each fuel
combustion technology for a range of sizes for power plants are presented in
Table E.1 for so 2, Table E.2 for particles, and Table E.3 for NOx. Data
are taken from EPA Publications or the New Source Performance Standards. The
standards are enforced for both newly constructed and significantly retro-
fitted facilities and represent the expected level of controlled emissions
from these power plants.
In Alaska, the Department of Environmental Conservation enforces regula-
tions regarding ambient air quality standards and source performance standards.
A permit to operate will be required for all fuel-burning electric generating
equipment greater than 250 kW generating capacity.
Major changes were made to the Clean Air Act in 1977 when the Prevention
of Significant Deterioration (PSD) program was added by Congress. The PSD
program has established limits of acceptable deterioration in existing ambient
air quality for so 2 and total suspended particulates (TSP) throughout the
United States. Pristine areas of national significance (Class I areas) were
set aside with very small increments of allowable deterioration. The remainder
of the country was allowed a greater level of deterioration. Other regulatory
factors apply to areas where the pollution levels are above the national stan-
dards. State and local agencies may take over the administration of these
(a) "The term standard of performance means a standard for emissions of air
pollutants which reflects the degree of emissions limitation achievable
through the application of the best system of emission reduction ... "
(Pub. L. 91-604, HR 17255, Dec. 31, 1970).
E.5
TABLE E.1. Controlled Sulfur Dioxide Emissions for Various Technologies
Technology
Steam Electric
Coal(b)
Oil(c)
Gas
Wood
Combustion Turbine
Oi 1
Gas(d)
Emission Rate
(lb/106 Btu)
0.10
0.20
0.0006
0.15
0.30
(a) 75% capacity factor.
(b) 70% scrubbing of 0.18% sulfur coal.
(c) New Source Performance Standard.
(d) Negligible.
20
67
131
0
99
269
50 2 0 400 600
169
329
1
246
673
674
1314
4
1348
2628
8
2022
3942
12
programs through the development of a state implementation plan acceptable to
the EPA. Table E.4 gives the National Ambient Air Quality Standards and
allowable PSD increments.
The PSD program is currently administered by the U.S. Environmental
Protection Agency (EPA). A PSD review will be triggered if emissions of any
pollutant are above 100 tons per year for coal-fired power plants or above 250
tons per year for the other power plants. This review entails a demonstration
of compliance with ambient air-quality standards, the employment of best
available control technology, a demonstration that allowable PSD increments of
pollutant concentrations (currently promulgated for so 2 and suspended
particles) will not be violated, and a discussion of the impact of pollutant
emissions on soils, vegetation, and visibility. It also generally includes a
full year's onsite monitoring of air-quality and meteorological conditions
prior to the issuance of a permit to construct.
E.6
TABLE E.2. Controlled Particulate Matter Emissions for Various Technologies
Technology
Steam Electric
Coal(b)
on(b)
Gas(c)
Wood(d)
Combustion Turbine
Oi 1
Gas(e)
Emission Rate
(lb/10 6Btu)
0.03
0.03
0.01
0.02
0.05
(a) 75% capacity factor.
(b) New Source Performance Standard.
(c) Typical.
Annual Emissions (tons/yr)(a)
Facility Size (MW)
20 50 200 400 600
20 49
20 49
7 16
131 329
46 125
197
197
66
394
394
131
591
591
197
(d) Assumes mechanical collection. Emissions may be reduced by 90%
using electrostatic precipitators or baghouse.
(e) Negligible.
In the near future, PSD control over other major pollutants, including NOx,
CO, oxidants, and hydrocarbons, will be promulgated. Obtaining a PSD permit
represents one of the largest single obstacles to constructing a major fuel-
burning facility.
Alaska has two permanent Class I areas in or near the Railbelt region,
Denali National Park and the pre-1980 areas of the Tuxedni Wildlife Refuge.
The new national parks and wildlife preserves have not been included in the
original designation, but the state may designate additional Class I areas in
the future. New major facilities located near Class I areas cannot cause a
violation of the PSD increment near a Class I area; thi~ requirement presents
a significant constraint to developing nearby facilities.
E.7
TABLE E.3. Controlled NOx Emissions for Various Technologies
Annual Emissions (tons/yr)(a)
Emission Rate
Technology { 1 b/106 Btu) 20
Steam Electric
Coal(b) 0.6 394
oil(b) 0.3 197
Gas(b) 0.2 131
Wood( c) 1.0 657
Combustion Turbine
Oil 0.59 530
Gas(d)
(a) 75% capacity factor.
(b) New Source Performance Standard.
(c) Probably significantly overstated.
(d) Comparable to oil.
Facilitl Size (MW}
50 200 400 600
986 3942 7884 11826
493 1971 3942 5913
329 1314 2628 3942
1643
1272
A potentially important aspect of the PSD program to developing electric
power generation in the Railbelt region is that Denali National Park (called
Mt. McKinley National Park prior to passage of the 1980 Alaska Lands Act) is
Class I, and it lies close to Alaska's only operating coal mine and the exist-
ing coal-fired electric generating unit (25 MWe) at Healy. Although the PSD
program does not affect existing units, an expanded coal-burning facility at
Healy would have to comply with Class I PSD increments for so 2 and TSP.
Decisions to permit increased air pollution near Class I areas can only be
made after careful evaluation of all the consequences of such a decision.
Furthermore, Congress required that Class I areas must be protected from
impairment of visibility resulting from manmade air pollution. The impact of
visibility requirements on Class I areas are not yet fully known.
In the Fairbanks and Anchorage areas, the levels of CO exceed the primary
National Ambient Air Quality Standards. The state regulatory agencies are
E.8
fT1 .
TABLE E.4. National Ambient Air-Quality Standards and Prevention of Significant Deterioration
Increments for Selected Air Pollutants
National Ambient Air
Quality Standard
Prevention of Significant
Deterioration Increments
Class I Class II
Pollutant 3 hr(a) 24 hr(a) Annual 3 hr 24 hr Annual 30 hr 24 hr Annual
Total Suspended
Particulate Matter
(~g;m3)
Sulfur giox ide
(~g/m )
None
uoo(b)
150(b)
26o(c)
6o(b) None
75(c)
so(d) 25
10
5
Nitroge~ Dioxide
(~g/m )
None None lOo(d) None None
Carbon Monoxide(e)
(mg/m3) None None None
(a)
~~~
(d)
Not be to exceeded more than once per year.
Secondary or welfare-protecting standard.
Annual geometric mean, advisory indicator of compliance.
Primary or health-protecting standard.
5 None 37
2 512 91
None None None
None None None
(e) Carbon monoxide primary ambient air q~ality standards are as follows: the value not to be
exceeded more than 1 hr/yr is 40 mg/m (may be changed t~ 29 mg;m3); the value not to be
exceeded more than one 8-hour period per year is 10 mg/m •
19
20
None
None
required to reduce CO emissions in these two airsheds to attain the standards.
This goal will be accomplished by requiring any new or modified major source
to install the lowest achievable emission rate for CO emissions and to obtain
offsets for the actual CO emissions. Consequently, the construction of a major
combustion facility in or near the nonattainment areas will entail the most
demanding pollution controls, as well as a lengthy and detailed regulatory
review.
COMPARISON OF PROJECT EMISSIONS
The comparison of fuel combustion technologies for their impacts on air
quality is determined by the anticipated rate of emissions of each pollutant.
Emission levels for the various technologies are presented in Tables E.l
through E.3. Estimated emissions from wood-fired boilers, although officially
published, are felt to be somewhat high, especially for so 2•
These tables were developed based on various assumptions. A 33% conver-
sion efficiency is assumed for steam-electric plants and a 25% conversion
efficiency for combustion turbines. For the power plant sizes provided in
the tables, emissions are directly proportional to the heat rate of a given
technology.
SITING STRATEGY
Based on information on emissions and regulations, several general con-
clusions can be drawn that bear on the siting of major fuel-burning facilities.
Coal or biomass-fired facilities should be easiest to locate if well away from
Class I areas. A minimum distance would probably be 20 miles, but each case
should be carefully analyzed to reliably choose a site. The forthcoming visi-
bility regulations may require a greater distance. Based on regulatory con-
straints, it would be preferable to site any of these facilities well away
from the nonattainment areas surrounding Anchorage and Fairbanks. In addition,
the major fuel burning facilities should be located away from large hills and
outside of narrow valleys or other topographically enclosed areas. Facilities
should be developed in open, well-ventilated sites whose atmospheric dispersion
conditions will contribute to minimizing impacts on air quality.
E.lO
Many acceptable sites should exist for coal-fired power plants in the
Beluga, Kenai, Susitna, Nenana, and Glennallen areas, near coal fields
(McNaughton 1979). Since Alaska coal is generally low in sulfur content, the
siting constraints will be less stringent than those normally encountered in
the eastern United States. Smaller biomass-fired plants could generally be
sited in broad valleys as well. Generally, emissions from natural gas and
fuel oil combustion are below the threshold of significance, and the siting of
such facilities is therefore less critical. If high-sulfur residual oils are
used, however, siting will become a more important factor.
E.ll
APPENDIX F
AQUATIC ECOLOGY IMPACTS FROM
STEAM-CYCLE POWER PLANTS
APPENDIX F
AQUATIC ECOLOGY IMPACTS FROM STEAM-CYCLE POWER PLANTS
The Railbelt region encompasses many marine and freshwater habitats that
provide spawning, rearing, and migration paths for a wide variety of com-
mercially and recreationally important species. Several of these species are
listed in Table F.l. These habitats may be impacted by steam-electric plant
construction and operation in several major ways, including construction area
runoff, water withdrawal for power plant use, and process water discharge. In
addition, air emissions (e.g., so 2 and NOx) from fossil-fuel plants can
impact the aquatic ecosystem through the creation of acid rainfall. The
degree of all potential impacts will depend upon the size, location, water
requirements and operating characteristics of the plant. Unless a specific
facility type is identified in the following sections, this discussion gen-
erally applies to all steam-cycle facilities.
CONSTRUCTION AREA RUNOFF
Construction area runoff can increase turbidity and siltation in receiv-
ing waters adjacent to site construction. Siltation in freshwater habitats
can eliminate fish spawning areas by inundating gravels with fine sediment
that smothers eggs and embryos. It can also block emergence of young fish
from the gravel (especially salmonids). Similarly, silt can smother benthic
organisms, alter their habitat, and reduce benthic primary production by
decreasing light penetration. Species of major concern in the Railbelt region
include salmonids, burbot, sheefish, and whitefish. Silt-laden runoff, if
severe, may also clog or damage the gills of these organisms.
If silt reaches the marine environment, especially areas where turbidity
is naturally lower (e.g., outer Cook Inlet or Prince William Sound), it could
smother benthic organisms and reduce benthic and pelagic primary production.
Potentially affected organisms in these areas include the marine vertebrates
and invertebrates listed in Table F.l. Especially susceptible are species
F.l
TABLE F.l. Some Commercially and Recreationally Important
Aquatic Species in the Alaska Railbelt Region
Fresh Water Organisms
Salmon ids
Arctic grayling (Thylmallus arcticus)
Lake trout (Salvelinus namaycush)
White fish (Coregonus ~-)
Inconnu (Stenodus leuc1chtys)
Other fish
Burbot (Lata lata)
Northern pike (Esox lucius)
Marine Organisms
Fish
Herring (Clupea harengus pallasi)
Halibut (Hippogossus stenolepis)
Invertebrates
Crab
Tanner (Chionectes 2£E.)
King (Paralithodes ~.)
Dungeness (Cancer magister)
Shrimp
Pink (Pandalus borealis)
Humpy (Pandalus goniurus)
Coonstrip (Pandalus hypsinotus)
Spot (Pandalus latyceros}
Sidestrip Pandalopsis dispar)
Bivalves
Razor clam (Siliqua patula)
Pacific scallope (Patinopecten caurinus)
Anadromous Fish
Chinook salmon (Oncorhynchus tshawytscha)
Chum salmon (Oncorhynchus keta}
Coho salmon (Oncorhynchus kisutch)
Pink salmon (Oncorhynchus gorbuscha)
Sockeye salmon (Onchrohynchus nerka)
Steelhead/rainbow trout (Salmo-galrdneri)
Cutthroat trout (Salmo clarkT)
Arctic char (SalvellnUs alpinus)
Colly vardin (Salvelinus malma)
Smelt (Thaleichthys pacifTCUS)
Source: Alaska Department of Fish and Game 1978.
F.2
inhabiting areas of low current and wave energy near the mouth of silt-laden
rivers. In these low-energy environments suspended solids are ultimately
deposited. Clam beds, rearing habitats for juvenile fish, and spawn of
Pacific herring would be especially vulnerable.
The impact from construction runoff would depend on the effectiveness of
erosion control measures, location and size of the plant, and the existing
soils. Potential problems to both fresh and marine waters can be minimized by
implementing appropriate site runoff and erosion control measures, including
runoff collection and treatment systems, soil stabilization techniques and
scheduling of earthmoving activities to coincide with seasons of low
precipitation.
WATER WITHDRAWAL EFFECTS
The principal impacts of water withdrawal include entrainment, impinge-
ment and reduction in downstream flow.
Entrainment and Impingement
Intake structures associated with water withdrawal have the potential to
impinge or entrain aquatic organisms. Impingement occurs when aquatic biota
are caught against screens and grates placed in intakes to keep organisms out
of the cooling system. Impingement of organisms on inadequately designed
screening or diversion structures can cause mortalities due to abrasion,
increased predation, or exhaustion. Entrainment occurs when aquatic biota are
caught in a cooling system•s intake water. Entrainment can acutely and
chronically affect organisms by thermal shock, pressure change, mechanical
damage, or toxic chemicals added to the recirculating cooling water. Most
organisms identified on Table F.l can affected by these processes at some
stage in their life cycle. Larvae of fish, crabs and clams are particularly
susceptible to entrainment, whereas larger forms such as juvenile salmonids
are susceptible to impingement.
Adequately designed screening equipment and proper approach velocities at
the intake structure will reduce the number of organisms impinged or
entrained. Locating intakes away from migratory routes or holding areas of
F.3
important species will also help reduce these impacts. The use of subsurface
water sources, like Ranney wells, would eliminate impingement and entrainment
of fresh-water and marine organisms.
Streamflow Reduction
Withdrawal of water in sufficient amounts from streams can also alter
flow patterns and reduce aquatic habitat downstream. Process water discharged
to the same body of water may partially compensate for withdrawals.
PROCESS WATER DISCHARGES
The characteristics of the intake water are altered during passage
through the plant. Changes include increases in temperature, and addition of
potentially toxic chemicals and corrosion products from the cooling water
system. Depending on the temperature and chemical composition of the process
water discharges, organisms may be attracted to the vicinity of the discharge
structure, thus increasing the mortality of organisms, or causing long-term
changes in the aquatic ecosystem.
Thermal Shock
Warm water discharges may attract aquatic organisms to the vicinity of
the outfall. This attraction may interfere with normal behavior patterns
(migration, feeding, etc.). Of particular concern in Alaska would be a situ-
ation in which marine organisms are attracted and become acclimated to a heat-
ed discharge with the potential for flow reduction or interruption. The
resulting rapid change to ambient levels can result in severe thermal shock
that can be lethal. Fish can also be entrained in the mixing zone of a power
plant's effluent, and if this effluent is hot enough, the fish can experience
thermal shock. Heated effluents may also alter community structure and rate
of species succession, depending upon the respective temperatures and flows of
the effluent and receiving water.
Chemical Changes in the Process Water
The chemical composition of the intake water is altered during its pas-
sage through the power plant. Changes in the composition generally depend on
the specific steam cycle and the power plant's capacity (see Appendix D), but
F.4
general alterations that occur in most plants are as follows: 1) addition of
chemicals (e.g., chlorine) to control biological fouling and deposition of
materials on cooling system components; 2) concentration of impurities in the
intake water during cooling system recirculation; and 3) incorporation of cor-
rosion products from structural components of the cooling system. Other char-
acteristic effects of certain steam cycles include lowered pH, increased bio-
chemical oxygen demand, and discharge of radionuclides (nuclear facilities)
and petroleum products.
One of these changes, such as the addition of heavy metals and radio-
nuclides, could have negative effects far from the site of their initial dis-
charge, whereas others like low pH and increased BOD will have the greatest
impact close to the discharge. Some constituents would have less impact on
marine systems than on fresh-water systems due to the buffering and chemical
complexing capacity of saline waters. High concentrations of dissolved
solids, which occur to some extent in most power plants but can be especially
high in geothermal plants, would have little effect on the marine environment,
which already posseses much higher concentrations of dissolved solids than
fresh water. Most other changes could have negative effects on both the
marine and fresh-water environment, but the marine environment•s much larger
volume diminishes the probability of adverse effect because of dilution.
Proper siting, design, and location of discharge structures, discharge
pretreatment (e.g., dechlorination with sulfur dioxide), use of cooling towers
or other heat dissipating systems, and cooling system optimization can reduce
or minimize effects from process water discharges. Also, siting on large
receiving water systems (e.g., the Copper or Susitna River, Cook Inlet) will
reduce impacts. Futhermore, if an area is highly sensitive, a "zero dis-
charge" system design can be implemented.
ACID RAINFALL
Emissions of SOx may occur from combustion of fuels such as many coals
and petroleum products containing sulfur. These emissions may result in the
production of acid rainfall. This production can cuase significant changes in
the pH level of receiving water bodies, which, if severe, can reduce or
F.5
eliminate certain species. The severity depends on the amount of acid rain,
the size and buffering capacity of the receiving water, the chemical com-
position of the soil, and the sensitivity of the aquatic organisms to pH
change. Acid rain would not affect the marine environment because of its
great buffering capacity. Most fresh-water systems in the Railbelt region
appear well buffered (see Table 0.4, Appendix D) and significant detrimental
impacts would not be expected. Generally, the potential for production of
acid rainfall depends upon plant size, sulfur contact of the fuel, SOx con-
trol systems and meteorological patterns. SO emissions can be reduced by X
incorporating SO control facilities and selecting low sulfur control fuel. X
Alaskan coals are of very low sulfur content (~0.25%).
F.6
APPENDIX G
TERRESTRIAL ECOLOGY IMPACTS FROM STEAM-CYCLE POWER PLANTS
APPENDIX G
TERRESTRIAL ECOLOGY IMPACTS FROM STEAM-CYCLE POWER PLANTS
Impacts on terrestrial biota resulting from steam-cycle power plants will
vary according to the type, size, and location of a specific plant. Plants
requiring large land areas in remote or sensitive locations will generally
exert the greatest impacts on vegetation and animals. Most impacts, however,
can usually be minimized through careful power plant siting.
In general, habitat loss represents the most significant impact on wild-
life. Other terrestrial impacts include those resulting from air emissions,
fuel and waste storage areas, and human intrusions. Approximate land area
requirements for various types of steam-cycle facilities are compared in
Tab 1 e G .1.
TABLE G.1. Approximate Land Requirements of Steam-Cycle Power Plants
Land Area
Electrical Per Unit
Steam-Cycle Generating Land Area (acres) Capacity
Power P 1 ants CaQaC it_y (MW) (all facilities) {acres}
Natural-Gas-Fired 20 to 600 8 to 670 0.4-1.1
Biomass-Fired 5 to 60 10 to 50 0.8-2.0
Natural-Gas-Fired 10 to 200 3 to 13 0.3
Distillate-Fired 10 to 200 4 to 20 0.4
Nuclear 800 to 1,200 100 to 150 0.1
Geothermal 10 5 (excluding we 11 s) 0.5
HABITAT LOSS
While any steam-cycle facility will cause a reduction or alteration of
habitat, the most significant impacts typically result from coal, biomass, and
nuclear plants because these technologies generally require the largest land
areas for development. In the Railbelt region, probable watersheds suitable
G.1
for development of steam-cycle facilities contain seasonal ranges of moose,
caribou, brown and black bear, mountain goat, and Dall sheep (Table G.2).
Disturbance of these range areas will lower the carrying capacity of the land
to support these species. Moreover, power plant development, if in remote
areas, can adversely affect certain wildlife sensitive to disturbance, such as
Dall sheep and brown bear. Wildlife impacts, however, can be minimized by
siting plants outside of important wildlife areas. This form of mitigation
will be most difficult to accomplish with geothermal plants and, in some
cases, with biomass and coal-fired plants, which may need to be sited at the
fuel resource sites to be economically viable.
AIR EMISSION EFFECTS
The release of toxic chemicals into the air can negatively affect vege-
tation and, subsequently, wildlife. Sulfur and nitrogen oxides (SOx and
NOx) are the major gaseous pollutants; of these, so 2 has the greatest
potential for affecting the terrestrial biota. The mechanism of so 2 injury
to plants is largely physiological. Damage results when plant tissues accumu-
late so 2 and produce sulfurous acids and sulfate salts faster than these
compounds can be oxidized and assimilated. At this point, sulfur compound
concentrations become toxic, resulting in chlorophyll destruction and cell
collapse. Plants in the Railbelt region that may be sensitive to so 2
include lichens. These plants are often an important food for wildlife,
especially for caribou.
Acid rain, which can be formed from SOx and NOx emitted from fossil
fuel and biomass plants, can further affect the terrestrial biota. This
phenomenon can modify the chemical properties of soils and affect the aerial
portions of plants, which intercept precipitation. Some of the impacts on
soils and vegetation known to result from acid rain include the following:
1) decreased aerial growth; 2) direct injury to foliage of coniferous and
deciduous trees; 3) changes in the physiology of foliar organs; 3) alteration
of root functions; 5) poorer germination of seeds; 6) accelerated leaching of
nutrients from foliage, humus, and soils; and 7) inhibition or stimulation of
plant disease (Dvorak 1978). The degree to which soils are changed will
G.2
TABLE G.2. Possible Watersheds Associated with the Development of Steam-Cycle Power Plants
in the Railbelt Region and Prominent Wildlife Found at These Locations
Watershed
Energy Prince
Technology Cook Wi 11 i am Sus itna Matanuska Copper Gulkana Tanana Nenana Chen a
SQeC i es Inlet Sound River River River River River River River
Energ~ Technolog~
Coal-Fired X (a) X X X X X X
Oil-Fired X X X X
Gas-Fired X X X X
Biomass-Fired X X X X
Nuclear X X X X X X
Geothermal X X X X X
Species(b)
G> Moose X X X X X X X X X
w Caribou X X X X X X
Bison X
Mountain Goat X X X
Dall Sheep X X X X
Black Bear X X X X
Grizzly/
Brown Bear X X X
Sitka Deer X X
Marine Mammal X X X X
Waterfowl X X X X X X X X X
Colonial
Nesting Birds X
(a) X signifies potential power plant development and wildlife species/group present.
(b) Wildlife information was taken from Alaska Regional Profiles 1974. (Selkregg 1974}
vary with the buffering capacity of the soils. Impacts on wildlife will
largely be indirect and result from modification of habitat.
In addition to gaseous emissions, particles and associated toxic trace
elements may affect soils, plants, and wildlife. In steam-cycle plants, these
substances are released in stack emissions and cooling tower drift. While
mitigative measures are generally employed, small particles (<1 ~m) are dif-
ficult to control. Small particles can cause greater impacts on soils,
plants, and wildlife than larger particles because they contain a greater
fraction of potentially toxic trace elements (e.g., mercury, selenium,
arsenic, bromine, chlorine, fluorine and others) in a state more readily
available for chemical interaction (Dvorak 1978).
Trace elements will primarily enter the soil through direct deposition,
plant litter decomposition, and the washing of particles from plant materials
and other surfaces by precipitation. The impacts of these elements on soils
are difficult to predict, but soils already at the tolerance limits of exist-
ing trace element concentrations will generally experience more severe
effects. Conversely, soils deficient in various trace elements (i.e., copper,
molybdenum, boron, zinc, and manganese) may benefit from their addition.
Particles and trace elements can also affect plants through direct injury
to aerial plant parts and through material uptake and accumulation. Stomates
(small openings in leaf surfaces used for gas exchange) may be blocked by
particles, which can interfere with the diffusion of co 2, o2, and water
vapor between the leaf air spaces and air. In addition, particles may
adversely affect plant absorption and reflectance of incident solar radia-
tion. Plant uptake of trace elements may result in reduced growth rate since
many trace elements affect various metabolic processes and enzymatic
reactions, such as photosynthesis and respiration. Trace element uptake will
vary with plant species, element, and many environmental conditions.
EFFECTS OF FUEL AND WASTE PRODUCT STORAGE
Storage of fuel and waste products from steam-cycle plants can have
potentially important impacts on terrestrial biota. Uncontrolled runoff from
these materials can be toxic to soils and vegetation. Spoil piles and fuel
G.4
piles require large land areas, which result in the loss of vegetation and
wildlife habitat. Wildlife use of waste ponds as drinking water sources can
also have adverse effects if concentrations of various elements reach toxic
limits. Windblown dust from storage piles, if deposited on vegetation, may
block leaf stomates, which may lower photosynthetic rates and may provide a
pathway for ingestion of particles by herbivores. Exposure of vegetation to
dust over long time periods could change vegetation community structure.
These impacts, however, can be minimized in the Railbelt region by designing
storage facilities to prevent runoff, seepage, dust, and access by wildlife.
HUMAN INTRUSION EFFECTS
Wildlife populations can be adversely affected by increased human
activity resulting from power plant construction and operation. Wildlife pop-
ulations in areas adjacent to power plant sites or access roads may be sub-
jected to greater hunting pressure, poaching, road kills, and other forms of
human disturbance. This situation may be particularly severe for power plants
located in isolated areas. Wildlife populations in these areas are not only
more sensitive to disturbance but also more vulnerable to exploitation. Of
the various types of steam-cycle plants, human disturbance is probably great-
est with geothermal plants because these are more likely to be sited in iso-
lated locations near their fuel sources. Power plants sited in remote areas
may require many miles of new road construction resulting in an even greater
loss of habitat.
Noise associated with power plant construction and operation is a
by-product of human intrusion; however, the severity of this disturbance is
uncertain. Potential impacts from noise can be related to hearing loss and
stress in animals. Noise can also interfere with the auditory cues for com-
munication among certain wildlife. Auditory cues can include those for ter-
ritorial defense, mate attraction, alarm calls, and nesting behavior of pas-
serine birds. Stress on wildlife will be largely physiological. Terrestrial
impacts from noise in the Railbelt region can largely be avoided through
installation of proper noise suppression equipment at the power plants.
G.5
COLLISION EFFECTS
Another wildlife impact results from birds colliding with the cooling
towers for waste heat rejection systems. The significance of this impact is
highly dependent on cooling tower design and location in relation to daily and
seasonal migratory routes. Locations subject to frequent fogging may also
increase the severity of this impact. Bird collision, however, can be miti-
gated through proper siting. In the Railbelt region, major migratory bird
corridors occur within the Susitna, Copper, Nenana, and Gulkana River Basins,
as well as throughout Cook Inlet and Prince William Sound.
G.6
APPENDIX H
SOCIOECONOMIC IMPACTS FROM ENERGY
DEVELOPMENT IN THE RAILBELT REGION
APPENDIX H
SOCIOECONOMIC IMPACTS FROM ENERGY
DEVELOPMENT IN THE RAILBELT REGION
Two types of decisions made during the energy development process will
result in community and regional impacts in the Railbelt region. First, the
decision to site a facility at a particular location will affect the people
living in that area. Secondly, the specific technology adopted for generating
electric power will affect both the community and the larger region defined as
the Railbelt. These decisions can result in both beneficial and adverse
socioeconomic impacts. Positive impacts will include employment opportunities
and revenues generated by the project, which will stimulate growth of the
local economy in the short term and, in the long term will contribute to the
expansion of the regional economy. Adverse impacts include the in-migration
of temporary workers to a community, potentially causing a boom/bust cycle.
The primary effect of a boom/bust cycle is a temporarily expanded pop-
ulation with insufficient infrastructure to support the new demands. The
in-migration of workers to a community will have an impact on land avail-
ability, housing supply, commercial establishments, electric energy avail-
ability, roads, public services such as schools, hospitals, and police force,
and public facilities such as water supply and domestic waste treatment
facilities. The magnitude of these impacts will depend on the existing popu-
lation of the area, the existing infrastructures, the size of the construction
work force, and the duration of the construction period. The bust occurs with
the out-migration of a large construction work force, which leaves the com-
munity with underutilized housing and facilities. Development of a power
plant, therefore, has the potential to affect the community at both the begin-
ning and end of the construction phase.
Two indicators of a boom/bust cycle have been developed. Since the per-
manent staff required to operate a plant is typically much smaller than the
construction labor force, the population will decrease dramatically following
H.l
construction. A measure of the potential for a bust, independent of community
size, can be inferred from the ratio of construction to operating personnel.
The probable magnitude of the boom/bust cycle can be determined by relating
the size of the work force to community size. These two measures are provided
for each technology in the attribute matrix.
The secondary effect of power plant construction is its impact on the
growth of the local and regional economies. The increased number of permanent
residents will usually result in new businesses and jobs to the community.
This effect may be perceived as either positive or negative, depending on
individual points of view. The expenditures on capital and labor during both
the construction and operation phases will increase regional income as well.
The effect on regional income would be caused by the expansion of construction
firms and related industries. A parameter of expansion of the regional
economy is flow of expenditures into the region, which can be measured in
terms of a percentage of plant-related expenditures.
COMMUNITY IMPACTS
The most pronounced impact on the community is the boom/bust cycle. The
potential for a boom/bust cycle is a function of the existing population of
the area and characteristics of the regional labor market. Existing pop-
ulation size reflects the ability of the community to meet new demands for
housing, roads, and public and community services. Characteristics of the
labor market include the size of the work force, skills, and unemployed
persons available for work.
The 1980 Railbelt population was 284,822 and comprised 72% of the State's
400,142 residents (U.S. Bureau of Census 1981). The population of boroughs
and census areas within the Railbelt is presented in Table H.1. Anchorage is
the Railbelt's major population center; remaining population is distributed
widely in small cities and towns among several regions including the Fairbanks
North Star Borough, Kenai Peninsula Borough, Matanuska-Susistna Borough, and
the Valdez-Cordova area. With the exception of Fairbanks, all communities
having populations exceeding 1,000 persons are located in the Anchorage area,
on the Kenai Peninsula, and along the southern coast. The rail corridor
H.2
TABLE H.1. Population of the Railbelt's Incorporated Areas (1980)
Area Po~ulation Percent
Anchorage 173,992 61
Fairbanks North Star Borough 53,610 19
Kenai Peninsula Borough 25,072 9
Matanuska-Susitna Borough 17,938 6
Valdez-Cordova Census Area 8,546 3
Southeast Fairbanks Census Area 5,664 2 -
Total 284,822 100
Source: U.S. Bureau of Census 1981.
between Wasilla and Fairbanks is characterized by a string of communities with
population sizes of less than 500 persons.
The population of the southern Railbelt has expanded significantly during
the 1970-1980 decade; the central and northern regions of the Railbelt have
grown at a slower rate. The Matanuska-Susitna Borough, and Wasilla in parti-
cular, have seen rapid growth over the last decade. Since 1970, the popu-
lation of that area has increased by 64% from 6,500 to 17,938 persons. This
significant rate of growth is explained by the proximity of the southern part
of the region to the Anchorage labor market. The Kenai Peninsula has also
grown rapidly during the last decade (37%), as has Anchorage itself (27%).
The reason for the large increase in population in the southern portion
of the Railbelt has been the expanding state economy, which has attracted
people from the lower 48 states. During the 1975-79 period, employment oppor-
tunities were greatest in Anchorage, Valdez-Chitina-Whittier, and the Cordova-
McCarthy areas where unemployment rates were lower than the state average.
Unemployment has been higher than the state average in other areas of the
Railbelt, particularly in the Matanuska-Susitna Borough, Fairbanks area, and
the Kenai Peninsula.
H.3
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Faitbank.:S., -a b·Oom 1.s· le-ss 11~<:1Yt s in e~ m-a11y. w pJ'~erS' cap·l·a ~eolllii1ute ttl tne site:
t:,.;om F·a'iro~n~<s.. t he imp act Qt p:l'o.Je.t t construc:tign ~~1·1! .al:$Ji be mit fg:ated .. by
the FJ.'ir)?.an k'~l ·s tz.ea:t?1'e-1-af>pr lll~r.k·et and ll·fi'Jll. uneroplo;Yroe.nt. l"<tt~,
A 'boom/~l,ls.t, t!ycl.e-w~uH be le ~: j:i r.t)lr.;;b le 1n t:h~ AncltoN.ge ·a!ld Lipper ~,en·a 1
ar~ac". La bor )'e qu ;·,-e(Tl er\t~, for pgyrer· ·p T ~·n t. c oo~trtJc t.-i on shQu 1'1:1 be me t .bY' the
Anc·ho\'qge l a bnr l)lar·k:et a n~. may e~>~en attr:act tM ~mellirll:a:ye~ la:apr poo 1 in tlie
,upper l<en a i P'l!rl tn·sula. In 1979 ·th~ U~lt()pa t~ortQ 1 ~l'ass.tflC.~thm :e.f craft wor·k-
eJ"'S ,, "~erator!>,. Artd laba:~"'~r"S' represente_o 32'11! \'If the: la,bp r far~e statJl.wiee.
rflis r.ate_goi'Y inclll,de-s ·mairJ~eil~h.t;e r:~ll<t~t er:>S; carpeot.ers,, h'e'a.vy e.ql,!·tpment
QP.ef-at-(l?s, afld tr.Ltck irlr'f\1.e"$ •. i)mOII 'fl otf\er q~QI.l,P at-i qn s , Erotl r,o.YJlr~"t in ti1i!se
TABLE H.2. Magnitude of Impacts from Power Plant Construction
Population
Increase
1000+
500-999
250-499
100-249
50-99
0-49
KEY:
as a Ratio of Population Increase to Community Size
Very Small
( 'V500)
Severe
Severe
Severe
Severe
Significant
Moderate
Sma 11
Community Size
Intermediate
(500-1,000} (1,000-5,000)
Severe Severe
Severe Significant
Severe Moderate-
Significant
Significant Moderate-
Significant
Moderate Moderate
Minor-Minor
Moderate
Ratio of
Population Increase
Magnitude of Impact to Community Size
Minor
Moderate
Significant
Severe
0.01 or less
0.02 -0.10
0.11 -0.39
0. 40 or greater
Large Very Large
(Fairbanks} {Anchorage)
Moderate Minor
Moderate Minor
Moderate Minor
Minor Minor
Minor Minor
Minor Minor
occupations is predicted to increase by 3,550 per year through 1985. Most of
these jobs are expected to be located in the Anchorage labor market area,
where over 50% of the firms specializing in heavy construction are located
(Alaska Department of Labor 1979).
Rapid growth due to power plant construction will be most dramatic in the
Railbelt's interior region, which is delineated by the railroad from Wasilla
to Fairbanks, the Alaska Highway from Fairbanks to Tok, and the Glenn Highway
from Tok to Palmer. This vast area of the Railbelt is characterized by few
H.5
and very small towns that would have difficulty in meeting the demands created
by the influx of workers to construct moderate to large-scale power plants.
The local economy will grow in the long term if a population bust does
not occur, which is more likely when construction periods are long and new job
opportunities develop during that time. The creation of new businesses and
jobs is more likely to arise in communities with a diverse economic base
rather than in those with a homogeneous economic base. The size of the opera-
ting and maintenance work force, although usually substantially smaller than
the construction work force, is another factor contributing to the permanent
population.
REGIONAL IMPACTS
The Railbelt region as a whole should not be affected by the local
boom/bust cycles resulting from power plant construction. It will, however,
be affected by the project expenditures that are made within the region.
The regional economy may be stimulated by power plant construction
through expenditures on equipment, supplies, and fuel, direct project employ-
ment, and through indirect employment arising from expenditures on goods and
services supplied to the project. Indirect employment will result from pro-
jects requiring a large work force over a long period of time.
The degree of economic growth is a function of the capital spent in the
region as opposed to necessary expenditures that must be made outside of the
Railbelt. The methodology used here for estimating the flow of capital into
the Railbelt for each technology is based on a standard code of accounts used
to calculate power plant costs. This code of accounts has been simplified to
three general categories that capture all costs associated with power plant
construction. The assumptions made regarding the flow of capital for each
category are presented in Table H.3. The proportion of expenditures allocated
to the site improvement, equipment, and labor categories will vary with each
technology and is presented in the detailed description of the individual
technology.
H.6
TABLE H.3. Flow of Capital Expenditures
Percent of Percent of
Expenditures Expenditures
Spent Outside Spent Within
Category Subcategory the Railbelt the Railbelt
Site Improvements Land 15 85
Grading
Foundation
Concrete
Equipment Mechanc i a 1 100 0
Instrumentation
E 1 ectri ca 1
Piping
Labor Supervisory 20 (a) 80
Engineering
Skilled Laborers
(a) Expenditures on labor for a nuclear power plant would be higher since
highly skilled workers are required.
The extent to which project construction expenditures can be contained
within the region will be largely determined by the proportion of labor,
equipment, and site improvements required for each technology. Virtually all
high-technology equipment, heavy machinery, and electronic components would be
purchased outside of Alaska. Most construction materials, including sand and
gravel aggregate, as well as tools, light machinery, and supplies, would be
purchased within the Railbelt. Cement and rebar, estimated to average
approximately 15% of site improvement expenditures, would be purchased outside
of Alaska. Construction supervisory and engineering personnel are normally
provided by the project developers, whereas skilled labor may be provided
fully from the local work force. For estimation purposes, 20% of the work
force was assumed to be derived from outside Alaska, whereas 80% would be
Alaska residents. In compliance with Alaska State labor laws, 60% of the
labor force must be Alaska residents, if they are found qualified.
H.7
Capital-intensive technologies that require a small or highly skilled
labor force will have a less beneficial effect on the regional economy. Con-
versely, labor-intensive projects (e.g., hydropower and tidal power) have the
potential to positively affect the regional economy, particularly through
direct employment.
Expenditures on operation and maintenance will be less significant than
the expenditures on capital and labor for project construction. Some tech-
nologies, such as combustion turbine, wind electric, solar electric, fuel
cells, diesel, and hydroelectric, can be operated by a small work force on a
part-time basis. The other technologies do not require a very large operating
and maintenance staff. Therefore, once construction is completed, plant
operation will have little effect on the regional economy through direct
employment.
The allocation of operating and maintenance expenditures have been calcu-
lated for each generating technology based on a set of assumptions. One hun-
dred percent of operating and maintenance personnel is assumed to be derived
from the Alaska labor pool; 20% of supplies and other materials would origi-
nate in Alaska; and 50% of outside maintenance costs would be for the purchase
of goods and services in Alaska.
H.8
APPENDIX I
WASTE HEAT REJECTION SYSTEMS
APPENDIX I
WASTE HEAT REJECTION SYSTEMS
Cooling water is required in all steam-cycle plants to condense the spent
steam to obtain increased pressure differential across the turbine and to cool
auxiliary system equipment such as seals, bearings, and pumps. As an order of
magnitude estimate, the quantity of condenser cooling water is approximately
1 cfs/MW of capacity. Auxiliary cooling systems may require an additional
0.01 to 0.1 cfs/MW. Appendix D presents estimates of the cooling water
requirements required by each of the technologies discussed in this study. In
general, cooling systems can be characterized as either once-through or
recirculating (closed cycle).
ONCE-THROUGH SYSTEM
In once-through system the total water requirement for the condenser is
pumped from the source through the condenser and is then discharged into the
receiving water body. The heat sink for this type of system is the receiving
water body. In the Railbelt area, once-through cooling water systems will
probably be considered only at coastal locations, if they are not precluded by
environmental or regulatory constraints.
RECIRCULATING SYSTEMS
In a recirculating cooling water system the atmosphere is used as a heat
sink for waste heat rejection. Several types of heat dissipation systems are
available for use, including lakes, spray ponds, wet natural draft cooling
towers, wet mechanical draft cooling towers, dry cooling towers and wet/dry
cooling towers. Figure 1.1 is a generalized schematic diagram of a
recirculating waste heat rejection system.
Cooling Ponds and Lakes
A cooling pond operates similarly to once-through cooling, unless the
body of water used is largely isolated from natural waters. Heat is
1.1
EVAPORATION
DRIFT
INTAKE MAKEUP
STRUCTURE
WATER HEAT
POWER
1-i Dl SSIPATION CONDENSER
N SOURCE PLANT
SYSTEM
Dl SCHARGE
CHEMICAL STRUCTURE BLOW DOWN TREATMENT BlOC I DE
TREATMENT
FIGURE 1.1. Typical Recirculating Haste Heat Rejection System
transferred from the heated water in the cooling pond by radiation, conduction
and evaporation before the water is recirculated from the pond to the
condenser inlet. Area requirements for dissipation of waste heat from a
cooling lake or pond are about 1 to 3 acres per MWe. Water vapor rising from
the surface of the pond will, in cool weather, condense to form fog.
Additional land is required to eliminate the offsite effects of fog. A
typical buffer zone of 1,000 to 1,500 ft is normally maintained.
During freezing conditions, fog will form layers of ice on nearby
structures, roads, and other surfaces. The fog plumes also tend to be long
during extremely cold conditions. The cooling pond is a proven, effective and
economical heat sink in areas where sufficient level land can be purchased at
reasonable cost. However, the Railbelt•s cold weather will cause these
localized icing conditions.
Spray Ponds and Spray Canals
Land requirements of cooling lakes can be reduced by a factor of up to 20
by sprays. As with cooling ponds, however, a buffer zone of about 1,000 to
1,500 feet is needed to confine fogging and drift effects to the site. In a
spray pond, waste heat is dissipated to the atmosphere by sensible and latent
(evaporative) heat transfer. The circulating water is cooled by spraying it
via floating spray modules. Spray ponds are similar to cooling ponds in that
their cooling effectiveness depends upon local temperature, relative humidity
and wind conditions.
To maximize cooling by reducing recirculation of air between sprays and
to minimize fogging, spray modules are generally placed in a long meandering
canal. The efficiency and drift loss from spray modules are a function of the
spray height and spray drop size, which are a function of the design of the
spray pump system. At higher pressures, the drops become very fine. Although
this results in high heat transfer, the finer drops can also be transported
readily by the wind, causing more local fogging in cooler months.
Spray ponds could find application in the coastal, maritime climate areas
of the Railbelt region. A decision regarding their use would be based upon
comparative cooling efficiency cost and problems resulting from potential
fogging and icing.
!.3
Cooling Towers
Two basic types of cooling towers exist: the wet tower that carries away
heat by evaporation and sensible heat transfer, and the dry tower that relies
on sensible heat transfer alone and, in principle, functions like an
automobile radiator.
Wet Cooling Towers
In wet cooling towers, about 75% of the average annual heat transfer is
due to evaporation, and 25% due to sensible heat transfer. The fraction due
to evaporation varies with weather conditions; values of 60% in winter and 90%
in summer are typical.
Makeup water is provided to wet cooling towers both to replenish water
lost through evaporation and drift and to compensate for water lost through
system blowdown. Periodic or continuous system blowdown is required to
control the concentration of dissolved solids in the recirculating cooling
water. As evaporation occurs, the natural salts in the cooling water become
concentrated. To prevent buildup and deposition on the components of the
system, those salts are continuously returned to the source of cooling water
supply as blowdown or are recycled to other water uses within the plant.
Wet cooling towers can be designed as counterflow or crossflow towers.
Counterflow towers maximize the air-water heat transfer time, thereby
resulting in a thermally more efficient tower. Crossflow towers offer less
resistance to air flow and therefore result in lower energy consumption for
mechanical draft cooling towers.
The size of the cooling tower will depend upon certain design parameters,
such as the cooling range (the decrease in temperature of the water passing
through the tower), approach to wet-bulb temperature (difference in
temperature between the water leaving the tower and the ambient wet-bulb
temperature), and the amount of waste heat to be dissipated. Typically,
evaporation of one pound of water will transfer about 1,000 Btus to the
atmosphere. Wet towers may be of natural draft or mechanical draft design.
!.4
Natural Draft Cooling Towers
A wet, natural draft cooling tower consists of the familiar large
reinforced concrete chimney (Figure 1.2) that induces an upward flow of air
through the falling drops of the water to be cooled. The chimney, or shell,
is hyperbolic in shape to decrease resistance to air flow. The shell is
characteristically built to heights of 400 to 600 feet. The condenser cooling
water is sprayed into baffles, or fill material, in the lower part of the
tower, where the water is cooled by evaporative and conductive heat transfer
UPPER
STIFFENING
BEAM
VOID
HOT -WATER
Dl STRI BUTION
SYSTEM
FILL
AIR AND WATER VAPOR OUT
REINFORCED
.....;..--CONCRETE
SHELL
HOT-WATER RISERS
COLD-WATER COLLECTING BAS IN
FIGURE 1.2. A Natural Draft Cooling Tower
I.S
to the air. The differential density between the heated air inside the tower
and the air outside creates the natural draft; the warm, vapor-laden plume
will usually continue to rise for some distance after leaving the top of the
tower because of its momentum and buoyancy.
Natural draft towers have several advantages over mechanical draft
units: operating costs are lower since fans are not needed to move the air,
noise levels are relatively low, and the discharge height above the terrain
greatly reduces the possibilities of ground-level drift deposition, fogs, and
icing problems. Major disadvantages include relatively high capital costs and
aesthetic intrusion, since the large structures and visible plumes tend to
dominate the surroundings. The aesthetic impact of the plume is reduced in
normally cloudy areas, such as the coastal areas, because the plume tends to
blend into the background cloud cover.
Natural draft towers tend to operate most effectively in cool, humid
climates, however. A relatively new design, the fan-assisted natural draft
cooling tower, uses fans to assist the natural airflow, increasing the
efficiency of heat dissipation. The cost of operation and construction is
somewhat higher for this design. Drift rates are slightly higher with the
fan-assisted systems, but the potential for downwash, fogging, and icing is
the same as that for other natural draft systems. Natural draft towers could
operate efficiently in the Railbelt region, although unacceptable fogging or
icing problems may result.
Mechanical Draft Cooling Towers
In mechanical draft towers, fans are used to pull air through the fill
section. Mechanical draft towers are typically of modular construction.
Figure !.3 shows a cross section of a typical cell. The cells may be arranged
in rows or in circular configuration.
Mechanical draft towers have been used for several decades for power
plant cooling and are proven, reliable, and economical heat sinks. They have
several advantages when compared to natural draft units, including lower
capital costs, greater flexibility, greater control of cold-water temperature,
and less visual impact because of the structure's lower profile. However,
!.6
AIR OUTLET
-4---:---FAN STACK
FIGURE 1.3. Mechanical-Draft Wet Cooling Tower (Cross Flow)
the mechanical draft cooling towers have more potential for ground-level
fogging and icing than the natural draft units. This phenomenon is caused by
the relatively low discharge elevation for the water vapor from the mechanical
draft towers, with aerodynamic downwash being the primary cause of fogging at
such towers. Experience indicates that the fog either evaporates or lifts to
become stratus clouds within about 1,500 ft of the towers. Drift rates from
such towers are somewhat higher than for natural draft units; however, almost
all of the drift that strikes the ground will do so within 1,000 ft or so of
the towers. The remaining drift droplets will evaporate and their salts will
remain airborne. Circular configurations tend to have reduced downwash,
fogging, and icing because of the concentrated buoyancy of the multiple plumes
from individual cells.
The formation of ice fog from mechanical draft units places a severe
restriction on their use in cold environments, including the entire Railbelt
region. The effects of ice fog formation and icing can be mitigated by
creating a large buffer zone around the cooling towers or by siting them in
insensitive areas.
1.7
Dry Cooling Towers
Dry cooling towers remove heat from the circulating cooling water through
conduction to air circulated past heat exchanger tubes. In contrast to wet
towers, direct contact does not occur between the circulating cooling water
and the ambient air. The heat exchanger tubes are generally finned to
increase the heat-transfer area. The lowest temperature that a dry cooling
system can theoretically achieve is the dry-bulb temperature of the air. The
dry-bulb temperature is always higher than (or equal to) the wet-bulb
temperature, which is the lowest temperature that a wet cooling tower
theoretically can achieve. Thus, cooling water returning to the turbine
condenser will generally be at a somewhat higher temperature for dry cooling
towers than for comparable wet towers. Warmer condenser cooling water will
increase turbine back pressures, resulting in reduced station capacity for a
given size generating facility.
A major advantage of a dry cooling tower system is its ability to
function without large quantities of cooling water. This ability allows power
plant siting in areas of restricted water availability. Other advantages,
compared to wet cooling towers, include elimination of drift, elimination of
fogging and icing problems, and elimination of thermal and changing pollution
from blowdown. Thus, dry cooling towers present an environmental advantage
over the wet system for the Railbelt region.
The environmental effects of heat releases from dry cooling towers have
not yet been quantified. Some air pollution may be encountered. Noise
generation for mechanical draft dry towers will be more severe than that of
wet cooling towers because of increased air flow requirements. And, the
aesthetic impact of natural-draft dry towers, which are taller than
natural-draft wet towers, will increase despite the absence of a visible
plume.
The principal disadvantage of dry cooling towers is economic: for a
given plant size, plant capacity can be expected to decrease by about 5 to
15%, depending on ambient temperatures and assuming an optimized turbine
design. Bus-bar energy costs for a dry cooling system are expected to be
!.8
about 20% more than a once-through system and 15% more than a wet cooling
tower system. Dry cooling towers are now being used for European and African
steam-cycle plants of 200 MW or smaller capacities in areas of cool climates
and winter peak loads.
Wet-Dry Mechanical Draft Cooling Towers
In this combination tower, a dry cooling section is combined with a
conventional evaporative cooling tower. Most design concepts and all
operating units are of the mechanical draft type, although a wet-dry natural
draft tower is feasible. The design is an attempt to combine some of the best
features of both wet and dry cooling towers. These towers cause little or no
fogging in winter, less water consumption, and more economical cooling by
using water evaporation.
Four basic tower designs are possible: air flow in series or parallel,
and water flow in series or parallel. In the one design currently in use, the
hot water first passes through the dry section of the tower and then the wet;
air flow is passed through either the wet or the dry section, or both, with
adjustable louvers used to control the two air flows (Figure !.4). The two
air flows mix inside the tower before discharge. The discharged air has a
higher temperature and a lower absolute humidity than it would have from a
standard mechanical draft tower, thus reducing the potential for fogging,
icing, and long plumes. The amount of reduction of fogging and plumes will
depend on the relative sizes of the two cooling sections.
Wet-dry towers can be designed to operate with "dry only" cooling below a
given design ambient temperature (e.g., 35°F). Such units are expected to
operate as "wet only" units in summer. Thus, water would be conserved only in
cool seasons.
Since more cooling surface is required for a dry section than for a wet
section of equal cooling capacity and since excess surface may be required to
achieve operating flexibility, wet-dry mechanical draft cooling towers would
be larger than pure wet towers and more costly to build and operate than
either natural draft or mechanical draft units.
!.9
AIR G--
INLET~ i
-WATER~~ J
INLET
AIR
INLET -
~ ,.
'
~
' ,,
' '
-...11+'' '
'I'=
L t!.
I
WATER OUTLET
.,
I
AIR OUTLET
1 I
l
" v
" } \ v
" v
" v
" v
" v
" v
" v
" v
" v ...
" v
" v
" v
' '
..
"
'·
:
FAN
·rt
~
,....
(.,
·~
v
~
0
DRY
SECTION
WET
SECTION
FIGURE !.4. Mechanical Draft Wet-Dry Cooling Tower
Wet-dry mechanical draft cooling can be of great advantage to plants in
geographical locations where the contribution of cooling tower moisture to the
atmosphere could increase the occurrence of fog or icing to an unacceptable
degree. The potential for fogging and icing conditions exists throughout the
Railbelt region. The wet/dry cooling towers therefore represent the preferred
waste heat rejecting system alternative from an environmental point of view.
1.10
APPENDIX J
AESTHETIC CONSIDERATIONS
APPENDIX J
AESTHETIC CONSIDERATIONS
In this appendix methodologies for assessing aesthetic considerations,
specifically visual, ooise, and odor impacts, are presented. The objective of
these methodologies is to provide a comparison of the typical aesthetic impacts
of the candidate electric energy technologies. At this level of study the
magnitude of aesthetic impacts from the candidate electrical generating tech-
nologies are discussed, assessed, and summarized in the sections below.
VISUAL
The study of visual considerations involves a three-step process: an
assessment of the present visual quality of a study area, a determination of
the viewer's sensitivity to modification of the landscape, and an assessment
of the visual impacts caused by the construction of a power plant. Several
methodologies can be used to conduct a visual impact study. The primary
objective of these methodologies is to translate concerns that are often
subjective into a common basis for a systematic evaluation.
The first phase involves a definition of the study area as well as visual
units within the study area. The inventory of the visual quality of the study
area can be completed through the analysis of topographic maps, a series of
ground and air observations, and photographs of the site. The landscape com-
ponents should be defined, including both manmade and natural features. A
description of the landscape components that define the characteristics of
each visual unit should include boundary definition, general form, terrain
pattern, distinctive visual features, vegetation patterns, water presence, and
cultural and land-use patterns. Dominant factors, such as form, line, color,
and texture, should be used as a basis for description. Visual quality cri-
teria should be developed to assess the baseline characteristics of the study
area.
In the second phase, the existing landscape units that are most sensitive
to change are identified. The visual sensitivity related to the landscape
J.l
components is caused by the way change is exposed to the viewer. Criteria are
generally developed to assess visual sensitivity and may include viewing dis-
tance, viewer location, and viewing frequency. The visual quality of each
landscape unit is then evaluated with attention paid to areas that are vulner-
able to any manmade changes.
The third phase involves identification of the project elements that cause
impacts and their effect on viewers. The various attitudes and values of the
individual viewers are taken into account as well as differences in the loca-
tion and duration of the view. Project elements may include site preparation
activities as well as the physical features of the power plant. The effect of
the project on viewers can be determined by mapping the areas from which the
power plant and associated project elements can be viewed and by evaluating
these areas' vulnerability to visual change.
Assessment of how a project element visually affects the viewers is based
on the evaluation of whether a project element either conforms to or disrupts
the visual qualities of a landscape unit. The assessment addresses whether
the power plant elements visually contrast or complement the environment,
dominate or are consistent with the visual perceptions of the viewers, and
degrade or enhance the setting.
Assessing visual impacts in the manner described above is not feasible at
the level of candidate electric energy technologies because visual impacts
from a power plant are site dependent. The impacts will be a function of
plant scale, components, dimension of the components, acreage requirements,
terrain, and land use in the vicinity of the site. Structural components that
should be assessed for visual impact include the plant and related facilities,
fuel storage facilities, and water intake facilities. Ancillary components
that apply to all technologies are transmission lines and substations. Visual
considerations of the candidate electric energy technologies are summarized in
Table J.l. A comparison of visual impacts among these technologies can be
made to some extent without knowledge of the site, but a detailed visual
impact assessment can be made only once the plant scale and site are known.
J.2
TABLE J.l. Visual Considerations for Assessment of Power Plant Impacts
Technology Visual Concerns
Coal Large land requirements; landscape dominated by gray and
black tones; components that may visually alter the land-
scape include stacks, cooling towers, coal stockpiles,
boiler plant, ash pond, coal storage area and fuel hand-
ling system and ash slurry pipelines. Cooling tower and
stack plumes may disrupt visibility and be visually
offensive.
Oil and Natural Gas Relatively clean technology with small land require-
ments; components that may be obtrusive include stacks,
cooling towers, and boiler plant. Cooling tower plumes
may disrupt visibility and be visually offensive.
Biomass Powerplant components that may affect the visual quality
of the landscape include stacks, cooling towers, and
fuel storage area. Cooling tower plumes may disrupt
visibility and be visually offensive.
Geothermai Land-intensive technology with dispersed wells; visually
intrusive components include extensive piping system,
boiler plant and cooling towers. Large quantity of
escaping steam and cooling tower plumes may impair
visibility and be visually offensive.
Nuclear Large land requirements; landscape may be dominated by
tall cooling towers and reactor building. Cooling tower
plumes may disrupt visibility and be visually offensive.
Combustion Turbine Small land requirements; compact facility; low stacks.
Combined Cycle Visual impact on landscape varies with plant scale;
scene may be dominated by cooling tower and stack.
Cooling tower plumes may disrupt visibility and be
visually offensive.
Diesel Small land requirements; small units; few support
facilities.
Fuel Cells Visual impact on landscape varies with scale; compact
facility.
Hydroelectric Altered waterscape; large land requirements; effects of
drawdown can be visually significant.
Pumped Storage Altered waterscape; large land requirements; effects of
drawdown can be visually significant.
Cogeneration Visual impacts generally minimal since industrial
setting is required.
Tidal Introduction of linear manmade structure into sea-
scape. Altered wave pattern.
Wind Large land requirements for wind farms; height of
turbine may form silhouettes against the sky.
Solar Thermal Large land requirements; field of tracking mirrors may
impair visibility.
J.3
Based on the visual concerns of each technology, offsite impacts will be
significant for coal-fired steam-electric, geothermal, nuclear, pumped storage,
solar, large-scale hydroelectric and tidal, and wind farms (Table J.2). Visual
impacts can be mitigated or avoided by siting power plants in less visually
attractive areas and through screening and camouflaging measures.
NOISE
Noise impacts are assessed by collecting baseline noise level data, by
identifying potential sources of noise impacts, by predicting noise levels,
and by determining the incremental noise levels due to plant construction and
operation. Although the methodology described below cannot be used at this
level of study, it contains the significant elements that should be identified
in a generic assessment of noise impacts.
Baseline data of ambient noise levels are generally collected throughout
one year to account for seasonal variation. In addition, data are collected
throughout the day to determine day/night average sound levels. Isolines are
drawn to indicate the decibel levels at various distances. Other data that
are collected from the survey include wind speed, temperature, and relative
humidity because they also affect noise levels.
Potential sources of noise impacts from power plants are then identified,
including preconstruction, construction, and operating activities. Noise pre-
dictions are generally based on models that calculate the transmission of sound
from project sources to various receptors. The noise levels of equipment and
plant operations are determined in a controlled environment without wind
attenuation or topographical shieldings.
Noise impact criteria are estabished based on the objectives of protect-
ing people from hearing loss and from negative health and welfare effects.
The Occupational Health and Safety Act (OSHA) regulates onsite sources of
noise to protect personnel. Offsite noise, which is regulated through the
Noise Control Act, can affect residences, commercial activities, wildlife
habitats, and domesticated animals. Maximum noise levels that are established
for various categories of land uses should be considered in the siting and
plant design processes.
J.4
TABLE J.2. Magnitude of Off-Site Aesthetic Impacts
from Power Plant Construction
Technology
Coa 1
(20 MW)
( 200 MW)
Oi 1 and Natura 1 Gas
(10 MW)
( 200 MW)
Biomass
(25 MW)
Geothemal
(50 MW)
Nuc 1 ear
(1000 MW)
Combustion Turbine
(70 MW)
Combined Cycle
(200 MW)
Diesel
(50 KW)
(15 MW)
Fue 1 Ce 11 s
(10 1-TW)
Hydroelectric
( 2.5 MW)
Pumped-Storage
(100 MW)
Cogeneration
(25 MW)
Tidal
( N/A) (a)
Wind
(2 MW)
(100 MW)
Solar
(10 MW)
Visual
Moderate
Significant
Minor
Significant
Moderate
Significant
Significant
Minor
Moderate
Minor
Minor
Minor
Moderate to
Significant
Significant
~1inor to
Moderate
Moderate to
Significant
Minor
Significant
Significant
Noise -----
Minor
Moderate
Minor
Moderate
Minor
Moderate to
Significant
Minor
Moderate to
Significant
Minor to
Significant
Minor to
Significant
Minor to
Significant
Minor
Minor
Minor
Minor
r~inor
Minor
Moderate
Minor
(a) Rated capacity will not alter basic design.
J.5
Odor
Minor
Minor
Minor
Minor
Significant
(t~unicipal
Waste)
Significant
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
An increase in noise levels due to power plant construction and operation
is calculated at various receptor areas. The noise levels of the various power
plant components are evaluated for their cumulative impact. Mitigation mea-
sures should be identified as well as noise sources that are difficult to
mitigate. Receptors and noise levels are then identified.
At this level of study, site-specific impacts cannot be addressed. Noise
impacts will be a function of plant scale, fuel transportation requirements,
fuel type, terrain, wind conditions, and land use in the vicinity of the site.
Generally, the impacts of noise-producing technologies can be mitigated by
siting the power plant in an area away from receptors, enclosing the equipment
in structures, and installing mufflers on the turbine-generator set.
The noise impacts of most technologies can be either mitigated or confined
to the site. Impacts of certain technologies, however, may be significant
irrespective of sites. Geothermal, wind turbines (several, as in wind farms),
combustion turbines, and coal-fired power plants have the potential to produce
substantial noise. Noise-related impacts generally associated with each of
the various technologies are summarized in Table J.2. For those facilities in
which noise could be a potential problem, the vents and turbines may have to
be sited well away from residential or commercial areas to comply with ambient
noise regulations. Consideration should be given to keep these facilities out
of narrow, sheltered valleys where wind speeds are light or vegetation is
sparse.
ODOR
The study of odor impacts involves a sensory evaluation of the odor source
after it has been diluted (Turk 1973). Most gases and vapors that are not one
of the normal components of air are odorous in some ranges of concentration.
Odors that are by-products of fuel combustion or the bacterial or thermal
decomposition of organic matter are objectionable to the majority of people.
J.6
Since an odorant may be a complex mixture of many components in an
extremely high dilution of air, a chemical analysis is not a sufficient mea-
surement of odor. Noxious odors must be diluted to be evaluated by a panel of
judges. Since odor is a logarithmic function of the stimulus, it is appropri-
ate for the concentrations of the odorous substance to be distributed along an
exponential scale. The substance can be appraised in terms of its quality
intensity profile by a panel of judges. Odor intensity can be measured on an
ordinal scale, using descriptions such as 11 slight,11 11 moderate,11 11 strong,11 and
.. extreme... The quality of an odor can be described by using specific odor
quality descriptors that are represented by odor quality reference standards.
The odor quality to be judged is defined in terms of a few qualities that have
associations with subjective perception and chemical analysis. Each reference
standard may then be expanded into a dilution scale using an odorless dilutant.
After the odorous substance has been evaluated for its quality and inten-
sity, conditions under which the substance will be odorous or odorless are
specified. This prediction can be accomplished through the collection of odor
threshold data. The odor threshold is the minimum concentration of a substance
that can be distinguished from odor-free air. Such predictions provide a basis
for calculating the required degree of dilution by ventilation or outdoor dis-
persal to avoid adverse impacts.
The approach to odor control of inorganic gases such as hydrogen sulfide
and organic vapors such as hydrocarbons is to reduce the odorant in concentra-
tion through diluting the odor by ventilation or dispersal, or through removing
the odorant by adsorption, scrubbing, or chemical conversion to odorless, or
nearly odorless, products. Dispersal and scrubbing are most widely practiced
in power plant emission control technology.
When odors are dispersed from an elevated source such as a stack, the
maximum concentration at ground level can be calculated as a function of the
stack geometry, concentration of the odorant in the plume, the effluent
temperature, and meteorological conditions. These calculations predict
average concentrations over a specified time interval. Since even a short
exposure to a foul odor may be unacceptable, the degree of dispersal required
to reduce the odor may be considerably greater than is predicted by the
calculations.
J.7
Since the dispersal of gas from a stack can be calculated theoretically,
the maximum level of odor that can be emitted from a stack without causing a
nuisance can be predicted. If the actual rate is higher than the calculated
value, then the dispersal is increased (by raising the stack) or the concen-
tration is decreased (by an abatement device), or both.
Offsite odor impacts from power plants are primarily a function of fuel
type. Geothermal brines and municipal waste are the two major sources of
odoriferous substances that cannot be mitigated easily. In a geothermal power
plant, steam from leaks and pressure vents contains inorganic gases, including
hydrogen sulfide. In a municipal waste-fired plant, the decay of organic
matter produces putrescible substances that are not easily controlled. The
impacts of these two technologies are considered to be potentially significant,
whereas the odor impacts of the other technologies should be minor.
J.8
APPENDIX K
SYNTHETIC FUEL TECHNOLOGIES
APPENDIX K
SYNTHETIC FUEL TECHNOLOGIES
Many technologies described in this report operate only on liquid or
gaseous hydrocarbon fuel. Among these technologies are combustion turbines,
combined-cycle plants and diesel-electric plants. Other technologies, includ-
ing steam-electric plants and fuel cells, will accept synthetic liquids or
gases as alternative fuels and may exhibit superior economic and environmental
operating characteristics using these fuels.
Because of the limited supply of natural liquid and gaseous hydrocarbons
and the relative abundance of coal, increasing interest is being shown in pro-
cesses that synthesize liquid or gaseous hydrocarbon fuels from coal.
The conversion of coal to gaseous and liquid hydrocarbons is not a new
science. Coal gases, produced as a by-product of the coking process, were
introduced to the English economy in the 18th century. These distillation
gases contained about 500 to 600 Btu/ft3 and were used for street lighting
and other applications. Improvements in gasification were introduced during
the 19th and early 20th century. Two general classes of gasifiers emerged:
"town gas" systems, run by utilities to serve residential and commercial needs
of communities; and 11 producer gas" systems, designed to serve the needs of
industry. Liquefaction processes emerged in the 20th century. As a result of
the pioneering efforts of chemists such as Friederich Berguis, Franzo Fischer,
Hans Tropsch, Mathias Peer, and other notable German scientists, a range of
processes and products has been developed.
The principles employed are conceptually simple, but are varied depending
upon the products sought. Coal is a heterogeneous solid substance with hydro-
gen/carbon (H/C) ratios of about 0.5 to 0.8, depending upon rank. This con-
trasts with crude oil and natural gas where H/C ratios are about 1.5 and 4.0,
respectively. Further, the macromolecules of coal are considerably larger
K.1
than the molecules of liquid or gaseous fuels. To convert coal to gaseous or
liquid fuels, then, the H/C ratio is increased by carbon removal (pyrolysis,
coking), hydrogen addition (direct hydrogenation), or total reformation (indi-
rect liquefaction through the production and reaction of synthesis gas, a mix-
ture of CO and H2). Simultaneously, the coal molecule is fragmented into
smaller units. Whereas some of the coal conversion reactions are exothermic
(heat releasing), most are endothermic (heat consuming). Fuel synthesis
processes, therefore, have different thermal efficiencies depending upon the
extent to which endothermic reactions are required and the degree to which
waste heat produced by exothermic reactions can be recaptured.
Coal gasification systems employing these principles produce low Btu gas
(100 to 150 Btu/ft3), medium Btu gas [(250 to 350 Btu/ft3 ), or high Btu gas
(substitute natural gas) 900 to 1000 Btu/ft3]. Coal liquefaction systems produce
synthetic crude oils, alcohol fuels, and gasoline and diesel oil liquids.
Alcohol and most vehicle fuels are currently produced by indirect liquefaction,
such as the Sasol I and Sasol II plants using the Fischer-Tropsch process.
These processes are described below.
SITING REQUIREMENTS
Synthetic fuel plants are, for the most part, similar to large petrochem-
ical complexes (Table K.1). Due to the large scale of these plants, siting
strongly depends upon the economic availability of the coal feedstock.
Land requirements for typical synthetic fuel plants are measured in
thousands of acres (not including the coal mine). Land is required for 30 to
90 days of coal storage, for the conversion facility itself, for auxiliary
facilities such as onsite power plants and cryogenic oxygen separation plants,
and for product storage. The Modderfontain site in South Africa (Sasol II),
for example, exceeds 12,000 acres.
If not located at mine mouth, the site must have transportation facilities
for moving coal to the facility and for transporting the product from the
facility. An exception to the latter requirement is low Btu gas, which must
be used onsite because of the expense of transporting the low-energy-content
gas.
K.2
TABLE K.1. Typical Sizes of Coal Conversion Facilities
(Sliepcevich et al. 1977)
Facility Daily Coal Da il~ Output
T~ee Consumption (tons) 10 6 Btu As Product
Producer Gas (Low Btu Gas) 40 -800+ 680-12,800 4.5-85+ X 106 SDCF (a)
Substitute Natural Gas (SNG) 20,000 250,000 250 x 106 SDCF
Synthetic Crude Oil 20,000-22,000 330,000 50,000 bbl
Methane 1 28,000 230,000 11,000 tons
Synthetic Motor Fuels
(Fischer-Tropsch) 35,000 250,000 42,000 bbl
(a) Standard dry cubic foot.
The site must have access to copious quantities of water for process
cooling. Water also serves as a source of hydrogen for altering the H/C ratio
in the water-gas shift reaction. Table K.2 identifies water requirements as a
function of end product. Water requirements for indirect liquefaction (metha-
nol, Fischer-Tropsch) are similar to those for SNG production. Cooling water
requirements are the most significant, although they can be minimized by atmo-
spheric heat rejection systems. However, water requirements of 4 million
gal/day may be considered typical values, and sites must be selected where
such quantities (or more) are available.
Electricity should be available, unless onsite generation is used, as
would probably be the case in the Railbelt area. Where onsite generation is
used, land and water requirements will escalate accordingly.
DETAILED PROCESS DESCRIPTIONS
The most appropriate processes for synthetic fuels production in the
Railbelt region include low and medium Btu gas production and liquefaction by
indirect and direct means.
K.3
TABLE K.2. Water Requirements for Coal Conversion Processes
End Product
Low and Medium Btu Gas
Substitute Natural Gas
Synthetic Crude Oils
Water Requirements (gal/MM Btu)
Process Cooling Slowdown
2-5 20 4
3-13 16 3
1-2 9 2
Source: Anderson and Tillman 1979.
Low and Medium Btu Gasification
In low Btu gasification, coal is fed into a fixed bed, entrained bed, or
fluidized bed gasifier. There it is reacted with air and steam. The air is
used to combust part of the coal, thus supplying heat for the endothermic
pyrolysis and gasification reactions. Steam is used to drive key gasification
reactions as follows:
The gas resulting from this process contains about 50% nitrogen because
of the use of air and has a heating value of approximately 150 Btu/SDCF (stan-
dard dry cubic foot). The gas is 11 Wet 11 and "dirty" and must be burned immedi-
ately in a boiler to preserve the gas•s sensible heat.
The fundamental difference between low and medium Btu gas production is
the oxidant used to generate heat for driving endothermic reactions. Medium
Btu gasifiers employ cryogenically separated pure oxygen as an oxidant instead
of air. Thus, nitrogen gas is not part of the product gas stream and the
heating value is increased to approximately 300 Btu/SDCF. Medium Btu gas may
be cleaned, cooled, and transported up to about 40 miles economically, although
it is ideally used onsite. Whereas it may be burned as a fuel, it also may be
used as a feedstock for producing chemicals. Figure K.1 shows a schematic of
K.4
Medium Btu ..
Gas
,..
Gasifier
Coal I -...;..~~•~ Preparation Coal : ..._ 02
....
~
Steam Nz Ash ._a.. .,
Steam l<lll~t---W_a;....t..;;..er;....__
Plant Fuel/Heat,
Air
Cryogenic .. Separation .. Plant
FIGURE K.1. Flowsheet of Medium Btu Gas Plant
a medium Btu gas plant. (In comparison, low Btu gasifiers do not have the
oxygen plant). Table K.3 shows typical product gas composition for various
gasifiers producing low and medium Btu gaseous fuels.
TABLE K .3. Product Gas Composition and Higher Heating Values
from Various Coal Gasifiers
Higher Heat-
Product Gas Com osition (Percent ing Value
Gasifier co C02_ _!i2_ _1!4 .1!2 _ (Btu/SDCF)
Wellman-Ga lusha 28.6 3.4 15.0 2.7 50.3 150
(Air Blown)
Lurgi (Air Blown) 13 0 3 13.3 19.6 5.5 48.3 150
Koppers-Totzek
(02 Blown)
52.2 10.0 36.0 1.5 300
Lurgi (02 B 1 own) 16.3 31.5 39.4 9.0 2.4 0.8 350
K.5
Thermal efficiencies for gasification can be defined as the fuel value of
product gas divided by total energy and fuel input (including electricity used
for 02 production). Typical values are in the 75 to 90% range, depending
upon gasifier design, product type, and extent of waste heat recapture.
Liquefaction
Indirect liquefaction begins with medium Btu gas. The gas can be shifted
to a volumetric H2;co ratio of 2:1 and reacted over a catalyst to produce
methanol (CH 30H). This process is essentially commercial today and is shown
in Figure K.2. Alternatively, the Fischer-Tropsch process employed by Sasol I
and Sasol II can be used to catalytically react medium Btu gas into gasoline
and diesel oil. This process stems from the original work of Fischer and
Tropsch in the 1920s and 1930s in Germany and is shown in Figure K.3. The
thermal efficiencies of indirect liquefaction are in the 40 to 45% range
depending upon the process used, final product, plant design, and coal
composition.
Direct liquefaction processes (hydrogenation) treat coal under elevated
temperatures and pressures with hydrogen. Catalysis may be employed to aid in
fracturing the molecule and, more importantly, in donating hydrogen to the
fragments. Figure K.4 shows direct hydrogenation by the solvent extraction
process; Figure K.5 shows a flow sheet for catalytic hydrogenation. Products
resulting from direct hydrogenation include syncrudes, boiler fuels, and
naptha. Thermal efficiencies are typically in the 60 to 65% range.
Direct hydrogenation is at the pilot plant scale of development and com-
mercialization is expected within the next 10 to 15 years. Major pilot plants
under construction or in operation are shown in Table K.4. Others, such as
the gasoline pilot plant in Cresap, West Virginia, and the COED Pyrolysis
pilot plant in Princeton, New Jersey, have been built, operated, and decommis-
sioned. Numerous other processes (e.g., Toscoal, University of Utah, Synthoil)
are or have been under intensive, although smaller scale study.
COSTS
No major coal gasification or liquefaction plant has been built in the
U.S. since World War II. Costs are typically extrapolated from experiences in
K.6
Air
Separation
Oxygen
Recycle
Tars and Oils
J J
Coal Gas Methanol Methanol
Gasification ---Preparation ---~ Preparation ~ Synthesis
Steam
Fuel Gas Steam/Power
Manufacturer Plant
Air
FIGURE K.2. Methanol Production Flowsheet
Air LPG
Separation I Oxygen Gasoline
Gas Oils _r Gasification Clean-up
Synthesis
Chemicals
Coal I Preparation -Tar, Oil, Naphtha Steam
I -Fuel Gas Steam/Power
Manufacture Plant
Air t
FIGURE K.3. Fischer-Tropsch Synthesis Flowsheet
K.7
Coal
Preparation !---
Air Oxygen
Separation (team
-Acid-Gas -Gasification r-Removal
Hydrogen
Production
Syngas
Coal Product
Dissolving -Flashing
I Filter ~ I
I
~
Naphtha --i Hydrotreating
Plant
Acid-Gas Fuel Gas
Removal
Light
l Distillation
I Fuel Oil
Hydrotreater J
Heavy
Fuel Oil
FIGURE K.4. Solvent Extraction Process Flowsheet
South Africa and other countries, and from pilot plant experiences. Costs are
therefore highly uncertain. Estimated capital costs are presented in
Table K.5. Total 1980 capital costs for a 50 x 10 3 bbl/day coal liquefac-
tion ~lant are estimated to be approximately $1.3 billion (Tillman 1981).
Operating costs are also uncertain. For gasifiers they are totally
dependent upon plant configuration and practices. For liquid fuels, such as
direct hydrogenation, annual O&M costs are estimated at about $330 million
(not including depreciation) for a 50,000 bbl/day refinery (Tillman 1981).
K.8
Plant Fuel Gas t Naphtha
Boiler
Gas Treating Product Fuel
t l Light Oil
Distillation
Coal Coal ~ Hydrogenation Solids
Preparation Separation Liquefier
t Char
Air Oxygen Hydrogen
Separation Production
-t Steam
FIGURE K.5. Catalytic Hydrogenation Flowsheet
TABLE K.4. Major Coal Liquefaction Pilot Plants in the United States
Pilot Plant (Process)
Solvent Refined Coal
H-Coa 1
Exxon Donor Solvent
(a) TID = tons per day.
Primary Industry Sponsor
Gulf Oil
Hydrocarbon Research
Exxon Corporation
Capacity (T/D)(a)
50
600
250
World oil prices would have to rise to $60/bbl ($10/MMBtu) for coal
liquefaction processes to be economically competitive at current estimates of
capital and O&M costs of liquefaction plants (Tillman 1981). This price is
about double the current world price of oil. Because of higher thermal effi-
ciencies and lower capital coal gasification's costs, it would be competitive
at much lower prices. Values frequently quoted range from 5 to $6/MMBtu.
K.9
TABLE K.5. Estimated Capita) Costs for Coal Conversion Facilities
(1980 Dollars)(a)
Process
Low Btu Gas
Medium Btu Gas
Methanol
Fischer-Tropsch
Solvent Extraction
Catalytic Hydrogenation
Capital Cost
$250/Btu/day Capacity
$450/Btu/day Capacity
$30,000-40,000/bbl/day
$28,000-36,000/bbl/day
$21,500-28,000/bbl/day
$20,000-26,000/bbl/day
(a) These costs have not been adjusted to Alaskan conditions.
Sources: Sliepcevich et al. (1977); Anderson and Tillman (1979).
ENVIRONMENTAL CONSIDERATIONS
The principal environmental effects of synthetic fuel plants include water
consumption, water-quality impacts, air emissions, and habitat disturbances.
Water Resource Effects
Synfuel processing plants may have a significant water requirement, which
can restrict their location to regions of abundant water supply. The specific
water requirements vary by conversion process and individual plant design, and
by the extent of water recycling and the ratio of air/water cooling employed.
Davis and Wood (1974) have made the following estimates for minimum water
demands:
SNG production: 72 gal/MMBtu for 90% water cooling
37 gal/MMBtu for 90% air cooling
Coal liquefaction: 31 gal/MMBtu produced as fuel.
These values compare with Davis's and Wood's estimate of 146 gal/MMBtu equiva-
lent to electricity from fossil fuel based generating stations. As a general
guideline, a minimum of 4 million gallons per day are required by a synfuel
K.10
plant. This requirement could have significant impacts in regions with
limited water supplies and could preclude development of a synfuel plant at
water-scarce locations.
If a total requirement of 14 million gallons per day for a synfuel plant
and its associated power plant, cryogenic oxygen plant, and other associated
facilities is assumed, a plant location in the Beluga coal fields would require
approximately 4% of the entire Susitna River flow during minimum flow condi-
tions, or almost 10% of the Matanuska River flow.
In addition to water supply impacts, synfuel plants may have significant
water-quality impacts. Most current synfuel technologies use process water
streams that come in direct contact with the intermediate products. Hence,
wastewater streams typically contain high concentrations of dissolved solids,
suspended solids, and dissolved organics (e.g., phenols). These effluents are
typically not significant in low or medium Btu gasification (e.g., Koppers-
Totzek process), but become a major concern in high Btu gasification (e.g.,
Lurgi process) or liquefaction processes. Extensive treatment facilities are
required to mitigate adverse impacts associated with the discharge of these
effluents. One existing facility using a Sasol II process that had been
designed as a zero wastewater discharge facility has proven ineffective in
practice in avoiding all adverse water-quality impacts.
In certain site-specific cases, water-quality problems can also arise
from leaching and surface runoff from fuel/coal storage. These impacts are
similar to those of a coal-fired steam-electric facility and are discussed in
Appendix D.
Air Resources Effects
The production of synthetic fuels creates the potential for large amounts
of atmospheric emissions. These emissions are similar to those of conventional
combustion processes and include primarily particulate matter, sulfur oxides,
nitrogen oxides, hydrocarbons, and carbon monoxide. These emissions are a
function of both process configuration and process efficiency (Anderson and
Tillman 1979). Specific emissions estimated on the basis of the heat content
of product fuels were made by the U.S. Energy Research and Development
Administration (1975). Projected emissions for a range of products and various
K.11
coal types are shown in Table K.6. These data indicate that a synfuel's
facility that produces fuel for a 15-MW power plant conservatively could be
considered a major source of air pollution and would require a complete air-
quality review.
Other emissions will be associated with the onsite use of the synfuels.
Although little practical experience with the use of these fuels exists, their
impacts roughly could be projected to be similar to those of oil or natural
gas. Viable mechanisms exist to remove sulfur and nitrogen from the product
stream and their extraction for sale as by-products enhances the economic
feasibility of a synfuel's project.
Aquatic and Marine Ecosystem Effects
The most difficult to mitigate effects from synthetic fuel production
plants are associated with water supply and wastewater discharge requirements.
In addition, the large land area requirement could result in large construction
runoff. Water withdrawal is associated with impingement and entrainment of
aquatic organisms (refer to Appendix F). Chemical and thermal discharges may
have acute or chronic effects on organisms living in the discharge plum area.
Thermal discharges can also cause lethal thermal shock effects in cold climate
regions when the discharge is stopped. The degree of these impacts will depend
on many factors, such as the location of the intake and discharge structure,
TABLE K.6. Range of Controlled Air Emissions from
Coal Conversion Facilities
Emissions Range
Pollutant (lb/MMBtu)
Particulates 0.01 -0.04
Sulfur Oxides 0.01 -0.30
Nitrogen Oxides 0.07 -0.40
Hydrocarbons 0.001 -0.01
Carbon Monoxide 0.006 -0.03
Source: U.S. Energy Research and Development
Administration (1975).
K. 12
the chemical composition of the water supply and effluent, the plant's water
and wastewater management plan, and the type and quantity of aquatic organisms
present in the receiving water. In general, however, the magnitude of impacts
can be related to a plant's makeup water requirements.
Synfuel plants most likely would be located near the Beluga coal field.
Many important aquatic resources are located near these areas, including
salmon in the Susitna River and shellfish, salmon, and other marine fish in
Cook Inlet. Due to the large water requirements as compared to many of the
river systems in the Railbelt, extensive mitigation efforts will be required
to avoid adverse impacts.
Terrestrial Ecosystem Impacts
The major impact on the terrestrial biota resulting from synfuel plants
is the loss of habitat. Synfuel plants require land areas that are two to
five times that of coal-fired plants for a given energy generating capacity.
In terms of land area, the synfuel plant, electrical generating facility, and
support facilities can occupy approximately 1000 to 3000 acres. In addition,
the work force needed to support this facility can create further disturbances
to local terrestrial ecosystems.
Terrestrial impacts can also result from air emissions. These impacts
will be similar to those of gas-and oil-fired plants. Whereas sulfur and
nitrogen oxides are generally retained as a plant by-product, particles and
other pollutants are released into the environment. Such particles can have
adverse effects on local soils, vegetation, and animals. A detailed discussion
of these impacts and possible mitigative measures are presented in Appendix G.
As noted earlier, in the Railbelt region sites for synfuel plants will
most likely be at or near the Beluga coal fields. Specific terrestrial impacts
at this site are presented in Appendix 0 and in Section 4.1 of this report
(Coal-Fired Steam-Electric Generation). Impacts primarily include the loss or
disturbance of moose, mountain goat, Dall sheep, and black bear habitat.
Socioeconomic Impacts
Because a synthetic fuel plant in the Railbelt most likely would be
located in the Beluga area, this site would present the advantage of mine-
K.13
mouth siting and would allow direct ocean shipment of products. Electricity
generated at the site could be readily transmitted to the Anchorage area or
could be fed to the proposed Anchorage-Fairbanks intertie. Use of Nenana
coal would be less desirable because of the expense of transporting product
fuels by rail and concerns regarding air-quality ethics on Denali National
Park.
The socioeconomic impacts of a synthetic fuels production plant are
difficult to predict since no United States experience exists from which to
extrapolate employment levels. Due to the large scale of these plants,
however, the construction work force requirements can be assumed to be at
least equal to those of a large coal-fired power plant. The work force
requirements for mining the coal would increase the impacts of a mine-mouth
synthetic fuels plant by an order of magnitude of at least two. The
cumulative impacts of a coal mine, synthetic fuels plant, and onsite power
plant would be severe.
The construction and operation of a synthetic fuels plant (including the
coal mine and power plant) would cause a permanent boom due the large cumula-
tive operating work force requirements. While the construction work force
would be substantially larger than the operating staff, the impacts caused by
the out-migration of the construction workforce would not be as great as the
initial boom. These effects would be due to the large scale and intensity of
a plant development and the remoteness of the Beluga sites.
The communities in the vicinity of the Beluga coal field are small in
population. The largest community in the area, Tyonek, is an Alaskan native
village with a population of 239. The influx of a construction work force
would severely disrupt the social structure of the community.
K.14
APPENDIX L
PERFORMANCE OF PASSIVE SOLAR OPTIONS
APPENDIX L
PERFORMANCE OF PASSIVE SOLAR OPTIONS
The performance of several passive solar options was assessed using a
1500 ft2 representative house.
OPTION A -USE EXISTING GLASS
I·n this first example, the 130 square feet of glazing on the model struc-
ture is assumed to be distributed equally to all four orientations. This
distribution is rare; it is assumed here for illustrative purposes, since most
housing in the last several decades has paid very little attention to orienta-
tion for solar.
Dividing the total glass area by 4 results in 32.5 square feet of south
glazing, worth approximately 5.5 MMBtu (million Btus) per year. Although all
free heat is beneficial, this is a very small percentage of the annual heat
1 oad.
OPTION B -RELOCATE GLASS
In the second example, the same amount of glass is kept, but most of it
is relocated to the south orientation. Not all the glass can be put there, as
most likely bedrooms will be located in other parts of the building without
access to the south wall glazing. Most solar home designs take advantage of
the south glass by putting living areas there, with bedrooms towards the north
wall. By fire codes, each bedroom must have a window for emergency egress;
therefore, all glass cannot be placed to the south.
Forty square feet of glazing is assumed to be required for the bedrooms,
leaving 90 square feet that can be placed to the south. These windows are
11 free 11 in the sense that there is no additional cost for them above and beyond
that included in the model house. They are simply being relocated for this
scenario. Likewise, no additional heat loss occurs through the windows. By
relocating the glazing, a total of 15.1 MMBtu is now available through solar
gain to heat the house.
L.1
OPTION C -ADD ADDITIONAL GLAZING
In this third example, south glazing is added to equal 10% of the floor
area. This addition requires an investment of 60 additional square feet of
double pane glazing, at a cost of approximately $725 in materials. (There
generally will not be added framing charges in new construction for the added
glass, unless it is excessive or involves a different construction system.)
With 150 square feet of south glazing, yearly solar gain is approximately
25.3 MMBtu. However, an additional heat loss of 7.8 MMBtu occurs through the
extra 60 square feet of window. This loss is in addition to the heat loss
previously calculated for the base-case windows. Adding this loss to that for
the original 90 square feet gives a total net gain of 17.5 MMBtu yearly, or
just 2.4 MMBtu better than the "free" glass in Option B.
OPTION D -ADD ADDITIONAL GLAZING
In the fourth example, 50 square feet of glazing is added to the level
found in Option C, for a total of 200 square feet. Total solar gain for the
year(a) is approximately 33.7 MMBtu. However, additional heat loss through
the 110 square feet of glazing (200 minus the original 90) is about 14.4 MMBtu,
for a net gain of 19.3 MMBtu annually. This gain amounts to a net of 4.2 MMBtu
over Option B, the free glass. The 110 square foot of glazing costs approxi-
mately $1330.
The above examples are somewhat deceiving, in that an annual averaging of
solar gain is an unfair method to evaluate performance in the Alaskan climate.
Solar has little benefit in the midwinter months and can have a great deal of
impact on home performance in the spring and fall months. In addition, actual
performance of solar houses appears to exceed the calculated percentages. As
mentioned earlier, solar data are poor and suspect.
Once a large portion of the heating load has been reduced through conser-
vation, solar gain is able to take up a fair amount of the heating needs.
Since the solar gain of the windows is offset largely by the heat lost back
(a) "Year" in this and all other examples denotes the heating season -
approximately late September to early May.
L.2
out through them at night and during cloudy periods, movable insulation over
the windows is necessary for an optimal solar performance. Little hard data
are available on installed costs of shutters because they are a new develop-
ment in the region. One Anchorage store sells a kit for fabric shutters
(Roman shades) for a material cost of about $3.50 per square foot. The shades
must then be sewn and installed by the owner. Resistive value is about R-7.
A very preliminary estimate of rigid shutters with wood facing (R-10) done by
J.A. Barkshire from Alaska Renewable Energy Associates, with assistance from a
local contractor, indicates an installed cost of around $7.50 per square foot.
Solar performance in Option D would increase by about 7 MMBtu net gain per
heating season if the shutters were used diligently during night and other
periods of no sun.
OPTION E -ADDING STORAGE MASS
Because solar radiation is not static, a space with large windows to the
south will experience a large variety of temperature ranges throughout the
year and even throughout the day. Storage mass is a common and accepted way
both to temper these swings in interior temperature and to store excess solar
gain coming through the glazing for later use.
In Alaska for much of the year, most of the available solar radiation is
used up immediately as it enters the space. Although little modeling has been
done, results show that only during the spring and fall months does storage
mass become effective to any degree. As such, it is the last investment a
homeowner is likely to make in passive solar applications. Nonetheless, it is
important in a structure with significant south glazing. Overheating by solar
gain as early as February in structures with no mass present has been reported.
However, the addition of storage mass most likely will be limited to new hous-
ing that is solar oriented in design.
Many types of storage mediums exist; water is the most effective for its
installed cost. However, very few installations use water. Consumer accep-
tance of water as a storage medium appears to be very low, mainly because few
if any architecturally pleasing containers are available to store it in.
L.3
Concrete walls and floor slabs appear to be the most popular storage
mediums. The slab need have no additional cost if designed into the house as
a structural system. If designed into the house, the slab generally can be
credited as a free investment for solar performance. The installed cost of a
4" thick concrete slab is approximately $3 per square foot.
A concrete wall is popular among some as a storage medium. Placed at the
rear of the room exposed to southern sun, it has the added advantage of acting
as a structural element and serves to break up the often boring interior
finishes of gypsum board. A concrete wall is expensive, about $30 per lineal
foot for an 8 foot high wall (including structural footing) or about $1000 for
a 32-foot-long wall. Such a wall presents about 250 square feet of surface to
the south and will increase the solar performance of Option D by about 5 to
7%. As such, it cannot be justified in life-cycle costs alone. As mentioned
earlier, the homeowner is making an investment in comfort and ease of control
of the solar system during those months when the mass is required. All cost
and solar performance results for this section were calculated for Anchorage.
Performance figures should be viewed with some caution until further studies
can be done.
Normally, passive solar is associated with new construction. Retrofitting
existing structures for solar applications is somewhat difficult and costly.
Tearing out walls to add solar windows is not easy, although it may be desir-
able if the proper orientation and site access exists. Adding a greenhouse
onto the south wall of a home is by far the most popular solar retrofit in the
Railbelt region. This retrofit offers many advantages above and beyond thermal
performance, such as plant and food production, addition of pleasant living
space, etc. However, repeated testing shows the greenhouse to be the lowest
performer in terms of thermal energy supplied to the home. The greenhouse
space itself must use solar gain to maintain ambient temperature before supply-
ing heat to the household. Each installation will be markedly different,
depending on type and care of construction, whether night insulation is used
over glazing, and desired temperature in the greenhouse.
show that a well-managed solar greenhouse will supply net
of 10 to 15% of the load.
L.4
Early calculations
benefit to the house
Costs of greenhouse construction will reflect those of current building
costs, $30 to $40 per square foot. These costs assume a well-built structure
with heavy insulation in the end walls and roof, and double-glazed glass
windows on the south.
A review of conservation and passive solar costs will show that the
investment in passive solar is not as attractive an investment as one in con-
servation. Study after study shows that conservation measures offer the
fastest payback. Conservation is the first and most practical step, particu-
larly in the North, where housing stock does not reflect the cold climate in
construction techniques. Passive solar is best suited to new construction, in
harmony with increased conservation. Nonetheless, increased understanding of
use of the sun increases retrofitting of existing structures for passive solar
gain.
All cost figures contained in this appendix were taken from suppliers and
contractors in the Anchorage Bowl area. Although cost increases in outlying
areas of the Railbelt do not reflect those of remote Bush construction, they
are higher than they would be in Alaska's largest commerce center.
The following cost multiplier was prepared for the entire state by an
Anchorage professonal cost estimating firm (HMS, Inc.). Excerpts for Railbelt
locations are listed here. The last update on this multiplier was March 1981.
Anchorage (base) 100.00
Anchorage zone (up to 50 miles) 110.03
Anchorage Zone (beyond 50 miles) 122.43
Fairbanks
Fairbanks Zone (up to 50 miles)
Fairbanks Zone (beyond 50 miles)
L.5
106.04
117.71
129.69
APPENDIX M
PERFORMANCE OF ACTIVE SOLAR WATER HEATING SYSTEMS IN FAIRBANKS
APPENDIX M
PERFORMANCE OF ACTIVE SOLAR WATER HEATING SYSTEMS IN FAIRBANKS
Not much research has been done in Alaska on the performance of active
solar hot water heating systems. The bulk of research has been from Fairbanks,
particularly the work of Rich Seifert from the Institute of Water Resources at
the University of Alaska, Fairbanks.
The effectiveness of an active system will obviously depend on the amount
of solar radiation available and the type and effectiveness of the system
installed. Somewhat less tangible is the load for water heating, which varies
with every household.
In a September 1980 article in Solar Age magazine, J. Carter noted an
average yearly load of approximately 22 MMBtu for a family of four. An
approximation to this figure has been used for the calculations in Table M.1.
In Table M.2 a family of six is assumed to use 36.5 MMBtu per year (100,000 Btu
per day). Eighty and 120 square feet of collector have been assigned to these
loads, respectively.
In both cases, almost 50% of the annual load can be met with an active
solar system. These figures differ little from Seifert's work over the past
several years and tend to further confirm this phenomena. One column shows
the percentage of load supplied by the 120-square-foot section. Although the
system is drained down during the mid-winter months, the high percentage of
performance results because a hot water load occurs year round.
·Costs for active systems are estimated to run from 25 to $80 per square
foot contractor installed, depending on the system design. The high end cost
reflects copper-tube flat-plate collector systems by major manufacturers. Most
of those systems are not readily available in Alaska. The low end reflects
the newer Solaroll~product Seifert has been experimenting with. These prices
are estimates, not quotes from Mr. Seifert.
(a) A trademark from the Bio-Energy Systems, Inc., Ellenville, New York.
M.1
TABLE M.l. Solar Hot Water Heating System Performance: Household of Four(a,b)
Load(c) Ref. Load Supp 1 i ed
Insola(i)n Temp by Solfr Percent Solar
Month {MMBtu} Factor d {oF} {MMBtu} e) Surn~ 1 i ed
January 2.07 0 0 0 0
February 1.87 0 0 0 0
March 2.07 1925 8.6 1.697 82
April 2.00 1904 30.2 1.700 85
May 2.07 1806 46.4 1. 734 84
June 2.00 1797 57.2 1.700 85
July 2.07 1559 59.0 1.5 76
August 2.07 1588 53.6 1.53 74
3: September 2.00 1040 42.8 0.96 48 .
N
October 2.07 836 26.6 0.68 33
November 2.00 0 0 0 0
December 2.07 0 0 0 0
Annual 24.36 11.57
(a) Fairbanks -Lat. 64°49' N; E 1. 436 ft.
(b) 80 ft2 collector area.
(c) 80 GPO, Tin 40°F, Tour 140°F.
(d) 50° collector tilt.
(e) System drained during mid-winter months.
TABLE M.2. Solar Hot Water Heating System Performance: Household of Six( a, b)
Load(c) Ref. Load Supplied
Insolafi~n Temp by Solfr Percent Solar
Month (MMBtu) Factor d {oF} {MMBtu) e) SUQQlied
January 3.102 0 0 0 0
February 2.802 0 0 0 0
March 3.102 1925 8.6 2.544 82
April 3.002 1904 30.2 2.552 85
May 3.102 1806 46.4 2.606 84
June 3.002 1797 57.2 2.552 85
July 3.102 1559 59.0 2.358 76
August 3.102 1588 53.6 2.295 74
September 3.002 1040 42.8 1.441 48
3: October 3.102 836 26.6 1.024 33 .
w November 3.002 0 0 0 0
December 2.07 0 0 0 0
Annual 36.524 Btu/yr Total Hot H 0 Load 17.372 x 10 6 Btus/year Solar -47 X
(a) Fairbanks -Lat. 64°49' N; El. 436ft.
{b) 80 ft2 collector area.
(c) 80 GPO, Tin 40°F, Tour 140°F.
(d) System drained during mid-winter months.
(e) 50° collector tilt.
The following are estimated installed costs at a contractor price of $25
per square foot of collector:
80 square foot @ $25 = $2000.00
120 square foot @ $25 = $3000.00
Actual square footage cost will vary with type of system (drain down, anti-
freeze, one or two tanks), and final installed cost is difficult to determine
except on a case-by-case basis. Note, however, that the above costs also are
for a complete system with a single hot water tank and short, simple plumbing
runs.
Reports from Fairbanks of home-built collectors using the Solaroll indi-
cate that construction costs of as little as $8 dollars per square foot is
possible. This figure is for the collector area only and does not include
associated costs.
Expected life of the Solaroll system averages 15 to 20 years if properly
installed. O&M costs are difficult to determine; a hypothetical estimate of
$25 to $50 per year is made. Replacement cost is largely restricted to the
pump(s) during the systems life. Pump replacement might occur at 7 to
10 years.
Man-hours required for an installation will vary; on a simple applica-
tion, 5 to 6 man-days might be required for collector assembly and installa-
tion. If the collector is shop built and simply has to be installed, 2 to
4 man-days generally will be required.
M.4
APPENDIX N
POWERPLANT AND INDUSTRIAL FUELS USE ACT
APPENDIX N
POWERPLANT AND INDUSTRIAL FUELS USE ACT
An objective of the Powerplant and Industrial Fuels Use Act (FUA) of 1978
is to curtail the use of natural gas and petroleum-derived fuels for the
generation of electricity where acceptable substitutes for these fuels are
available. Pursuant to the FUA, natural gas or petroleum-derived fuels may
not be used as a primary fuel in new electric generating plants except under
special conditions subject to approval of the Department of Energy (DOE).
Thirteen conditions are set forth in the FUA, 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 ten 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
alternate fuels to natural gas or petroleum. Qualifying site
limitations 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) unavailabiity of land
for controlling and disposing of wastes resulting from use of
alternate fuels.
503.34 Inability to comply with applicable environmental requirements
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, nuisance
or zoning laws) rendering use of alternate fuels infeasible.
N.1
503.37 Use of cogeneration, where electricity would constitute more than
10% and less than 90% 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.
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 is 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 three-year periods.)
N.2
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